OGE Energy Corp. (OGE) Q4 2025 Earnings Report, Transcript and Summary

Good day, and thank you for standing by. Welcome to the OGE Energy Corp. 2025 Fourth Quarter Earnings and Business Update Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to turn the conference over to your speaker for today, Casey Strange, Investor Relations, Senior Manager. Please go ahead.

Thank you, Lisa, and good morning, everyone, and welcome to our call. With me today, I have Sean Trauschke, our Chairman, President and CEO; and Chuck Walworth, our CFO. In terms of the call today, we will first hear from Sean, followed by an explanation from Chuck of financial results. And finally, as always, we will answer your questions. I would like to remind you that this conference is being webcast, and you may follow along at oge.com. In addition, the conference call and accompanying slides will be archived following the call on that same website. Before we begin the presentation, I would like to direct your attention to the safe harbor statement regarding forward-looking statements. This is an SEC requirement for financial statements and simply states that we cannot guarantee forward-looking financial results but this is our best estimate to date. I will now turn the call over to Sean for his opening remarks. Sean?

Thank you, Casey. Good morning, everyone, and thank you for joining us today. It's certainly great to be with you. 2025 was another strong year and a continuation of the momentum we are building and setting the foundation for a long runway of future growth with generation and transmission opportunities. This morning, we reported consolidated earnings of $2.32 per share for the year, including $2.47 per share at the electric company and a holding company loss of $0.15. This time last year, we talked about how we would deliver in 2025, and we did, including delivering earnings in the top half of guidance, filed for recovery of generation needs to meet growing demand, secured financing for long-term growth, leveraged the strong local economies to drive job growth and investment in our service area. We were named in Oklahoma Top Workplace, and we were recognized by the Southeast Electric Exchange for our top-ranked safety performance. And we remain committed to our North Star of reliable electricity at some of the lowest costs in the nation. We met our commitments and more, strengthened our financial position and continued investing in reliability and growth while keeping affordability front and center for our customers, lengthening that runway for continued future growth. Since our last call, we executed a well-subscribed equity offering, filed for generation preapproval of the 300-megawatt Frontier Energy Storage project, issued 2 RFPs and a 2026 draft IRP. And as I look ahead for the remainder of 2026, we will advance our transmission strategy and finalize the opportunities from the SPP ITP, recognizing its critical role in reliability and its growing contribution to long-term investment opportunities. We'll secure approval for the Frontier Energy Storage project in both states, and we'll file for generation preapproval in both jurisdictions following the results of the RFP we issued last month. We do plan to file a rate review midyear in Oklahoma, and we'll evaluate the timing of an Arkansas rate review later in the year. Building on these strong financial results, we continue to invest in our future and strengthen our commitment to the communities we serve. In line with this momentum, tomorrow, we will host a ribbon cutting for our new combustion turbines at Tinker Air Force Base. These new units showcase our ongoing investments in community partnerships to benefit all customers and in this case, provide vital support to our country's national defense. Over the last 10 years, we've built and put into service approximately 1 gigawatt of generation. Tomorrow, we cut the first ribbon on the next 1.3 gigawatts of generation we will build and put into service before the end of the decade. Yesterday, we issued our draft 2026 IRP, which outlines our long-term resource strategy. And we are finalizing a 1 gigawatt contract with one data center customer referenced as customer X in the IRP, and we'll also file a large load tariff, both of these by midyear. Across these initiatives, our priority remains protecting residential customers, and we have built explicit consumer protection measures into that framework. In addition, we continue to advance our transmission strategy. And earlier this month, the SPP determined that several large transmission projects will be considered short-term reliability projects, meaning that OG&E was assigned a significant portion of the Seminole-to-Shreveport 765 line. After we work through the notice to construct process at SPP, we will update our investment timing and financing plans. We're discussing a number of exciting growth opportunities today, and I want to remind you that our sustainable business model's foundation is our low rates. Our relentless commitment to affordability translates to our rates as the lowest in the states we operate, lower in our region and among the lowest rates in the country. And from a cost control perspective, our O&M per customer growth over the last decade is less than 1%. We remain committed to delivering reliable electricity to all those customers at low rates. And finally, before turning the call over to Chuck, I want to recognize our incredible employees whose dedication makes these results possible. Every day, they bring a relentless focus on efficiency and affordability, helping us deliver reliable service while keeping rates among the lowest in the nation for the communities we serve. Next week, OG&E will celebrate its 124th birthday. We're a company innovating for the future with a solid foundation built over time. With that, thank you. And Chuck, I'll turn the call over to you.

