Evergy, Inc. (EVRG) Earnings Call Transcript & Summary

Good day, and thank you for standing by. Welcome to the Evergy Q1 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 your first speaker, Peter Flynn.

Thank you, Cory, and good morning, everyone. Welcome to Evergy's First 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 disclosure 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 first quarter highlights, recent legislative outcomes, provide updates on economic development activities, our 2025 integrated resource plan and regulatory updates. Bryan will cover our first 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 will now turn the call over to David.

Thanks, Pete, and good morning, everyone. I'll begin on Slide 5. This morning, we reported first quarter adjusted earnings of $0.54 per share compared to $0.54 per share a year ago. Relative to last year, this quarter's results were driven by recovery of regulated investments, partially offset by lower industrial demand and higher interest and depreciation expense. And while absolute retail demand grew 2.7% and heating degree days increased 18%, the volume benefits from the cold weather did not manifest into margin given declining block pricing in the winter months. We also saw weakness in sales due to scaled back activities following 2 significant heavy snow events as well as a large industrial customer outage caused by an unplanned maintenance shutdown at their refinery. Fortunately, this customer has returned to normal operations this month. As we look forward to full year 2025, we continue to see strength in our underlying operations to keep us on track to deliver on our earnings expectations. We are reaffirming our 2025 adjusted EPS guidance range of $3.92 per share to $4.12 per share with a midpoint of $4.02 per share. Bryan will go into more detail regarding our financial results as part of his remarks. The long-term outlook for our business is as strong as it has been in decades, bolstered by strong demand from large new customers, 1 of the most robust customer pipelines in the industry and constructive regulatory frameworks and supportive legislation in both Kansas and Missouri. We are reaffirming our long-term earnings growth target of 4% to 6% through 2029 based on the 2025 midpoint of $4.02 per share. From 2026 to 2029, we anticipate being in the top half of this guidance range relative to the 2025 baseline with significant additional tailwinds from potential large new customers and investments to serve them. Moving to operations. Our teams drove solid performance in the first quarter. Our average outage duration and frequency, as measured by SAIDI and SAIFI are performing favorably relative to targets. Our generation team achieved strong availability and ran well through extreme weather, including the blizzard in early January and record-breaking cold over consecutive days in late February. The latter cold spell drove a new winter peak load record of over 48 gigawatts in the Southwest Power Pool surpassing the previous record that was set in December of 2022. These outcomes demonstrate the benefits and need for our continued investment in energy infrastructure, including grid modernization projects and new dispatchable generation. I'd like to thank all of our frontline employees for their unwavering dedication and hard work in maintaining the reliability of our system and keeping the lights on for our customers. On the legislative front, constructive bills were passed in both Kansas and Missouri that enhance our strong regulatory frameworks and further enable infrastructure investment to drive growth and prosperity for our region. On Slide 6, we highlight recent legislation that will empower growth and investment in our region and firmly position Kansas and Missouri as premier destinations for new advanced manufacturing facilities and data centers. These outcomes are the product of broad-based alignment between Evergy, the governor's offices, 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 new and existing customers are critical to our success and the bills passed this year in both states as well as last year in Kansas directly advance these priorities. The PISA natural gas CWIP provisions serve to mitigate regulatory lag and support our strong credit profile as we execute on our $17.5 billion capital plan. While data center tax incentive packages bolster the business-friendly environments that Kansas and Missouri are already known for which have been instrumental in attracting new customers. All told, these legislative advancements will attract the investment of major industry players and