Fortis Inc. (FTS) Q4 2025 Earnings Report, Transcript and Summary

Thank you for standing by. This is Betsy, the conference operator. Welcome to the Fortis Inc. 2025 Annual Results Conference Call. [Operator Instructions] The conference is being recorded. I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Ms. Amaimo.

Thank you, Betsy, and good morning, everyone. Welcome to Fortis' Fourth Quarter and Annual 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 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. Before we get started, I'd like to take a moment to express our gratitude to Linda Apsey, CEO of ITC for her exceptional leadership ahead of her retirement next month. Throughout her tenure as CEO, she has guided ITC with clarity, integrity and a deep commitment to the people and communities that ITC serves. Her steady leadership has strengthened ITC's foundation and helped position the company for continued success long into the future. We wish her all the best in retirement. And as we look to the future, we are excited to have a long-time executive at ITC, Krista Tanner, succeed Linda in the role of President and CEO, and she is on the call with us today. Her experience and insight will be vital as ITC continues to meet the changing demands of the energy landscape. Turning to our business highlights slide. 2025 marked another strong chapter in the Fortis story, During the year, we continued to deliver safe and reliable service to the millions of people who depend on us each day. Our utilities invested $5.6 billion in capital, which strengthened our systems, enhanced our resilience and supported the long-term needs of our customers and communities. These investments translated into strong rate base and earnings growth and supported our track record of increases in dividends paid to 52 consecutive years demonstrating the value of our regulated growth strategy. Fortis was also recognized by the Globe and Mail's Annual Board Games Report with the #1 ranking in governance out of 206 companies in the S&P/TSX Composite Index, reflecting our Board's commitment to best-in-class practices. And today, we released our 2026 climate resiliency report, which outlines how our utilities are responding to climate risks and utilizing data-driven insights to strengthen our energy network. A strong culture of reliability and safety continues to be the foundation of our utility operations. In fact, 2025 was one of our best years on record for both safety and reliability and reflects continuous improvement relative to our Canadian and U.S. industry averages. A core tenet of our strategy is to operate cost effectively for the benefit of our customers. While we have experienced cost and supply chain pressures over the past few years, we have been successful in keeping controllable operating costs at or below inflation. Innovative practices like deploying grid-enhancing technology and using AI for targeted vegetation management and equipment inspections are reducing costs while improving reliability for our customers. Our utilities continue to prioritize capital investments based on operational needs and with consideration of the customer bill impact. We also have energy efficiency programs that help customers directly lower their bills and several of our utilities provide low-income discounts and customer bill assistance programs to help those in need. Our long history of achieving strong shareholder returns continued in 2025 with a 1-year total shareholder return of nearly 24%. Looking back over a 20-year time frame, Fortis has delivered average annual total shareholder returns of approximately 10%, exceeding the returns generated by the benchmark indices. In the fourth quarter, we rolled out our new $28.8 billion 5-year capital plan, our largest to date. The plan consists of a diverse mix of regulated investments across our utilities, primarily focused on transmission and distribution assets. The plan is highly executable and low-risk with only 21% relating to major capital projects. Over the next 5 years, we expect rate base to increase by $16 billion, supporting average annual rate base growth of 7%. Above and beyond the plan, we are focused on incremental growth opportunities in both the near and long term. At ITC, we are working on pursuing additional customer connections and MISO LRTP projects. As you might recall, ITC expects additional Tranche 2.1 investments between USD 3.3 billion and USD 3.8 billion for projects awarded through the rights of first refusal in Michigan and Minnesota and system upgrade projects in Iowa that are not subject to competitive bidding. Most of these investments are expected post 2030. ITC continues to evaluate competitive bidding opportunities and any project awarded would be incremental to this estimate. As it relates to retail load growth in Arizona, in December, the Arizona Corporation Commission approved the energy supply agreement for approximately 300 megawatts to support a planned data center in Tucson Electric Power service territory. The project will use existing and planned capacity with the ramp-up beginning in 2027 and continuing through 2029. The customer will take service under TEP's commission-approved large power service tariff at full tariff rates with no discount. The 10-year contract includes a 75% minimum billing requirement, providing revenue stability regardless of actual energy use and also includes strong credit and security provisions. The energy supply agreement remains subject to contractual contingencies and continues to progress with the developer closing its land lease with Pima County in December 2025, keeping the project on track. Beyond this initial phase, negotiations continue for an incremental 300 megawatts of capacity to support a full build-out of 600 megawatts at the site. TEP is also in active negotiations for additional capacity at a second site in the range of 500 to 700 megawatts. Just last month, more than 600 acres of land in Morana was approved for rezoning for the second site. If agreements are finalized for these subsequent phases, we continue to estimate new generation in the range of USD 1.5 billion to USD 2 billion through 2030 would be required. At FortisBC, the BCUC's approval of the Tilbury LNG storage expansion project late last year provides up to $300 million of potential incremental capital subject to the timing of environmental assessment approvals. In 2025, we increased our dividends paid per common share by 4% compared to 2024, marking 52 consecutive years of increases in dividends paid. Looking ahead, we remain committed to building on this record through the execution of our growth strategy, supporting our 4% to 6% annual dividend growth guidance through 2030. Now I will turn the call over to Jocelyn for an update on our fourth quarter and annual financial results.

