Evergy, Inc. Aktie

Good day, and thank you for standing by. Welcome to the Q3 2026 Evergy, Inc. Earnings Conference Call. [Operator Instructions]. Please be advised that today's conference is being recorded. I would now like to hand the conference over to Peter Flynn, Senior Director of Investor Relations and Insurance. Please go ahead.

Thank you, Kelly, and good morning, everyone. Welcome to Evergy's Third Quarter 2026 Earnings Conference Call. We posted a presentation on the Investor Relations page of our website that will be referenced by our speakers. As noted on Slide 2, today's discussion will include forward-looking statements that are accurate only as of the date of today's webcast. Actual results could differ materially from these forward-looking statements due to a number of factors, which are set forth in our earnings release, the slide presentation and our other SEC filings. Management will also discuss certain non-GAAP financial information. Reconciliations to the applicable GAAP measures are included in today's earnings release and slide presentation, both of which are available on the Investor Relations page of our website.

Joining us on today's call are David Campbell, Chairman and Chief Executive Officer; and Bryan Buckler, Executive Vice President and Chief Financial Officer. David will cover third quarter highlights, our economic development progress and our regulatory agenda. Bryan will review third quarter financial results, retail sales trends and our 2026 and long-term 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 third quarter adjusted earnings of $2.58 per share compared to $2.03 per share a year ago. The year-over-year increase was driven primarily by warmer weather, continued load growth, revenue from large customers and recovery of regulated investments, partially offset by higher operations and maintenance and depreciation expense. Year-to-date adjusted earnings were $4.15 per share compared to $3.41 per share a year ago. Brian will discuss the financial drivers in more detail in his remarks.

During the quarter, we worked closely with two of our large customers to refine their anticipated load profiles and update their electric service agreements. As a result, we are announcing three amendments that we expect will increase peak load under those agreements by approximately 250 megawatts, adding incremental large load of the 2027 to 2030 period and beyond. Additionally, we signed a letter of intent with Digital Realty for 1.4 gigawatt expansion project which I'll discuss in more detail on Slide 7. These agreements demonstrate the strength of our customer relationships and continued large customer interest in locating and expanding in our Kansas and Missouri communities.

Operation results have been strong this year with safety, reliability and generation availability trending favorably to Target. Our generation team performed well through a demanding summer, maintaining reliable operations through hot weather and record peak demand for both Evergy and the Southwest Power Pool. Their execution helped ensure that we reliably serve our customers during the most strenuous tests of our fleet and the grid. Given strong year-to-date results, driven by solid operational performance and warmer-than-normal weather, we expect full year results to exceed the top end of our annual guidance range. We are increasing our 2026 adjusted EPS guidance to $4.35 to $4.50 per share, up from $4.14 to $4.34 per share.

We're also reaffirming our long-term adjusted EPS growth target of 6% to 8% plus through 2030, measured from the original 2026 guidance midpoint of $4.24. We continue to expect annual adjusted EPS growth to exceed 8% beginning in 2028 and through 2030. Finally, I'm pleased to announce a 4% increase in our quarterly dividend, bringing the annualized dividend to $2.89 per share. This is in line with last year's increase and consistent with our objective moving toward a payout ratio of 50% to 60% over time. Turning to Slide 6, we highlight the major gains in regional rate competitiveness Evergy has achieved over the past 9 years. This success since the merger that created Evergy directly supports the growth opportunities we're discussing today.

Since 2017, our rate trajectory has remained well below regional peers and far below inflation. The cumulative change in Evergy's all-in rates over that time is approximately 7% compared to our regional peer average of 25% and overall inflation of 33%. Holding electric rate increases to a 0.7% annual rate reflects the scale benefits and cost savings resulting from the merger, promises we made and promises we kept. Our continuous focus on affordability and cost discipline is critical to ensuring all of our customers benefit from a new era of economic development and infrastructure investment. Our commitment is further underpinned by the large load power service tariff or LPS.