prove that Kansas and Missouri are top destinations for new business and growth. We'd like to thank our many stakeholders for the engagement and participation that made this possible. For our part, Evergy remains committed to investing to provide safe, affordable and reliable electric service to our 1.7 million existing customers and the new customers we are bringing online. All of our stakeholders stand to benefit from this unprecedented investment opportunity as large new customers help spread our fixed cost over a broader base. Our communities benefit from job creation, development of ancillary businesses and services, improved economic resiliency with a more diversified industrial base and a larger tax base. Slide 7 describes our pipeline in greater detail. As I just described, we are well positioned to continue to track economic development. Relative to our size, our backlog of growth opportunities is one of the most robust in the country, reflecting the competitiveness and vitality of our region. Of course, the environment for new economic development projects is competitive, and we do not expect to win all projects in the queue. Since our fourth quarter call, our pipeline has expanded by 1 gigawatt to 12.2 gigawatts. We have also moved 300 megawatts out of the finalized category and into the active -- actively building category. This reflects the expansion of the data center project in Missouri, and we expect this load to ramp beginning in 2030. This customer has signed agreements, and we are actively building on the site. We are in final stages of negotiation with 2 large customers for 2 data center projects representing 1.3 gigawatts of load. One of these customers is evaluating our Kansas service territory and the other, an existing data center customer, is evaluating expansion in Missouri. We are very excited about the prospects of serving these new projects and bringing economic development to our communities. Both customers remain on track to share announcements regarding their plans later this year. Subject to final agreements and project announcements, we expect to begin to see an impact on our demand growth from these customers in 2027 and 2028 and into the next decade. Bryan will cover this demand profile in more detail as part of his remarks. We also remain in advanced discussions with customers whose load would represent approximately 3 gigawatts. While these customer projects are not as far along as the others in the pipeline that I've described, they have acquired land or land rights, presented a site plan and in some cases, signed letters of agreement to advance the evaluation process. The remaining balance of our pipeline, which grew from 6 gigawatts to 7 reflects initial conversations with potential customers. While all of this load may not be addressable, the continued interest, nonetheless demonstrates significant activity and interest in Kansas and Missouri and customers who stand ready if others drop out of the queue. Moving to Slide 8. We provide a consolidated summary of our 2025 integrated resource plan filings which we submitted in Missouri in March and in Kansas last week. This year's IRP reflects the impact of updating our long-term expected demand growth, including the addition of potential large loads in our finalizing agreements pipeline category as well as other important inputs such as reserve margin requirements of the Southwest Power Pool have changed, construction cost estimates and commodity price forecasts. Overall, our approach reflects an all of the above strategy for new generation development and adds approximately 2.1 gigawatts of new generation from 2025 through 2035 relative to last year's IRP. Earlier this week, we issued an all-source request for proposals to solicit bids for projects through 2032 to identify and help serve these needs. This process will complement our self-developed opportunities. Our planning process involves identifying the most cost-effective and resilient plan that reliably serves our customers across uncertain future scenarios. We believe that the renewable and natural gas additions, as shown in our IRP, are being planned in a manner that will allow Evergy to take advantage of best-in-class efficiency and support economic development in our service territory, while at the same time helping to minimize the impact on affordability and ensuring that we provide reliable electric service. You'll also note that our preferred plan delays the retirement of certain facilities and factors in potential conversions to natural gas. While there are risks and uncertainties for these plants given their age, the limited availability