FTS

Thank you for standing by. This is Betsy, the conference operator. Welcome to the Fortis Inc first quarter 2026 results conference call. As a reminder, all participants are in a listen-only mode, and the conference is being recorded. After today's presentation, there will be an opportunity to ask questions. To join the question queue, you may press star then one on your telephone keypad. Should you need assistance during the conference call, you may signal an operator by pressing star then zero. I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Miss Amaimo.

Thanks, Betsy, and good morning, everyone. Welcome to Fortis' first quarter 2026 results conference call. I'm joined by David Hutchens, President and CEO, Jocelyn Perry, Executive VP and CFO, other members of the senior management team, as well as CEOs from certain subsidiaries. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slideshow. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. Non-GAAP financial measures referenced in our prepared remarks are reconciled to the related U.S. GAAP financial measures in our first quarter 2026 MD&A. Unless otherwise specified, all financial information references in Canadian dollars. With that, I will turn the call over to David.

Thank you, good morning, everyone. Before getting into the results, I'd like to take a moment to acknowledge Gary Smith, Executive Vice President of Operations and Technology, who is retiring at the end of this month. Gary has had an incredible 42-year career with Fortis, serving in leadership roles and boards across our utilities. He has been integral to Fortis' growth and success, and we're incredibly grateful for his many contributions. We truly wish Gary all the best in retirement. We are pleased with our start in 2026, building on the momentum from last year. During the first quarter, we delivered safe and reliable service while advancing our long-term growth strategy. We invested CAD 1.4 billion of capital into our utility systems and reported earnings per share of CAD 0.99.

We also successfully concluded the UNS Gas rate case, reaching a constructive regulatory outcome for our customers and stakeholders. With 25% of our capital plan invested in the first quarter, we remain well-positioned to execute our CAD 5.6 billion of planned investments in 2026. Major capital projects continue to progress. A significant milestone was achieved at the Big Cedar Industrial Center, where ITC completed the substation that will support 300 MW of load growth for the first data center. Transmission upgrade work for the Big Cedar load expansion project is also underway at this location to serve another 1,600 MW of new data center load expected to be completed by 2028. At UNS, the ACC approved an amendment to the Springerville Generating Station's Certificate of Environmental Compatibility to allow the conversion from coal to natural gas generation.

This approval advances TEP's plan to extend the operational life of the facility and supports long-term customer affordability and system reliability. As we have discussed in the past, our utilities continue to prioritize capital investments focused on operational need and customer bill impacts. At ITC, with the substantial data center load anticipated to come online in Iowa, ITC Midwest network transmission rates are expected to be reduced by approximately 20% by the end of the decade. At TEP, the coal-to-natural gas conversion at Springerville Generating Station will be approximately 10% of the capital cost of new gas generation. This is an economical solution benefiting our customers and the communities we serve.

Also at TEP, the 300 MW of load growth for the data center associated with the approved energy supply agreement is expected to save a typical residential customer approximately $13 per month once at full production, thanks to this additional revenue. Overall affordability continues to be an integral part of how we plan, invest, and operate across our group of companies to ensure cost-effective service for our customers. Turning now to slide seven. With our 2026 and five year capital plans on track, we continue to expect average annual rate base growth of 7% through 2030. Above and beyond the plan, our teams continue to drive forward a strong slate of incremental growth opportunities. First, at ITC, the MISO LRTP portfolio of projects is advancing.

For Tranche 2.1, ITC expects $3.3 billion-$3.8 billion of investment beyond 2030 for projects that have been awarded and are not subject to competitive bidding. For projects that are subject to a competitive process, ITC is actively evaluating opportunities and preparing bids as appropriate. As it relates to competitively bid projects, ITC, alongside its Grid Acceleration Coalition partners, filed a joint complaint at FERC in April against the competitive bidding processes in MISO and SPP. The complaint urges the commission to either direct MISO and SPP to exempt transmission projects from the solicitation process when those projects facilitate new generation or large load interconnection or suspend the solicitation process entirely for the next five years. The complaint emphasizes that competition delays much-needed infrastructure development, slowing down AI implementation through regulatory red tape and increasing costs to customers.

While complaints at FERC are not subject to a fixed timeline, the coalition has asked the commission to issue a ruling by July 16th. Shifting now to load growth opportunities in Arizona. In April, key contractual contingencies tied to the approved ESA for 300 MW advanced at TEP with credit support now in place. As you may recall, this initial phase will leverage existing and planned capacity with a ramp-up expected in 2027 and continuing through 2029. Beyond this ESA, negotiations continue for an incremental 300 MW of capacity to support a potential build-out of 600 MW at this site. TEP is also in active negotiations for additional capacity at a second site in the range of 500 MW-700 MW.