Above all, the LLPS protects existing customers by ensuring large customers pay the full costs associated with serving them and their fair share of incremental system costs, all while delivering affordability benefits back to our other retail customers and providing for strong commission oversight. To that end, we recently made a filing to augment our approach in Kansas with the customer affordability enhancement plan, a new vintage of tariffs designed to incorporate the strong guardrails already in place, while generating incremental affordability benefits for our customers. I'll discuss this filing in more detail shortly. We look forward to advancing our affordability objectives and working with Governor like Holscher, who we know from our service to Kansas as a collaborative legislator at the State Senate.

We'd also like to thank Governor Kelly for her leadership throughout her two terms. In our Missouri service territory, we are equally focused on ensuring protections and driving benefits for our customers and communities as we advance our robust Missouri pipeline in tandem with the economic development and growth agenda of Governor Kehoe and state leaders. We understand that new large customers aren't a good fit in every community, and our strategy remains prioritizing large customer projects in areas that are well suited for these developments and backed by local permits and local support.

Turning to Slide 7. Execution of our large customer strategy continues to deliver tangible progress for energy customers and the communities we serve. The amendments we announced today at approximately 110 megawatts of make rental peak load across 2 existing large load SAs. As a result, the 5 executed ESAs now represent approximately 2.6 gigawatts of steady-state peak load, and together with non LPS large customers, we expect these projects to require approximately 3.1 gigawatts of peak load over time. Additionally, we executed a third agreement for 140-megawatt expansion of an existing project. The amendment is contingent on the results of a transmission study expected by the end of this year. We're also pleased to sign a letter of intent with Digital Realty for a 1.4 gigawatt expansion at a site adjacent to their 600-megawatt project with assigned ESA as announced on our Q1 earnings call.

Together, these projects represent 2 gigawatts of load with Digital Realty. This LOI demonstrates alignment on commercial terms, and a shared interest in investing in Kansas to deliver affordability benefits to our customers and enable economic growth in the local economy, part of a 9,000-acre industrial site, formerly a large U.S. Army ammunition plant that has since been remediated, that is well suited for this type of development. We anticipate executing an ESA in the first half of next year. Each of our 5 ESAs operates under a large load power service tariff for LPS which includes premium demand rates, binding, minimum bills and meaningful credit and collateral protections.

This framework is designed to ensure that large customers pay their direct costs and a fair share of existing and new system costs. while helping spread fixed costs across our broader base for the benefit of existing customers. We are very encouraged by the momentum across our pipeline and are advancing multiple expansion opportunities with current customers and several projects with prospective new customers. Over the next 12 to 18 months, we see the potential for a steady cadence of pipeline conversions to announce ESAs. These agreements would further establish Kansas, Missouri as premier destinations for infrastructure investment and contributed significantly to economic growth and long-term prosperity across our region.

Slide 8 summarizes the progress we've made in converting our large customer pipeline and signed agreements and provides an update on activity further down the queue. Starting the top row, the now 3.1 gigawatts of Tier 1 customers with active operations or binding ESAs, enables a transformative growth opportunity for Evergy and the communities we serve, supporting our expected 7% to 8% annual retail load growth through 2030. This total consists of projects already in operation, progressing towards a steady state of 1.4 gigawatts and as well as 1.7 gigawatts of additional projects that have executed ESAs, all of which require minimum monthly bill provisions, expanding 15 to 17 years, whether or not the capacity is full even.

Regionally, these will deliver significant benefits, including supporting a leading-edge economy, creating jobs and significantly expanding the local tax base, enabling us to spread system costs over a broader loan profile to maintain affordability for all customers. In the next category, we highlight approximately 2.0 to 2.5 gigawatts of Tier 1 expansion opportunities that are at or adjacent to our existing customer sites. This category includes the potential 1.4 gigawatt expansion with Digital Realty that I described earlier. Agreements related to these opportunities will require amending load ramps in existing SAs or new assets. In tandem, we are working on the transmission and generation solutions to enable them.