of replacement parts, and potential future investment requirements to maintain reliability, we are committed to a flexible approach that best serves our customers. Evergy has managed our generation fleet to operate efficiently, meet environmental standards and be available when called upon. The ultimate goal of our IRP is to ensure reliability and affordability for our customers as we advance a balanced all of the above generation portfolio. This view is reflected in the slide, which includes solar, wind, batteries and natural gas. Moving to Slide 9, I'll provide a brief update on our regulatory priorities and activities in Kansas and Missouri. On the Kansas side, we continue to work through our pending Kansas Central rate case. The procedural schedule calls for intervenor testimony by June 6, followed by rebuttal testimony on July 3. Settlement conferences will be held on July 8 and 9 with hearings commencing on July 21. We look forward to working with our regulators and stakeholders over the coming months to achieve a constructive outcome for our Kansas Central customers. As a reminder, Kansas rate case is run on an 8-month clock and we anticipate final resolution in late September. We also have pending requests before the KCC for predetermination on partial ownership of 2 combined cycle natural gas plants as well as a new solar farm. We are pleased to reach settlement agreements for these 3 projects. We appreciate the dialogue and participation from KCC staff, CURB, industrial consumers and other stakeholders all as part of the process. We anticipate a commission order by July 7. The KCC recently approved a procedural schedule for our request to approve a large load power service tariff that would apply to prospective data center customers. We believe the tariff allows for adequate cost recovery associated with large new loads while being competitive with rates in neighboring states. The procedural schedule calls for an early settlement offer by June 20, settlement discussions on June 23 and the settlement agreement due by July 3. If an early settlement is not reached, there will be opportunities for additional discussions in the fall ahead of hearing starting on October 8. Pivoting to Missouri, we have pending requests for certificates of convenience and necessity, or CCNs related to 2 solar farms', partial ownership and 2 combined cycle natural gas units and full ownership of a simple cycle natural gas plant. In April, the Missouri Public Service Commission staff recommended approval of construction for all of these facilities with certain conditions. We believe these projects, which are part of our IRP for Missouri, form a cost-effective package of reliable energy solutions for our customers and demonstrate alignment with the Missouri Public Service Commission's interest in securing additional generation resources for our Missouri utilities. For both the solar and gas projects, settlement conferences begin on May 22, followed by hearings for solar on May 27 and natural gas on May 29. Similar to Kansas, in February, we filed a request in Missouri to approve a large load power service tariff. Parties proposed a joint procedural schedule that would call for intervener rebuttal testimony on July 25, a settlement conference on September 23 and hearings from September 29 to October 3. We're also working with Missouri stakeholders to have advanced settlement discussions similar to the Kansas schedule. I'll conclude my remarks with Slide 10, which highlights the core tenets of our strategy. Our efforts to enhance affordability have yielded significant progress in improving regional rate competitiveness over the past few years. Our strategic plan is designed to sustain this momentum by keeping our long-term rate trajectory in line with the rate of inflation while still investing in infrastructure to support growth across our region. By prioritizing affordability, we support prosperity within our states and contribute to our robust economic development pipeline. Ensuring reliability is also a core element of our strategy as measured by SAIDI, SAIFI, grid resiliency and generation fleet availability. This also includes a focus on metrics relating to customer service, safety in all elements of our operations and infrastructure investment. And with respect to sustainability, we continue to advance the transition of our generation fleet as detailed in our 2025 IRP updates. We look forward to continuing to advance a balanced all of the above mix of resource additions over the coming years to support growth and prosperity in our states. And with that, I'll turn the call over to Bryan.