If agreements are finalized for these subsequent phases, we estimate new generation investment in the range of $1.5 billion-$2 billion would be required. Our track record of long-term sustainable growth reflects the strength of our regulated businesses and supports our commitment to deliver 4%-6% annual dividend growth through 2030. Now I will turn the call over to Jocelyn for an update on our first quarter financial results.

Thank you, David, and good morning, everyone. For the quarter, we reported net earnings of CAD 501 million or CAD 0.99 per common share. As shown on the slide, we have identified the EPS drivers for the quarter by segment. Our Western Canadian utilities contributed a CAD 0.04 increase in EPS, largely driven by capital investments and timing of operating costs. At ITC, EPS increased by CAD 0.02, largely due to continued capital investment and related rate base growth. For our U.S. electric and gas utilities, EPS decreased by CAD 0.02. Lower earnings at UNS Energy were driven by wholesale market conditions, timing of planned generation, maintenance costs, milder weather, as well as regulatory lag for rate base not yet included in rates.

Moderating this was higher earnings at Central Hudson due to a shift in quarterly revenue, timing of operating expenses, as well as rate base growth. The corporate and other segment reflects higher finance costs and unrealized losses on foreign exchange contracts. While not shown on the slide, earnings at our other electric segment were largely offset by the disposition of FortisTCI in 2025. In total, the dispositions had a CAD 0.02 dilutive impact on the first quarter results, and we expect a CAD 0.05 dilutive impact for the full year. Continuing on, foreign exchange had an unfavorable CAD 0.03 impact for the quarter, and higher weighted average shares issued under our dividend reinvestment plan impacted EPS by CAD 0.01. On the financing activities for the quarter, our utilities issued CAD 800 million of long-term debt.

Additionally, in April, ITC Holdings issued $900 million of unsecured notes, with proceeds expected to repay maturing debt and short-term borrowings. Our capital plan is expected to be funded largely from cash from operations, utility debt, and our dividend reinvestment plan. Our CAD 500 million ATM program has not been utilized to date and remains available for funding flexibility as required. On the rating agency front, Morningstar DBRS recently confirmed our A low issuer and unsecured debt credit ratings and stable outlook. Overall, our liquidity position and our funding plan support our strong investment-grade credit ratings. Several regulatory filings advanced in Arizona during the quarter. In February, the ACC issued an order in the UNS Gas general rate application, authorizing an allowed ROE of 9.61% and a 56% equity ratio.

The order also approved a formula subject to a range of ±50 basis points around the allowed ROE and inclusive of post-test year adjustments. The first rate adjustment under the formula is expected to occur in April 2027. New rates went into effect on March 1st. With respect to TEP's general rate application, the ACC staff filed testimony during the quarter recommending a 9.75% ROE and a 55% equity ratio. Staff also filed rate design testimony recommending a formula rate framework that closely mirrors the recently approved approach for UNS Gas. Hearings commenced last month. Based on the procedural schedule, we continue to expect an order in the fall. That concludes my remarks. I'll now turn the call back to David.

Thank you, Jocelyn. To wrap up, we are off to a solid start in 2026, with first quarter results aligned with our expectations. Our utilities are executing their capital plans focused on reliability and customer affordability. Looking ahead, we will continue to drive meaningful shareholder value through execution of our five year capital plan and delivery of our 4%-6% annual dividend growth guidance through 2030. That concludes my remarks. I will now turn the call back over to Stephanie.

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

Thank you. We will now begin the question and answer session. To join the question queue, you may press star, then one on your telephone keypad. You will hear a tone acknowledging your request. If you are using a speakerphone, please pick up your handset before pressing any keys. To withdraw your question, please press star, then two. We will pause for a moment as callers join the queue.

The first question today comes from Maurice Choy with RBC Capital Markets. Please go ahead.

Thank you. Good morning, everyone. If I could just start, in your prepared remarks, you mentioned that affordability has been an integral part of how you plan, invest, and operate across your companies. You've also shared how TEP and ITC Midwest customers will benefit from your data center initiatives. With that, given the heightened nimbyism, how would you characterize how data center sentiment among your local stakeholders have evolved since the Q4 call?

Yeah. Thanks, Maurice. Thanks for that question. It's obviously a big topic. If folks understand how you can do data center development correctly, if you make sure that you have the protections in place for the rest of the retail customers, then you definitely can have a positive impact from an affordability standpoint. It's just, you know, in essence, fairly straightforward math. When you add some assets that someone else is gonna pay for, and then you actually have some kilowatt hours that they use to spread the rest of the fixed costs among a larger pie, then it definitely does help. It is really hard. I'm not gonna lie. It's hard to get folks to understand that messaging.