And to be clear, our 5-year financial plan does not yet incorporate any impact from these potential expansion projects, including the 1.4 gigawatt Digital Realty expansion, and the 140-megawatt contingent dirt ESA amendment described today, all of which would create additional growth into the 2030s. Our Tier 2 category includes approximately 1 to 2 gigawatts of advanced discussions with new customers. These projects have 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. All of the projects in our expansion opportunities in advanced discussions categories made meaningful progress in recent months. We look forward to converting a large portion of these prospective customer initiatives in the ESAs in the quarters ahead.

The remaining pipeline totaling well over 10 additional gigawatts highlights robust activity and a sustained interest in our region. Serving this load will require working collaboratively 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 Q evolves. And before I move on to the next topic, I will summarize by saying that we continue to have a high level of confidence in achieving a total of 5 to 7 gigawatts of large low customer agreements, which will drive significant affordability benefits for our existing customers and exceptional growth for the company well into the 2030s.

Moving to Slide 9, we are pleased to reach a partial revenue requirement settlement in our Missouri Metro rate review in October. Select items remain open for commission evaluation outside of the partial revenue settlement with staff, including return on capital. If the settlement is approved and if the midpoint of staff testimony, our return on capital is used 7% return on equity with a 52% equity ratio. We expect the revenue increase would equal approximately $118 million before the impact of large load. In addition, we filed a partial stipulation agreement related to the LLPS tariff. If approved, the settlement would deliver approximately $60 million of net benefits from new large customer revenues, resulting in a total net revenue increase of approximately $58 million.

Relative to our last rate case in Missouri Metro, the 2022 rate review, this increase would represent a 1.5% annualized impact. Relative to the end of 2017, the annualized impact is just 0.7%, incredible story for our customers when compared to the rate trajectory of other Midwest utilities and the cumulative impact of inflation in the U.S. economy over the same time period. Missouri Metro was the first rate case that we have advanced with LLPS customers, delivering $6 million annually to the benefit of reducing residential customer and industrial customers. serves as an early and powerful example of how a large customer strategy can deliver meaningful affordability benefits to all. In addition, the agreement provides for an earnings sharing mechanism.

In the event of large load revenues drive improvements in realized returns, earnings above the specified level would be shared 65-35 between customers and shareholders with customers receiving 65%. We believe these settlements provide a constructive path forward for customers and the company. We expect a commission order in December with new rates in January 2027. On Slide 10, I'll provide a brief update on our regulatory priorities in Kansas and Missouri. In Kansas, our natural gas, solar and battery storage predetermination proceeding is underway with an order expected by April 2027. These new resources are consistent with our all-of-the-above approach to meeting growing customer demand while maintaining reliability and affordability. Staff testimony is due January 6, followed by a settlement conference on February 4.

On October 29, we requested approval of our LLPS customer affordability enhancement plan in Kansas. Since the approval of the LPS tariff in November 2025. The marketplace for large load and new generation projects has continued to evolve. The enhancement plan is a proactive approach to build on the strong foundation of the LLPS tariff and add new tools. including a vintage cost rider to accommodate higher cost of new generation resources as well as nonrefundable advance payments. In tandem, these mechanisms would increase the financial contribution from new large load customers towards the investments needed to serve them. We believe these enhancements will generate additional affordability benefits for existing customers while further strengthening the financial framework supporting our large load growth strategy all while ensuring transparency and strong oversight from the Kansas Corporation Commission and other stakeholders.

While a procedural schedule has not yet been approved, we anticipate an order by midyear 2027. Separately, we filed a motion seeking clarification under our existing LLPS tariff that would allow voluntary customer advance payments prior to energization, a similar feature to the one filed as part of our customer affordability enhancement plan. We filed a settlement on October 30, which, if approved, would apply these conditions to future customers taking service under the existing LLPS vintage. We anticipate a commission decision in the coming months. Moving to Missouri. We filed a rate review from Missouri West on November 3. This case is primarily driven by new generation investments for which we've received CCN approvals as well as beneficial grid modernization projects that improved reliability for our customers.