Thank you, David. Thank you, Pete, and good morning, everyone. I'll start on Slide 12 with a review of our results for the quarter. For the first quarter of 2025, Evergy delivered adjusted earnings of $125 million or $0.54 per share compared to $124.7 million or $0.54 per share in the first quarter of 2024. As shown on the slide from left to right, the year-over-year drivers are as follows: First, the net impact of retail sales volumes, pricing and weather drove a $0.01 benefit. While colder winter weather produced an 18% increase in heating degree days, the volume benefits from this weather manifested into a limited margin benefit given the declining block pricing, where rates in the winter decline as customer usage enters higher tiers. Our results also reflect the roll-off of the leap year impact in 2024, which benefited the prior year by approximately $0.03. Further impacting results was a large unplanned customer outage as I'll speak to shortly. Next, recovery of and return on regulated investments, driven by new retail rates at Evergy Missouri West and FERC regulated investments contributed $0.13 of EPS. Higher depreciation and interest expense due to increased infrastructure investment drove a $0.10 decrease in EPS. And finally, other items negatively impacted results by $0.04. Turning to Slide 13. I'll provide more details on our sales trends. On the left-hand side of the screen, you'll see total demand grew 2.7%, while weather-normalized demand decreased by 3%. The colder winter weather led to increases in residential and commercial usage, but major snowstorms limited the business activity in January and to some degree in February. On the industrial side, as I briefly alluded to, the year-over-year decline in demand was driven primarily by a large industrial customer going offline for most of the first quarter due to a temporary unplanned maintenance shutdown. Importantly, in April, this customer began to resume operations, and we expect him to be at normal production levels this month. While the combination of these factors had an outsized impact on the weather-normalized load in the first quarter, we continue to anticipate healthy growth for the balance of the year. Our forecast is supported by strong underlying increases in customer numbers, which were up 1% compared to last year, as well as the expected ramp of Meta and Panasonic in the second half of the year. As we move to Slide 14, I'd like to discuss year-to-go consideration supporting our 2025 adjusted EPS guidance. With the unusual items I noted earlier, the first quarter was a slower start to the year than anticipated. We have analyzed the balance of the year drivers and without litigation, we would be trading approximately $0.05 below our 2025 adjusted EPS guidance midpoint. Fortunately, the foundational earnings drivers of the company remains strong, and we anticipate meeting the midpoint of our EPS target with normal weather the rest of the year. There are a few factors that give us confidence in achieving our target. For example, year-to-date, our operational performance, including O&M cost management, has been strong. As we look to the balance of the year, we remain laser-focused on driving cost efficiencies and pulling O&M levers as necessary to achieve our financial targets. Additionally, as I previously described, we anticipate a rebound in weather-normalized demand growth in the third and fourth quarters, which we expect to be supplemented by growth in revenue from recovery of our state and FERC regulated investments. In short, we are committed to executing our plan and achieving our financial goals. Let's now turn to our financing plan on Slide 15. Our projected capital investments over the 5 years through 2029 stand at $17.5 billion, consistent with our capital plan update we provided on the fourth quarter earnings call. In fact, there's no change in our messaging from the previous quarter with respect to our financing plan through 2029. We anticipate funding our investment prudently, targeting an FFO to debt ratio of approximately 15% throughout the forecast period. Our strong cash flows from operations will be supplemented by an issuance of debt, equity and equity-like instruments. Our forecasted equity issuances across 2026 to 2029 remain at $2.8 billion, and as a reminder, our 2025 guidance does not contemplate new equity issuances this year, and we anticipate roughly $1.2 billion of equity issuances in total across 2026 and 2027 combined. As I mentioned during our fourth quarter call, the EPS and financing plan we are sharing with you again today only includes load growth expectations from the first set of large customer additions. We are optimistic that our equity needs will be lower for this $17.5 billion capital plan if additional large customers begin to come online by 2028, which as previously discussed, is becoming increasingly likely. In short, our customer pipeline has a potential to not only increase Evergy's earnings power, but would also provide a substantial benefit to operating cash flow, allowing us to moderate equity issuance in the future, assuming the $17.5 billion capital plan is unchanged. You may soon see us take steps to begin to address our future equity needs. We would expect any equity issuance activity in 2025 to settle no earlier than 2026. These steps will allow us to be nimble in our approach to accessing the capital markets. Turning to Slide 16. Here, we profile our demand growth outlook in tandem with the tremendous large customer opportunities in front of us. As a reminder, our 2% to 3% demand growth forecast through 2029 only reflects large customer announcements to date. We expect a combination of Panasonic, Meta and Google's load ramps to contribute approximately 500 megawatts of new load by 2029, with the balance driving growth into the early 2030s. This is incremental to our traditional base retail planning assumption of 0.5% to 1%. As David described earlier, load from customers in the finalizing agreements category would be additive to 2% to 3% demand growth forecast reflecting approximately 600 megawatts of incremental demand by 2029. This would potentially drive our total retail sales growth to 4% to 5% through 2029 with further additional upside in those years for the next customer pipeline that we have termed to be in the advanced discussion stage. To step back again and relative to our size, we continue to believe we have one of the most compelling customer growth opportunities in the entire industry that could drive robust growth not just in our 5-year forecast, but into the next decade for Evergy and for the communities we serve. I'll close on Slide 17 with a recap of our long-term financial expectations. As David stated, Evergy's long-term business outlook is as strong as it's been in decades. We are reaffirming both our adjusted EPS guidance range for 2025 as well as our long-term adjusted EPS growth target of 4% to 6% through 2029. From the baseline midpoint of $4.02 in 2025, we expect to grow in the top half of our 4% to 6% adjusted EPS target range through 2029 with additional tailwinds through this plan including potential additional wins from our large customer pipeline. Our employees remain focused on consistent execution of our customer, operational and financial goals as we advance our strategic objectives of ensuring affordability and reliability for our customers in driving a sustainable business model for the long-term prosperity of our customers and our communities. Thank you for joining us today, and we will now open the call up for your questions.