You have to prove it, and that's hopefully what we're gonna be doing here as we go forward, as we add this contract that TEP has in place for that first data center. You know, with no additional resources needed to supply it, they're paying for the transmission interconnection. Now it's really just the, you know, just the end result of them using a lot of kilowatt hours and paying for a lot of the system that our the rest of the customers would have. It's an ongoing conversation and ongoing, you know, information flow that we have to have out there. If you are doing it right, you should be making that loud and clear.

Understood. If I could finish with a question on ITC. Recognizing that the Grid Acceleration Coalition complaint was only filed a few weeks ago, I wonder if you had any early feedback from FERC about whether they're moved by your arguments and how you think this will all play out in the coming months towards your mid-July deadline request.

Yeah. Let me turn that directly over to Krista Tanner, CEO of ITC, and she's the one who's been at the front of this. Krista?

Yes. Good morning, thank you for the question. Obviously we haven't talked to the FERC since we filed because that would be an ex parte. We had several meetings beforehand, we continue to have meetings with other key stakeholders. I think it's fair to say that everyone understands that there's a problem here. What they will do, whether if they will take our options or come up with their own, I think remains to be seen. When you have data centers wanting to connect in 24 months or less, that's precisely how long the competitive solicitation process takes, that's just an untenable situation. You know, we provided a lot of good data about we will not win the AI race in this country if we don't move faster. I think those arguments are compelling.

I think everyone understands them. We are optimistic that something will be done, but obviously we'll have to wait to see the final order before we see what that solution is.

Thanks, Krista. If I could have a quick follow-up.

Sure.

Have you seen a counter-complaint, being filed with FERC on this?

We haven't seen a counter-complaint. The only thing that proponents of so-called competition have submitted are studies that cherry-pick, you know, a handful of projects that were competitive that came in, nothing, I think, really compelling. Again, if you look at the data and the testimony that we filed with our complaint, I think it's really clear that so-called competition has not lowered costs for customers. In fact, it's increased cost in some cases, and the cost associated with delay is far greater than any savings you might see. Really all that so-called competition has accomplished is delay. I mean, there's just, you know, there's just no evidence to contradict that.

Furthermore, we've had a real-world situation, where someone won a bid in Wisconsin, and then three of those substations had to go to variance analysis because they couldn't be completed in time for a data center. Yes, of course, there's, you know, there are other arguments out there. I would not characterize them as compelling, and they have not filed anything.

All right. That's good to know, and thanks for that. My congratulations to Gary on his retirement, and all the best.

The next question comes from Robert Hope with Scotiabank. Please go ahead.

Morning, everyone. It would seem like you've been making some regulatory and contractual progress at TEP regarding the initial 300 MW. You know, this would include the $40 million termination fee. Can you speak to what the next steps are for this project to get across the line and what milestones we should be watching?

Yeah. I'll turn that over to Susan Gray, CEO of UNS, so that she only says the things that are public.

Yeah. Thanks, Dave, and thanks for the question, Rob. You know, we just hit some really major milestones in terms of having that, CAD 40 million letter of credit established and payment for the construction agreement to build out the substation and the transmission interconnection. The site has been prepared and they're starting to build at this point. Phase I is off and running. The next steps are really around expanding the capability at that first site up to a possible 600 MW. The first 300 MW is underway now looking at doubling that capacity. The second site that's in Marana, just north of Tucson, we're also negotiating an agreement, a service agreement for that site.

It's about, you know, once we have all of the terms established, we will have to build new generation to serve those additional agreements. I think the terms of the contracts will help guide us in terms of what we need to build and when. Those are really the next steps, but really pleased to see that phase I is underway and moving forward.

All right. Appreciate that. Then my follow-up question relates to phase II. You know, when you're thinking about planning for incremental generation requirements to serve the next phase of load there, you know, how are you incorporating increasing delivery timelines for electrical equipment such as generators? You know, could you potentially, you know, look to lock these up a little bit earlier if you are able to get line of sight to an agreement or, we'll call it backstopping from the counterparty?

Yeah, I think we would really need to have certainty from the customer that they are going to move forward and have those customer protections in place. I think that is the incentive to get the agreements locked up here so that we can start moving forward with procurement and potentially partnering with a builder to start actually getting those sites going.

All right. Thank you. David, all the best. Thanks, all.

