Fortis Inc. (FTS) Q2 2025 Earnings Report, Transcript and Summary

Thank you for standing by. My name is Chuck, and I'll be your conference operator. Welcome to the Fortis Inc. Second Quarter 2025 Earnings Conference Call and Webcast. [Operator Instructions] I would now like to turn the conference over to Ms. Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Ms. Amaimo.

Thanks, Chuck, and good morning, everyone. Welcome to Fortis' Second Quarter 2025 Results Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting 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 second 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.

Thank you, and good morning, everyone. Today, we are pleased to report another great quarter. With capital expenditures of almost $3 billion during the first half of the year, we are executing on our core objective of delivering safe and reliable energy to our customers. Financially, we delivered second quarter earnings per share of $0.76 a $0.09 increase over the same period last year. During the quarter, we also made progress on the regulatory front. Notably, Tucson Electric Power filed its general rate application, and Central Hudson reached a multiyear rate settlement agreement on its general rate application. Jocelyn will speak to these regulatory developments in more detail shortly. In Arizona, TEP's retail load growth opportunity advanced with an important milestone reach for a planned data center development. And today, we released our 2025 sustainability update report, highlighting our consistent progress to deliver cleaner energy to our customers. Through 2024, we have achieved a 34% reduction in Scope 1 greenhouse gas emissions when compared to 2019 levels. In July, the first phase of the Roadrunner Reserve Battery Storage Project was placed in service at TEP. The 200-megawatt energy storage system will facilitate the integration of renewable energy onto the electric grid with the capability to store 800-megawatt hours of energy. This project was part of the $2.9 billion that we invested in the first half of the year. Given this progress, both our annual and 5- year capital plans are on track. We are well positioned to deliver on our growth strategy with rate base expected to increase by approximately $14 billion to $53 billion in 2029. This supports average annual rate base growth of 6.5%. In Arizona, TEP announced that it plans to convert approximately 800 megawatts of coal-fired generation at a Springerville generating station to natural gas by 2030. This will allow us to be coal-free by our 2032 target. The conversion supports customer affordability, local communities and reliability as well as our transition to cleaner energy. This, along with many other factors will impact our resource planning at our Arizona utilities. As a result, we will reassess our 2030 and 2035 interim greenhouse gas targets and share the results once complete. We will provide the project details with the release of our 2026 to 2030 capital plan later this year. New retail load growth opportunities in Arizona continue to advance. TEP just reached an agreement with a data center customer to serve a demand of approximately 300 megawatts that starts to ramp up in 2027 and we'll use existing and planned capacity. This agreement was structured to benefit existing customers, maintain reliability and ensure the power is supplied consistently with -- consistent with 2023 integrated resource plan, including solar and storage projects currently in development. This agreement is subject to HCC approval as well as other contractual contingencies. Further negotiations are ongoing for additional capacity to support a full build-out at that initial site of 600 megawatts in total. The project's developer also shared that additional capacity may be required at a second site in the range of 500 to 700 megawatts. If negotiations are finalized for these subsequent phases, new generation and transmission investments would be required. Beyond these opportunities in Arizona, our utilities continue to pursue various opportunities to support load growth, improve grid resilience and facilitate the interconnection of cleaner energy. Work is underway at ITC to prepare to bid on projects within the MISO LRTP tranche 2.1 portfolio subject to a competitive bidding process. These projects, if awarded to ITC, would be incremental to ITC's estimate of USD 3.7 billion to USD 4.2 billion of capital expenditures for the tranche 2.1 projects. With a long track record of increasing dividends and our sustainable growth runway, we remain committed to our annual dividend growth guidance of 4% to 6% through 2029. Now I will turn the call over to Jocelyn for an update on our second quarter financial results.