[Operator Instructions] Our first call comes from the line of Durgesh Chopra of Evercore.

Just to start off, a quick clarification on the quarter itself. Bryan, you mentioned $0.05 above your expectations, and you mentioned that was a number after some mitigating actions. May be just give us what the gross number is? And if my understanding of the $0.05 is accurate?

Yes. Durgesh, just to clarify there, the $3.97 I pointed to, which is $0.05 short of the $4.02, that's actually before mitigating items. So that's just our base plan, our base outlook, if you will, for the full year, sitting here today before mitigating items. We're already being in active discussions with our entire officer team to mitigate that $0.05 delta. And we actually fully expect to be at $4.02 for the full year sitting here today.

Okay. So just to be clear, the first quarter came in $0.05 below where you would have expected it to be. Is that a fair articulation?

That's the way to think about it.

I appreciate that. And then just any color you can share on the timing, 1.3 gigawatts, Nice to see the 300 megawatts moved into the execution mode here. But just any color you can share on the timing of when those contracts may be signed? And it doesn't sound like this is -- again, just asking for confirmation, but doesn't sound like you're seeing any softness of demand from your customers or just any perspective there given all the Microsoft noise, et cetera.

Yes. Great question. We still have tremendous confidence in the discussions we're having, very active discussions and the pipeline has actually expanded. So the folks who stand ready if later in the queue if folks drop out, that's as robust as ever and we've advanced significant conversations with the folks in the actively building and finalizing agreements categories. A lot of investments already been made directly on behalf of those customers that they've either paid for directly or backstopped. I anticipate exact timing. I think it's probably linked to when we finalize the large load power service tariff proceedings, which we do expect to wrap up by year-end, but the exact timing is a little dependent on whether we get settlements and following the hearings, but it will likely be right around the end of the third quarter and into the fourth quarter. And I expect the announcements could precede that but there's a linkage obviously, with finalizing those tariffs. But back to your overall question, very positive discussions. We haven't disclosed all the names of the counterparties, of course. So some of the names have been public in the past because there have been a couple of announcements and those parties continue to show commitment to the underlying strategy that's reflected and very robust interest in our territory. And we continue to take the steps needed to make sure that we can serve them.

David, so it's Q3, Q4 after -- kind of most likely after you finalize these tariff discussions in both states. Understood.

Our next question comes from Nathan Richardson of Barclays.

My first question is, so I know you talked a little bit about how increased sales could lead to downward pressure on equity, but I was wondering if you could quantify that at all. If there's a sensitivity every 1% of sales growth is x billion dollars of equity or anything along those lines?

Nathan, it's Bryan. Yes, thanks for the question. We haven't laid out our exact kind of guidance, if you will, on how much equity issuances could go down with the load growth. But going from the 2% to 3% load expectation that's currently embedded in our 5-year plan to what we think is ultimately going to be more like 4% to 5% as more of these customers sign up and begin operations. And as early as late 2027 and we think they'll get some pretty robust loan growth from them in '28, 2029. It's really impactful to your FFO. And as you know, an FFO dollar goes a long way to improving your metrics on FFO to debt. So suffice it to say, it could be hundreds of millions of less equity over that 5-year period, based on a $17.5 billion capital plan.

Makes sense. And then one more question. So I saw that there's some increased guidance on the IRP and given that there is clearly some pressure higher on load growth, does the IRP currently tie into the 2% to 3% prior guidance? Or could it absorb some of the incremental megawatts that are popping up the backlog right now?

So it's a good question. We've actually, in the latest integrated resource plan filings, given how advanced the discussions are in the need to plan ahead, we actually included the customers and the actively building and finalizing agreements categories in the integrated resource plan. And that's one of the drivers of why we see the increased resource needs and also some flexing in the retirement time lines and consideration of conversions to natural gas. And I know that leaves a natural question of, okay, which resources are in our forward financial plan, the $17.5 billion capital plan and which are not. So we actually added a page, full credit to the team in doing that. So Slide 23 in the appendix lays out which resources in our latest integrated resource plan are in the capital plan and which are not yet in the capital plan. And consistent with our overall approach of sticking with the demand growth forecast of 2% to 3% we do see real opportunities, just as Bryan described on incremental load, we'll also see the incremental resources we expect to have in the mix to serve these customers. So those will be part and parcel as we give updates as customers make their announcements.

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

Just wanted to clarify something. So the 300 megawatts that you were talking about that went in the construction, I suppose. And then ramping your expectation in 2030, is that the typical time line that you're seeing among either large load customers or even specifically data center customers that kind of 4-year type of build and ramp?

