Fortis Inc. (NYSE:FTS) Q3 2025 Earnings Call Transcript

Fortis Inc. (NYSE:FTS) Q3 2025 Earnings Call Transcript November 4, 2025

Fortis Inc. beats earnings expectations. Reported EPS is $0.625, expectations were $0.61.

Operator: Thank you for standing by. This is Betsy, the conference operator. Welcome to the Fortis Inc. Third Quarter 2025 Earnings and New 5-year Capital Outlook Conference Call. [Operator Instructions] The conference is being recorded. [Operator Instructions] I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead.

Stephanie Amaimo: Thanks, Betsy, and good morning, everyone. Welcome to Fortis’ Third Quarter 2025 Results and New 5-year Capital Outlook Conference Call. I’m joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries. Before we begin today’s call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. Non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our third 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. Today, we are proud to announce another solid quarter marked by strong execution and momentum from our regulated growth strategy. Operationally, we continue to deliver safe and reliable service to our customers. And through September, our utilities invested $4.2 billion in our systems. For the full year, we expect to invest approximately $5.6 billion. Financially, we delivered adjusted earnings per share for the third quarter of $0.87. In September, we completed the sale of FortisTCI. The sale strengthens our balance sheet and reduces our risk profile. More recently, we entered into an agreement to sell our investments in Belize, including the non-regulated hydro generation facilities to the government of Belize.

I am happy to announce that the transition closed last Friday and that Fortis is now comprised of 100% regulated assets. We recognized these were long-held assets in the Fortis family, and we wish our best to the teams in Turks and Caicos and Belize as they continue to serve their customers and communities. And today, we are pleased to unveil our 5-year capital plan and announced that our Board of Directors has declared a fourth quarter dividend increase of approximately 4%. Our new $28.8 billion 5-year capital plan is up $2.8 billion compared to the prior plan. This supports rate base growth of 7% and annual dividend growth guidance of 4% to 6% through 2030. This new plan was developed with a strong emphasis on maintaining customer affordability.

We prioritize capital investments that provide cost savings that flow through to our customers. This includes the coal to natural gas conversion at the Springerville Generating Station in Arizona, which is more economical compared to the new energy resources included in the prior plan. Our utilities are also continuing to manage operating costs by finding efficiencies through innovation and process improvements. As you can see on the slide, the growth in our 5-year plan is largely driven by higher transmission investments. At ITC, the $2 billion increase was primarily driven by new interconnections, including the Big Cedar Load Expansion project as well as the MISO long-range transmission plan and baseline reliability projects. At UNS, transmission and distribution investments increased $1 billion with FERC-regulated transmission making up $700 million of the increase.

This was largely attributed to a new transmission line at TEP. Generation investments at UNS were reduced by $900 million driven primarily by the planned conversion of the Springerville Generating Station to natural gas, which I spoke to previously. The remaining increase is driven by growth at our other regulated utilities and a higher assumed foreign exchange rate. The new plan is highly executable with approximately 77% directed towards transmission and distribution investments and critical infrastructure that drives stable, predictable returns. The capital program is low risk and anchored in 100% regulated projects and includes only 11 major capital projects representing 21% of the plan. Consolidated rate base is expected to increase by $16 billion from approximately $42 billion in 2025 to $58 billion in 2030, supporting average annual rate base growth of 7%.

This is up 50 basis points from the 6.5% in the prior plan. Now I’ll take a few minutes to dig a little deeper into our larger utility capital plans. ITC’s capital plan of $9.8 billion is the largest in the company’s history and support strong rate base growth of 8%, up 100 basis points compared to the prior plan. Key elements of ITC’s plan includes investments for base infrastructure, MISO’s long-range transmission plan, customer connections and grid security. Significant opportunities above and beyond the base plan exists at ITC, including approximately USD 3.3 billion to USD 3.8 billion post 2030 for tranche 2.1 projects assigned through rights of first refusal. Work is also underway at ITC to evaluate projects within the tranche 2.1 portfolio that are subject to the competitive bidding process.