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

Yeah, good morning, everyone. Last quarter, you guys said that you thought maybe FERC would start to tidy up some loose ends. We saw the decision on transmission operators in New England. Are you expecting more to come? Is there any expectation that they'll address the adders this year?

Thanks, Mark. We haven't seen any indication. We're hopeful that that stale docket finally gets pushed aside, and, you know, if they do want to address incentive adders, that they do it in, you know, the Folsom approach that they started at way back when in 2020, which was looking at all the different incentive adders that you could add based on, and not just the RTO adder. That was in a bucket of several adders, including additions for using new technology, reducing costs, increasing reliability. If they do set that aside and want to address it, we'd hope that they would start with a fresh view of those incentives and what's needed on a going-forward basis.

Okay. In the last week, there's been some media reports about a potential executive order around some things like dynamic line rating, reconductoring for transmission coming from the White House. Is that something you guys feel like will come through, and what could that mean for ITC, if anything?

Can't say. That's the first I heard of that. Krista, is this something that you've heard? It says that you know, obviously the things like dynamic line rating and other, you know, conductor, reconductoring for higher capacity is something that we always look at from an affordability perspective, but had no idea there was an executive order chatter on it. Krista?

I think there was just something that came out yesterday, Dave, so you're not behind. There's always discussion about the proper use and are we using dynamic line ratings and other technology enough. I think, you know, for ITC, we use it, and we have used it when appropriate. When it's not appropriate, we don't. I think we're hopeful through the conversations we've had that it wouldn't be an across-the-board mandate or to use it when it doesn't make sense. I think if there is an executive order issued, that it would just be for FERC to look at it and consider it, which frankly they do and utilities do anyway. I don't see this as significantly moving the needle rather than just advancing the conversation that's already happening.

Understood. Just last question from me. Just some of the media reports about, you know, just B.C., LNG, you know, Woodfibre expansion. Can you remind us again where the pipe is sized right now, if there's the potential to do incremental investments there in B.C.?

Roger, you wanna take that one?

Yeah. Thanks, Dave. Morning. There is a opportunity to expand pipe. It would require a debottlenecking further upstream from the current expansion of our pipeline. We haven't entered into discussions yet with Woodfibre, but it's something that we will be looking at, I'm sure, in the near future here.

Okay. Thanks, everyone.

Thanks, Mark.

The next question comes from Benjamin Pham with BMO. Please go ahead.

Hi. Morning. I wanna stay at B.C. You mentioned the environmental assessment update on the Tilbury storage site. Was that in response to the Middle East situation that's occurring? Maybe just add incremental context on future expansions, if that potentially could be accelerated.

So far everything that we have been doing has been based on projects that we've had in the queue for quite a while. Nothing that's incremental or increased due to the Middle East. Obviously, there's a lot of attention on LNG. It's having quite the moment now. That's probably the genesis of that prior question on, you know, looking at whether or not you can increase capacity at Woodfibre for additional LNG. That EA was just the EA, there's a couple different EAs going on.

One is related to the Tilbury tank, the larger size one that we got approved last year, and the other is for any ultimate additional LNG liquefaction capacity that we can put at the Tilbury site, which is we refer to as Tilbury Two in that EA process. Nothing is directly, I'll say impacted or pushed by the current situation.

Okay. Got it. Maybe switch to the stats that you've or your expectation the customer impact from the data center volume and integration, and particularly the pronounced impact you're seeing in the U.S. Midwest throughout the decade. Is that something you think is more applicable to the Fortis, especially magnitude? Do you think that's more of a broader industry trend that you're anticipating? Maybe just related, is there any expectation that this is more of a allow more room for rate base deceleration?

Yeah. It is a broader sector. I'll say it's broader depending on how you're doing it. If you're making sure that the data centers are paying for the incremental or marginal generation that's being installed and I'll say infrastructure in general that's being installed to supply them, and you're recovering that from that data center with all of course, the appropriate, you know, credit enhancements, et cetera. You are also getting a bit of contribution back to paying for the rest of the infrastructure that's needed to support that. You don't just, you know, plop it on the grid and not need to have the ancillary services and all the rest of the support that you get from the overall grid.

It will have a positive impact for customers. You know, obviously, ITC is the transmission rate. You're putting a ton of kWh on that system. You're basically doing a few interconnections to get there. It's got some really good economics as that percentage decrease reflects. In Arizona, same thing. If you're not building even on the next phases, we would make sure that whatever those next phases are, that those data centers are paying for that marginal cost of energy and then some so that there is a positive customer contribution.

It is if you're doing it right, especially if you're in a region where you're controlling those portions of the cost, whether it's ITC as a transmission only company, or a vertically integrated utility, we have the ability to see quite clearly how that will benefit customers.