I think the -- when you see both the actively building and finalizing agreements category, we try to lay out in both how much of the total megawatts will we see through '29 and then how much are coming online after '29. You'll see in both categories, it's 1.1 gigawatts in the actively building category, about 500 megawatts that we expect through 2029 up to 500 megawatts through 2029 is what we expect in those categories, obviously, more further along. In finalizing agreements categories, obviously, we're in advanced discussions there as well, 600 megawatts by 2029. So I think -- there are obviously still extremely large customers, but it is reasonably typical to see a ramp for these folks over time. So I described the shifting in the categories partly reflects an expansion when they expect that to come online. But the degree of conviction, the level of discussion, the amount of work underway is why we shifted in the actively building category. But that mix is pretty similar across those 2 groups as you saw by '29 versus ramping up after the '29 time period.

And Travis, I might just add a little bit to that. On the Slide 7 that shows the advanced discussions of 2.9 gigawatts. Some of that load or some of that customer peak demand could start impacting our load as early as late '27, certainly by '28, 2029. So I just wanted -- that maybe gives you a feel too that even some of our deeper parts of our pipeline could turn into load growth here in the 5-year plan.

Okay. So kind of staggered across different customers over that time period. Okay. That makes sense. And then just another clarification. On the residential demands, the weather-adjusted demand decline. Can you go over that again or explain what happens in that residential category, if I missed that?

Yes, it's a good question. I'll ask Bryan to go into it later. and I'm a big fan of the weather-adjusted analysis, but when weather gets extreme, it can become a little -- there's a little bit of art in the science. So you'll see that the overall residential demand was up 8%, weather adjusted down 3%. So it's a little bit art in what that split is. So I don't -- we're not reading if Bryan mentioned on the total number of customers went up. So we don't think there's something systematic going on there. But it's something that we'll track. We've had robust growth in the residential side last couple of years. So I think it's a little bit in the art and science. It's my personal view. And the phenomenon that we did cite, and this is something that is not true in all jurisdictions. Frankly, my past history was a little bit different, but the block pricing phenomenon is real other than one of our biggest residential groups is in Missouri Metro. And once you get to the highest levels of the usage, rates dropped by 45% so the declining block phenomenon of pricing in the winter is real. It's actually the inverse in the summer. It doesn't go up by nearly that percentage, but actually goes up a little bit as you consider more. So that's the dynamic that happened. Anyone who has kids in the school systems in the greater Kansas City area knows that they had a couple of full weeks when they basically didn't have their kids in schools. So that's an impact on commercial activity and some knock on industrial. So that's an unusual quarter in the amount of snow impacts on some of the underlying economic activity and then the concentration in residential that was mitigated by the block pricing. Bryan, anything to add on that?

No, that's perfect. Maybe just briefly, I was thinking about this some more yesterday, Travis. And when you look at a rolling 12 months, you get a better feel for trends, real trends in residential and commercial, in particular. Residential is up 1.2% on a weather-normalized basis over a rolling 12-month period and commercial is up nearly 1.5% over a rolling 12-month period. So want you to have that as well. This kind of shows the overall economic strength and strength in the growth of residential numbers actually here in Kansas and Missouri areas.

Sure. Okay. I figured your 1Q is always obviously a little bit lower than 3Q certainly. Okay. Well, that's very helpful. I appreciate all the details.

Our next question comes from the line of Julien Dumoulin-Smith.

This is [ Tanner ] on for Julien. You somewhat spoke to this in your response to Nathan's question on the IRP. But kind of drilling in on the coal plant retirement specifically, could you discuss the rationale that went into extending the timing of the retirement specifically with -- regarding the specific dates chosen? Clearly, keeping these plants online provide some room to help, at least in the near term, accommodate and integrate new large customer load even if it's not directly tied. But kind of depending on how things break over the next few years, is there further flexibility to manage these retirement dates?