As we've discussed in the past, Missouri West is our smallest utility, with some of the lowest rates in the region and in the country, reflecting in part the need for significant infrastructure investment including new dispatchable generation to reduce reliance on market energy. These investments will enhance reliability while supporting economic development and low growth. Importantly, our request also reflects approximately $61 million of revenue offset from largely customers, demonstrating how the benefits of low growth can accrue to existing customers in this jurisdiction similar to Missouri Metro. Longer term, as these benefits continue to grow as these customers ramp up these new large customers.

We remain confident in our ability to manage residential rate increases toward inflation while delivering the infrastructure needed to support reliability economic development and continued low growth. We look forward to working constructively with the Missouri Public Service Commission and stakeholders throughout the process to achieve a balanced outcome that supports much-needed investment in Missouri West while maintaining competitive rates and delivering long-term benefits for customers. Similar to Kansas, we also continue to make progress with our request for generation investments for Missouri customers. Our CCN request includes a new natural gas plant solar farm and battery storage facility. A settlement conference is scheduled for January 14 and evidentiary hearings on February 24.

And lastly, we were able to reach a nonunanimous stipulation and agreement for our CCN request for a second combustion turbine at Mullen Creek, and we anticipate a commission order by January. These proceedings represent important steps in advancing the generation of investments needed to support reliability and capacity needs for our growing customer base. I'll conclude on Slide 11 with the core tenets of our strategy: affordability, reliability and sustainability. Affordability remains central to our decision-making. Our capital investment plan is elevated relative to historical levels, but so too is the low growth supporting it. Large customers pay premium rates and fund the direct costs required to serve them while their additional usage spread system cost over a larger base.

That is the value of our large load growth strategy, investing meaningfully in the system while leveraging incremental demand from new large customers paying premium rates. And reliability is equally fundamental. We are investing in grid modernization, resiliency and new generation capacity while maintaining strong operating performance across our transmission, distribution and generation fleets. Our teams remain focused on safety, customer service and dependable execution as we enter a period of significant construction and growth. And with respect to sustainability, we are inventing a cost effective, all of the above generation portfolio. Our planned investments in an efficient natural gas generation, solar resources and battery storage are designed to meet growing demand, preserve reliability and support the long-term prosperity of Kansas and Missouri.

We have positive momentum, a clear strategy and a motivated and aligned team. We are well positioned to convert unprecedented customer demand into durable long-term growth and meaningful affordability and economic development benefits for our customers and communities. I will now turn the call over to Bryan.

Thank you, David. Thank you, Pete, and good morning, everyone. I'll begin on Slide 13 with a review of our third quarter results. For the third quarter of 2026, Evergy delivered adjusted earnings of $610 million or $2.58 per share compared to adjusted earnings of $475 million or $2.03 per share in the third quarter of 2025. As shown on the slide from left to right, the year-over-year drivers were as follows: [indiscernible] demand and large customer revenues contributed $0.46 per share. Cooling degree days were 31% higher than the third quarter of 2025 and 26% above normal. This category also benefited from weather-normalized demand growth of 4.5% and increased large customer revenues from data center projects currently operating.

Next, return on and recovery of regulated investments was driven by new retail rates in our Kansas Central jurisdiction and FERC regulated investments, which in total contributed $0.17 of EPS. The Offsetting these favorable drivers was the combination of higher O&M and increased depreciation and interest expense net of AFUDC related to our capital infrastructure investments, which drove a $0.15 decrease in EPS. And finally, other items increased earnings per share by $0.07. As David noted earlier, we've generated strong financial results through the third quarter and are raising our full year 2026 adjusted EPS guidance range to $4.35 to $4.50 per share from our original guidance range of $4.14 to $4.34 per share. Our updated guidance range includes an expectation to make targeted O&M reliability investments in our distribution grid and generation fleet during the fourth quarter.