If any of these projects are awarded to ITC would be incremental to ITC’s plan. Other avenues of growth at ITC include customer connections associated with over 8,000 megawatts of load growth for proposed data centers and economic development projects in various stages of development across their footprint. This is up 3,000 megawatts just since last quarter. ITC may also realize future opportunities associated with the ongoing MISO LRTP process. All in all, it’s a very exciting time at ITC with a significant transmission build-out. Let’s now turn to UNS Energy. Their capital plan of $5.6 billion supports average annual rate base growth of approximately 7%. As a vertically integrated utility, investments are spread across the value chain. Notably, 1/3 of the capital plan is concentrated in transmission with the balance consisting of generation and distribution investments.

Regulated generation includes the coal to natural gas conversion of 800 megawatts at the Springerville Generating Station, which is aligned with TEP’s exit from coal by 2032 as well as the Black Mountain generation project at UNS Electric. While there is no new generation reflected in the plan associated with data centers or other large load growth, a new era of demand is approaching with a significant interconnection queue. As we discussed last quarter, TEP reached an energy supply agreement to serve a demand of approximately 300 megawatts that starts to ramp up in 2027 and will use existing and planned capacity. The agreement awaits ACC approval as well as other contractual contingencies. Negotiations are actively ongoing for an incremental 300 megawatts of capacity to support a full build-out of 600 megawatts at this initial site.

TEP is also in active negotiations for additional capacity to second site in the range of 500 to 700 megawatts. If agreements are finalized for these subsequent phases, we estimate new generation in the range of approximately USD 1.5 billion to USD 2 billion through 2030 would be required as well as new transmission. We expect the supply will include a mix of renewable energy, natural gas generation and energy storage. All agreements will be structured to maintain reliability and provide financial protections for our customers and the company. Other opportunities beyond the plan include new energy resource investments required at TEP and UNS Electric as part of their next integrated resource plans expected to be filed in 2026. In British Columbia, our natural gas infrastructure is in focus.

FortisBC’s capital plan of $4.9 billion supports projects that ensure system reliability and integrity as well as major capital projects for LNG and advanced metering infrastructure. Beyond the base plan, we have several opportunities. Just last week, the BCUC approved the Tilbury LNG Storage Expansion project. Given our capital plan assumes a smaller storage tank, we now have potential upside of approximately $300 million. This project is contingent on an environmental assessment, which we anticipate next year. Other opportunities include LNG expansion at Tilbury for marine bunkering as well as customer and load growth in the Okanagan electric service territory. Some of these opportunities have the potential to fall within the plan period.

This is a dynamic and promising time to be an energy delivery utility in North America. As we execute our base 5-year capital plan, we are concurrently focused on unlocking growth opportunities above and beyond the plan across all our jurisdictions. Turning now to our favorite slide. Today, we announced the declaration by our Board of Directors of a fourth quarter dividend of $0.64 and representing a 4.1% increase. This brings us to 52 consecutive years of increases in dividends paid, a track record that speaks for itself. With our strong dividend history and regulated growth strategy, we are extending our 4% to 6% annual dividend growth guidance through 2030. Now I will turn the call over to Jocelyn for an update on our third quarter financial results.

Jocelyn Perry: Thank you, David, and good morning, everyone. For the quarter, reported earnings were $409 million or $0.81 per common share, and on a year-to-date basis, reported earnings were $1.3 billion or $2.57 per common share. As you can see on this slide, reported earnings include income taxes and closing costs of approximately $0.06 per share associated with the disposition of FortisTCI. Excluding this impact, adjusted EPS for the quarter was $0.87 per common share, up $0.02 compared to the third quarter of last year. And year-to-date September adjusted EPS was $2.63, up $0.18 per common share compared to the same period last year. Adjusted EPS growth to date in 2025 reflects strong performance across all our regulated utilities.

On Slide 14, you will see the adjusted EPS drivers for the quarter by segment. Our U.S. Electric and Gas utilities delivered a $0.03 increase in EPS, higher earnings at UNS reflected an increase in transmission revenue and higher AFUDC associated with ongoing major capital projects. As we discussed last quarter, earnings at UNS are tempered by regulatory lag, driven largely by over USD 700 million of rate base, not reflected in rates. The increase in earnings at Central Hudson was due to rate base growth as well as a change in the recognition of a regulatory deferral for uncollectible accounts effective July 1, 2025. Growth was moderated by a contribution to a customer benefit fund associated with the joint settlement agreement, which concluded an ongoing enforcement proceeding.