Thank you, Sean, and thank you, Casey. Good morning, everyone, and thank you for joining us today. We delivered another strong year in 2025, finishing at the upper end of our original guidance range, and we're entering 2026 with solid momentum. This morning, I'll review our 2025 results, introduce our '26 outlook and walk through our long-term growth framework. Starting with full year results, consolidated net income for 2025 was approximately $471 million or $2.32 per diluted share compared to $442 million or $2.19 in '24. Ending the year $0.05 higher than the midpoint is consistent with our message of delivering results in the top half of the guidance range. At the electric company, net income increased to approximately $500 million or $2.47 per share, up from $470 million or $2.33 per share, driven by recovery of capital investments and strong load growth. At the holding company, the loss was $29 million or $0.15 per share, slightly higher year-over-year due to increased interest expense, partially offset by a onetime legacy midstream benefit. Fourth quarter details are included in the appendix. Our service area continues to perform well. Customer growth was just under 1% and weather-normalized load grew approximately 7%, reflecting strong local economies and the strength of our sustainable business model, low rates, reliable service and communities that continue to attract investment. Turning to 2026. We are guiding to consolidated earnings of $2.43 per share, with a range of $2.38 to $2.48. The midpoint represents a 7% increase from the 2025 midpoint. We are also setting our long-term EPS growth target of 5% to 7% off of this higher starting point and continue to expect to deliver in the top half of the range in '27 and '28. Since becoming a pure-play electric company, we've consistently delivered at the high end of our guidance. Our track record of setting the bar higher and higher continues to compound into increased future earnings expectations. We reliably deliver results. And over the past 10 years, we've achieved roughly 6% earnings per share compound annual growth and nearly 7% over the last 5 years. From a regulatory perspective, we plan to file a rate review in Oklahoma this summer with new rates in '27. We're also evaluating a potential filing in Arkansas by year-end. Looking at growth drivers, we expect customer count to increase about 1% and weather-normalized load to grow 4% to 6% in 2026. This builds on a strong 5-year trend with total retail weather-normalized load up more than 24% since 2021. Turning to financing. We expect to issue approximately $300 million of debt at the electric utility this year with no long-term debt issuance planned at the holding company. As a reminder, we issued equity last November to support the roughly $1 billion of incremental CapEx we added to our plan through 2030. This transaction, including the forward, satisfies our equity needs through 2030 under the current plan. Our balance sheet remains a key strength. We expect FFO to debt of approximately 17% through 2030. We are targeting a 60% to 70% dividend payout ratio with a stable and growing dividend. Earnings per share growth is expected to grow faster than dividends to support this goal. As always, we'll evaluate our plan each year in light of the company's growing investments. As we look ahead, 2026 includes several important catalysts. Growth in our customer base and policy changes at the Southwest Power Pool are driving increased capacity needs. In January, we issued 2 draft RFPs, one for bridge capacity between 2027 and 2032, and a second all-source RFP for accredited capacity available for 2032. We expect bid selection in the third quarter, followed by preapproval filings before year-end. Supporting that process, we issued a draft IRP identifying approximately 1.9 gigawatts of capacity needs by 2031. About 800 megawatts of that increase is driven by SPP policy changes. This 1.9 gigawatt need is incremental to the 300 megawatts from the Frontier Energy Storage project, and we are seeking preapproval for in Oklahoma and Arkansas. On transmission, SPP has finalized its 2025 ITP portfolio. OG&E was directly assigned a significant portion of the Seminole-to-Shreveport 765 kV line. We were also allocated several additional transmission and substation projects. Next steps include developing refined project estimates and schedules for all of the 25 ITP projects. In the second half of the year, we would expect to accept NTCs and add the projects to our investment plan. Taken together, we see a compelling set of long-duration investment opportunities incremental to our plan. We'll be prudent by balancing affordability and execution, and we'll update you on capital and financing as projects receive approvals. In closing, we remain confident in our financial plan with disciplined execution and a clear investment road map, we are well positioned to deliver results in the top half of our 5% to 7% EPS growth range through 2028 with meaningful upside ahead. It's an exciting path forward, and we're proud to support the customers and communities we serve. With that, we'll open the line for your questions.