Thank you, David, and good morning, everyone. Before I get into the annual results, I want to briefly touch on our fourth quarter. Reported earnings per common share for the quarter were $0.83, $0.04 higher than the fourth quarter last year. Reported earnings for the fourth quarter were impacted by losses associated with the disposition of our investments in Belize and reported earnings for the fourth quarter of 2024 reflects a refund liability at ITC associated with the MISO-based ROE decision. Excluding these items, adjusted EPS was $0.07 higher than the fourth quarter of 2024. Strong rate base growth across our utilities was a key driver for the quarter. Unrealized gains on derivative contracts and a favorable impact of foreign exchange also contributed to the increase quarter-over-quarter. The increase was moderated by lower earnings at UNS driven by regulatory lag and milder weather. Higher holding company finance costs as well as lower earnings contributions from FortisTCI and Belize also impacted the quarterly results. As David mentioned, we delivered strong EPS growth in 2025. Reported EPS was $3.40, $0.16 higher than in 2024. Reported EPS for 2025 reflect losses associated with the disposition of Turks and Caicos and Belize, totaling $0.13 per share, approximately half of which relate to income taxes. Adjusted EPS was $3.53, $0.25 higher than 2024. On Slide 12, you'll see the adjusted EPS drivers for the year by segment. Our Western Canadian utilities contributed a $0.10 increase in EPS, largely driven by rate base growth including earnings associated with FortisBC's investment in the Eagle Mountain Pipeline project. This growth was partially offset by the expiration of the PBR efficiency mechanisms and a lower allowed ROE effective January 1, 2025, at FortisAlberta. Our U.S. electric and gas utilities delivered an $0.08 increase in EPS. The increase in earnings at Central Hudson was due to rate base growth and the rebasing of costs effective July 2024. Earnings were also impacted by a change in the recognition of a regulatory deferral for uncollectible accounts effective July 1, 2025, and a contribution to a customer benefit fund associated with the settlement of an enforcement proceeding. Lower earnings at UNS Energy was due to regulatory lag associated with over USD 700 million of rate base, not yet included in rates as well as lower retail sales due to milder weather and lower margin on wholesale sales. This was partially offset by higher transmission revenues and AFUDC for major capital projects. Moving to ITC. Continued capital investments and related rate base growth increased EPS by $0.04. The increase was moderated by higher stock-based compensation and higher finance costs. For the Corporate and Other segment, the $0.01 increase reflected unrealized gains on foreign exchange contracts tempered by higher finance costs as well as lower earnings contribution from Fortis Belize. A favorable impact of foreign exchange contributed an $0.08 increase for the year and higher weighted average shares reduced EPS by $0.06, driven by shares issued under our dividend reinvestment plan. And lastly, while not shown on the slide, other electric earnings for the year were impacted by rate base growth, offset by the disposition of FortisTCI. Looking back over the past 3 years, Fortis has delivered average annual rate base and EPS growth of approximately 6.5%, continuing our solid growth track record. During this time, we have also successfully reduced our adjusted dividend payout ratio to approximately 70%, highlighting our ability to grow responsibly. We are in a strong liquidity position with $2.7 billion of long-term debt issued in 2025 and nearly $4 billion available on our credit facilities at the end of the year. With the hybrid debt issuance and asset dispositions in 2025, the growth in our capital plan is still 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. On the rating agency front, we are happy to report that in November, S&P confirmed our A- issuer and BBB+ senior unsecured debt ratings confirmed and revised the outlook from negative to stable due to improving financial measures as well as developments at our utilities to mitigate physical risks, namely wildfires. Additionally, it's worth noting that last month, Moody's withdrew its ratings for Fortis Inc. at our request. Our decision was made after evaluating the cost and benefits of that rating and does not impact the stand-alone rating of our utilities rated by Moody's. Overall, our key credit strengths coupled with our funding plan support our strong investment-grade credit ratings with S&P, Fitch and Morningstar DBRS. In Arizona, both the UNS and TEP general rate applications continue to progress. Last month, the ACC administrative law judge issued a recommended opinion and order with respect to the UNS Gas general rate application, recommending an allowed ROE of 9.57% and a 56% common equity component of capital structure. While the order also recommended a formula, it reflected certain revisions to the formula, including post-test year adjustments. UNS Gas filed its response on Monday, including its objection to the revisions to the formula. The rate application remains subject to ACC approval, which is expected in the first quarter. The order proposes implementation of new rates by March 1, 2026. At TEP, staff filed its testimony earlier in the week, recommending a 9.75% ROE and 55% common equity component of capital structure. Staff's rate design testimony, including the formula will be filed in late February and hearings are expected to commence in April. Based on the latest procedural schedule, we expect an order in the fall. That concludes my remarks. I'll now turn the call back to David.

