Evergy, Inc. (NASDAQ:EVRG) Q1 2026 Earnings Call Transcript

Evergy, Inc. (NASDAQ:EVRG) Q1 2026 Earnings Call Transcript May 7, 2026

Evergy, Inc. beats earnings expectations. Reported EPS is $0.69, expectations were $0.63.

Operator: Good day, and thank you for standing by. Welcome to the Evergy’s First Quarter 2026 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 today, Peter Flynn. Please go ahead.

Peter Flynn: Thank you, Dana, and good morning, everyone. Welcome to Evergy’s First Quarter 2026 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, provide an economic development update and discuss our regulatory agenda and integrated resource plan.

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’ll now turn the call over to David.

David Campbell: Thanks, Pete, and good morning, everyone. I’ll begin on Slide 5. This morning, we are pleased to announce the signing of a fifth large customer electric service agreement and the favorable amendment of 2 previously signed contracts. As I’ll discuss in a moment, Evergy’s large customer team continues to excel in bringing economic development to Kansas and Missouri. We also are reporting solid first quarter results as we delivered adjusted earnings of $0.69 per share compared to $0.55 per share a year ago. The increase was primarily driven by recovery of regulated investments, growth in weather-normalized demand and revenues from our large load customers. Other factors impacting results were the effect of mild weather, higher operations and maintenance expense and higher depreciation expense.

Bryan will cover these results in more detail. During the quarter, we worked closely with 2 of our large customers to refine their anticipated load profiles and amend their electric service agreements, or ESAs. As a result, we will receive a boost to 2026 margins, helping to offset the impact of the mild winter weather earlier this year. The first quarter demonstrated ongoing momentum in our large customer strategy. During our year-end earnings call in February, we signaled our expectation to execute at least one more ESA in 2026 that was not yet incorporated into our financial plan. Today, I’m excited to announce a new ESA with a premier developer for a new data center project in our Kansas Central service territory that will drive affordability benefits for our customers.

This new customer will take service under our large load power service tariff, the framework under which new large customers pay a premium rate that covers their fair share of existing and new system costs. This ESA will bolster our adjusted EPS growth, demand growth and credit metrics throughout our 5-year plan. Bryan will also cover this in more detail. With this solid start, we are reaffirming our 2026 adjusted EPS guidance range of $4.14 to $4.34 per share. We are also reaffirming our long-term adjusted EPS growth target of 6% to 8% plus through 2030 off of the 2026 midpoint of $4.24. We expect adjusted EPS growth to exceed 8% annually beginning in 2028 through 2030. Slide 6 summarizes our recent data center announcement. As I mentioned, the fifth ESA is for a data center in Kansas Central.

While customer specifics are confidential, we can confirm that the customer is a large, well-known developer with strong investment-grade credit ratings and is working with the hyperscaler offtaker. We anticipate further disclosure in the coming months. In aggregate, we have executed ESAs for 5 data center projects under our LLPS tariffs, securing the strong protections that the tariff requires for our existing customers. These 5 ESAs include steady-state peak load of approximately 2.5 gigawatts, including the 450 megawatts of steady-state peak load from non-LLPS customers, such as the Panasonic electric vehicle battery manufacturing plant, the total reaches 3 gigawatts. We continue to make progress with other large customers, and we expect at least 1 additional ESA in 2026.

As a reminder, any additional ESAs would represent upside to the financial plan that we are sharing with you today. These economic development wins solidify Kansas and Missouri as premier destinations for data center customers and will empower investments in growth, helping to drive prosperity for our region. Slide 7 summarizes the progress we’ve made in converting our large customer pipeline into signed agreements and provides an update on activity further down the queue. Starting in the top row, the 3 gigawatts include the 5 announced ESAs and large customers that have already commenced operations. This Tier 1 demand enables a transformative growth opportunity, supporting our revised estimate of 7% to 8% annual retail load growth through 2030.

