Good day and thank you for standing by. Welcome to the Evergy Q1 2025 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speakers' presentation, there will be a question-and-answer session. [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 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 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 two 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, one 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…

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 to 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 you 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%. Colder winter weather led to increases in residential and commercial usage, but major snow storms 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…

Thank you. At this time, we will conduct a question-and-answer session. [Operator Instructions] Our first call comes from the line of Durgesh Chopra of Evercore. Your line is open.

Hey, team. Good morning. Thank you for the time.

Good morning, Durgesh.

Hey, good morning, Dave. Just to start off, quick clarification on the quarter itself. Bryan, you mentioned $0.05 below your expectations, and you mentioned that was a number after some mitigating actions. Maybe 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.

Yes. 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.

Okay. Thanks. Appreciate that. And then just any color you can share on the timing of the 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 doesn't sound like this, again, just asking for confirmation, but it doesn't sound like we're seeing any softness of demand from your customers, but 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's 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 have already been made and directly on behalf of those customers that they've either paid for directly or backstopped. I anticipate exact timing, we 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 proceed that, but there's a linkage obviously with finalizing those tariffs, but back to your overall question, very positive discussions. I mean, we haven't disclosed all the names of the counterparties, of course, though some of the names have been public in the past, but 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.

Thank you, David. So it's Q3, Q4 after kind of most likely after you finalize these tariff discussions in both states. Understood. Thank you and I'll get back in the queue.

Great. Thank you.

Thank you.

Thank you very much. One moment for our next question. Our next question comes from the line of Nathan Richardson of Barclays. Your line is open.

Hey, everybody. Can you hear me okay?

We can. Good morning.

Good morning. 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?

Hey, Nathan. Good morning. 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 is currently embedded in our five-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 in as early as late 2027 and we think there'll be some pretty robust load growth from them in '28 and 2029. It's really impactful to your FFO. And as you know an FFO dollar goes a long way to improving your metrics on the FFO to debt. So suffice it to say, it could be hundreds of millions of dollars of less equity over that five-year period, again, based on a $17.5 billion capital plan.

Makes sense. Thank you. And then one more question. So I saw that there is 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 in 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 and the need of plan ahead. We actually included the customers in 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 timelines and consideration of conversions in natural gas. And I know that leaves a natural question of, okay, well, which resources are in our forward financial plan, the $17.5 billion capital plan and which are not. So we actually added a page, give 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.

Got it. That makes a lot of sense. That's all I had. Thank you, everybody.

Thank you.

Thank you, Nathan.

Thank you very much. One moment for our next question. Our next question comes from the line of Travis Miller at Morningstar. Your line is open.

Thank you. Good morning.

Good morning.

Good morning, Travis.

I just wanted to clarify something. So the 300 megawatts that you were talking about that went into construction, I suppose, and then ramping your expectation in 2030, is that the typical timeline that you're seeing among either large load customers or even specifically, data center customers, that kind of four-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 many -- how much of the total megawatts will we see through '29 and then how much 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 and finalizing agreements categories, obviously, we're advanced discussions there as well, 600 megawatts by 2029. So I think -- those are obviously still extremely large customers, but it is reasonably typical to see a ramp for these folks over time. So I'd describe the shifting in the category as partly reflects an expansion in 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 into the actively building category. But that mix is pretty similar across those two 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 five-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?

No, it's a good question. I'll ask Bryan to go into later the -- and I'll -- 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, if you will. So you'll see that the overall residential demand was up 8%, weather-adjusted down 3%, so it's a little bit hard 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.

That's right. Yes.

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. I'll just cite in one of our biggest residential groups is in Missouri metro, and once you get to the highest levels of usage, rates drop by 45%, so the declining phenomenon of pricing in the winter is real. It's actually the inverse in the summer, doesn't go up by nearly that percentage, but actually goes up a little bit as you consider more. So that's a dynamic that happened. Anyone who has kids in the school systems in the Greater Kansas City area knows that they had a couple full weeks when they basically didn't have their kids in school. So that's an impact on commercial activity and some knock-on 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 residential that was mitigated by the block pricing. Bryan, anything you'd add on that?

No, that's perfect. Well, maybe just briefly I was thinking about this some more yesterday, Travis and when you look at a rolling 12 months to 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 I wanted you to have that as well. It kind of shows the overall economic strength and strength in the growth of residential members actually here in Kansas Missouri areas.

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

Thank you.

Thank you.

Thank you. One moment for our next call. Our next question comes from the line of Julien Dumoulin-Smith. Your line is open.

Hi. This is Tanner on for Julien. Good morning.

Good morning.

Good morning. You somewhat spoke to this in your response to Nathan's question on the IRP, but 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 provides 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 higher with older units like these. Once we get into the 2030s, 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 a human being because I'll be in that same category. But for coal plants as you get in that phase, 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 EPA rules at the time or they had some maintenance that has been done in light of the expected timeline. Lawrence, which is the unit that's 450 megawatts in total is our oldest unit. Jeffrey Energy Center 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 sometimes do dedicated forgings to find spare parts and the potential incremental investment requirements to maintain reliability to 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 shorter amount of time that we've deferred in terms of the retirement timeline and even the conversion. But with 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. Thanks. And then, switching gears, with respect to your ability to pull O&M levers to meet '25 guidance, can you discuss the different buckets you can sort of manage through the end of the year, 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? Thanks.

Yes. Well, I think, yes, for better or worse, 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 past years where there's -- 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 eight months left in the year. So and I don't think it impacts our ability to hit our future targets or the growth that we see in the future. I will make sure that we're still spending what we need to ensure reliability and serve our customers.

Great. Thank you very much.

Thank you very much.

Thank you.

One moment for our next question. Our next question comes from the line of Paul Cole of Bank of America. Your line is open.

Thank you. Good morning. 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 interests 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 a large load of power service tariffs, because we think having a dialog 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 dialog 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 can we hit a timeline. 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 dialog with parties and you obviously see the result later this year, but we feel good about how they're trending.

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

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

That's perfect. Thank you for clarifying. Thank you.

Great. Have a good day.

Thank you.

You too.

Thank you very much. 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.