Thank you, David, and good morning, everyone. For the quarter, we reported net earnings of $384 million or $0.76 per common share $0.09 higher than the second quarter of 2024. Through year-to-date June, EPS was $1.76, reflecting a $0.16 increase over the same period last year. EPS growth was mainly driven by rate-based investments across our utilities and higher earnings at Central Hudson and FortisBC, which I'll discuss on the next slide. On Slide 11, you will see the highlighted EPS drivers for the quarter by segment. Within our U.S. electric and gas utilities, Central Hudson contributed a $0.04 increase in EPS. This increase largely reflects rate base growth as well as the rebasing of costs and a higher allowed ROE effective July 1, 2024. The impact of a contribution to a customer benefit fund in the second quarter of 2024 and the timing of operating costs also supported the increase quarter-over-quarter. At UNS Energy, the EPS contribution was unchanged from the second quarter of last year, an increase in transmission revenue was offset by regulatory lag. For our Western Canadian utilities, EPS increased $0.03 largely driven by rate base growth, including earnings associated with the Eagle Mountain Pipeline project. At FortisAlberta, timing of operating costs, the expiration of a PBR efficiency mechanism and a lower allowed ROE of 8.9%, 7% effective July -- January 1, 2025, tempered growth quarter-over-quarter. At our Other Electric segment, EPS increased $0.02 due to rate base growth, higher electricity sales as well as the timing of quarterly earnings at Newfoundland Power related to regulatory approvals. And while not shown on the slide, financial results at ITC were largely consistent with the second quarter of 2024 as rate base growth was offset by higher stock-based compensation and higher holding company finance costs. Foreign exchange gains associated with the revaluation of U.S. dollar-denominated liabilities contributed a $0.02 EPS increase for the quarter. For the Corporate and Other segment, the decrease reflects the timing of income tax recoveries and higher finance costs, partially offset by mark-to-market gains on foreign exchange contracts. And finally, higher weighted average shares lowered EPS by $0.01, 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, lower margin on wholesale sales due to market conditions tempered earnings at UNS on a year-to-date basis. All in all, a very strong first half of 2025. Through June, we raised over $1 billion of debt to repay borrowings and to fund our capital program. As we discussed last quarter, our 5-year capital funding plan remains intact. With a healthy participation from our dividend reinvestment plan, our $500 million ATM program has not been utilized to date and remains available for funding flexibility as required. During the quarter, Fitch has signed Fortis a first-time BBB+ credit rating. This new rating underscores Fortis' strong overall credit profile and will support cost-effective capital market funding options. With S&P, we remain focused on highlighting our key initiatives around addressing physical and climate risk. In July, we implemented a public safety power shut up or PSPS plan at FortisBC for high-risk areas within its service territory. This builds on the PSPS plans already implemented earlier this year in Alberta and Arizona as well as the wildfire legislation passed in Arizona. Turning now to recent regulatory activity. In June, TEP filed its general rate application with the ACC seeking new retail rates effective September 1, 2026. The application includes rate base of USD 4.3 billion, representing an increase of approximately USD 750 million since the last rate case. The increase is largely driven by investments in grid upgrades and new energy resources to maintain reliability, improve resilience and serve expanding energy needs. The application proposes to phase out or eliminate certain adjustor mechanisms and request an annual formula rate adjustment consistent with the ACC's formula rate policy statement issued in 2024. If approved by the ACC, the formula rate plan is expected to improve rate stability for our customers, reduce regulatory and administrative burden as well as simplify the number of adjuster mechanisms. The formula is also expected to allow for timely recovery of prudent investments and costs within plus or minus 20 basis points of TEP's allowed return. And while not shown on the slide, UNS Gas rate case continues to progress. In July, the ACC staff filed testimony recommending an allowed ROE of 9.75% and use of an annual formula rate adjustment with an ROE dead band within plus or minus 50 basis points. Lastly, in June, Central Hudson filed a constructive joint proposal with the New York Public Service Commission in relation to its general rate application. The joint proposal provides for a 3-year rate plan with retroactive application to July 1, 2025, an allowed ROE of 9.5% and a common equity ratio of 48%. An order is expected in the second half of 2025. And with that, I'll now turn the call back to David.

Thank you, Jocelyn. In conclusion, strong results for the first half of the year progress on the regulatory front and advancements of our growth opportunities beyond the plan positions us nicely for the remainder of 2025 and beyond. As we finalize our next 5-year capital plan to be released later this year, we remain focused on continuing to deliver reliable and affordable service to our customers and compelling long-term returns to our shareholders. That concludes my remarks. I will now turn the call back over to Stephanie.

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

[Operator Instructions] And our first question will come from Rob Hope with Scotiabank.

Regarding the Arizona data center opportunity. When we look at the incremental 300 megawatts at the first site and the 500 to 700 megawatts at the other site, how quickly could you develop generation to support these assets? And is this a key gating factor at this point?

Yes. That's a great question, Rob. I've got Susan sitting here next to me to provide a little color. But as you know that first 300 megawatts is using existing and planned capacity. So that's always great to be able to serve them as quick as we can. And hopefully, they're on the same time line as we have disclosed on the 2027 time period. So we have that first 300 sort of under our belt to get them situated there. And then, Susan, if you want to provide a little color on what we're thinking time line-wise for adding the generation and the transmission interconnections we need for the next 300 at that initial site.

