Evergy, Inc. (NASDAQ:EVRG) Q3 2025 Earnings Call Transcript

Evergy, Inc. (NASDAQ:EVRG) Q3 2025 Earnings Call Transcript November 6, 2025

Evergy, Inc. misses on earnings expectations. Reported EPS is $2.03 EPS, expectations were $2.14.

Operator: Good morning, and welcome to Evergy’s Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to Peter Flynn, Senior Director of Investor Relations and Insurance. Please go ahead.

Peter Flynn: Thank you, Haley, and good morning, everyone. Welcome to Evergy’s Third Quarter 2025 Earnings Conference Call. Our webcast slides and supplemental financial information are available on our Investor Relations website at investors.evergy.com. Today’s discussion will include forward-looking information. Slide 2 and the disclosures in our SEC filings contain a list of some of the factors that could cause future results to differ materially from our expectations. They also include additional information on our non-GAAP financial measures. Joining us on today’s call are David Campbell, Chairman and Chief Executive Officer; and Bryan Buckler, Executive Vice President and Chief Financial Officer. We will cover third quarter highlights and provide updates on economic development activities and our regulatory agenda.

Bryan will cover our third quarter results, retail sales trends and our financial outlook. Other members of management are with us and will be available during the Q&A portion of the call. I’ll now turn the call over to David.

David Campbell: Thanks, Pete, and good morning, everyone. I will begin on Slide 5. This morning, we reported third quarter adjusted earnings of $2.03 per share compared to $2.02 per share a year ago. The increase over last year was driven by a recovery of regulated investments and growth in weather-normalized demand, partially offset by higher interest and depreciation expense and dilution from convertible debt. Our year-to-date adjusted earnings are $3.41 per share compared to $3.46 per share a year ago. With these results year-to-date, we are narrowing our 2025 adjusted EPS guidance range to $3.92 to $4.02 per share from our original 2025 adjusted EPS guidance range of $3.92 to $4.12 per share. The lower midpoint is primarily due to weather headwinds from below normal cooling degree days in the second and third quarters, which negatively impacted our results by $0.13 per share.

I would like to compliment the team for implementing mitigating actions across the business, offsetting more than half of the weather headwinds. However, we have not been able to offset the full magnitude in what has otherwise been a strong year of regulatory and operational execution while advancing our strategic objectives. Our fundamental long-term outlook remains very strong, bolstered by tailwinds from a generational economic development opportunity and the investment needed to enable it. Bryan will discuss the quarterly drivers and our earnings outlook in more detail in his remarks. We’ve achieved strong operational and reliability performance through September. Year-to-date, our generation availability as measured by the forced outage rate as well as our overall grid reliability as measured by SAIDI are both favorable to target.

These results demonstrate the benefits of our continued infrastructure investments and the hard work of our operations teams. I’d also like to recognize Wolf Creek as it nears completion of our 27th refueling outage with strong safety and overall performance. Wolf Creek generates around 1,200 megawatts of non-carbon-emitting energy enough to power more than 800,000 homes. I’d like to thank everyone on our nuclear team for their hard work and focus on sustaining the excellent operational performance of the plant. I’m happy to announce a 4% increase in our quarterly dividend or $2.78 per share on an annualized basis. This increase is consistent with our updated growth outlook and working toward the midpoint of our 60% to 70% target payout ratio.

Looking ahead, we will provide a comprehensive financial outlook update on our year-end call in February. We will include refreshed views on our load forecast based on large customer impacts, our 5-year capital investment plan, the related financing plan and our long-term adjusted EPS growth outlook. The 5-year capital plan will incorporate expected generation investments to serve load and meet SVP’s increasing reserve margin requirements as well as transmission and distribution projects to support reliability. As Bryan will discuss with respect to the long-term update, we believe there are noteworthy tailwinds to our earnings power as we advance our plans to support growth and economic development that will benefit our Kansas and Missouri customers and communities.

Slide 6 outlines our economic development pipeline and opportunities over 15 gigawatts, which relative to our size, represents one of the most robust backlogs in the country. Reflecting the geographic advantages of our region, the overall pipeline is strong in both Kansas and Missouri, and we are well positioned to continue to attract new businesses. Large customer interest in the Evergy service territory remains very strong. Focusing on the top 3 categories of the pipeline, we outlined a 4 to 6 gigawatt opportunity of large new customer load that represents the most active part of our queue. This Tier 1 demand represents a transformative 10-year growth opportunity for Evergy. When executed, we expect these projects will deliver significant regional benefits across our states, supporting a leading -edge digital economy, creating jobs and expanding the tax base while enabling us to spread system costs over more megawatt hours, helping to maintain affordability for all customers.

We continue to work closely with Tier 1 large load to develop and implement transmission and distribution solutions to serve their expected ramp rates over the coming year. We are confident that we will be successful in winning and serving a large portion of this queue, which would in turn transform the size and growth of our company and enhance the economic prosperity of our region. The remaining pipeline totaling well over 10 additional gigawatts highlights the robust activity and sustained interest in Kansas and Missouri. Many customers have already secured land or land rights, finalized site plans and are actively participating in capacity studies. While not all of this load will ultimately be addressable, the ongoing dialogue underscores the depth of engagement and the readiness of customers to step in should others exit the queue.