This total consists of projects already in operation progressing toward a steady state of 1.2 gigawatts. The remaining 1.7 gigawatts represent additional projects that have executed ESAs contractually requiring minimum monthly bill payments, whether or not the capacity is fully utilized. Regionally, these will deliver significant benefits, billions of investment that will create jobs, support a leading-edge digital economy and expand the tax base, while enabling us to spread system costs over a broader base to maintain affordability for all customers. In the next category, we highlight approximately 1 to 1.5 gigawatts of expansion opportunities with existing customers who have signed ESAs. These expansions would require amending load ramps that are already in existing contracts, and we are working on the transmission and generation solutions to enable them.

To be clear, our 5-year financial plan does not incorporate any upside from the potential expansion projects, which could materialize both before or after 2030, depending on individual project timing. We remain in advanced discussions with multiple new customers in our Tier 2 category, representing approximately 1.5 to 3 gigawatts. These customers have acquired land or land rights, signed letters of agreement, and we are actively reviewing transmission and generation capacity solutions. The opportunity from these customers is primarily beyond 2030. Taken collectively, the opportunity set with Tier 1 expansion and Tier 2 category customers gives us confidence that our exceptional earnings and load growth will continue into the 2030s. The remaining pipeline totaling well over 10 additional gigawatts highlights the robust activity and sustained interest in our region.

Serving this load will require working in tandem to identify creative solutions with our customers who stand ready to move forward as capacity opens, allowing us to prioritize the best-fit projects as the queue evolves. Moving to Slide 8, I’ll provide a brief update on our regulatory priorities in both Kansas and Missouri. In Kansas, we expect to file our 2026 Integrated Resource Plan in the second quarter. This year’s update will reflect several key developments, including higher long-term demand growth driven by new electric service agreements, impact of Southwest Power Pool’s capacity reserve requirements, changes to federal tax credit policies, new construction cost estimates reflecting the results of RFPs and coal plant retirement schedules.

Together with other key inputs, these factors will inform the selection of future generation projects and shape the recommended resource mix in our preferred plan. Once the IRP is filed, we anticipate related generation predetermination filings over the balance of the year. Additionally, the Kansas Corporation Commission approved a unanimous stipulation and agreement to return all deferred nuclear production tax credits to customers over a 3-year period, which is a constructive outcome for our Kansas customers. In total, we are expecting to monetize in excess of $100 million of nuclear production tax credits per year that will be flowed back to our customers over time, further enhancing affordability. Pivoting to Missouri, we filed our Missouri Metro Rate Case on February 6.

The procedural schedule calls for staff and intervenor testimony by June 30, settlement conferences on September 23 and 24, and hearings beginning October 5 with new rates effective around January 1, 2027. We look forward to working collaboratively with the Missouri Public Service Commission staff and our stakeholders to achieve a constructive outcome for our metro customers. Later today, we will file our 2026 Integrated Resource Plan in Missouri. Similar to Kansas, we anticipate multiple CCN filings for the balance of the year as we advance the next phase of our all-of-the-above generation strategy. I’ll conclude my remarks with Slide 9, which highlights the core tenets of our strategy. We will continue to prioritize customer affordability in our long-term plan.

While capital investments are higher than historical levels, so too is load growth. Serving new large customers has a dual advantage. The premium rates help cover not only the cost to serve them, but also any new investment needed. And in addition, the higher energy sales allow us to spread system costs over far more kilowatt hours. We expect to see customer rate increases over the next several years to be in line with or below inflation for the significant majority of our residential customers. Missouri West is our smallest utility with the lowest rates in our system and some of the lowest rates in the nation, partly because the utility is in need of infrastructure investment, in particular, dispatchable baseload generation. As a result, as new generation plants come online to serve that jurisdiction, these customers may see rate increases above inflation over the next 5 years.