Sure. Thanks for the question. Yes. So as Dave said, the first 300 megawatts of capacity that we're already building and then the second 300 will be -- we'll go through our all-source RFP process. We also announced that we're looking at a green tariff with [indiscernible]. And so it will depend on what kind of generation we move forward with, but the goal is to be in service with that second 300 megawatts in that 2030 to 2031 time frame.

All right. That's great. And then I guess more broadly, when you take a look at your entire system and relative to the existing capital plan, would it be fair to assume that we're seeing the greatest upside potential in Arizona and ITC. And then as we take a look at kind of the '26 plan later this year, are there other key areas we should be looking at where we're seeing probably some outperformance?

Yes. I think you hit the nail right on the head there. We do see some -- and you'll see that in sort of our beyond the plan list. There's a lot at ITC quite a bit at Arizona as well. But we continue to look across the entire footprint. We've got some additional opportunities in BC related to LNG, et cetera. So -- and then across the rest of our footprint, we're looking at opportunities as well. So those are the 2 big ones, but we've got, I think, irons in the fire across the entire portfolio. Thanks, Rob.

The next question will come from Maurice Choy with RBC Capital Markets.

Just wanted to touch on the Springerville position. In your slides, you mentioned that it may take Fortis a longer time to achieve its entrant GHG targets. Alongside the conversion of Springerville, you're not expecting a material impact to your 5-year plan. From these statements, is it fair to assume that the cost of conversion, which I assume has elevated over the past few months, roughly matches some form of renewables for storage in your current IRP?

Yes. There's a bunch of puts and takes that are going to be going on here, and that's kind of why we're getting ready to do our next integrated resource plan in Arizona next year. But on our 5-year capital plan, we'll lay out kind of all those puts and takes that we have in the capital plan. Obviously, this is a great affordability story for our customers to be able to use existing steel in the ground. Also, that's steel in the ground that's already there, so you don't have to get in line to buy it from somebody else and also has the transmission assets to bring it in, so you don't need additional interconnections. And of course, probably one of the best benefits that we see around that is that overall affordability to our customers and just having those additional jobs in a community that's been so important TEP over these several decades.

Maybe just a quick follow-up to that. Is there any potential for Four Corners to also be converted to gas just as Springerville is going to?

Yes. Yes, that's not -- I don't think we've looked at that, but there's always, I guess, potentials. This is a time I think where a lot of folks are looking at repowering existing coal plants. And the reason that we were able to do this at Springerville is we had one of our partners, both -- who was a partner in Springerville, but also has a cold generating station down the road from Springerville Coronado that Salt River project is being able to partner with someone to make it economic to build a gas pipeline that gets down there. But once it gets down there, hopefully, other folks are using it as well.

Understood. And if I could just finish off with a quick question on my favorite province in Canada, which is BC. I wonder if I could have your latest thoughts on the landscape and outlook for gas infrastructure in the province, particularly given the push for energy infrastructure in the country and seemingly an alignment on gas amongst federal, provincial and indigenous theaters? And what this all means for FortisBC?

Perfect. So I'll turn that over to Roger. But before I do just for full disclosure, Maurice, we are -- actually the teams here in Vancouver. So we now recognize how early it is for you to get up for these calls. Go ahead, Roger. Roger A. Dall’Antonia: Thanks for the question. I would say much like Canada, B.C. is a bit of a pivot where they're embracing gas, in particular, the LNG opportunity. As you know, we're pursuing expansion of our LNG bunkering opportunity, and we have our LNG storage tank regulatory process ongoing. So directionally, we see that as positive. As far as gas connections at our domestic infrastructure, CleanBC, which is the signature policy that is dictating issues like client standards, building code standards, which is the policy that is municipalities are using to constrained new gas connections in new buildings, that's in the midst of a review, and that will come out later this year. So I think that will be the first key signpost to understand how the focus on export of LNG translates into a domestic gas agenda. So more to come on that.

The next question will come from Ben Pham with BMO.

Maybe going back to the Arizona data center update and maybe more broadly on the industry overall, this additional second site that you flagged, did this materialize with you potentially just during the last couple of months is always in the cards we had discussions. And then maybe on a broader level, can you comment your pace of discussions with the data center companies have their power needs expanded recently? Has it gone to maybe more jurisdictions than you had anticipated? And how do you think about the pace of announcements going forward?

Yes, sure. I'll turn that over to Susan to answer.

So the data center that we've been reporting on is we were just lumping it all into total number for capacity. And now there's -- as we bring forth more detail on the project, we're just representing that it will be broken into separate sites. So first building out the first 300 that we signed the contract for in July and then up to 600 megawatts at that first site. And then the second side is another 500 to 700 megawatts. So it's all the same project that we've been talking about for a while.