Slide 7 expands upon the 4 to 6 gigawatt Tier 1 large customer load opportunity. Beginning with the actively building category, I’m happy to report that last week, Lambda announced its plan to transform an unoccupied data center located in Kansas City, Missouri into a state-of-the-art AI factory and data center. Their facility is expected to launch in early 2026 with 24 megawatts of capacity and has a potential to scale up to more than 100 gigawatts — 100 megawatts, excuse me, in the future. This project is a great example of a data center leveraging existing infrastructure with an ability to ramp load relatively quickly with minimal grid investment required and exemplifies why Missouri is an attractive destination for projects of all sizes.

For the balance of our actively building customers, Panasonic and Meta are up and running, and our third large customer is making good progress through its heavy construction phase. Inclusive of Lambda, we now anticipate peak demand of 1.2 gigawatts from these customers with over 500 megawatts online by 2029, supporting our demand growth forecast of 2% to 3%. Moving to the finalizing agreements category, we remain in the final stages of negotiation with large customers for 2 data center projects. Subject to final agreements and project announcements, we expect to see an impact on our demand growth from these customers in 2027 and ’28 and into the next decade, which would raise the overall company demand forecast to 4% to 5% load growth through 2029.

Approval of the LLPS tariffs in both states is a key next step for finalizing these negotiations. Additionally, we recently added a third data center to this category, reflecting significant progress and initial executed agreements. This project was previously in our advanced discussions category and demonstrates the high interest from large customers in advancing their projects. We also remain in advanced discussions with multiple customers whose load would represent approximately 2 to 3 additional gigawatts of peak demand. These customers have secured land and land rights, shared site plans and in some cases, reached letters of agreement and provided financial commitments to move the evaluation forward. Load from these customers is not contemplated in our upside view of 4% to 5% annual load growth and therefore, would be incremental.

Overall, we continue to see an incredible level of interest in our service territories, and we’re making progress with potential new large customers across all stages of discussion. Each category reflects potential new entrants that will empower growth, investment and drive prosperity for our region. Now moving to Slide 8, I’ll touch on our latest regulatory developments. 2025, as you know, has been a busy year for our regulatory team, and we’ve demonstrated considerable progress in advancing our strategic objectives. The team’s results this year reflect the constructive policy framework and economic development opportunities in both states as well as our ability to find alignment with broad groups of stakeholders and achieve constructive settlement agreements.

Beginning with Kansas, we filed for and received approval of predetermination to own partial shares of 2 new combined cycle natural gas units and a solar farm, both — are all at Kansas Central. These projects were identified in our IRP preferred plan and reflect our all-of-the-above approach to meeting growing customer demand and higher capacity margin requirements in the SPP. The Kansas Corporation Commission issued an order approving a unanimous settlement agreement for Kansas Central rate case on September 25. The settlement achieved a balanced outcome for all parties, including adequate recovery for the investments needed to provide reliable and affordable electric service. A key open agenda item in Kansas is the unanimous settlement agreement we filed on our large load power service tariff docket on August 18.

The proposed tariff applies to customers with demand exceeding 75 megawatts and establishes a rate structure with a focus on large customers paying their fair share and being subject to additional protections that I’ll describe later in my remarks. We believe the LLPS establishes a competitive rate and positions Evergy to attract and serve large new loads, enabling growth and prosperity for our communities. We anticipate an order from the KCC on the settlement agreement as part of the commission’s business meeting later today. Pivoting to Missouri, we’ve successfully advanced plans to construct new generating resources. The MPSC approved settlement agreements in our CCN applications for 2 solar farms, partial ownership in 2 combined cycle natural gas units and full ownership of a simple cycle natural gas plant.

We believe these projects form a cost-effective package of reliable energy solutions for our customers, and this outcome demonstrates alignment with the Public Service Commission’s interest in securing additional generation resources for our Missouri utilities. Similar to Kansas, the large load power service tariff proceeding continues to advance in Missouri. Parties filed a nonunanimous settlement agreement earlier this fall with terms similar to those filed in Kansas, including contractual protections, provisions to ensure that large customers pay their fair share of system costs and a competitive rate that supports economic development. We anticipate an order from the MPSC by the end of the year. Last, the planning process for our upcoming Missouri Metro rate case is underway, and we expect to file the case in February 2026.

Slide 9 highlights legislation and regulatory mechanisms that support growth in our region and help to position Kansas and Missouri as premier destinations for infrastructure investment to ensure reliability and new advanced manufacturing facilities, data centers and other large customers. These mechanisms are the product of broad-based alignment between Evergy, the governor’s office, state legislators, our regulatory commissions and key stakeholders as well as our shared commitment to seize on the growth opportunities ahead of us for our customers and communities. Constructive regulatory frameworks that enable timely infrastructure investment to meet the needs of both existing and new customers are critical to our success and the bills passed over the past 2 years in both states advance these priorities.