Thank you, Jocelyn. To summarize, 2025 was another great year. We invested more than $5.6 billion in capital and delivered solid EPS and rate base growth. We had strong safety and reliability results, and we delivered compelling returns for our shareholders. These accomplishments wouldn't be possible without the continued commitment of our people. Going forward, we are focused on executing our $28.8 billion capital plan, which will drive rate base growth of 7% and support our dividend growth guidance of 4% to 6% 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.

[Operator Instructions] The first question today comes from Maurice Choy with RBC Capital Markets.

Starting with a question on Arizona and data centers. You mentioned in your prepared remarks that the commission approved the full tariff rates with no discounts, 75% minimum billing requirements, strong credit and security provisions. Recognizing that affordability is a big theme this year, I wonder if you could just speak holistically as to why you think this arrangement works in Arizona and perhaps why other power markets across North America continue to have issues with tariff design or cost allocation?

Yes. Thanks for that question, Maurice. Obviously, affordability is at the tip of everybody's tongue these days talking about how we're going to grow and make sure that we do that in an affordable and responsible manner from a customer perspective. And this is actually one of the prime examples of how it should be done. This energy supply agreement, as we look at our current portfolio at TEP, that's roughly 300 megawatts is supplied out of existing capacity and energy that we -- so we do not have to build anything additional for them. And a little bit of investment that we have to make from interconnection, et cetera, is going to be paid by this customer. So when you look at the difference between what TEP's rates and customer base would look like with and without this data center, you'll see that there's a lot of new KWH without additional dollars and investments that we would be making on their behalf that will go in to provide a lot of additional fixed cost recovery from all those KWH. And actually, I'm saying KWH, but as I mentioned, the 75% minimum billing demand is there as well. So it actually doesn't necessarily even revolve around how much energy they use. So this is, I think, the poster child example of how it should be done. And then, of course, as we look forward and building additional capacity for the next phases of those data centers, we will do it in the same manner where we make sure that those data centers cover all of the costs and basically investments that we need to make on their behalf and then some, right? Because when you look at their -- again, their energy usage and how they'll be leaning on the rest of the grid, those kilowatt hour charges that they'll be paying will be spreading out the cost that we have in our system over a much bigger pie. So if you do it right, this is a fantastic customer affordability story, and we're going to make sure that we do it right.

And maybe as a quick follow-up, what gating items are there for the remaining 300 megawatts in this initial site? Is it just waiting for the first 300 megawatts to be built first and then we get to the next 300? Or are there other things to consider?

Yes, there's -- I mean, the second 300 megawatts will need additional capacity that will need to be added. And so of course, how we do that, the timing for that and the negotiations of all the contractual details that covers all of those things that I mentioned to make sure that we are protecting ourselves, the company, et cetera, as well as the customers, that all still has to be finalized.