That's a great question. You heard me comment on that in my remarks. So there's some risks and uncertainties that are with older units like these. Once we get into the 2030s, given the majority of our coal fleet will be in its 60s, so more than 60 years old. And I think that's a tremendous age for human being because it'll be in that same category. But for coal plants as you get in that phase. And we've made some investments in a number of these, but the units that were identified for retirement are ones that either have potential incremental investment needs for environmental retrofit equipment depending on the status of the EPA rules at the time or they had some maintenance that has been done in light of the expected time line. Lawrence, which is the unit that's 450 megawatts in total is our oldest unit. Jeffrey Energy Center in Unit 2 is one that, for example, doesn't have an SCR. So there is some flexibility. But as you get over time, the age of the unit, the availability of replacement parts because you have to do some of those dedicated forgings to buying spare parts and the potential incremental investment requirements to maintain reliability and meet standards that could change. There's some flexibility, but we recognize that it's like an older car, there's only so far long that you can take it. So some of this will be responsive to what the rules are that are applicable, of course, on the federal side. But this flexibility, we think, makes sense. Lawrence is our oldest unit. You see it's a short amount of time that we've deferred in terms of the retirement time line and even the conversion. But this reflects our best thinking, but we know that there's a little more uncertainty with some of these older units given their age.

Great. And then switching gears, with respect to your ability to pull O&M levers to meet '25 guide, can you discuss the different buckets you've managed through the end of the year and maybe how to think about the effect that could have in terms of your future optionality available to you in '26 and '27, especially as your target EPS CAGR accelerates?

Yes, for better words, we, like other companies have a fair bit of experience and you always want to have some flexibility to manage your business and mitigate issues that arise. So $0.05 category is something that our team has demonstrated the ability, if you've seen our cost management in the past years, where there is -- and there's a wide range of levers across the business. So it's from -- generally involves discretionary activity, third-party spend. We will do what we need to do to make sure we maintain reliability and keep the integrity of our system going. But there's always some levers that you can pull in managing your business. And it's really across all the different parts of our business. And we've got a fair bit of experience with it. I don't think we're unique in that. I think other companies have that same capability. And it's early in the year. It's a pretty modest amount, still important. So we've got work to do to make sure we get there. But we're confident in our ability to identify that amount given that we're sitting here with still 8 months left in the year. So -- and we don't -- I don't think it impacts our ability to hit our future targets or the growth that we see in the future. I want to make sure that we're still spending what we need to, to ensure reliability and serve our customers.

Our next question comes from the line of [ Paul Cole ] of Bank of America.

I wanted to go back, if I could, to the large load tariff disclosures you made around Kansas and Missouri. Can you talk about the spread of parties and interest in these dockets and how important a constructive outcome is to the conversations that you're having with the data center developers and other large load users?

I think it's a great question. Thank you, Paul. It's obviously a very important discussion. We went the route of filing for large load power service tariffs because we think having a dialogue that includes the key parties is really important. These are very large new customers. We think there's a real opportunity here to have a win for the new customers because we have the ability to serve them. We're in a market where we've got competitive rates and the ability to have the transmission generation capacity to serve and the time they need to. At the same time, have a win for our existing customers because we're bringing in large new customers who can really help to spread fixed costs. But they're large enough that we want to have a tariff so that it's a proceeding in which everyone is involved. Very wide participation in these proceedings in both states, as you would expect. We've had a high level of dialogue with our large customers, as you would expect, it's been constructive throughout. So we've been very transparent in our approach with those customers. They know exactly what we're trying to achieve, and they continue to have advanced discussions with us. So they know what we're trying to do, where we're trending and we wanted to get ahead of this because we know it's an important element of the process. But they're also solving for availability and can we hit a ramp rate and hit a time line. So we've taken the steps and they've taken the steps to stay on that track while we're having the conversation. So it's -- we still have to get through those proceedings, but we're already in constructive dialogue with parties and you'll obviously get -- see the results later this year, but we feel good about how they're trending.

Perfect. And then a quick follow-up, Bryan, to some of the comments you made around equity expectations for this year. And can I -- am I understanding correctly when I say that you're not precluding the option of issuing equity this year, but it would be under a mechanism whereby there will be no dilution until 2026?

[ Paul ], yes, your understanding is right. Like many of our peers, we may be thoughtful about accessing the market here in 2025 but anything we do would have a forward component to it that settles in 2026 or 2027. And as we've articulated, we have a sizable equity need beginning in '26 in the out years as our capital investment plan increases. What's really nice is that we have load growth that's also accelerating, beginning in '26 in those out years. So the plan, we think, is coming together very nicely, but there will be no dilution from new equity issuances here in 2025.

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

Thank you, Cory. Thanks, everyone, on the call, for your interest in Evergy. This concludes our session today. Have a great day.

Thank you for your participation in today's conference. This does conclude the program, and you may now disconnect. Have a wonderful day.