This supportive landscape reinforces our region’s position as a top destination for growth. Evergy is committed to delivering safe, affordable and reliable service to our 1.7 million customers. As large new customers join our system, all stakeholders benefit from broader cost sharing and unprecedented economic development. I’ll conclude my remarks on Slide 10, which highlights the core tenets of our strategy. I’ll focus specifically on affordability. Since the merger that created Evergy, we have achieved tremendous progress on affordability and regional rate competitiveness, driven by significant reductions to our cost structure and investing at a slower pace than peer utilities. Over that time, our rate trajectory has remained well below regional peers and far below inflation.

This required hard decisions and the full focus and dedication of everyone in our company. I’m very proud of the results that these activities enable us to deliver for all of our customers. It is critical that we sustain this momentum as we enter a new era of growth and demand and economic development. This new era will require the same level of dedication and focus from our company, and that’s exactly what we intend to deliver. As part of that focus, we will continue to invest in infrastructure and operate our business in a way that maintains reliability and benefits all of our communities. Higher levels of investment to serve new large customers must be fairly borne by those customers, and we designed our large load power service tariffs to do exactly that.

Under the proposed LLPS tariff, new large customers will pay a higher rate than that paid by our existing large customers. As a result, the revenues from new customers will directly mitigate future rate increases for our existing customers as we are able to spread the fixed cost of our system over a broader base. In short, new large customers will pay a reasonable premium to the cost to serve them while also maintaining a competitive rate. And all customers will benefit from a modernized grid and new highly efficient generation resources. The tariffs are also designed with key safeguards in place. These include, among others, customer commitments of 12- to 17-year terms, an 80% minimum monthly bill requirement, exit fees upon early termination and collateral posting.

It’s important to note this tariff structure is consistent with the intent of our large new customers to be good stewards as part of our Kansas and Missouri communities. In the LLPS dockets, they were active participants throughout the process and along with many other stakeholders, contributed to and signed on to the settlement agreement. As I noted earlier, these agreements are currently pending approval by the Kansas Corporation Commission and Missouri Public Service Commission with the KCC’s decision expected later today. Collaboration with large customers does not stop at paying their fair share. Their projects will create construction jobs, permanent jobs and expanded property tax base and community development benefits. As an example, one of our customers announced it will bring its Skilled Trades and Readiness or STAR program to the Kansas City area.

The company is collaborating with Missouri Works Initiative and the Urban League to help increase the entry-level pipeline in the skilled trades with a focus on underrepresented communities. All STAR preemployment programs are paid training programs and offer networking opportunities to help participants move directly into employment on local construction projects. We hope and expect that this example will be just one of many. The vitality of our region has made it an attractive destination for advanced manufacturing and data center customers and their investments in turn have tremendous potential to drive a virtuous cycle of growth and prosperity in Kansas and Missouri for years to come. I will now turn the call over to Bryan.

W. Buckler: Thank you, David. Thank you, Pete, and good morning, everyone. Let’s begin on Slide 12 with a review of our results for the quarter. For the third quarter of 2025, Evergy delivered adjusted earnings of $475 million or $2.03 per share compared to $465 million or $2.02 per share in the third quarter of 2024. As shown on the slide from left to right, the year-over-year drivers are as follows: first, a 2% increase in weather-normalized demand growth drove the majority of the increase of $0.06 per share in the margin shown on the slide and recovery of and return on regulated investments contributed an additional $0.11 of EPS. Offsetting these favorable drivers are higher depreciation and interest expense related to our infrastructure investments, leading to a $0.07 decrease in EPS and dilution from our convertible notes led to a $0.03 decrease for the quarter.

Turning to Slide 13, I’ll provide more detail on our sales trends. On the left-hand side of the page, you’ll see weather-normalized demand increased by 2% in the third quarter as compared to last year, following the 1.4% year-over-year increase we experienced in the second quarter. This continued strong momentum was driven by increases in both residential and commercial usage, including load from the Meta data center in Missouri that is reflected in our commercial customer class. At a macro level, the continued robust customer demand in our service areas is supported by a strong labor market as the Missouri, Kansas and Kansas City Metro area unemployment rates remain below the national average of 4.3%. Moving to Slide 14, I’ll provide some further detail on our expectations for full year 2025 results.

As David mentioned, we are narrowing our guidance range to $3.92 to $4.02 as compared to the original guidance range of $3.92 to $4.12. Our mitigation efforts of approximately $0.10 of EPS benefit are expected to offset a substantial portion of the $0.13 of headwinds experienced by below normal cooling degree days in the second and third quarters. In addition, we now anticipate an incremental $0.02 of dilution related to our convertible notes given our recent strong stock performance. We have forecasted incremental dilution from the convertible notes in our 2026 EPS modeling and continue to expect to achieve the top half of 4% to 6% growth in EPS in 2026 off of the midpoint of our 2025 original guidance range. As I’ll discuss shortly, Evergy’s fundamental long-term outlook remains stronger than it has been in decades, bolstered by tailwinds from a generational economic development opportunity and the investment needed to enable it, which will benefit all future years in our financial plan.