Together, these regulatory items impacted adjusted EPS by $0.01. Moving to ITC, continued capital investments and related rate base growth increased EPS by $0.02, the increase was partially offset by higher stock-based compensation and holding company finance costs. For our Western Canadian utilities, EPS increased $0.01, largely driven by rate base growth, including earnings associated with FortisBC Energy’s investment in the Eagle Mountain Pipeline Project. The expiration of a PBR efficiency mechanism and a lower allowed ROE effective January 1, 2025, at FortisAlberta tempered earnings for this segment. And while not shown on the slide, at our Other Electric segment, EPS was largely consistent with the third quarter of 2024. Rate base growth was offset by the September 2 disposition of FortisTCI.

For the full year, we expect the sale of FortisTCI to have a $0.02 impact on adjusted EPS. A higher U.S. dollar to Canadian exchange rate also contributed a $0.01 EPS increase for the quarter. For the Corporate and Other segment, the $0.03 decrease reflects higher holding company finance costs, unrealized losses on foreign exchange contracts and lower unrealized gains on total return swaps. And as David mentioned, we sold our assets in Belize in October and do not expect the transaction to have a material impact to adjusted earnings going forward. And finally, higher weighted average shares impacted EPS by $0.02, driven by shares issued under our dividend reinvestment plan. While most of the factors discussed for the quarter are the same for the year-to-date period, the increase in earnings for the 9-month period also reflects growth at Central Hudson due to the rebasing of costs and a higher allowed ROE effective July 1, 2024, as well as the timing of operating costs in 2025.

Earnings year-to-date also reflect lower margins on wholesale sales at UNS Energy and the timing of operating costs at FortisAlberta. Through September, we raised over $2 billion of debt, including an inaugural corporate hybrid issuance of $750 million at 5.1%. Proceeds from both the hybrid issuance and the sale of FortisTCI during the quarter were used to repay our corporate credit facilities, including the non-revolving term loan providing funding flexibility as we focus on executing our capital program. As I just mentioned, with the recent hybrid issuance and asset dispositions, the growth in our capital plan is expected to be funded largely from cash from operations, utility debt and our dividend reinvestment plan. Our $500 million ATM program has not been utilized to date and remains available for funding flexibility as required.

Overall, our funding plan remains largely consistent with the previous plan and supports average cash flow to debt metrics up over 12% through the period with ample cushion in the latter part of the plan. This balanced approach to funding supports both our growth objectives and strong credit profile. Turning now to recent regulatory activity with one item of note. In August, the New York State Public Service Commission approved Central Hudson’s 3-year rate plan with retroactive application to July 1, 2025, including the continuation of an allowed ROE of 9.5% and a common equity ratio of 48%. That concludes my remarks. I’ll now turn the call back to David.

David Hutchens: Thank you, Jocelyn. At our core, we are a utility built on strong fundamentals and a clear, disciplined regulated growth strategy with a long CapEx runway supported by FERC-regulated transmission and retail load growth opportunities in Arizona. For our customers, we remain committed to prioritizing safety, reliability, affordability and the delivery of cleaner energy. For our shareholders, we offer a compelling low-risk return profile reinforced by our capital investment plan and dividend growth guidance through 2030. 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: [Operator Instructions] The first question today comes from Maurice Choy with RBC Capital Markets.

Q&A Session

Maurice Choy: Just first question is on the timing and likelihood of some of the opportunities over and above the base plan. But within this 5-year period plan, specifically, you mentioned earlier that there is about USD 1.5 billion to USD 2 billion of incremental generation opportunities at TEP that may be required through 2030, and also another $300 million for the LNG Tilbury storage expansion upside. If my math is right, that’s about $2.5 billion to $3 billion of incremental investments or another 100 basis points addition to your rate base CAGR. Any reason why you think that these two items may not come through in the coming months, such that we probably could potentially put this as part of our base estimates?