We still anticipate their rates will remain regionally competitive, and these investments will reduce the reliance on market-provided energy, making rates more stable for our Missouri West customers. Longer term, as the full benefits from large load customers are realized, we are confident that we can manage residential rates to a level consistent with inflation and all Evergy customers will benefit from these infrastructure investments for decades to come. Affordability has been at the forefront of our strategy since the merger that created Evergy back in 2018. Evergy’s prices in Kansas and Missouri have been stable in recent years with our overall rates today about 5.1% cumulatively higher than in 2017, an increase of well under 1% per year, far below inflation during that time.

By prioritizing affordability, we also contribute to the robust economic development pipeline ahead of us and support the substantial economic potential within our states. Ensuring reliability is also a core element of our strategy. We are targeting top-tier performance in reliability, customer service and generation as measured by key metrics such as SAIDI, SAIFI, grid resiliency and generation fleet availability. Our teams delivered strong results in these areas in 2025, and we are pleased to report a strong start for these metrics in 2026. With respect to sustainability, we continue to advance the evolution of our generation fleet as will be outlined in our 2026 IRP updates. Our primary objective is to implement a cost-effective, all-of-the-above generation strategy.

Informed by the analysis from the IRP process, we will advance this objective through targeted investments in natural gas, energy storage and solar resources to serve our customers. We remain focused on maintaining a balanced portfolio of resource additions to support long-term growth and prosperity across our states. And with that, I will now turn the call over to Bryan.

W. Buckler: Thank you, David. Thank you, Pete and Kyle, and good morning, everyone. Let’s begin on Slide 11 with a review of our results for the quarter. For the first quarter of 2026, Evergy delivered adjusted earnings of $162 million or $0.69 per share compared to $128 million or $0.55 per share in the first quarter of 2025. As shown on the slide from left to right, the year-over-year drivers are as follows: first, load impacts were essentially flat versus the prior year quarter. Reflecting our exceptional business fundamentals, weather-normalized demand was strong in the quarter, growing 4.7%, while mild winter weather resulted in fewer heating degree days compared to prior year and versus normal, impacting EPS by approximately $0.06 compared to budget.

These drivers effectively offset each other in the quarter. The strong start to the year in weather-normalized load growth is consistent with the overall 3% to 4% full year load growth expectations we shared with you in February and reflective of the positive economic development outlook in our service areas. In fact, in the first quarter, we saw strong results from Panasonic and from the start-up of operations of a large data center in March, which was a couple of months ahead of plan. In tandem, these 2 large customers drove a $0.02 EPS benefit in the quarter compared to prior year. As we look to the full year 2026 outlook, other revenues and incremental large load margin from the amended ESAs David mentioned are projected to fully offset Q1 mild weather and place us in a solid position to meet the midpoint of our 2026 EPS guidance of $4.24.

The next driver of Q1 results to mention is recovery of and return on regulated investments, driven primarily by new retail rates and FERC-regulated infrastructure investments, which in total contributed $0.15 of EPS. Next, the combination of higher O&M and increased depreciation and net interest expense related to our capital infrastructure investments drove a $0.10 decrease in EPS. And finally, other items contributed a positive $0.09 variance in the quarter. To assist investors and analysts with their modeling, we are providing second quarter adjusted EPS guidance of 17% to 19% as measured against the $4.24 midpoint of our 2026 adjusted EPS guidance range. Turning to Slide 12. I’ll provide more detail on sales trends. As I mentioned earlier, weather-normalized retail demand grew 4.7% in the first quarter with strong growth across customer classes.

Residential demand grew 3.3%, reflecting solid underlying customer growth as our Kansas and Missouri service areas continue to see migration into our communities. Commercial demand grew 3.8%, driven primarily by the initial ramp-up of data centers. Industrial demand grew 10.1%, driven primarily by Panasonic’s continued ramp as well as higher usage from a large customer that experienced an unplanned outage last year in Q1. We anticipate robust growth in the commercial and industrial classes throughout 2026, given the continued ramps of large customers, including the data center project that energized in March. At a macro level, the robust customer demand in our service areas is supported by a solid labor market as the Missouri, Kansas and Kansas City Metro area unemployment rates remain below the national average.