Slide 15 outlines a recap of our long-term financial expectations and considerations for our comprehensive growth update we will share with you during our fourth quarter call in February. First, we highlight our Tier 1 customer opportunity of 4 to 6 gigawatts of peak load. As a reminder, our current 5-year plan incorporates load growth of 2% to 3% annually through 2029, reflecting solid growth in our current customer base and buoyed by the Panasonic, Meta and Google projects. This load growth expectation is further bolstered by rapid development data centers such as the Lambda facility discussed by David earlier, which is able to scale more quickly than the mega data centers via their use of existing buildings and existing electric infrastructure.

Also, we are nearing final agreements with 2 data center customers that could drive an incremental 600 megawatts by 2029, which would raise our load growth forecast substantially to 4% to 5% on a CAGR basis through 2029. We’ve also made great progress with customers in the advanced discussions category, which represents a 2 to 3 gigawatt opportunity, driving even more load growth toward the back half of our 5-year plan. We certainly believe we have one of the most compelling customer growth opportunities in the entire industry that we expect will drive robust growth, not just in our 5-year forecast, but into the next decade for Evergy and for the communities we serve. Next, I’ll discuss our capital expenditure and rate base growth forecast.

The foundational earnings power of the company will be fortified by our capital investment program. Higher levels of infrastructure investment are needed for grid modernization and incremental generation capacity to support the expansion of our existing customer base and new large load customers. These are tailwinds to our current $17.5 billion capital plan and corresponding to 8.5% rate base growth through 2029. On the regulatory front, to maintain the credit profile of our utilities and to incorporate the affordability benefits of large loads, which allow us to spread system costs over a broader base, we plan to be on a somewhat regular cadence of rate case proceedings. With a large infrastructure plan comes regulatory lag. And over the past couple of years, the states in which we operate have taken proactive steps to help utilities better manage elevated depreciation and interest expense through the use of plant and service accounting mechanisms.

We also utilize natural gas CWIP provisions in both Kansas and Missouri. These constructive mechanisms help to reinforce our solid credit profile. During this phase of significant infrastructure build-out, we will utilize equity and equity content financing options to fund a portion of our capital requirements and to support our strong investment-grade credit rating and FFO to debt threshold of 14%. It is important for you all to know that we will continually evaluate the overall level of equity funding needs, recognizing that large load customers in our pipeline could significantly improve our cash flows from operations, beginning in 2026 and accelerating throughout the next several years. Thus, there is a real opportunity to moderate our equity needs for the current $17.5 billion capital investment plan.

Now our company can only be successful when our communities thrive and we maintain affordability for our customers. We are committed to staying laser-focused throughout the years ahead on affordability for our current customers, and we believe our long-term plan will be successful in doing so. As we look to rolling out our updated 5-year plan in February, I’ll mention again the many tailwinds to our current adjusted EPS growth outlook and the transformational opportunity for us here at Evergy. We’re excited for what’s to come and look forward to sharing details with you on our year-end call. And with that, we will open up the call for your questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Paul Zimbardo from Jefferies.

Paul Zimbardo: The first one I wanted to touch on just as we think about 2026 in Missouri legislative session, obviously, there’s been a lot of progress in recent years for all the different flavors of utilities. Do you have any priorities or anticipate efforts for 2026? And could this influence the rate case cadence?

David Campbell: Paul, we were pleased to work closely with many stakeholders last year in Missouri. It had a list, obviously, the Commission Chair Hahn, the governor’s office. legislative leadership of the utilities and key stakeholders. So there’s a lot of progress made in SB4. A lot of next year will be around implementing and following through on the elements of SB4 related rulemakings. So I don’t anticipate there’s — I always talk with the team, we always talk with the team about ways that we continue to advance constructive mechanisms. But after such a busy year and such consequential legislation last year, I think it might be a little lighter calendar in 2026. But important steps to undertake to advance forward on the constructive mechanisms on SB4.

Paul Zimbardo: Okay. Understood. And then obviously, you’ve got the big refresh coming ahead. Just maybe a little bit of a sneak peek, not so much on the numbers, but even just the cadence in the current plan, it’s slower upfront and then accelerates. With whatever — to the extent you do change the growth rate, should we think about that as kind of a linear profile or also accelerating as you move towards the end of the decade?

David Campbell: Gosh, Paul, it’s hard to answer that question without getting into what will be in our year-end update. So I think that Bryan did a nice job of describing the multiple tailwinds that are — make us so excited about the prospects for growth in our region and all that’s going to bring for our customers and communities, and that’s both the load growth element, the investments needed to make sure that we can serve that load and meet SPP’s higher reserve market requirements and beneficial impacts it can have in the financing plan. So the — our prior capital plan, we laid that out by year. We’ll lay it out by year in our upcoming capital plan. There’s obviously a significant amount of investment. You can see what that is by year, but there’s also loan growth that helps to mitigate any regulatory lag.

So we’re really excited about the tailwinds around it, and I won’t get ahead around the profile. I think Bryan did describe for 2026 itself. We got — we’re reaffirming our confidence being in the top half of the range of ’26, and then we’ll be talking about the — how those tailwinds manifest themselves in upgdeddated set of — an updated financial plan that we’ll outline in the year-end call.

Paul Zimbardo: Okay. I understand. I had to try.

David Campbell: We’re excited, Paul, as you know, because we’re excited because of the benefits it’s going to bring to our region, our customers and communities, and it’s a comprehensive set of factors that are driving that excitement.