Understood. And just finishing off with ITC. Have you seen any updates from FERC, particularly now that it has a new chair on moving on with any of the ongoing FERC matters?

So we haven't. I know there's been some chatter out there that there could be some -- but we haven't heard anything. And I'm going to turn that over to Krista because she's recently been wandering the FERC calls and she may have some additional information. Krista?

Yes. Thanks, Dave. That's absolutely right. There has been a lot of chatter, but we haven't heard anything specifically about ROEs or incentives. What I will say, however, is that I think this chair and this commission is laser-focused on running the commission well. And to that end, the Chair has been very vocal that she wants to clean up things that have just been hanging out there for a while. So we are optimistic that things have been hanging out there and are kind of the questions that we get from all of you every time we see you about what's going to happen. We are optimistic that there will be some movement on there. I think the other thing we're seeing from this FERC is that as part of running the agency well, they're very focused on making sure that their decisions have staying power. This back and forth between administrations is not helpful. And so this Chair has been very intentional about making sure they follow the record, follow the law and get bipartisan support. So while we don't have any insight on what they'll be taking up, I think we're really optimistic that they will be kind of cleaning out the cobwebs and closing some of these old dockets and doing it in a very thoughtful way that will give us some regulatory certainty going forward.

Perfect. Congratulations to Linda and Krista.

The next question comes from Rob Hope with Scotiabank.

I'll extent my congratulations as well. Maybe keeping in Arizona, the ALJ decision on the formula mechanisms moving forward, there was some commentary in the release there about kind of things that were put forward and things that weren't put forward. Can you maybe just kind of speak to your view of what the ALJ's decision is and kind of what you would -- what you like about it and what you don't like about it?

Yes, I'll kick that over to Susan to address. I will just say, as a lead in here, obviously, we've got a couple of different rate cases going on, both UNS Gas and TEP. And I would just want to say on upfront, that these are definitely 2 different companies, 2 different dockets, 2 different mechanisms that were proposed, 2 different ALJs. So it's hard to get -- because it might be your follow-up question, Rob, so sorry if I jumped to it, which is that it's hard to get readthrough from one of these cases to another, but I'll let Susan opine on the UNS Gas case here.

Yes. Thanks, Dave, and thanks for the question, Rob. So it's a lengthy process as we go through the rate case and multiple rounds of testimony working with ACC staff on a design that is acceptable to them. And we came to a pretty good place where other than the dead band, we were in agreement with staff. And the recommended opinion and order was a little different than what we had submitted. I'd say you asked what did we like that's in the, I'll call it, the [indiscernible]. The judge recommended calling it a pilot program, which we think is good because this is the first round of formula rates in Arizona. And so we want the opportunity to continue to adjust the design as we are able to experience it and see how it goes for our customers and for the company. There's a couple of other kind of minor things that we agree with in terms of the judge's recommendation. I'd say the things that were really hopeful to get changed back to the way that we had proposed and staff had agreed with the design for the formula rate because of the extension of the approval period, we submitted a request to get 6 months of post test year plant recovery. And I think that's really important as the recovery period gets extended to cover those costs and to reduce regulatory lag, which is really the intent of having a formula rate. We're okay with the larger dead band as long as we can get that post-test year plant. I think the other thing that we feel like the 9.77% ROE is justified and that should not be reduced because of a formula rate. And then the efficiency credit, I think, is just maybe a misunderstanding of -- we had proposed an efficiency credit with the system improvement benefit. And that's pretty typical for a system improvement benefit, but doesn't really relate to a formula rate or this ARAM that we recommended. And so I think that 5% efficiency credit needs to be reconsidered. So I think we have a good track record with this commission. We filed an amendment on Monday, proposing to go back to basically what staff had recommended, including their deadline range of plus or minus 40 bps. And I think there's a good opportunity here for discussion with the commission as we kind of play out the consequences of the way that the recommended order was written that we can get back to what was recommended by staff.

All right. Appreciate that. And yes, my second question was going to be the readthrough. But instead, I'll go to BC. LNG and increasing energy exports and LNG, we'll call expansion seems to be a focus for the government. Any movement on the next wave of projects at Tilbury with the government and the approvals there?