Moving to Slide 13, we highlight our updated large load demand growth profile. This table reflects the results to date from years of dedicated efforts to advance competitive frameworks for capital investment in Kansas and Missouri that is enabling our ability to invest for growth in a way that promotes economic prosperity for our customers and communities, while solidifying our region as a premier destination for advanced manufacturing and data center customers. As indicated on the chart, the large load customer ramps are already underway, and we continue to build — and we’ll continue building in aggregate through 2030 and beyond, supporting our retail load growth CAGR of 7% to 8% through 2030. This reflects the impact of the fifth ESA we announced today as well as the amendments of 2 ESAs previously signed.

And as a reminder, the new ESA and the amended ESAs are all subject to the minimum bill protections previously described. To put in perspective the great progress the team has made in the last couple of months, on this slide, we highlight the significance of the increase in megawatts served in the 5-year plan compared to what we showed you during our February investor call. For example, while not shown on the slide, 2026 large load capacity revenues are starting earlier within that next year, leading to EPS benefits in 2026. And as we look to future years, 2027 large load capacity revenue will now be tied to megawatts in ESAs that are 100 megawatts greater than previously disclosed, trending up further in ’28 and 2029, and with 2030 projections now approximately 500 megawatts greater than our previous projection of capacity served by the end of that year.

In fact, by the end of 2030, we expect to be serving up to 2.25 gigawatts of capacity for this set of new customers. This tells a powerful story of growth, anchored by long-term contracts and clear parameters on monthly billings, providing significant visibility into our earnings growth and cash flow streams for ESA LLPS contracts that generally span 16 to 17 years long. As a reminder, this plan reflects the contributions from customers under signed ESAs for 5 large projects. And furthermore, we continue to make strong progress with several additional large customers and expect to execute at least one more ESA in 2026, whose load and capacity served could represent upside to this 5-year forecast and importantly, well into the next decade. As David described, we’ll continue working in a measured fashion through our massive pipeline of prospective customers to build on the success we’ve achieved thus far.

Let’s briefly touch on Slide 14. This slide highlights our strong load growth profile, which has been further strengthened by today’s large customer announcements. As indicated on the chart, the large load customer ramps are already underway and will continue building in aggregate through 2030 and beyond, supporting our retail load growth CAGR of approximately 7% to 8% through 2030, up from our previous forecast of 6%. This exceptional growth trajectory anchored by long-term contracts and clear parameters on monthly billings provides significant visibility into our earnings growth and cash flow streams. Importantly, we now expect load growth ranging from 6% to 11% in each of our 3 utilities over the next 5 years, paving the way for affordability benefits for customers across our service areas.

Let’s conclude on Slide 15 by summarizing the key updates to the plan we shared with you in February. As previously mentioned, we now anticipate higher load growth and higher revenues for our entire 2026 through 2030 forecast as a result of the fifth ESA we announced today and amendments to 2 previously signed ESAs. Our forecasted 2025 through 2030 retail load growth CAGR is now approximately 7% to 8%, up from our prior forecast of 6%. The amended ESAs accelerate revenue earlier than our previous plan, and the fifth ESA will begin contributing in early 2027. Regarding our potential upside to the 5-year capital plan, we will soon file our Integrated Resource Plans in Missouri and Kansas, which will outline the generation capacity projects needed to serve our projected peak load profile for customers that have been signed to date.

This current view of generation needs is referred to as the preferred plan in those IRPs. The preferred plan will represent modest upside to our $21.6 billion capital investment plan, taking our projected rate base CAGR to approximately 12% compared to our previous disclosure of 11.5%. These IRPs will also articulate the dynamic nature of our customer pipeline and load growth projections, which could require additional capital projects beyond what will be shown in the preferred plan as our business evolves in the months and years ahead. As it relates to our EPS outlook, we are reaffirming our 2026 adjusted EPS guidance midpoint of $4.24. For 2027 through 2030, all years are now strengthened, and we expect annual earnings growth to exceed 8% beginning in 2028 with an upward bias from the ESA additions announced today.