Operator: Our next question comes from the line of Travis Miller from Morningstar.

Travis Miller: It seems like Kansas and Missouri have been working pretty well together here over the last few years. I was wondering within your service territory, how much competition is there at the local level in terms of attracting some of these large loads? I got to think just the way all states work that there might be some competition here, either legislatively, politically, local to try to get some of this economic development. Is that happening?

David Campbell: That’s a great question. And as a person, I’m now nearly 5 years in this region. And I’ve been very impressed. And of course, our service territory extends over to Central Kansas and Wichita. So we’re — it’s much broader than just the Kansas City area, and there are parts of the states that are more distant from the state line. But to ask the question narrowly about our region, I’m Vice Chair of a group called the Kansas City Area Development Council. It represents counties on both sides of the state line extending all the way from Topeka to Kansas City and Eastward to North and South. So it’s — and it’s a collaborative approach. There’s actually been legislative truths in the past to mitigate potential poaching of that might go on across state lines.

So they really do a nice job of collaborating the — in the great state of Texas, I live 250 miles from many state lines, and I was reasonably close to them. Here, I’m quarter mile from the state line, and it’s the collaboration that happens when you’ve got that kind of seamless integration, I’ve been very impressed to see. I’ve got an older brother. There are times when within a family, you might have dynamics, and that can happen. But in general, the teamwork is strong and the collaboration is high.

Travis Miller: Okay. We’ll hear more family stories later on.

David Campbell: Indeed, — they often involve.

Travis Miller: Yes. And then other question. In terms of that $17.5 billion CapEx, assuming that you get the large load tariff there, you’ve got — you’ll have that, you’ll have the PISA, the CWIP. How much of that $17.5 billion would actually be subject to a typical rate case filing, right? Essentially, how much of that can you recover without going through a regular rate case, as you call it, the cadence of base rate cases?

David Campbell: Yes. So there’s — ultimately, all of our investments are subject to reviews to make sure they’re prudent and reasonable. There’s a set of different mechanisms that help to mitigate the cash regulatory lag. With PISA in both states that mitigates the earnings lag, but we’ve got riders in place in both states. all from property taxes to pension to other elements. And the CWIP will help with our new natural gas plants. We lay out the different parts of our capital plan in the appendix. So the new generation component is shown, I think it’s on Slide 21. So that could give you a good measure for what — which pieces of the capital plan. are in the more traditional category versus what’s in the new generation category.

The CWIP mechanism is slightly different between Kansas and Missouri. But in both states, we were pleased to get that — those provisions introduced. It was in Kansas ’24 and Missouri in ’25, reflecting the support in both states. We’re building new natural gas generation and recognizing that, hey, with the investment programs of that size is important to have some mitigants to lag. So that’s — out of our total capital plan, you’ll see that new generation is about 1/3 and 2/3 is in the traditional categories, grid modernization, ensuring reliability, keeping the lights on and providing great service to our customers.

Travis Miller: Okay. That makes sense. So then the other one, transmission would be obviously FERC so to pull that out. So it would be the 3 buckets of potential base rate would be legacy generation distribution in general.

David Campbell: Yes. And most of our transmission investments in the Kansas side, you’ve got that right.

Operator: Our next question comes from the line of Nicholas Campanella from Barclays.

Nathan Richardson: It’s actually Nathan Richardson on for Nick. I just have a quick one for you. So I was wondering if you could talk a little bit about the third data center you mentioned. And given the 4% to 5% sales growth guidance, I was wondering how impactful that third data center specifically could be in moving the needle for the sales growth.

David Campbell: Nathan, that’s a great question, and I’m glad you asked it. So the — as you know, we’ve included in our financial plan that we provided last year, a 2% to 3% annual load growth, but we have quantified that the 2 customers in the actively building category have potential to raise that annual load growth to 4% to 5%. The addition of the third — I’m sorry, the addition of the third customer, and this is in the finalizing agreements category, even I’m mixing up the categories. So the 2% to 3% load growth is from the actively building category. The potential to go to 4% to 5% is from the first 2 customers in the finalizing agreements category. You’re absolutely right, that third data center customer we’ve now added to the finalizing agreements category would be additive to the 4% to 5% as with the customers in the advanced discussions category. So thank you for that clarification.

Nathan Richardson: Is there any quantification there or just that is incremental?

David Campbell: No. The bulk of that, we expect would be post 2029, but we’ve not quantified it, but that will be part of our — obviously updated the year-end call what the overall view is on load growth tailwinds. We added it to the category of finalizing given just the sheer amount of progress we’ve made with that customer in terms of advancing discussions and advancing agreements and agreements related to those. So it made sense to include in that category. We’ve not quantified the incremental amount, but we’ve just noted that it’s — those additional customers beyond the 2 that are in the finalizing agreements category would actually be additive to the 4% to 5% annual load growth potential.

Operator: Our next question comes from the line of Steve D’Ambrisi from RBC Capital Markets.