[Operator Instructions] Our first question today will be coming from the line of Shar Pourreza of Wells Fargo.

This is Whitney Mutalemwa on for Shar. Great quarter. So investors can see the investment plan, and you've been clear you're funding major projects such as Horseshoe Lake but it's harder to translate that into a rate base trajectory without more explicit disclosure on timing and recovery mechanics. What's the best way to think about rate base growth versus the investment plan? Is it fair to assume a relatively tight linkage? Or are there meaningful timing recovery dynamics that make the conversion lumpy?

Yes. So great question. So we do have a slide towards the end of our packet that's got our investment plan laid out the current plan, and we've got a footnote on there that under that plan, that indicates rate base growth of about 9% -- so obviously, in our remarks today, we talked about a lot of opportunities that would be incremental to that. But the plan as laid out on that slide equates to 9%. Does that help?

Yes. Yes, that totally makes sense. And given that backdrop, your 4Q materials and recent Oklahoma discussions have emphasized outsized load growth and just a deeper large load opportunity set along with the '26 outlook, what specifically has changed since the last update with -- in the large load panel? Like how much is contracted, committed versus still in the advanced pipeline stages?

Yes. I don't think anything has changed. We still are in active negotiations with 6 to 7 large load customers in various stages. What we did disclose today is the customer X that's been identified in our IRP plans. We are finalizing those agreements, and we expect to have that filed with the commission along with the large load tariff by midyear. So in terms of what has changed, I think that is nearing the conclusion.

And our next question is coming from the line of Julien Dumoulin-Smith of Jefferies.

It's Brian Russo on for Julien. Could you just talk about the -- it looks like moderating of weather-normalized load growth in 2026, so 4% to 6% versus 7.2% in 2025. I was just wondering if you can maybe break down the key customer class drivers. I'm sure the commercial/crypto class has something to do with it.

Yes, Brian, I think this is really indicative of what we talked about all along and that these loads are not always super, super steady and that there's some ebb and flow to that. So what I think I highlighted in my remarks is that when you look over a little broader scale since '21, we averaged about 5%. And going forward, that's kind of right what we're seeing this year. So in the grand scheme of things, I see us really quite in line with that. Again, you think about it, really abnormally strong trend line relative to history. And then with the catalyst that we have going forward, clearly, that's a good positive sign going forward.

Okay. Good. So nothing structurally changed and it is also ex large data center customers?

Yes. So definitely, as Sean indicated, much more certainty around customer X as we prepare to finalize that.

Okay. Good. And could you comment on the disclosure in the IRP section of the 10-K regarding the Black Kettle Energy Storage capacity purchase agreement that was terminated due to some sort of event default. And I'm just curious, not knowing the details but does that kind of support kind of the least cost, least risk scenario of more utility generation ownership in these 2 pending RFPs?

I think it does, Brian. I think we've been a strong proponent of being the owner and the operator of these assets. We're good at it. And we see how they perform in extreme conditions, and we want the ball. And this situation here, I think, to your point, is exactly right. It just further validates that thesis.

Okay. Great. And then just lastly, the disclosure on the $7.3 billion base capital plan. It still seems like you might evaluate capital prioritization, maybe pushing out some transmission and distribution spend to kind of create some room for some more generation capacity to manage rates and the whole affordability narrative. Is there any more detail you can provide there because you have not done that yet?