As David discussed on our fourth quarter call, for the later years in our forecast period, we continue to estimate an approximate 250 basis points delta between rate base growth and EPS growth, which is now compared against the approximate 12% rate base CAGR that I described earlier. The benefits of the recently signed and amended ESAs also strengthen our credit metrics. In comparison to an estimated 14% FFO to debt forecast we disclosed on our February call, we now anticipate higher FFO to debt across the entire 5-year forecast. From 2026 to 2028, we expect to be in the range of 14% to 15%, further strengthening thereafter as our large customers ramp towards their peak load. This target range also reflects the impact of the 3-year flowback period for nuclear production tax credits in Kansas.

We understand the importance of a strong balance sheet to our equity and credit investors and many other stakeholders. In short, our strong financial outlook has been bolstered by further execution on the large customer front, which will in turn drive greater affordability benefits for our customers. We believe Evergy has one of the most compelling growth opportunities in the industry with robust growth into the next decades, resulting in sustainable growth and affordability benefits for our customers and communities over the long term. I speak for the entire leadership team in saying that we are excited about the future at Evergy and are deeply committed to successfully executing our business plan and delivering consistent results for our customers, communities, employees and shareholders.

And with that, we will open up the call for questions.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Nicholas Campanella of Barclays.

Nicholas Campanella: So I know I just — Bryan, thanks for the clarity on — it looks like this 500 megawatts is worth about 50 basis points of growth to the rate base CAGR. So you’re pointing people more towards 12%. I know you kind of talked about 250 basis points of lag. So it just seems like you could be well above 9% here. Is there anything that you would kind of flag that’s an offset to kind of that basic walk?

W. Buckler: Yes, Nick, thanks for the question. And I think you interpreted exactly what we were trying to communicate. There’s a lot of great momentum. These are signed ESAs with great counterparties with minimum bills that just give us tremendous line of sight. And so it sounds like you’re hearing what we want you to hear, which is confidence that not only can we exceed 8% in those out years, but it’s trending towards the math you just described.

Nicholas Campanella: Okay. Yes. Sorry to be naive there. And then I know you’ve talked about executing one more ESA in 2026. And you have this bucket of 1 to 1.5 gigawatts into the 2030 window of higher probability. Could you just expand on how many customers that’s made up of?

David Campbell: So Nick, we don’t break out the customer piece, but you can have a sense for how large these customers typically are for the — by the load if you just analyze the load impacts of the 5 ESAs that we’ve signed. So there’s a range of sizes. Some folks are even larger, but there’s a range there that’s reflected. If you look at our 5, they’re generating a peak in the 2.4 gigawatt range. And I would describe the opportunity set is pretty robust across, especially the Tier 1 and Tier 2 categories. There’s some natural advantages that come with the expansion opportunities because you already have a signed ESA where the site is. We’re working with some known parameters, but we also have some very interesting discussions in the Tier 2 category.

And of course, we’re not going to lose sight of the Tier 3 as well. A little more creative solutions required for Tier 3 and that’s likely to be primarily beyond 2030, but we’re excited about each bucket. But the most promising is always, of course, the expansion opportunities where you’ve already got that relationship and you’ve already got an ESA in place.

Nicholas Campanella: Okay. Great. And then just one last confirmation on this new kind of outlook. You’re going to roll in some additional capital, it looks like, and you have an increase in the FFO to debt. Just on the new role, how are you thinking about that communication around equity in 2030?

W. Buckler: Nick, this is Bryan again. Yes, so for capital updates, it’s still where we’ve described it before. When we updated our capital investment plan back in February, we funded that with about 37% equity. So the incremental capital was around 37%. We generally have given a range of 40% to 50% assumption on that going forward. So I think that still applies here.

David Campbell: And Nick, as Bryan mentioned in his remarks, as a result of the additional ESA, the ESA amendments and the settlement reached around the affordability benefits we can provide by flowing back nuclear PTCs over 3 years, our FFO-to-debt metrics have strengthened over the plan. So we’re in that 14% to 15% range and then trending up in that range, particularly as new customers come online in the back half of the plan.

