Evergy, Inc. (NASDAQ: EVRG) Q3 2025 Earnings Call dated Nov. 06, 2025
Corporate Participants:
Peter Flynn — Director of Investor Relations
David Campbell — Chief Executive Officer, President & Chairman of the Board
W. Bryan Buckler — Executive Vice President & Chief Financial Officer
Analysts:
Paul Zimbardo — Analyst
Travis Miller — Analyst
Nathan Richardson — Analyst
Stephen D’Ambrisi — Analyst
Paul Patterson — Analyst
Anthony Crowdell — Analyst
Paul Fremont — Analyst
Presentation:
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 — Director of Investor Relations
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. David 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 — Chief Executive Officer, President & Chairman of the Board
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, which is $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 five-year capital investment plan, the related financing plan, and our long-term adjusted EPS growth outlook.
The five-year capital plan will incorporate expected generation investments to serve load and meet SPP’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, an opportunity that is 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 energy service territory remains very strong.
Focusing on the top three categories of the pipeline, we outline a four- to six-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 years. 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 dialog 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 megawatts 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 to 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 the negotiation with large customers for two 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 2028 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 the 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 for large customers in advancing their project.
We also remain in advanced discussions with multiple customers whose load would represent approximately two to three additional gigawatts of peak demand. These customers have secured land or land rights, shared site plans, and, in some cases, reached letters of agreement and provided financial commitments to move the evaluations forward. Load from these customers is not contemplated, and our upside view of 4% to 5% annual load growth, 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 the 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 two 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 our 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 that 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 MDSC approved settlement agreements in our CCN applications for two solar farms, partial ownership in two 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 non-unanimous 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 on the 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 two 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 with slide 10, which highlight 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 pure 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 in 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 costs 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, there 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 Awareness and Readiness, or STAR, program to the Kansas City area. The company is collaborating with the 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. Bryan Buckler — Executive Vice President & Chief Financial Officer
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 loads 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, 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 five-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 Meta data centers via their use of existing buildings and existing electric infrastructure. Also, we are nearing final agreements with two data center customers that could drive an incremental 600 megawatts by 2029. And 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 five-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 five-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 the 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 five-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.
Questions and Answers:
Operator
Our first question comes from the line of Paul Zimbardo from Jefferies. Your line is now open.
Paul Zimbardo
Hi. Good morning, team. Thank you very much.
W. Bryan Buckler
Morning.
David Campbell
Morning, Paul.
Paul Zimbardo
Thank you for the time. The first one I wanted to touch on, just as we think about 2026 and 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 the many stakeholders last year in Missouri. It had a list, obviously, the commission, Chair Hahn, the Governor’s office, legislative leadership, the utilities, the key stakeholders. So, there’s a lot of progress made in SB 4. A lot of next year will be around implementing and following through on the elements of SB 4-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 SB 4.
Paul Zimbardo
Okay. Understood. Thank you very much. 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 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 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 the beneficial impacts it can have in the financing plan.
So, our prior capital plan, we lay that out by a year in our upcoming capital plan, there’s obviously a significant amount of investment. And you can see what that is by year, but there’s also load 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 that profile.
I think Bryan did describe for 2026 itself we got. We’re reaffirming our confidence being the top half of the range of 26, and then we’ll be talking about how those tailwinds manifest themselves in an updated set of an updated financial plan that we’ll outline here and call.
Paul Zimbardo
Okay. I understand. Thank you. I had to try.
David Campbell
Yep. We’re excited, Paul. As you know, we’re excited because of the benefit that’s going to bring to our region, our customers and communities, and it’s the comprehensive set of factors that are driving that excitement.
Paul Zimbardo
Absolutely. Thank you, team.
David Campbell
Thank you.
Operator
Thank you. Our next question comes from the line of Travis Miller from Morningstar. The line is now open.
Travis Miller
Good morning. Thank you.
David Campbell
Morning.
Travis Miller
Good morning. It seems like Kansas and Missouri have been working pretty well together here over the last few years. I’m wondering, within your service territory, how much competition is there at the local level in terms of attracting some of these large loads? I’ve got to think, just the way all states work, that there might be some competition here, either legislatively, politically vocal, to try to get some of this economic development. Is that happening?
David Campbell
That’s a great question. As a person, I’m now nearly five years in this region, and I’ve been very impressed. And, of course, our service territory extends over to Central Kansas and Wichita. So 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 and northward and southward.