David Hutchens: I like your optimism, Maurice, but there’s a lot of wood to chop between here and there, right? So we have to get the agreements done with these counterparties. We obviously have to have the ability to build the infrastructure that’s needed in the time line that they want. So all those things are definitely possibilities, but still getting generation cited, getting things in the queue, all of those pieces and most importantly, getting these customers to sign up for all the protections that we want for us from a credit perspective and for our customers from a rate perspective. And then going through the regulatory process. There’s just a lot of steps between here and there, specifically around the data centers.

And then also for the storage tank in BC, still have to go through the EA process there. So we obviously are very excited and bullish and after these projects as much as we can be. But as you know, we don’t drop those things into our capital plan until we have signatures on the dotted line. And we’ll keep you posted as those negotiations go and once we reach agreements with some of those third parties.

Maurice Choy: Understood. If I could finish off with the question on the funding plan on Slide 17, where there was a mention about the balance of equity funding to be satisfied from, among others, asset sales. Obviously, you’ve sold a number of things here, Turks and Caicos as well as Fortis Belize and Belize Electricity and also Aitken Creek gas storage in the past. So you’re 100% regulated right now, as you mentioned, thoughts on what else might be worth trimming, optimizing? Or do you feel like this is no longer an avenue that’s worth exploring?

David Hutchens: Yes. So we’re focused mostly on executing that 5-year capital plan and that laundry list of additional opportunities above and beyond the plan that we just went through. So there is no read-through from the transactions that we just completed. Our portfolio is a great portfolio. And we do have 100% of our assets being regulated now. So there’s — that’s not — when you read that sentence that was looking back not forward. So that’s we look at funding our capital plan is clearly laid out by that funding plan on the slide. And I’d reiterate that the DRIP is the only source. We don’t have any discrete equity in there. So the DRIP is the only source of equity. We have the ATM and hot standby, but that’s not needed in the current capital plan process.

Operator: The next question comes from Rob Hope with Scotiabank.

Robert Hope: Good to see the update on the capital plan. Maybe to follow up on the USD 1.5 billion to USD 2 billion of new generation in Arizona. Can you maybe help us understand kind of the timing of when this capital could be secured, just understanding that a lot of these items have relatively long lead times and when they could be in service?

David Hutchens: Yes. So if you ask the customers who are asking for this, it’s pretty much tomorrow is when they want it. But obviously, it takes time to build data centers. It takes time for us to get the siting and permitting, and of course, building additional generation, you’re going to have to get in the Q4 combustion turbines or combined cycles whatever the resource portfolio requires. But it’s also kind of not fully defined at this point where you can look at things that are available, as I mentioned in my prepared remarks, we expect this to be a mix of different energy resources, including battery storage, which can happen pretty quick. Renewables, of course, which can supply a good chunk of energy. And then you look at what the best capacity resource, whether that’s a combustion turbine or combined cycle depending on the load features.

So that I still think that when you look at longer term, like the current time line that we have with the project in Arizona for the first 300 megawatts as they’re looking to be online in ’27 and ramping up over the next year or so after that. So I would expect other time lines to be similar to that. But when we look at our plan that goes all the way to 2030, depending on availability of, say, combustion turbines, which would probably be the critical lead item on that. We still think that, that’s doable to get that done in that next 5-year time period.

Robert Hope: All right. Great. And then maybe taking a look at ITC. So you mentioned that there’s 8 gigawatts of potential loan growth associated with data centers and you have Big Cedar in hand. Can you maybe add a little bit of color on how many opportunities you’re looking at for that 8 gigs as well as could we see some sanctioning in the next 12 months?

David Hutchens: Yes. I’ll turn that over to Linda to give some details, but I will remind folks on the call that our three largest customers are DTE, CMS and Alliance. So I’m sure you’ve seen some of the conversations in those earnings calls as it relates to some of this development as well. So Linda, I’ll turn it over to you.

Linda Blair: Great. Thank you, Dave, and thanks for the question, Rob. Yes, certainly, the 8 gigawatts that certainly, we are — we have sort of insight into in terms of those conversations with customers, ongoing planning studies to accommodate them. Certainly, we remain hopeful. I would say there’s a lot of activity. We’re working closely, as Dave mentioned, with our customers. We’re really not in a position to really say or identify just sort of from a time line perspective. I think what we can say is that we continue to see that queue of those prospective data center or other economic development projects continue to grow. So we remain hopeful and optimistic that we will continue to see further announcements. But really, at this point in time, it’s premature for us to speculate on which projects were or exactly when. But I would say the queue continues to get larger, and we remain optimistic.