Stephen D’Ambrisi: Yes, I just had a quick one on the LLPS tariff discussions. Given you guys have a settlement, I know it’s not unanimous, but can you just talk about like effectively at a high level, what’s left there, what the main sticking points are? And what you think kind of the time line for resolution around some of this stuff is? I’m pretty sure there’s a settlement conferences coming up and then expected time line is the end of February, but just want to hear about that and then how that works into kind of moving some of these finalizing agreement buckets into the actively building bucket or signing ESAs associated with it.

David Campbell: You bet. I’m glad you asked the question because I’ll clarify because I think you may be thinking about the time line that’s occurring on a different side of the state. in Missouri. So for us, we have 2 LLPS proceedings. One is in Kansas. We have a unanimous settlement agreement that we signed in Kansas, and there’s already been briefing on that. And it’s actually — we expect a decision on that by the Kansas Corporation Commission later today. It’s on the docket for today. So given that they’ve already had a hearing on that unanimous settlement agreement, we actually anticipate a decision in Kansas later today. And that was a unanimous settlement agreement covering all issues, including all parties. In our Missouri LLPS proceeding, we did have a partial settlement.

We have gone through a hearing. Not all parties were alignment on it. The structure of the settlement that included many parties, but not all, has terms that are very similar to the ones in Kansas. So it has protections. It has a rate that is higher for the LLPS customers. And it’s a structure that ultimately like as we saw in Kansas was a result of robust dialogue and included the large customers. So I think it’s a competitive rate as well. We think it aligns with the governor’s policy in the state and support for growth and development and with the commission’s overall focus on that. But we’ll have a decision on that we expect by the end of the year in our case. There are other proceedings in Missouri for other utilities that are a little behind ours.

We filed that first. So hopefully, that makes sense with respect to the different context in Kansas.

Stephen D’Ambrisi: That’s helpful. And so basically, the comment on the slide that talks about announcements expected after LLPS tariffs are finalized to the extent the facilities are in Kansas, that could be freed up as early as tomorrow, and then we’ll see when Missouri gets done hopefully by the end of the year. Is that — those are the kind of the gating items from a time line perspective?

David Campbell: I like your thinking. I’ve got some team members in the room now, and I’ll tell them they need to be — no, I’ll kidding aside. Yes, I think the LLPS being signed is a very important enabling step. So that’s — and we do hope — Kansas has always been a little bit ahead schedule-wise, but Missouri is not far behind. So we think that the time line sets us up well for what we know is going to be an important update in the year-end call. And it’s important for these customers as well. The queue is a very active one. Folks are eager to come online. A big chunk of why we have a such a big queue is because we’ve got customers lined up for any reason, and we don’t see those reasons happening. There’s tremendous interest in the customers who are interactively building and finalized agreements with the category, a lot of momentum, but we’ve got folks lined up behind them.

So we believe that the LLPS decisions being on the time line they are should enable us to move on the time line we’re hoping to achieve.

Operator: Our next question comes from the line of Paul Patterson from Glenrock Associates.

Paul Patterson: Just on the financing plan and the $2.8 billion, and I see the forward — we obviously have the forward and what have you. But I’m just wondering how we should think about this? I mean, you’re also mentioning, obviously, the potential for what you guys mentioned earlier about the cash coming from these potential new agreements being finalized. How should we — if you could just sort of quantify like how that — how much that you think that would impact the $2.8 billion and the sort of timing or if you could just elaborate a little bit more on how we should think about the finalizing of those agreements and what have you.

W. Buckler: Paul, it’s Bryan. Thanks for the question. As a reminder for everyone, our current capital investment plan 5 years is $17.5 billion. In total, we believe that will be funded in part by up to $2.8 billion of equity and equity content capital market instruments such as JSN’s Junior Subordinated Notes. I do think it’s important for you to know that we’ll continually evaluate the overall level of equity funding needed, recognizing that, as you say, that energy usage from customers in our pipeline could significantly improve our cash flows from operations beginning in earnest in 2026 and then accelerating throughout the next several years. Thus, there’s a real opportunity to bring that level of equity down by what I’ve said before, hundreds of millions of dollars.

I should also mention that we continue to see upside bias in our capital investment needs to serve our existing and expected new customers in the year ahead, which will also necessitate a somewhat balanced approach to debt and equity financing. Does that help?

Paul Patterson: Yes, that does. I mean — but just to sort of clarify, so that would be something that would obviously have — require more capital needs and therefore, might be an offset to some of this cash flow that you’d be seeing as well. Is that how we should think about it?

W. Buckler: Yes, that’s the way to think of it for modeling for sure.

Paul Patterson: Okay. And I guess we’ll get more clarity, obviously, as time goes on. But — and then I guess I wanted to — on the $0.10 of mitigation measures that you guys had, with respect to the earnings. How should we think about those mitigation measures going forward? Do those — are those a timing issue and they’ll show up next year? Or are those things that you found that you think are more ongoing or some mixture of the 2?