Turning to Slide 14, I'll provide more detail on retail sales trends. Weather-normalized retail demand was strong with 4.5% growth in the third quarter, that level of growth is worth highlighting. A 4.5% increase in weather normalized electricity usage is well above what we've experienced in recent years and provides evidence of the step change in demand growth underway across our service territory. We believe this marks the beginning of a period of transformational growth, which we expect will accelerate, especially beginning in 2028 and create meaningful benefits for our customers, our communities and our company in the years ahead. The weather normalized results in Q3 include residential demand, which increased 0.8%, commercial demand, which increased 8.7% and industrial demand, which increased 3%.

Commercial growth reflects increased data center customer usage, while industrial results were driven primarily by Panasonic's continued ramp of operations. On a year-to-date basis through September 30, when the normalized retail demand is up 3.7% and tracking in line with our expectations for the full year of 3% to 4%. At a macro level, the robust customer demand in our service areas is supported by a solid labor market as Missouri, Kansas and the Kansas City metropolitan area unemployment rates remained below the national average. Our attractive service territories also continue to benefit from population growth and in-migration contributing to continued growth in residential customer counts. And few regions in the United States are as well positioned to benefit from the accelerating investment cycle in power infrastructure and AI-driven data centers as the Kansas City metro area including the cities of Overland Park, Kansas; Lenexa, Kansas; and Kansas City, Missouri as well as many other towns throughout Kansas and Western Missouri. The region's deep concentration of EPC firms and highly skilled engineering talent creates a competitive advantage that should drive sustained economic development, employment growth, increased electricity demand across both Kansas and Missouri for years to come.

Moving to Slide 15. We highlight our updated large load demand growth profile. The 5 executed LLPS ESAs, together with non-LLPS customers are expected to support 3.1 gigawatts of peacode over time. including today's binding ESA agreements that added 110 megawatts of peak and increased load across each year 2027 through 2030. In total, aggregate large customer demand is expected to build from approximately 350 to 400 megawatts today to approximately 2,250 megawatts in 2030, further expanding to 3,100 megawatts post 2030 at its peak. As a reminder, Digital Realty's 1.4 gigawatt expansion project and the aforementioned 140-megawatt expansion agreement are not reflected in these numbers, and therefore, would represent upside to this forecast potentially as early as 2029 and 2030.

This chart illustrates a powerful period 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 the ESA LLPS contract terms that are generally spanning 16 to 17 years. In addition, we continue to make strong progress with several other large customers across multiple industries, and we remain very confident in the pipeline and our ability to continue converting these opportunities into executed ESAs for the next several quarters. The associated load and capacity from these potential incremental ESAs would represent further upside to load growth over the long term, and importantly, has the potential to extend our exceptional oil growth well into the 2030s.

As David described, we will continue working in a measured and disciplined manner through our substantial pipeline of prospective customers to build on the success we have achieved to date. Let's close on Slide 16 by summarizing our long-term growth outlook. First, based on signed ESAs and announced large customers that we expect will ultimately reach a steady state of 3.1 gigawatts, we forecast retail demand to grow approximately 7% to 8% annually through 2030. Additionally, ESAs would extend this growth profile with the largest impact expected in the 2030s. Secondly, our $21.6 billion capital plan supports strong foundational earnings growth. In fact, our 2026 IRP preferred plants provide approximately $1 billion of incremental investment taking our estimate of 5-year CapEx through 2030 to $22.5 billion, increasing -- which increases our projected rate base CAGR through 2030 from 11.5% to approximately 12%.

Additional large mode ESAs would provide further investment upside, and we'll update our capital plan on our fourth call in February. Regarding the Digital Realty expansion project, we anticipate owning the vast majority of the generation resources needed to serve their load. For this project alone, we anticipate capital investments could be in the neighborhood of $4 billion. To fund our investment plan, we will use -- we will utilize our expected strong cash flow from operations and reinvested earnings, along with a prudent mix of debt and equity financing to support our strong investment-grade credit rating and FFO to debt that we currently project to be in the range of 14% to 15% from 2026 to 2028, continuing to strengthen in 2029 and 2030.