Do you think this is maybe a kW to rate base conversion similar to that recent historical trend of OpEx to rate base?

Yeah. It's all going You always have to look at things on a bill basis, on what our customers pay. Anything that puts downward pressure, on bills is a good thing. That's really what we're focused on, not necessarily saying, "Well, the downward pressures allow for, you know, additional incremental investments." We're only making the investments that we need to provide value to our customers.

The more offsets we have for those needed investments that don't necessarily pay for themselves, we have a lot of, you know, CapEx for OpEx, kinds of conversations, you know, steel for fuel, whatever you wanna call it, where you are replacing some of the operating costs with capital, and still maintaining or even decreasing customers' bills in that sense. There are things around resiliency and others investments that we have to make that would normally just increase costs. It is good to have this other side of the ledger, helping to keep customers' rates balanced.

Okay. Understood. Thank you. Very useful.

Yep. Thanks, Ben.

Once again, if you have a question, please press star then one to join the question queue. The next question comes from John Mould with TD Cowen. Please go ahead.

Hi. Good morning, everybody. Maybe just, starting with the Tucson Electric rate case and, you know, appreciating it's a library case. I was wondering if you could provide some initial thoughts on how the parameters in the rate ask have been received and any points of debate, you know, so far that may have varied versus what you saw in the UNS gas rate case process that concluded in February. I'm thinking both about the formulaic rate ask and just also the broader points of the rate case.

Yeah. John, it is obviously an ongoing rate case. The testimony started a couple weeks ago, meaning the in-person testimony. Of course, most of this is actually done, you know, trade and paper testimony, which frankly hasn't, we haven't seen anything come up in the hearings that would surprise us from a perspective of not already seeing or hearing the conversation or arguments in the written testimony. We were really pleased with the UNS Gas outcome. We were the first utility in Arizona, the UNS Gas was to get that formula rate. We see that we're basically having those same types of conversations in the TEP rate case. I think it bodes well from that perspective.

It's still, you know, in the middle of the process, so we'll kind of couch it at that.

Okay. No, that's fair. Thanks for that. Then maybe just stepping back, you know, on the broader opportunities, above and beyond the existing capital plan, be curious to know just which are you the most optimistic about in terms of turning some of those more aspirational opportunities into a firm security investment, I mean, whether it's some of the near-term opportunities or items that extend beyond your current capital planning horizon right now?

We've got a really good slide in our deck that kind of breaks this conversation up into the two different timeframes. One is, you know, what's possible in the kind of in the current five year capital plan, then what's possible post five year capital plan. You know, obviously we're generally like most folks focused on getting those near-term opportunities while still working to get those longer term opportunities that fill in the growth opportunities later on. We have a lot of that just in things that are already happening, like the rest of the, you know, Tranche 1, Tranche 2.1 and wherever MTEP 26 goes. There's a lot of transmission opportunities that are longer term.

The really, the short-term ones are, you know, some additional data center connections that could happen in manufacturers. In general, interconnections, generation unload in ITC's footprint. Of course, the data center developments that we have in Arizona. Those can be, well, they'd love them to be even shorter term, at least from a, the data center perspective and as quick as possible. You know, timing and availability of equipment, et cetera, can delay that a little bit. We are looking at those opportunities. We still have, we still have a huge additional one that we really aren't talking about yet because we're in the process of developing the integrated resource plans in Arizona. That's gonna spit out some longer term investment opportunities for us as well.

Very, you know, target-rich environment as it were.

Okay. I'll leave it there. Thanks for taking my questions.

Thanks, John.

The next question comes from Patrick Kenny with National Bank. Please go ahead.

Good morning. Just a quick question on FortisAlberta with, you know, I guess, the number of proponents here looking for data center projects. You know, I know I've seen FortisAlberta partner up with, you know, at least a couple projects. Just wondering if you could walk us through some of those partnerships and, you know, help us distill the overall upside potential if and when the phase two allocation does take off in the province.

Yeah. Thanks, Patrick. I'm gonna kick that over to Janine Sullivan, CEO of FortisAlberta.

Good morning, Patrick. Thanks for the question. There certainly is a lot of data center activity. Certainly a lot of discussion first happening in the province. With the ISO having introduced its 1,200 MW cap, it certainly is leading to discussions at the distribution level as to how we can interconnect some of the smaller loads that they want more imminently interconnected. Lots of conversations going on between ourselves, the transmission facility owner and operator and the ISO right now as to how we can facilitate the more timely interconnection of some of this data center opportunity for the province sooner than later.

Okay. That's great. Thank you.

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

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

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