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

Julien Dumoulin-Smith: So unfortunately, I’m going to follow the same direction as Nick here. Hopefully, that’s okay here. But if you can, obviously, you’ve got these 5 ESAs in hand, how do you think about latitude for 6 and onwards? And what I’m getting at here is, how do you think about spare capacity versus transposing incremental ESAs into further generation and supply resources of various flavors? I just want to understand sort of the alignment when you see these next announcements, how much more capital intensity there might be with that? And then also how you think about the sort of the cadence if you have used up the bulk of your capacity, how you would set expectations on this front? Again, obviously, I’m very cognizant of how you just described things a moment ago.

David Campbell: Yes. I appreciate that, Julien. And it’s an insightful question because not every additional ESA is going to have the exact formulaic impact on capital because we — even if you’re going to do some good math and you’ll see it, okay, given the amount of megawatts we added to our peak load, we’ve got a robust improvement in the amount of capital we’re describing. That’s rate base growth that goes from 11.5% to approximately 12%. In some cases, as you add ESAs, there may be — it will be in that range, but maybe a little more capital impact. What I would emphasize is that on our last call, we signaled our confidence that we’d sign one more ESA, and we’ve announced that ESA here on this call. So on this call, we are also announcing our confidence that we’ll sign at least one additional ESA this year.

We have tried to be thoughtful about the long lead time equipment from turbine capacity to the things you need on the T&D side to be in place and have the — basically the equipment available so that we can be able to meet that demand that we see. We’re not going to meet everything in our pipeline, but we’re confident in the expression that we had today that we signed at least one additional ESA. We’ve got turbine reservations beyond what’s needed in the ESAs that we have announced. We continue to work with customers to be responsive to their needs, and it’s typically around the transmission and generation capacity side. So we’ve been purposeful in thinking about our queue and being positioned to continue to grow. So I described that if we have additional ESAs as we expect to have at least one, that will have an impact on the capital plan.

It’ll create some more upward bias and across the board. It will be under the ESA framework, so that will have all the protections and the premium rate that comes along with the LLPS tariff. But we’ve got high confidence that we’re not done. The team has done tremendous work. We’re pleased with how attractive our region is to these large customers. We’ll continue to work with them to find the right locations for those opportunities. We got execution, of course, as we bring the large customers online. But we’re excited about the momentum. We really expect to continue it.

Julien Dumoulin-Smith: Excellent. And maybe just, Bryan, just to follow up on that. How do you think about ATM or block? I mean just as the cumulative capital accelerates here, how do you think about funding it or prefunding it? We’ve seen some companies talk about this in recent days. So curious on your latest.

W. Buckler: Yes. Thanks, Julien. Our equity issuance plan for now is unchanged. It’s $700 million to $900 million per year from 2026 through 2029. Still no needs in 2030 as our credit metrics just become credit — stronger and stronger throughout the forecast period. So that’s $3.3 billion in the aggregate. For 2026, we’ve already priced $125 million. For our remaining need in 2026, we have no plans currently for a block issuance as our needs are easily addressable through our ATM program. So basically, we plan to dribble it out as we go through 2026.

Operator: Our next question comes from the line of Shar Pourreza of Wells Fargo.

Andrew Kadavy: Actually, this is Andrew Kadavy on for Shar. On the amended ESAs, was there a step-up in the amount of final load you’ll be serving? Or is this just a change in the ramp profile? And then can you offer any insight into what spurred that step up?

David Campbell: Sure, Andrew. If you look at — in our material, we try to provide a sense that will give you a really good view of what the — how the total load has changed in Slide 13. So it was in Bryan’s section. So we’re actually detail the megawatts served each year for our — total of our LLPS and our non-LLPS customer. So you’ll see that the peak demand from these customers, relative to last quarter, has gone up to 3,000 megawatts, and it was 2,400 last quarter. So that’s a cumulative increase of 600 megawatts. So that’s the impact of both the amended ESAs and the new ESA. I think it’s fair to say that the new ESA is the main driver of the cumulative increase. Some of the amendments are higher levels over the interim period.