David Campbell: Paul, I’ll describe those. Those are in-year mitigation measures. So obviously, we are — the size of the weather headwinds and a little bit of incremental headwind from the convert was — we would hope that we could offset all of it, but we were able to offset $0.10 of it, but that’s really in-year mitigation measures. It doesn’t impact our fundamental long-term outlook. I’ve now been — this is my fifth year at the company. There are 2 years where we had really warm weather and adjust the range upwards didn’t change our long-term fundamentals. This is a year where we have weather headwinds, so it’s going to impact our performance of this year, but it’s — both the weather impacts and the mitigation measures are really within the context of this calendar year. The drivers for our fundamental plan, as Bryan mentioned, our view on 2026 and then the drivers for our long-term plan remains intact and sort of unaffected by the vagaries of weather.

Paul Patterson: Okay. And then with respect to the Lambda deal, which would seem sort of interesting here. I’m just wondering, would that — I guess, first of all, when would it go — at what time frame would it go from 25 to the 100? I guess 25, it sounds like it would — the 25 megawatts would be beginning of next year, but then it goes to 100. I’m just wondering how long does that ramp-up take? I’m just curious. Or is it known?

David Campbell: Yes. We — as I described, it’s the in the 25-megawatt range starting next year, and it’s probably in the next 4 to 5 years that it gets to that potential overall size. Really excited about that project, new company deploying advanced technology in their data center and AI factory as they describe it. So it’s — we are pleased to see that announcement. It was tied well with some economic development meetings here in town and reflects how attractive our region is and really impressed by how they leverage an existing building, an existing T&D infrastructure largely, and that’s how they were able to ramp up to that level. Historically, a 25-megawatt customer would be considered very large. Now in the new era, it is a new era. But it’s still obviously a creative approach, and we’re pleased to have an advanced facility like that taking advantage of a building like that.

Paul Patterson: Right. That sounds kind of unique. I guess what I also wondered was like in terms of the context of these large load tariffs that you were describing, since it’s under 75 megawatts and then going to 100 megawatts, would a scenario like that be subject to — obviously, it’s hypothetical as and all they approved. But I’m just wondering how in the context of these settlements that you’ve had with these large load tariffs, how would a customer like that be treated? Would that be a large load since it came in initially below the 75 megawatts, but would go to the 700 megawatts, do you follow what I’m saying? Or would it be because the final number is 100, it would be a large load. Does that make sense?

David Campbell: Yes. Typically, these customers are focused on what their ultimate load level is going to be because they want to make sure that they’ve got the infrastructure and capacity to get there. And this is an example. So the tariff addresses as you ramp up getting up to those higher levels. And again, these customers, the ones that go into the large loads definitely want to make sure they’ve got the capacity and ability to do this, and they know and are contemplating getting up to the LLPS. If ultimately stay in the 25-megawatt range, you need a different tariff level. But the ones that — these customers are very interested in those higher levels of loads, and they know that as they get there, they get to that tariff rate.

Paul Patterson: Right. So it’s what they ultimately get to, would it be 1 of these like — okay I got it, I understand.

Operator: Our next question comes from the line of Anthony Crowdell from Mizuho.

Anthony Crowdell: If I could follow up, I think, on Steve’s question earlier. On Slide 7, is the actively building category, is that what’s currently in the 4% to 6% EPS growth rate and the finalizing advanced discussion is what’s not included in the current growth rate?

David Campbell: Yes, the actively building — that was probably my fault for how I answered it earlier. So if you look at Slide 7, a good place to go. The actively building, which is Panasonic and Meta and the third customer is in the heavy nearing completion of construction, that’s in the 2% to 3% load growth rate. And that’s…

Anthony Crowdell: And in the 4% to 6%, right?

David Campbell: No, the 4% to 6%, you get to if you include the 2 data center customers that are in the finalizing agreements category. This is the annual load growth rate. You’re talking about — if you’re talking about the earnings growth rate of 4% to 6% — sorry. The earnings growth rate of 4% to 6% that we said we’re targeting the top half and then we’re going to update on the year-end call. That is reflected in the 2 that are in the actively building category.

Anthony Crowdell: Great. Just the 2, not the third?

David Campbell: Correct.

Anthony Crowdell: Great. And then I think when I look at your spread between your rate base growth and your earnings CAGR, it’s roughly about 250 basis points. Is that a good spread going forward or the adoption of the large load tariff or the additional load, if you expect that to change, where is a good place to think where that settles out?

David Campbell: Yes. So we haven’t given guidance on that specific range. But I think if you look at our — the $17.5 billion capital plan going back in time, there were higher levels of capital in the out years in that plan. We know that we will be presenting as part of the year-end call an integrated financial plan that reflects the relationship between rate base growth, incremental load growth is obviously help in reducing regulatory lag and the relationship that you see between that rate base growth and earnings growth. And there’s a range that you see across different companies, and there’s no reason why we would be outside that range, though obviously, links as well to what the phasing is of both the load growth and the capital in the plan.

So we would — we know that that’s a question that we’ll be addressing as part of our year-end update and the load growth and as we move into higher years in our capital plan, that will be reflected in the update that we provide.

Anthony Crowdell: Great. And then just lastly, you talked earlier, I think, in your 5 years there, you’ve seen some big weather swings. I think for 3 of the 5 years this year, very mild weather, you ended up lowering 25. As you work on rolling out a new capital plan with a new load, does the very big swings in weather, will that cause you either to give a wider range or bake in more conservatism in your plan, given you’ve seen how much of a swing weather could be in your yearly performance?