Yes. I think we have tremendous flexibility in allocating capital, and we're certainly focused on the overall affordability metric because that's really what's been fueling this growth we're seeing in our service territory. So we're balancing all that. What Chuck was talking about, though, is as you look forward, we are going to be looking for additional generation. We're going to be working through this transmission line. When we get those finalized, we'll layer those in at that point. So that's probably the data point or the time period where you ought to look for if we were to make any changes, what they would be.

The next questions come from the line of Aditya Gandhi of Wolfe Research.

I just wanted to start on the 765 kV transmission line. I believe SVP came out with a $2.4 billion estimate for that particular line. Recognize you're still going through updating the cost estimates and timeline. But can you give us some initial sense of what OGE's portion of that project would be relative to AEP?

Yes, thanks for the question. So I think, first of all, you laid it out exactly right. We're very early in the stages on that. The SPP just made that designation, which we wholeheartedly supported. So I think we've got some work to do to kind of get through those points. But as I mentioned in the remarks, it's that line and there's some other associated work. So I think at this kind of preliminary stage, I see it as probably something that's on the order of 20% of our current capital plan. But again, that's a preliminary kind of feel, and we will work with the SPP to fine-tune that and hope to get that buttoned up before the end of the year.

Yes. Aditya, this is Sean. Just one other point. The routing is still to be determined and the direct routing of that line. So this will all get fleshed out, and we'll certainly disclose that later in the year.

Understood. That's helpful. And then I also wanted to touch on the data center contract that you're finalizing. Can you just remind us for this 1 gigawatt, do you intend to meet those capacity needs through the RFP process that you're running right now as well as generation that's already in your plan? And then maybe can you just speak to some customer protections that you're building into that large load tariff framework?

Yes, Aditya. Yes, those -- so that contract, that customer is worked into the IRP numbers that was released today. So we do intend to approach that holistically through the RFP process. In terms of customer protections, it's -- we've been very clear on this ever since customer X has come up in terms of customer protections that ensure that, that large customer pays its fair share, has minimum terms, collateral requirements, all those types of things that you would expect. And we'll be happy to share more details around that once that regulatory filing gets made.

Our next question is coming from the line of Chris Hark of Mizuho.

This is Chris on for Anthony. My question is pretty similar to the last one but just want to get a little more insight on the customer class breakdown in that 4% to 6% number. And how much of that is being driven by customer X and then also the retail class?

So Chris, we don't have a whole lot of detail broken out in our filing. But what I can tell you is that customer X really doesn't come on this year, right? So that's a little bit further out than this year. So that's not driving the 4% to Other -- the key areas, obviously, we look at residential is definitely a bellwether class, and we kind of see that as definitely as steady as always. So hopefully, that gives you a little bit of insight there. But customer X is not in that 4% to 6% for this year.

Okay. Super helpful. And then the next question I had was just more about the election and with Hyatt's term ending in this upcoming January next year, what are your thoughts on the turnover in the commission and just the elections that are going on in your jurisdictions?

Great question. So there's -- we certainly have a governor's race and Attorney General's race and then we certainly have a Corporation Commissioner race. We've been involved and spoken to all the candidates. I think all the candidates for each one of those races would be constructive and we'd be comfortable with. And we know them. And so I think essentially, that -- those races will be determined, I would expect in the June primary. And we'll probably have a good idea of who the Governor and the Attorney General and the Corporation Commission are going to be in June.

[Operator Instructions] The next question is coming from the line of Nicholas Campana of Barclays.

This is Michael Brown on for Nicholas Camppella. So my question is, recently, IREN has announced a data center in Alva, Oklahoma. And we also noticed your draft IRP has 1.9 gigawatts of new needs by 2031. Can you confirm that this opportunity in Alva is in your service territory? And how are you framing what else is needed to get to ESAs with the counterparties in your territories if it is in your territory?