So a lot of — the predominant impact of the higher peak is from the new ESA. The logic for the amended ESAs is that these customers had a high appetite for basically — I won’t say as much as we could provide, but that wouldn’t be much of an exaggeration to say as much as we provide. So we identified an ability to serve them at higher levels. Those customers are interested in doing that. Under the framework of the existing ESAs, we made those amendments. So it was a mutual solution to help serve a customer need that we were happy to be able to serve.

Andrew Kadavy: Great. And then can you give us a little detail on what’s included in and what drove the $0.09 in other tailwind on bucket — in the other bucket on Slide 11?

W. Buckler: Andrew, it’s Bryan. There’s a few items in there. Our C-O-L-I, so COLI, company-owned life insurance proceeds added about $0.03 year-over-year. We had some incremental power marketing revenues that were also a bit higher than prior year. And lastly, our ETR is lower than prior year. So altogether, a modest portion of this $0.09 is favorable to our original plan, but a lot of it is just budgeted activity.

David Campbell: Yes, we’ve got — as we reaffirmed, we’re — there was real mild weather this — the start to the winter, but we’re pleased with the start to the year, delivered solid results and reaffirmed our guidance for the year.

Operator: Our next question comes from the line of Michael Sullivan of Wolfe.

Michael Sullivan: On the regulatory side, maybe if you could just give us a sense of potential to settle the Missouri case this year? And then you seem to be kind of like setting the stage for where rates could be going at Missouri West. When do you plan to file there next? And what is the rate trajectory going to look like after it’s been kind of so depressed in recent history?

David Campbell: A lot there, Michael. So good questions. On the Metro case, the last few cases we filed in both states, we’ve been able to reach settlements. So we’re certainly going to be working towards getting a constructive solution with staff, OPC and other stakeholders in Missouri. They won’t file their testimony until June. So the settlement conference comes later towards the fall time line. So more to come on that. Those settlement discussions actually follow a schedule in Missouri. So we — I noted that in the script when the actual dates are for the settlement conference. So more to come. It will actually — the schedule is after even our next quarterly call. So we’ll see where that goes. But again, we’ve had good progress in the last few rate cases in both states in reaching settlements.

And I’ll note that in our Metro jurisdiction, rates actually went — base rates went down in our last rate case, which was after a 40-year stay-out in Missouri. So the trajectory in Metro has been terrific in terms of the overall rates being much — the trajectory has been far lower than the impacts of inflation. And that affordability focus is one we’re going to continue to have. So Missouri West, the cadence that we’ve had there is typically every other year or so, that would put us on a time line to file a case sort of back part of this year, early next year. And I’ll just reiterate the remarks I made regarding affordability in Missouri West. So overall, for the significant majority of our customers, residential customers, we expect to be in line with or below inflation.

Missouri West, we do expect it’s going to be a little higher inflation over the next 5 years, but manageable over the long term to that inflationary level. And that’s really a result of Missouri West being — having a level of infrastructure investment that’s lower than our other jurisdictions. It’s more exposed to market power trends. So when there have been price spikes, for example, during Winter Storm Uri or when there were flaps in natural gas prices in ’22 and then actually in January of this year, too, that jurisdiction is a little more susceptible. So it needs that infrastructure investment. It’s got by far the lowest rates in our system as well. So the jurisdiction has benefited from the lower investment, but eventually, we need to make sure they’ve got adequate capacity.