Yes. So as we sit here today, we don't -- other than that update that I gave in the prepared remarks, related to the LNG tank that we received the approval for late last year. So other than that, obviously, there's some additional projects that we're looking at there, but we don't have anything else to announce right now. There is obviously, I think, a good emphasis in British Columbia on looking for some of the large projects. We hope that bubbles up to some additional investment opportunities for us in that area.

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

I just wanted to go back to the data center opportunity in Arizona. Commission has been supportive, but more recently, the Attorney General came out with some comments. Any risk that creates a delay or puts a jeopardy some of the planned expansions?

At this point, the pushback from the AG, I think we don't see that as necessarily a big issue or threat to this first contract that we have negotiated. We feel that the comments perhaps that were made on this wasn't quite fully understood exactly how the contract was formed that this was absolutely a 100% Arizona Corporation Commission approved tariff. There weren't any discounts. It was -- so I think some of the arguments -- well, I would say all the arguments that we saw against the energy supply agreement, we feel we have the right answers for. So I think with the clarity of daylight on all of those terms, I don't think we will have an issue.

So Dave, since the comments were made by the AG, have you been able to have some dialogue with them, share some evidence, communicate your position to help clarify some of the maybe misperceptions on that?

So we have spent a bit of time with publicly putting out that same message and both letters to the editor and the paper and things like that. I don't know, Susan, if we've sat down with the AG on this topic or not, but you can opine if you have.

Yes. I think that's right, Dave. We have not sat down with the AG, but we have publicly been sharing the details of the agreement that we're able to. I think you're right.

Okay. And then just in terms of some of those upside drivers you've outlined, I think it's on Slide 8, just in terms of some of the items that could be upside to the plan. If you think about since last quarter when you gave your 5-year plan, progress since then, like if you had to rank those, is it the data center opportunity in Arizona that's the best? Is it load and ITC? Just sort of how you would say that opportunities are shaping up in terms of incremental upside to the plan?

Yes. I guess ranking them, I suppose, there's obviously additional opportunities in ITC related to the -- what was formerly known as the Tranche 2.2 now known as MTEP 26. I think those are obviously a great opportunity for us if and when we want to participate, and we're still evaluating the competitive bidding process in Iowa. Those are things that are pretty close in as well. The data centers in Arizona, for sure, that feels like it's -- I mean, we're having those conversations now. If we can get that story out, explain very well how these things can benefit the rest of our customers, I think -- which I think we're as an industry on the verge of getting that information out there and getting that explanation so that hopefully, we turn that corner and folks see that some of these big load growth opportunities are actually a way to get more affordable rates. Once that dam breaks, I think we'll get a lot of positive support for those types of projects. And then like the question before on BC, there are some good opportunities there in that jurisdiction for additional LNG investments. And given, again, the focus there of the government on big projects and some good opportunities to provide economic benefits to that province, that and the -- there's quite a bit of investment opportunities that we see in the Okanagan and our small electric company there as well that we hope to see come to fruition. So it's a pretty big laundry list, but we're happy how full it is.

The next question comes from Benjamin Pham with BMO.

On the annual formula mechanism for both UNS Gas and TEP, do you think that the commission can rule on that mechanism when you have a pending Court of Appeals case outstanding?

Yes, we think they can. So that Court of Appeals is more from a procedural perspective. It was really looking at whether or not they view the policy statement as being required to go through a rule-making process, which just takes a little bit longer time and a little bit more detailed process. The beauty of this is I think we have the record in our favor in that there have been mechanisms like this past, whether it's the system improvement benefit charge or other trackers that we've had. We had a decoupling statement years ago, policy statement. But the most important part is the policy statement was just that. It didn't -- it was the ability for utilities to file in a fully litigated rate case, formula rates, which were then, of course, fully litigated in that rate case. So it wasn't a rule-making that had any shells in it. It was that a utility may apply for a formula rate based on a handful of principles. So we don't see that as being an issue in us going through a rate case and getting that. And in fact, there's no reason that we needed to even have a policy statement before asking for these types of mechanisms in a rate case. As long as it's a fully litigated rate case, it's within the bounds of the Arizona statutes, then you can ask and the commission can grant anything within those bounds.

