And we are finalizing a one gigawatt contract with one data center customer referenced as Customer X in the IRP. We will also file a large load tier, 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–Shreveport 765 kV line. After we work through the notice to construct process at SPP, we will update our investment timing and financing plans.

We are 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 the lowest in the states we operate, lower in our region, among the lowest rates in the country. And from a cost control perspective, our O&M per 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 are a company innovating for the future with a solid foundation built over time. With that, thank you. And, Chuck, I will turn the call over to you. Thank you, Sean, and thank you, Casey. Good morning, everyone, and thank you for joining us today. We have delivered another strong year in 2025, finishing

Charles B. Walworth: at the upper end of our original guidance range, and we are entering 2026 with solid momentum. This morning, I will review our 2025 results, introduce our 2026 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 2024, 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 $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 one-time 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 2027 and 2028. Since becoming a pure-play electric company, we have 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 ten years, we have achieved roughly 6% earnings per share compound annual growth and nearly 7% over the last five years. From a regulatory perspective, we plan to file a rate review in Oklahoma this summer with new rates in 2027.

We are 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 five-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 will 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 two 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 2025 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 will be prudent by balancing affordability and execution, and we will 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 roadmap, 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 is an exciting path forward, and we are proud to support the customers and communities we serve.

With that, we will open the line for your questions.

Operator: Thank you. At this time, if you would like to ask a question, please press 11 on your telephone. You will hear the automated message advising your hand is raised. If you would like to remove yourself from the queue, press 11 again. We also ask that you please wait for your name and company to be announced before proceeding with your question. Our first question today will be coming from the line of Whitney Mutalemwa of Wells Fargo. Your line is open.

Whitney Mutalemwa: Good morning, team. This is Whitney Mutalemwa on for Shar. Hi. Good morning, Whitney. Thank you. Great quarter. So investors can see the investment plan, and you have been clear you are funding major projects such as Horseshoe Lake, but it is harder to translate that into a rate base trajectory with that more explicit disclosure and timing and recovery mechanics. What is 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?

Charles B. Walworth: Yes. So great question. So we do have a slide towards the end of our packet that has our investment plan laid out, the current plan, and we have a footnote on there that under that plan, that indicates rate base growth of about 9%. So obviously, you know, 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?

Whitney Mutalemwa: Yes. Yes. That totally makes sense. And given that backdrop, your fourth quarter materials and recent Oklahoma discussions have emphasized outsized load growth, and just a deeper large load opportunity set along with the 2026 outlook. What specifically has changed since the last update within the large load panel? Like, how much is contracted, committed versus still in the advanced pipeline stages?

Robert Sean Trauschke: Yes. I do not think anything has changed. We still are in active negotiations with six to seven large load customers in various stages. What we did disclose today is the Customer X that has 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.

Whitney Mutalemwa: Sounds good. Thank you.

Robert Sean Trauschke: Thank you. Thank you. One moment for the next question.

Operator: And our next question is coming from the line of Brian J. Russo of Jefferies. Your line is open.

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

Charles B. Walworth: Yes, Brian, you know, I think this is really indicative of what we talked about all along, in that these loads are not always, you know, super, super steady, and that there is some ebb and flow to that. So what I think I highlight in my remarks is that when you look over a little broader scale, you know, since 2021, we averaged, you know, about 5%. And, you know, going forward, that is kind of right what we are seeing this year. So, you know, in the grand scheme of things, I see us really, really quite in line with that. Again, you know, you think about it, really abnormally strong trend line relative to history.

And then with the catalysts that we have going forward, clearly, that is a good positive sign going forward.

Brian J. Russo: Okay. Good. So nothing structurally changed, and it is also excluding large data center customers.

Charles B. Walworth: Yes. So definitely, as Sean indicated, much more certainty around Customer X as we prepare to finalize that.

Brian J. Russo: Okay. Good. And could you comment on the disclosure, the IRP section of the 10-Ks regarding the Black Kettle energy storage capacity purchase agreement that was terminated due to some sort of event default? And I am just curious, not knowing the details, but does that kind of support, you know, the least cost, least risk scenario of more utility generation ownership in these two pending RFPs?

Robert Sean Trauschke: I think it does, Brian. I think we have been a strong proponent of being the owner and the operator of these assets. We are 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 basic capital plan, it still

Brian J. Russo: seems like you might evaluate capital prioritization, maybe pushing out some transmission and distribution spend, due 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.

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

Brian J. Russo: Alright. Great. Thank you very much.

Robert Sean Trauschke: Thanks, Brian.

Operator: Thank you. And one moment for the next question. Next question is coming from the line of Aditya Gandhi of Wolfe Research. Your line is open.

Aditya Gandhi: Good morning, Sean, Chuck, and Casey. Thank you for taking my questions. I just wanted to start on the 765 kV transmission line. I believe SPP came out with a $2.4 billion estimate for that particular line. Recognize you are still going through updating the cost estimates and timeline, but can you give us some initial sense of what OGE portion of that project would be relative to AEP?

Charles B. Walworth: Yes, Aditya. Good morning. Thanks for the question. So I think, first of all, you laid it out exactly right. We are very early in the stages on that. The SPP just made that designation, which we wholeheartedly supported. So I think we have some work to do to get through those points. But as I mentioned in the remarks, it is that line, and there is some other associated work. So I think at this kind of preliminary stage, I see it as probably something that is on the order of 20% of our current capital plan.

But, again, that is 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.