On the equity front, we have made solid progress utilizing our ATM program with approximately $700 million of common equity price as compared to our forecasted average of approximately $700 million to $900 million annually through 2029. We have used our ATM program throughout this year to meet all our equity needs. Similarly, as we think about the rest of this year, we believe that our remaining needs will be addressable through issuances under our existing or any potential replacement ATM program.

Turning to our EPS outlook. We are reaffirming our long-term adjusted EPS growth target through 2030, up 6% to 8% plus measured from the original 2026 midpoint of $4.24 per share. For 2027, we are reaffirming our expectation to grow earnings per share in the 6% to 8% range. And we continue to expect adjusted EPS growth to exceed 8% annually beginning in 2028 and through 2030. As we have discussed on prior calls, we continue to forecast an approximate 250 basis point delta between rate base growth and EPS growth in 2028 and through 2030 and compared against an approximate 12% rate base CAGR discussed earlier. Driving on average 9.5% EPS growth annually in those 3 years. As a reminder, our financial forecast only incorporates the ESAs we have signed today with further upside to and/or extension of our exceptional growth well into 2030s, if additional ESAs of significance are signed in the future.

In summary, continued execution of our large customer strategy is further strengthening our financial outlook, supporting long-term growth and delivering meaningful affordability benefits for our customers. Lastly, with respect to the current year EPS outlook, we are raising our 2026 adjusted EPS guidance range to $4.35 to $4.50 per share compared to our prior range of $4.14 to $4.34 per share primarily due to favorable weather in the third quarter. I'd like to join David in thanking all of our employees for the strong operational and financial results year-to-date and most importantly, for working safely and keeping our customer rates as some of the lowest in the nation. And with that, we will open the call for your questions.

[Operator Instructions]. Our first question comes from the line of Richard Sunderland of Truist Securities.

Good morning. Thanks for the time today. I wanted to start with that DLR update, the $4 billion CapEx potential for that project, could you speak to how much that could fall in the next 5-year period and what impact that may have on the kind of 12% upside rate base growth you quantified in the script there.

We won't go into those details today, but I will emphasize that this is a site where DLR has shown strong interest. You've heard them comment on it really for the past several months. It's at a great location for this kind of development. It's the old sunflower U.S. Army Ammunition Plant. It's over 9,000 acres, which is almost 60% the size of the island of Manhattan. So it's an old ammunition plan that's been remediated. It's well suited for industrial uses now, but really for that kind of purpose. So we're thrilled the DLRs made their big investment in that territory. And the LOI that we've signed reflects alignment on commercial terms, contemplates that we need to make sure they get any remaining local approvals and is aligned with our enhanced tariffs that we're seeking approval for. So we expect to sign an ESA in the first half of 2027.

The time line for the bulk of that is really into the 2030s. But we'll really give details about the specifics once we get that signed. But we're very excited about that opportunity sufficiently so that we are comfortable announcing on today's call. and as well as we anticipate that we would be providing the capacity to serve, which, as Bryan described, as in and of itself in the range of $4 billion of capital. Now typically, that capital trends along with when the ramp rate will occur and you need to have it in place little bit in advance. And again, the bulk of this will probably be in 2030 and beyond when it really hits its ramp. But there'll be meaningful capital that will be associated with this and under a structure with enhanced provisions on the LPS, all reflecting really our twin objectives, making sure that we've got a tariff where the large customers are paying their direct costs. And their share of any incremental system costs so that there are real benefits driven to our existing customers and making sure it's that at sites that really makes sense for this kind of activity. So again, we have more details when we sign the ESA and give a broader update. We're really excited about this partnership and opportunity.

So that's a helpful overview, and maybe I'll follow up on that last point around the enhanced LLPS. Can you speak a little bit more to kind of the process out of that filing is -- is it something you could see settled on a more expedited basis than kind of a full procedural schedule contemplate? And I guess, if settled, could that also expedite finalizing the DLR USA.