Operator: The next question comes from Ben Pham with BMO.

Benjamin Pham: Could you update us on your thoughts with respect to an EPS CAGR initiation, if there’s any?

David Hutchens: Yes, we still continue whether or not we want to take that next step and give earnings guidance, but we have been pretty happy with all the details that we — and we hope our investors and analysts are happy with the details that we give on rate base growth and seeing how clear our capital plan and funding plan tied together. We give the dividend guidance as well. And we always evaluated, I think probably the last time I’ve had conversations with you all kind of the one thing that we’re waiting for because there’s a lot of variability in earnings in Arizona to see the outcome of the Tucson Electric Power rate case. Formula rates will provide a much steadier earnings outlook for us, which would allow us to give a little bit more visibility and detail for you all, whether or not we — I’m not saying that if we get formula rates, we’re going to give earnings guidance. But that’s one thing that’s keeping us from giving it now.

Benjamin Pham: Okay. Understood. And then maybe next on the asset sale side of things. Maybe not to talk specifically on Caribbean valuations. But can you share just the trends you’ve seen with buyer appetite for those assets? And it seems like you’re willing to more do deals with neutral to maybe slightly dilutive perhaps. And just how do you think about CUC in the overall for this portfolio mix today?

David Hutchens: Yes. I’d say the interest like in any market, waxes and wanes. I mean, we’ve seen that over many years as folks had approached us about the Caribbean assets, et cetera. But it’s — there’s no like kind of consistency necessarily there. And of course, the buyer universe changes almost on a year-to-year basis. So — but again, just as far as CUC goes, this isn’t a read-through that we’re exiting the Caribbean. This is — those are two distinct and discrete transactions that we did and it doesn’t mean we’re looking to do anything else.

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

Mark Jarvi: Just wanted to come back to sort of like friction points on potentially higher spend. As far as I can tell, it doesn’t seem like customer affordability is one or balance sheet. So really, is it just equipment availability and permitting, Dave?

David Hutchens: Yes. So I’m glad you brought up affordability because when you think about these new large load customers that actually can and well, should be, if you design it rightly, if you correctly, you would get the new customers, the large data center to pay for the growth that is needed in your infrastructure is the kind of growth pays for growth argument. So we definitely want to structure them that way so that in the end, we have a positive impact on customer affordability. They either get improved reliability and don’t pay any extra or you end up with the great reliability that we always provide and actually seeing some downward rate impact because of all the energy and infrastructure that those larger customers are now paying part of basically paying a bigger part of the pie.

So now that is a very difficult conversation, not necessarily to say, but for folks to hear and understand that because there’s a lot of mixed messages out there that are telling people in different markets that data centers can drive your cost up. Well, when you have the control over the full value chain like you do in a vertically integrated utility, you can make sure that doesn’t happen. And your regulators will make sure that doesn’t happen. So that’s the tack that we’re taking in Arizona. And so when it comes down to it, I mean there’s always additional things like making sure that your — the community is supportive that you — if you have, whether it’s water cooled or air cooled that you understand what that means from a resource perspective, which is one of the reasons that in Arizona, they are all shift into air cooled — air cooling for the data centers instead of water cooling to kind of take that out of the argument.

So it is all of those things permitting, siting. They’re great for economic development and jobs in the area, tax base. I mean, it’s a great story to tell. But sometimes, it’s a bit of a hard story to make sure everybody hears it all.

Mark Jarvi: You brought up the shift to air cooling. Just on that 300 megawatts, the initial site, is that all moved ahead? Is there anything else that need approval for that 300 megawatts? And then in terms of other municipal support or other approvals, what’s required then to get to the sort of investment decision on the next 300 megawatts of data center load?

David Hutchens: Yes, I’m going to turn that over to Susan. We do have the — as I mentioned, the energy supply agreement has been filed with the Corporation Commission, which is the first thing we have to get through, but I’ll turn it to Susan to talk about any of the other pieces that might need to happen.