And then what was the second half of your question there, Ben? What's it?

Yes. And maybe you could expect that a broader thought process and the pace of discussions, the customer needs, have they changed materially over the last 3 months?

Yes. So we do have a long queue of projects in Arizona that are behind this initial project. But when we only have so much capacity, you sort of got to give it to the first folks in line. So that sort of, I would say, puts the rest of the negotiations on ice until you can figure out how you can develop things -- additional resources after the first one takes this 300 megawatts. But to Susan's point, I mean, there's a lot of details and a lot of conversations that we have with folks in the queue and particularly the one here at the top of the queue. It's just that we're basically allowed now because it's getting public information on how those different megawatts are broken out by sites, et cetera. Prior to that, of course, and we still are under an NDA for any details that they're not allowing us to release or that they haven't released. So it's just filling in the gaps as we get on the road a little bit further, but also as they're finalizing their plans as well.

Okay. That's great. And my second one on the OBBBA legislation, how that you had a bit more visibility on how things are shaking out. Can you comment impact on Fortis? I'm thinking more renewables and in rate base, ITC that impact? And then anything else that you may have done in the legislation?

Yes. So overall, there was -- there's not a lot of impact from One Big Beautiful Bill Act that was passed. Corporate tax obviously didn't change. We have -- obviously, a few weeks ago, we were talking a lot about that 899 Section, which luckily didn't make it in. Obviously, the renewable energy credit reductions and phase out there, that doesn't really have much of a near impact -- a near-term impact for UNS given where they're at in their cycle of projects. However, on a going-forward basis, it just changes the calculus of RFPs and options as you go forward. It just creates obviously different economic outcomes when those credits aren't in there for renewables and storage. So we -- I think we'll see a longer-term impact related to that. It's just there's nothing really that we can quantify. Obviously, this -- the tax credits don't necessarily -- they make them -- they make those projects more cost effective for our customers because of the credit. So that's something we'll have to consider. ITC really isn't impacted again in the short term, either, remember those LRTP tranche 2.1 projects that were allocated to ITC. I mean they're done. I mean, done dusted and given to ITC to build. So there's not any impact there. I would say longer term when you think about the implications of reduced renewable energy and storage development, it might change the mix of generation. Will it be less renewables, obviously, fossil generation is a bit in vogue, again, particularly natural gas to build to fill all the data center needs and growth opportunities. But that's just different generation that ITC would be interconnecting, right? So take gas or renewables. We still have to build the transmission to serve all this additional load that's being talked about, whether it's data centers, manufacturing or the continuation on the clean energy transition that so many utilities have started. So longer term, we'll see how it plays out. But in the short run, it's a very, very limited impact. Thanks.

Our next question will come from Richard Sunderland with JPMorgan.

There's been discussion of new interstate pipeline capacity into Arizona. I'm curious if UNS is involved in discussions here and if you have a need as you begin building gas plants?

Well, for the Springerville repowering one, that's the -- yes, we have had those conversations and all that additional public information about -- obviously, we got to get gas to Springerville and that's -- that was the big kind of nut to crack to figure out how to do that economically. And as I mentioned earlier, it's great to have a partner like Salt River Project and being an offtaker for that as well. That's the one that we've got in the queue now -- or not in the queue, the discussions to get it in the queue now.

Understood. And then, I guess, just again, same topic, but looking into the 2030s, do you see a growing need there. It seems like the state is probably in an okay position for the next 3 or 4 years, but the next decade is probably a little different.

Yes, that's the calculus we have to look at, right? When we look at our integrated resource plan, next year down in Arizona, I mean this is not static. Remember that 3 years ago is when we did the last integrated resource plan. So as we look going forward, it's going to be a very different load curve that we have to serve. And so that's what we look at and then stack up the resources that we need. I'm sure natural gas will be a part of it. Obviously, renewables and storage will be a part of it. So all of those things kind of go into that mix from a long-term perspective. So it's all a bit TBD at this point. But at the end of the day, infrastructure is going to be needed across our sector and frankly, everyone that serves our sector, right? So if there's additional gas needs, for generation, there's going to be likely additional pipeline needs as well. But that all goes into that long-term planning process.

I appreciate the commentary. I'll leave it there.

This concludes the question-and-answer session. I would like to turn the conference back over to Ms. Amaimo for any closing remarks. Please go ahead.

Thank you, Chuck. We have nothing further at this time. Thank you, everyone, for participating in our second quarter results conference call. Please contact IR should you need anything further and have a great day.

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