Robert Sean Trauschke: Yes, Aditya, this is Sean. Just one other point. You know, the routing is still to be determined, and the direct routing of that line. So this will all get flushed out, and we will certainly disclose that later in the year. Understood. That is helpful. Thank you. And then I also wanted to touch on the data center contract that you are finalizing. Can you just remind us, for this one gigawatt, do you intend to meet

Aditya Gandhi: those capacity needs through the RFP process that you are running right now as well as generation that is already in your plan? And then maybe can you just speak to some customer protections that you are building into that large load tariff framework?

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

Aditya Gandhi: Great. Thank you for taking my questions.

Operator: Thank you. And one moment for the next question. Our next question is coming from the line of Chris Hark of Mizuho. Your line is open.

Chris Hark: Good morning, everybody. This is Chris on for Anthony. How are you? Good morning. Good morning. Morning. My question is pretty similar to the ones, 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?

Charles B. Walworth: So, Chris, we do not have a whole lot of detail broken down in our filing. But what I can tell you is that Customer X really does not come on this year. Right? So that is a little bit further out than this year. So that is not driving the 4% to 6%. Other, you know, the key areas—obviously we look at the residential—is definitely a bellwether class, and we see that as definitely 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.

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

Robert Sean Trauschke: Great question. So we certainly have a governor’s race, an attorney general’s race, and then we certainly have a Corporation Commissioner race. We have been involved and spoken to all the candidates. I think all the candidates for each one of those races would be constructive and we would be comfortable with, and we know them. And so I think essentially those races will be determined, I would expect, in the June primary, and we will probably have a good idea of who the governor and the attorney general and the Corporation Commissioner are going to be in June.

Chris Hark: Thank you. That is it for me. Congrats on the year.

Robert Sean Trauschke: Hey. Have a great day. Thank you.

Chris Hark: You too. Bye.

Operator: Thank you. As a reminder, if you would like to ask a question, please press 11 on your telephone. And one moment for the next question. Next question is coming from the line of Nicholas Campanella of Barclays. Your line is open.

Michael Brown: This is Michael Brown on for Nicholas Campanella. So the question is, recently, iRunner 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?

Charles B. Walworth: So we have 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 flavor of the type of customers we have 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 have not included any of those at this time. So, really, you are looking at that 1.9. Recall that last year, we were solving for 2030 capacity needs.

And the way our IRP works is we have a five-year action plan, so we have essentially just shifted that out one year. And when you look at the impact of shifting it out one 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 is 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.

Michael Brown: Okay. Thank you.

Robert Sean Trauschke: 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 does this customer need, whether it is permitting or water permitting, to properly move forward with the FFA? 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 are certainly involved in that process, engaged in that dialogue, and we will stay focused on it to make sure that there is adequate protection for the existing customers.

In terms of Customer X, what things they need to do to move forward, I think the gating item, quite frankly, is just finalizing our agreement. We are in pretty good shape. Actually, I just have one more.

Michael Brown: Okay. With your rate base,

Robert Sean Trauschke: I just have one more question, Patrick. I am sorry. Okay. With your base CAGR already at 9% and dilution at roughly 0.75%, and coupled with the upside CapEx, I am curious as to why your growth is better than 6.5%. Yes. I think good question. And so what we have tried 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—those are the assumptions—we put forward to you today.

What we have highlighted is when we receive the final clarification and the total numbers around the ITP projects at the SPP, we will layer that in and tell you how we are going to finance it. When we receive approval for all of the generation that is coming out of these RFPs, we will show you what that is, the timeline, and how we are going to finance it and the earnings impact. So that is how we are doing that. We will layer these in, and, obviously, that will have an impact on earnings.

Michael Brown: Okay. Thank you. I really appreciate that.

Charles B. Walworth: Thank you. My question.

Operator: Thank you. One moment for the next question. And the next question is coming from the line of Stephen D’Ambrisi of RBC Capital Markets. Your line is open.

Stephen D’Ambrisi: Hey, Sean. Hey, Chuck. Thanks for taking my question.

Robert Sean Trauschke: Hey, Steve. Good morning.

Stephen D’Ambrisi: Good morning. I dialed in as Steve this time, so I did not get a Stephanie. Hi. I noticed that. We were not going to say anything. I figured I would 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—you know, there are people in your service territory, it seems like, who are talking about having power secured. And just so, can you talk about what the timeline is, or what it looks like, when you will go to update the street on potential other customers other than Customer X, for example?

Because it just feels like there is load out there that is substantial relative to your peak and that you may have to build for, and, you know, just want to try and understand how we have to feather that in over time.

Robert Sean Trauschke: Yes. I mean, to put it in perspective, in our remarks, we said by the end of the decade, we will add 2.3 gigawatts, and then the IRP is calling for another 1.9. So it is pretty substantial.

Stephen D’Ambrisi: I

Robert Sean Trauschke: think what is going to happen is these large load customers, as they materialize and we have line of sight to the finish line, we are going to announce it, and just like we did with Customer X here to give you some timeline. But, you know, 1.9 gigawatts is a lot to have in by the 2031, 2032.

Stephen D’Ambrisi: Yes.

Stephen D’Ambrisi: Totally understand. Not saying there is not a lot, but it seems like there is even more.

Stephen D’Ambrisi: Oh, I think, you know, and, you know, you have to draw the line somewhere, Steve.

Robert Sean Trauschke: And we are 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 are out there, and we are working hard to secure them.

Stephen D’Ambrisi: Understood. I appreciate it. Thanks, Sean.

Robert Sean Trauschke: Thanks, Steve. See you.

Chris Hark: Thank you. And that concludes today’s Q&A session. I would like to

Operator: turn the call back over to Robert Sean Trauschke. Please go ahead.

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

Operator: This concludes today’s programming. Thank you so much. You have a great day. You may now disconnect.

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OGE Energy (OGE) Q4 2025 Earnings Call Transcript was originally published by The Motley Fool