Susan Gray: All right. Thanks, Mark, for the question. So yes, as Dave mentioned, on our side, the biggest approval that we need is that Corporation Commission approval, which we expect to get by the end of this year. But on the data center side, I think the main approval that they need as a permit to dig a well, which is a state permit. This is on county land and the state would actually approve the water. And that’s water just for regular building use like kitchens and bathrooms kind of things. So that’s for the first 300 megawatts. I would say anything beyond that, we’re still negotiating contracts. And so not really sure what the types of approvals we would need, but certainly, anything beyond this first contract, we would need to build something new in terms of a generation resource.

So that’s going to be a more extended period of time. As Dave talked about earlier, it all depends on the resource mix and certainly, some of the generation resources can be built a lot more quickly than others.

Mark Jarvi: So the customer would like to push the time lines, but you need to do your own sort of analysis on generation mix to come back to them with a solution, is that right?

Susan Gray: I would say we need to do the analysis on the overall grid impact and make sure that we have all the infrastructure in place to serve the new customers as well as our existing customers as reliably and affordably as possible. I think in terms of what we would build, the customer will have a huge influence on that, right? So if the customer wants to go primarily renewable, that would be their decision and based on what they’re willing to pay in terms of resource mix. So we’re willing to build whatever they need, whatever they prefer as long as the customer is willing to pay for that incremental cost of maybe increasing the amount of renewable resources.

Mark Jarvi: Understood. And then, Jocelyn, a question for you. Just in terms of the funding plan for the next 5 years, does it contemplate further hybrid issuances? And if yes, can you kind of outline roughly the quantum?

Jocelyn Perry: Yes. Thanks, Mark. Yes. No, we don’t have any further hybrid included, but we do have capacity. So with that growth that we’re talking about here today that is not in the plan, should it come in the plan, then it’s possible that we will explore the hybrid market when we look at that growth. And we may also look at it regardless, depending on the market and how the hybrids are pricing relative to other instruments. So yes, definitely an area that we’re exploring.

Operator: The next question comes from John Mould with TD Cowen.

John Mould: I’d like to take another stab on the large load front in a couple of places. Maybe just starting with ITC. And I’m not asking for a view on in-service dates, but I’m just wondering if you can provide a little more detail on how the timing of the connection requests are paced. And this 3 gigawatts of growth that you’ve seen since last quarter, in particular, the pacing of at least what customers are looking for.

David Hutchens: So are you asking like how soon they come in before they need it, or just…

John Mould: Yes, how soon they’re seeking to get connected, like just if I was trying to map out the timing of all those requests, is there a particular time period to which it’s weighted?

David Hutchens: Yes. Let me — I don’t have any visibility to that. Linda, do you have a view on kind of the detailed queue, I guess, CODs that they’re looking for?

Linda Blair: Look, I mean, I think I would be sort of generalizing, but I think back to Dave, I think on an earlier comment you made is that look, they all want to be connected as soon as possible. Certainly, there’s practical realities just in terms of where they are looking to locate their facilities? Are they co-located with existing transmission infrastructure? If not, what is the infrastructure that’s necessary, the MISO approval process to get that infrastructure through the MISO queue. So it’s a difficult question. I guess I would generalize and say for the majority, I would say, of the conversations that we are involved with prospective customers, I would say that many of their requests as well as what is reasonably doable, we’re looking at the outer years of that existing 5-year plan.

Obviously, there’s different ramp perspectives around those because some of them want to move more aggressively faster. Some of them are willing to be able to take what they can get as quickly as possible. So I think it’s a really difficult question to give any specificity on, but I would say at least for the existing conversations that we are engaged with, I would say, the majority of those requests are looking at the latter part of our existing 5-year plan, so out into the ’28, ’29, ’30 time frame. So hopefully, that provides some context.

John Mould: Yes. That’s very helpful color. And then just on Arizona and the new IRPs that you’re planning to file in 2026. By what time would you need on the large load side to have something more definitive in place so that, that’s reflected in the broader IRP and also allows you to potentially demonstrate the rate benefits that could potentially come from that in the various IRP portfolios. Just wondering what the timing looks like there.