So, it’s a collaborative approach. There’s actually been legislative truces in the past to mitigate potential poaching that might go on across state lines. So they really do a nice job of collaborating. In the great state of Texas, I live 250 miles from any state lines, and I was reasonably close to them. Here, I’m a quarter mile from the state line, and it’s the collaboration that happens when you’ve got that 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 in the collaboration time.
Travis Miller
Okay. We’ll hear more family stories later on. Indeed. They often involve sports. Yeah. 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
Yeah. So, 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. They just go all the way 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 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 those provisions introduced. It was in Kansas in ’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, it’s important to have submitted against the lag. So, out of our total capital plan, you’ll see that new generation is about a third. Two-thirds 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 they’ll pull that out. So, it’d be the three buckets of potential base rate would be legacy generation distribution in general.
David Campbell
Yeah. And most of our transmission on the Kansas side, you’ve got that right.
Travis Miller
Okay. Very good. That’s all I had. Thanks.
David Campbell
Thank you.
Operator
Thank you. So, our next question comes from the line of Nicholas Campanella from Barclays. Your line is now open.
Nathan Richardson
Hey, everybody. It’s actually Nathan Richardson on for Nick.
David Campbell
Good morning, Nathan.
Nathan Richardson
Good morning. 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, 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 two customers in the actively building category have the potential to raise that annual load growth to 4% to 5%. The addition of the third customer, and this is in the finalizing agreements category. I’m not 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 two 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 would the customers in the advanced discussions category. So, thank you for that clarification.
Nathan Richardson
Is there any quantification there or just that it’s 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 year-end call with the overall views on load growth tailwinds. We added it to the category of finalizing agreements, just the sheer amount of progress we’ve made with that customer in terms of advancing discussions, advancing agreements, and national agreements related to those.
So, it makes sense to include it in that category. We’ve not quantified the incremental amount. But we just noted that it’s those additional customers beyond the two that are in the finalizing agreements category would actually be additive to the 4% to 5% annual load growth potential.
Nathan Richardson
Okay. Got it. Thank you.
David Campbell
Thank you.
Operator
Thank you. Our next question comes from the line of Steve D’Ambrisi from RBC Capital Markets. Your line is now open.
Stephen D’Ambrisi
Hey, David. Hey, Bryan. Thanks for taking my question.
David Campbell
Good morning.
W. Bryan Buckler
Good morning.
Stephen D’Ambrisi
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 the timeline for resolution around some of this stuff is? I’m pretty sure there’s a settlement conference that is coming up, and then expected timeline as the end of February, but just want to hear about that and then how that works into 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 timeline that’s occurring on a different side of the state in Missouri. So, for us, we have two 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 aligned 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’s 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 dialog 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 ours first. So, hopefully, that makes sense in respect to the different contexts 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 the gating item from a timeline 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’m kidding. Jokes 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 of schedule-wise. Those are not far behind. So, we think that the timeline sets us up well for what we know is going to be an important update of the year-end call. But it’s important for these customers as well.
The queue is a very active one. Folks are here to come online. A big chunk of why we have 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 in our actively building and finalized agreements category, a lot of momentum. But we’ve got folks lined up behind them. So, we believe that the LLPS decisions, being on the timeline they are, should enable us to move on the timeline we’re hoping to achieve.
Stephen D’Ambrisi
Okay. That’s all I had. Thanks very much for the time. Appreciate it.
David Campbell
You bet. Thank you.
Stephen D’Ambrisi
Thanks, Steve.
Operator
Thank you. Our next question comes from the line of Paul Patterson from Glenrock Associates. Your line is now open.
Paul Patterson
Hey, good morning.
W. Bryan Buckler
Morning.
David Campbell
Morning.
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, which you guys mentioned earlier, about the cash coming from these potential new agreements being finalized. How should we — if you could just quantify, like, how that — how much you think that would impact the $2.8 billion? And the 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. Bryan Buckler
Hey, Paul. It’s Bryan. Thanks for the question. As a reminder for everyone, our current capital investment plan, five years, is $17.5 billion. In total, we believe that’ll be funded in part by up to $2.8 billion of equity and equity content capital market instruments, such as JSNs, 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 the 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?
Paul Patterson
Yeah, that does. I mean, but just to clarify, so that would be something that would obviously have required 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?
David Campbell
Yeah. 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 then I guess I want 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 two?
David Campbell
Paul, I’ll describe those. So, those are in-year mitigation measures. So, obviously, we are — the size of the weather headwinds and a little bit of incremental headwinds from the convert was, we would hope that we’d offset all of it, but we were able to offset $0.10 of it. And 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 were two years where we had really warm weather and adjusted the range upwards, didn’t change our long-term fundamentals. This is a year where 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 a context of this calendar year. The drivers for our fundamental plan, as Bryan mentioned, are you on 2026, and then the drivers for our long-term plan remain intact, and unaffected by the vagaries of weather.