Okay. Understood. And on the second question on customer affordability, you've had a pretty good list there on how you plan to manage that going forward. I'm curious, are you sensing from customers or feedback in certain states or provinces where this is a bit more heightened when you look at across your franchises across North America?

Yes. I think it's probably different state by state, province by province, depending on the focus of -- a lot of times, politicians and governments and pushing the affordability question, which everyone should be doing. We just have to make sure that we fully understand the impacts and drivers of affordability, and we're trying to get out there within our own companies and the sector even from a wider perspective and explaining what we're doing in order to address that.

Okay. It seems like a broad conversation, but not something that's being more pointed in that particular area for Fortis.

No, I think we -- as a company and with all our utilities, it's got to be -- this is an extremely important topic. And I would say probably the #1 question that we get asked by you all from an analyst perspective, which is a great -- I think a great result that we're all focused on the same thing, making sure that at the end of the day, we're doing the best job we can to provide our customers the level of service they need and do that as affordably as possible. So we're all on the same page. We just have to make sure that we're looking at it consistently across our Fortis footprint. So we don't say, oh, this jurisdiction hasn't been a big issue or it hasn't come up, let's not pay attention. This is something we're focused on 24/7 in every jurisdiction.

The next question comes from John Mould with TD Cowen.

Just going back to the UNS Gas rate case, and I appreciate you don't want to get ahead of your regulator, how should we think about what could come out of the upcoming ACC open meeting? Could that provide some clarity on finalized details of the formulaic rate structure in terms of an order? Or is that just too short a time line given the exceptions by both you and others? Any insight on that?

So I could pontificate, but I think it's better to just wait a week. So it just got put on next -- a week from today is the 19th open meeting. There's a special open meeting for the UNS Gas case. So instead of getting front run in that, it's just right around the corner. So we'll leave it at that.

No, fair enough. Appreciate that. And then maybe just moving to Ontario. You're on a list of potential participants in competitive transmission procurements and there is one being launched. There's also potential for changes to the LDC landscape in the province with this government pulse expert panel that's in progress. How are you thinking about the potential for more investments in Ontario by Fortis?

Yes. It's a province that we've been in for 30 years. And we've done -- we've got our utilities there as well as our background in building the Wataynikaneyap project. And so we love Ontario. We'd like to invest more there. And so we're trying to see if we can. So it's a good opportunity. And if it works out, great. I mean that's something that we would love to participate in bringing some of our capital into the province and help them build out. They've got a really great energy plan, and we'd love to be a part of it even just on the edges.

[Operator Instructions] The next question comes from Elias Jossen with JPMorgan.

I appreciate the color on the regulatory developments across the Arizona rate cases. So as you move through the process throughout this year, how do we think about increased clarity shaping the potential to issue earnings guidance at some point in the future?

Yes. The increased clarity, good regulatory mechanisms that allow us to forecast a little bit better, taking the peaks and valleys out of the Arizona utilities does provide a little bit better clarity for us from an earnings perspective. And I would say is not the only thing. It's obviously something that would go on the side of the ledger that would allow us to give earnings guidance. But at the end of the day, that's -- there's a lot of other considerations around that as well. So it's sort of one less thing but doesn't necessarily mean that it drives us straight to earnings guidance.

And then recognize you guys have already talked a lot about the large load outlook in Arizona. But can you frame your involvement on the ongoing IRP workshops? I know there's a lot of stakeholders at the table there, but just to get your perspective on those IRP workshops. And can you remind us when we might expect an update there?

Yes. So we're in early days in the integrated resource plan. We've had a couple of public meetings. We put together this big stakeholder group that goes through the entire process. And you can follow -- actually, there's a spot on our website at TEP that you can follow along on the developments there, including once we start putting load forecasts and those kind of estimates there. I'm glad you brought that up because that was one of the big pieces I meant to mention this a little bit longer term, but an additional above and beyond the capital plan opportunity as we see that and start building out that integrated resource plan, we'll be able to then see how much additional generation and transmission investments we'll need to serve the growing load in Arizona. So it is still early days, but we -- I think we filed that in August of this year. So it will be getting pretty active here over the next few months.

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

Thank you, Betsy. We have nothing further at this time. Thank you, everyone, for participating in our fourth quarter and annual results 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.