David Hutchens: Yes. So the IRP is going through its process. They’ve had a couple of workshops and we’ll continue more for — through 2026 with a target of filing those integrated resource plans, I think, in August of next year. But there will be a bunch of different resource portfolios based on different load growth scenarios with and without data centers. And I think even if we file an integrated resource plan and it doesn’t include something that we need later, we just we just update that, right? I mean it’s just — that’s basically putting a stake in the ground for sort of the bread and butter resources that we need to serve our load growth. But any of these additional investments that we would see and need and require for additional data center growth.

I kind of think of it as almost like its own little mini IRP and rate base that would have its own revenue requirement that would be served by, or that would be met by these customers. So it’s a bit of a different model. You wouldn’t necessarily need to put them all together. And it’s not like we filed this thing in August and say, okay, we got to close up shop any more data centers that come in and ask us for energy, we can figure this out. I mean, this is basically what we’ve been doing for the past a couple of years while we’ve had the 2023 integrated resource plan in effect is we still have these conversations, look at how we can meet the load and then adjust accordingly.

Operator: The next question comes from Patrick Kenny with National Bank Capital Markets.

Patrick Kenny: Just looking at the rate base CAGRs by utility and seeing Alberta and BC continuing to lag the 7% portfolio average. You touched on some upside in the Okanagan, but I’m just wondering if there might be any other macro or political tailwinds that you’re watching out for that might help these two utilities close the gap relative to the group average growth profile, say, over the next 3 to 5 years?

David Hutchens: Yes, for sure. So the Okanagan one is — actually, it’s a smaller part of the BC utility portfolio. But I think, has some good substantial growth opportunities there. So I know we don’t usually talk too much about the electric business in BC because of the gas business is so big, but that does definitely have some additional opportunities there. And then on the LNG front, I mean, this is all about not just the extra upsized, I’ll call it, storage tank that just got approved by the BCUC, that’s one piece of additional investment. But also the additional LNG liquefaction capacity that we could put there for increased bunkering — mostly for increased bunkering at that Tilbury site. And there are some political tailwinds, I know there’s been a lot of conversations about some major projects and across Canada, related to trying to get the economy jump started.

I think maybe some of the more of those details might come out later today when the budget is released, but there is some good emphasis on LNG investments in BC. We hope some of that bleeds down and has some good impact on looking at additional LNG investments for bunkering for BC. So there are some investments there. And I should note, I’ll come to BC’s defense here a little bit as well. These things are cyclical, right? So the load growth when you complete a bunch of big projects, and then do a new 5-year plan, it might not look as robust as the last one. But believe me, there’s a lot of stuff in there. They’ve executed well on the past and look to add to that on a going-forward basis.

Patrick Kenny: Okay. That’s great. And then maybe for Jocelyn, just back on the funding plan, looking at that 5-year average cash flow to debt ratio of, call it, 12.4%. Is that 40 basis points above S&P’s threshold anyway. Is that where you’d like to see it on a sustained basis? Or would you still like to see a little bit more cushion built over time? I guess maybe a different way to look at it, like how much dry powder might you have based on your debt metrics to flex the capital program or to handle any further weakness in the Canadian dollar?

Jocelyn Perry: Yes. Thanks, Patrick. Yes, you’re right. The average for the S&P metric over the 5 years is 12.4%. But as you get to the latter part of the plan, we’re actually pushing more like 100 basis points. And you’ve probably heard me say before that, that’s sort of where we have been targeting our cushion. It gives us a lot of dry powder to have the flexibility to finance the projects that are not in our capital plan that we’re talking here today. So yes, so this is a plan that sets us up nicely to actually get to that adequate ample cushion in the latter part of the plan. I’ll actually say 100 basis points is actually a lot of cushion. So I feel comfortable really having like 75 to 100 bps above the threshold of 12%, and we’re getting there.

And so it’s — this plan has actually improved over the prior year plan, which is a good thing. And in large part, it came from the fact that we’ve done some asset dispositions and we’ve continued our DRIP. So yes, the cushion is certainly met on average of 12.4%, but we do get to the, I’m going to call it the ideal cushion by the latter part of the plan.

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

Stephanie Amaimo: Thank you, Betsy. We have nothing further at this time. Thank you, everyone, for participating in our third quarter results and new 5-year capital outlook 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.