Paul Patterson
Okay. And then, with respect to the Lambda deal, which seems interesting here, I’m just wondering, would that — I guess, first of all, when would it go — what timeframe 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
Yeah. As I described, it’s in the 25-megawatt range starting next year, and it’s probably in the next four to five years that it gets to that potential overall size. I’m really excited about that project. It’s a neat company, deploying advanced technology in their data center and AI factory, as they describe it. So, we were 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 they’re 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 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, this hypothetical hasn’t all been approved. But just wondering, 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 what would go to 100 megawatts? Do you follow what I’m saying? Or would it be, because its final number is 100, it would be a large load? Does that make sense?
David Campbell
So, 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 their large loads, definitely want to make sure they’ve got the capacity and the ability to do this, and they know and are contemplating getting up to the LLPS. If ultimately stayed in the 25-megawatt range, it would be 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 one of these, like, okay, I got you. I think I understand. Thanks so much. I really appreciate it. Okay. Thank you.
David Campbell
Thanks, Paul.
Operator
Thank you. Our next question comes from the line of Anthony Crowdell from Mizuho. Your line is now open.
Anthony Crowdell
Hey. Good morning. 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 and advanced discussion is what’s not included in the current growth rate?
David Campbell
Yeah. The actively building, and that was probably my fault for how I answered it earlier. So, if you look at slide 7, you have a good place to go. The actively building, which is Panasonic and Meta, and a third customer is in the heavy nearing completion of construction, that’s in the 2% to 3% load growth rate. And that’s the total of…
Anthony Crowdell
And in the 4% to 6%, right?
David Campbell
No, the 4% to 6% you get to, if you include the two 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’ve said we’re targeting the top half, and then we’re going to update on the year-end call, that is reflected in the two that are in the actively building category.
Anthony Crowdell
Great. Just the two, 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’s a good place to think where that settles out?
David Campbell
Yeah, so we haven’t given guidance on that specific range, but I think if you look at our $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 helping 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. So obviously it links as well to what the phasing is of both the load growth and the capital in the plan. So 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 updates that we provide.
Anthony Crowdell
Great. Then just lastly, you talked earlier, I think, in your five years there, you’ve seen some big weather swings, I think, for three to five 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’s worked with a couple of different utilities. I know in my background, I 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 the 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 to easily track and identifiable like weather, and 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 on being very transparent with their web tax, because they, as I mentioned, they didn’t impact the fundamentals when they were positive. They aren’t going to impact the fundamentals when it’s a year when it’s a little more mild. It’s a very mild August in particular year. 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 — that 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.
Anthony Crowdell
Great. See you guys at EEI. I appreciate you taking my questions.
David Campbell
See you at EEI.
Operator
Thank you. Our final question comes from Paul Fremont from Ladenburg. Your line is now open.
Paul Fremont
Thank you very much. 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 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 three customers in the finalizing agreements category are 1.5 to 2 gigawatts. So that gives you a pretty good sense of the average size. That’s a good indicator for us if we haven’t given more specificity in terms of size by customer. But that math will give you a pretty good roadmap for what the peak size typically is. There’s some variability by customer, of course, but it’s clearly large — it’s three large customers making up that 1.5 to 2 gig.
Paul Fremont
Okay. Because it’s — 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 the size of your facilities to be more modest.
David Campbell
Most of our customers want to expand past the 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 very unique large ones out there. But we’re — average size 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 their regional peak if we’re able to accommodate it, but we’d like some diversification in customers and sites, which is reflected in having 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 three 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 developed that Integrated Resource Plan, we included — because you can track this information — we had included the two 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 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 plans we need to serve those, SPPs with reserve margin requirements, but also changes in federal and local policies impacting renewables.
And 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. Bryan Buckler
Yeah. Paul, this is Bryan. We haven’t given an exact number for regulatory lag, we expect compared to allowed or 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 load 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 bridge that gap and get, we hope, very close to our authorized level of ROEs. So that’s directionally what I would give you, and we’ll share more details in February.
Paul Fremont
Great. Thank you very much.
W. Bryan Buckler
Thank you.
David Campbell
Thank you.
Operator
Thank you. This concludes the question-and-answer session. I would now like to turn it back over to David Campbell for closing remarks.
David Campbell
And Helen, 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 participation in today’s conference. This does conclude the program. You may now disconnect.