So in the -- we've had a lot of discussion since the last IRP about what large customers are in and not. And you recall, we had one customer that was not in there, but just again, trying to give folks a flavor of the type of customers we've been having discussions with. So this update of the IRP does not have another customer similar to customer X in it. Again, we are talking with other counterparties. But again, just keeping with our prudent conservative bent, we haven't included any of those at this time. So really, when you're looking at that 1.9 billion, recall that last year, we were solving for 2030 capacity needs. And the way our IRP works is we have a 5-year action plan. So we've essentially just shifted that out 1 year. And when you look at the impact of shifting it out 1 year, our load is up because of that. The Black Kettle resource that we talked about earlier, moving that out that was in there before. And then just some kind of general odds and ends on the load forecast, that's what gets you to that number. As well as the SPP policy changes that were enacted this year. That was about 800 megawatts. So a pretty substantial change there, too.

Okay. My last question. You said you plan to have a DC deal by midway through this year. How are you thinking about current legislation impacting that? And what do customers -- what do -- what does this customer need, whether it's permitting water or water permitting to properly move forward with the AFM?

Yes. Good question. So in terms of the first part of that, in terms of the legislation that seems to be popping up in every jurisdiction, we're certainly involved in that process, engaged in that dialogue, and we'll stay focused on to make sure that there's adequate protection for the existing customers. In terms of customer X, what things they need to do to kind of move forward, I think the gating item, quite frankly, is just finalizing our agreement. we're in pretty good shape.

I just have one more. Actually, I just have one more. With your rate base -- I just have one more question, actually. I'm sorry. With your base CAGR already at 9% and dilution at roughly 0.75% and coupled with the upside CapEx, I'm curious as to why your growth isn't better than 6.5%.

Yes. I think good question. And so what we try to do is make sure that we lay out for you exactly what has been approved through the regulatory arenas with a financing assumption. And so that is the assumption we -- those are the assumptions we put forward to you today. What we've highlighted is when we receive the final clarification on the total numbers around the ITP projects at the SPP, we will layer that in and tell you how we're going to finance it. When we receive approval for all of the generation that's coming out of these RFPs, we will show you what that is, the time line and how we're going to finance and the earnings impact. So that's how we're doing that. We will layer these in. And obviously, that will have an impact on earnings.

And the next question is coming from the line of Steve D'Ambrisi of RBC Capital Markets. Stephen D’Ambrisi: I dialed in Steve this time, so I didn't get Stephanie.

I noticed -- we noticed that. We weren't going to say anything. Stephen D’Ambrisi: I figured out. I'd let you know. Yes. So just following up on the same line of questions. Obviously, I understand that you guys are a very conservative management team. But I just want to -- look, there are people in your service area, it seems like -- service territory, it seems like, who are talking about having power secured? And just so can you talk about like what the timeline is or what it looks like when you'll go to update the Street on potential other customers other than customer X, for example? Because it just feels like there are -- there is load out there that is substantial relative to your peak and that you may have to build for. And I just want to try and understand like how we have to feather that in over time.

Yes. I mean to kind of put it in perspective, in our remarks, we said by the end of the decade, we'll have added 2.3 gigawatts and then the IRP is calling for another 1.9. So it's pretty substantial. I think what's going to have these large load customers as they materialize and we have line of sight to the finish line, we're going to announce it. And just like we did with Customer X here to give you some time line. But 1.9 gigawatts is a lot to have in by the winter of '31, '32. Stephen D’Ambrisi: Yes. Totally understand. Not saying there's not a lot but it seems like there's even more.

I think you have to draw the line somewhere, Steve. And so -- and we're out there all the time talking to different people. I rode the elevator this morning with somebody and they were telling me about another opportunity. So they're out there, and we're working hard to secure them.

Thank you. And that concludes today's Q&A session. I would like to turn the call back over to Sean Troy. Please go ahead.

Great. Thank you, and thank you, everyone, for joining us today as well as your continued support. Take care, and have a wonderful day.

This concludes today's program. Thank you so much. You have a great day. You may now disconnect.