David Campbell: I think it’s a very insightful question. I think it’s something I really like having Bryan and Pete join the team. Bryan worked with a couple of different utilities. I know in my background, I’d like being able to describe to investors here are the factors that we can control, here are the factors that are clearly outside of our control and are readily quantifiable, but recognize that a number of our peer utilities and there’s — like the investors can like to see, hey, you can offset even if it’s something easily track and identifiable like weather, you find mechanisms in your plan or build in an approach in the plan that can offset that. So we’ll continue to have that discussion internally because we recognize that feedback.

We’ll always be very transparent — plan to be very transparent with [indiscernible] because they — as I mentioned, they didn’t impact the fundamentals when they were positive. They’re not going to impact the fundamentals when it’s in year when it’s a little more mild. It’s a very mild August in particular here. But it’s something that we’ll consider, and Bryan will be a real helpful thought partner as we consider what the best approach is there. But again, we’re very excited about the long-term fundamentals. We’re certainly not overreacting to the — was demonstrably a very mild Q2 and Q3, recognizing that we needed to implement the offsets that we did. And we’re certainly always going to strive to be within hitting our targets and hitting our ranges.

So it’s a good question. We’ll continue to think about it.

Operator: Our final question comes from Paul Fremont from Ladenburg.

Paul Fremont: I guess my first question, I just want to get a sense of the type of data center developments that are in your service territory. When the largest of those sort of build out, how many megawatts is that in terms of demand for the largest of your customers right now?

David Campbell: We haven’t given the size by customer, though I suppose you can — if you go back to our last — well, we’ve said it’s 3 customers in the finalizing agreements category are 1.5 to 2 gigawatts. So that gives you a pretty good sense for the average size. That’s a good indicator for us. We haven’t given more specificity in terms of size by customer. But that math will give you a pretty good road map for what the peak size typically is. There’s some variability by customer, of course, but clearly large — 3 large customers making up that 1.5 to 2 gig.

Paul Fremont: Okay. Because — I mean, it does seem like the size is smaller than in some of the neighboring states. And I was just wondering, is there some factor that is causing sort of the size of your facilities to be more modest?

David Campbell: Most of our customers want to expand past their regional peak once up. Some of these projects are similar customers involved. So I don’t think there’s a fundamental dynamic there. And for most of the — we obviously track what the other customer announcements are. And there are a couple of unique large ones out there. But we’re — it’s an average size that is in the 600 to 700 megawatt range is still a very, very large customer and very large data center. And as I noted, the most want to expand past original peak if we’re able to accommodate it, but we like some diversification in customers and sites, which is reflected in a robust queue that helps keep everyone motivated as well.

Paul Fremont: And then at what point would you need to build new generation in terms of, I guess, the 3 categories that you’ve outlined actively building, finalizing and advanced discussions?

David Campbell: So we — that’s a great question. And as we noted, that’s going to be one of the factors that’s a driver for our plan update that we plan to give. Our integrated resource plan that we filed in ’25, and we outlined in the appendix, which projects in the integrated resource plan were in last year’s capital plan, which were not. As we develop that integrated resource plan, we included — because track this information, we had included the 2 customers that were in the finalizing agreements category. You will see in that IRP from last year, a significant amount of incremental generation required to serve that load that was not yet included in the plan. So we have taken steps in terms of long lead time equipment, actions we need to take to be able to serve the customers that we’ve lined up.

So we have some flexibility to do that. But I’d also note that we’re going to be — the next update to our capital plan and our integrated resource plan is going to factor in not only load growth expectations and the plants we need to serve those, SPP’s reserve margin requirements, but also changes in federal and local policies impacting renewables. If renewables are less economic or harder to build, for example, we’ll look at market capacity options. We’ll look at potential retirement delays. We’re going to look at the whole package to make sure that we are driving reliability and affordability for our customers. But at the end of the day, there’s some incremental investments that we expect are going to need to be made. But we’re going to look at that package of things in terms of what’s that right mix of generation and how do we make sure we ensure reliability, take advantage of the growth opportunity, but also always keep an eye on affordability.

Paul Fremont: And last question for me. Taking into consideration all of the legislative and regulatory changes, what estimate would you have for regulatory lag on a go-forward basis in your jurisdictions?

W. Buckler: Yes. Paul, this is Bryan. We haven’t given an exact number for regulatory lag we expect compared to allowed our authorized ROEs in our states. Things we point to is that historically, you’ve seen us earn — have some pretty low ROEs, but the PISA and CWIP legislation certainly help in that regard. We also have loan growth that we haven’t seen in many years, and we think it’s going to be at a level that we haven’t seen in many decades, which will help us kind of bridge that gap and get, we hope, very close to our authorized level of ROE. So that’s directionally what I would give you, and we’ll share more details in February.

Operator: This concludes the question-and-answer session. I would now like to turn it back over to David Campbell for closing remarks.

David Campbell: Thanks, Halen, and thanks, everyone, for joining the call today. We look forward to seeing all of you at EEI this weekend and next week. And that concludes today’s call. Thank you. .

Operator: Thank you for your presentation in today’s conference. This does conclude the program. You may now disconnect.