So there will be a level of inflation over the next 5 years. But over the long term, we expect to be in that range of inflation. And we really know that Missouri West will benefit from these investments, these needed investments for decades to come. So that’s how I describe it for that jurisdiction. It’s currently our smallest. It’s got very robust load growth. So the good news about the LLPS tariff is that it’s got a premium rate. So Missouri West, we expect to grow 10% to 11% per year in sales growth. That gives a lot more kilowatt hours over which to spread those investments that we’re making. That’s helping to moderate that rate increase trajectory. So it’s a really great situation in Missouri West, which if we didn’t have the large load growth, we would be needing to make this investment, but we wouldn’t have the same kind of incremental sales at our premium customer to spread it over.

So I’ll leave it at that, Michael.

Michael Sullivan: Okay. That’s very helpful, David. And then just in terms of when you’re signing these ESAs with maybe some of the non-AA-rated counterparties, like how important is visibility into ultimately having a hyperscaler offtaker? I think you mentioned this most recent one. We should know more in the next couple of months. And then I kind of go back to the one with Beale from last quarter, where does that kind of stand? So yes, just if you could give us a feel for how important the visibility to a hyperscaler is.

David Campbell: So it’s an important consideration, Michael, no doubt about it. The sophistication of the counterparty, their knowledge of how to bring it together, their ability to line up those end-use customers. The LLPS tariff has a set of collateral and credit requirements that every customer has to meet in addition to having confidence as to who their offtaker is. So we’re not announcing the counterparty today, though we did note that it’s a premier developer. It actually does have a strong corporate rating, BBB+. But all of our customers have to meet the credit and collateral requirements that are in there. So if there’s not a parent with an investment-grade rating in the system, then we’ve got to be letters of credit that follow the terms of the LLPS.

So we — in our ESA discussions, the counterparty situation, making sure we’ve got the right setup in terms of counterparty and credit is a key part of every discussion is how I describe it. Now of course, we have 2 Google — Google is our counterparty for 2 of the data centers. Meta for another. So those are companies with capitalization levels that I [ cannot ] conceive of in the multitrillions. But with the developers that have the strong offtake with hyperscalers, they’re also great counterparties, but they all have to meet the credit and collateral requirements in the LLPS.

Operator: Our next question comes from the line of Paul Fremont of Ladenburg.

Paul Fremont: Great quarter. I was curious if we could get a sense of on Slide 13, what would be the end date in terms of the 3,000 megawatts for peak demand?

David Campbell: Obviously, we haven’t laid that out, but I would describe it as it goes into the — not quite out to the mid-2030s, but it goes out well into the 2030s. And you’ll see that we’ve got an additional 800 megawatts to 1,000 megawatts where we will continue to expand. So it’s a robust growth rate well into the 2030s. And of course, the pipeline that we have, a lot of those discussions are focused on in the 2030 and beyond time frame. So we feel — I’m very confident about the growth rate being sustained in that time line, not only from the same — from the signed ESAs, but also from the customer discussions that are underway.

Paul Fremont: And then I guess, I’m assuming that most of the — all of that increase is based on the new contracts. Has the end year changed significantly from the fourth quarter to the first quarter disclosure?

David Campbell: When you say end year, you’re talking about is the general time line when folks peak load, has that changed materially for the existing ESAs? No. And the new ESA is generally in line in terms of the time line overall in terms of when they’re ramping up. There’s a — folks are — it’s a historic opportunity. So folks are generally on a time line that moves pretty fast. It’s still in the — well into the 2030s, but that time line hasn’t changed significantly, Paul.

Paul Fremont: And I think we’re using like a 5-year assumption. Is that sort of reasonable for — to ramp to full load?

W. Buckler: That’s right, Paul. And these 5 ESAs, they start in years from 2026 through 2028. So some of the 2028 ESAs go into 2032, for example. Hopefully, that helps.

David Campbell: Generally, LLPS has a 5-year ramp rate provision and 10- to 12-year peak provision. So that’s kind of embedded in the structure of the tariff.

Operator: I’m showing no further questions at this time. I would now like to turn it back to David Campbell for closing remarks.

David Campbell: Great. Thank you, Dana, and I want to thank everyone for joining our call today. This concludes the call. Have a great day.

Operator: Thank you. This does conclude the program. You may now disconnect.