It's a great question. I do think it is a proceeding that can move under a more accelerated schedule, certainly than relative to a rate case. But it is a proceeding where you want to make sure you get full input from stakeholders full commission oversight. You'll recall we went through the process with the original large load power service tariff because we wanted to make sure we had something that had full input and oversight and that we've signed that first wave of VSAs after we got that LLPS finalized. And that agreement in Kansas, I'll remind you, was a unanimous settlement. So the residential representative curb representative of the large industrial customers, existing customers, staff, all the stakeholders were participants in that settlement, which ultimately was approved by the commission. So we see the value of going through the process.

I do think that we will -- we do expect it to resolve in the first half of the year. we're well aligned with DLR and what they're seeking to approve the investment they've made in the land and what they're seeking to achieve. So we like this approach because it makes sure that we're delivering on that protections for existing customers that actually end up delivering benefits for customers and having a site that everyone's alone. So we expect those to move in tandem with ESA in the first half of the year.

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

So, I just wanted to ask just with the new leadership in the state of Kansas, obviously, there's been different views on large load customers through elections broadly. But you also have many opportunities that are in the Tier 1 bucket that are just expansions of current sites that I believe are already permitted or maybe ready to go. Can you just talk to how resilient the pipeline is if there is a change in policy understanding that there is real economic development and affordability benefits to these customers. Can you talk to that at all?

You bet, Nick. Great question, and thank you. So I'll first note that we look forward to working with government Holscher in Kansas. We know her from her service in the Canada Senate, where she has a collaborative legislator and supportive generally of critical infrastructure serve Kansas. I'll note that there weren't really any major state-wide elections in Missouri. So Governor Kehoe, Key state leaders are still in place there. what I'll remind folks of about Kansas, big change with respect to electing a Democratic U.S. senator. That hasn't happened for over 90 years. But in the state elections in Kansas, unlike some of the other states where there's a lot of news, what the result of those state elections is actually a continuation of the status quo.

Outgoing Governor Kelly is a 2-term Democratic governor. We worked collaboratively with her throughout her 8 years and thank you for her service to the state. Throughout that time, there has been a Republican majority Kansas Senate and a Republican majority Kansas House, and that's actually the status quo that will continue after this week's election. So a Democratic governor and a Republican majority Senate and Republican majority house. And with that split between the branches of the government, we worked effectively throughout that time, including passage of some very important legislation supporting infrastructure development and economic development in recent years.

So overall, we continue to have high confidence in achieving 5 to 7 gigawatts of large load customer agreements. So capitalizing on the pipeline that we have. as you noted, a big chunk of that are expansion in existing sites, and it's a pipeline that's balanced across both states. Once you take account of the DLR letter of intent that we signed today, the majority of the expansion opportunities and advanced discussions in Tier 1 and 2 are actually on the Missouri side. But as you noted, what I'd emphasize is that our approach will continue to take in both states is one that really focuses on making sure that we have a tariff in place that has large oil customers paying directly for what they the costs we need to incur and making sure that they're paying their share of incremental system costs so that it's really delivering benefits for existing customers, why we filed for the enhanced tariffs.

And we're also really focused on sites that work well for local communities and the sunflower site for DLRs LOI is a great example of that. It's a that really is only going to be well suited for industrial applications like this 1 in a massive acreage so you can have it in the right location. So we feel good about our pipeline, the benefits that we'll deliver as we look across our two states. And as you noted, in particular, as we look at a lot of these are expansions and a robust pipeline across both Missouri and Kansas.

That's great. I really appreciate it. And then thanks for the commentary on the $4 billion for DLR, just as we think about additional opportunities maybe outside of generation, SPP and the new ITP portfolios for '27 have been getting previewed. And obviously, those are going to get whittled down. But could you just give any sense of how much capital would be at play there? And I know a lot of this would maybe 2030. But is there a way to kind of put a framework around what the available opportunity set is for the next ITP?

It's probably early days to specify what the exact opportunity is other than to note that as you cited, it's a very robust overall program, the integrated transition plan that released about $20 billion, about $10 million of that involving projects that span across our service territory. Now there are going to be some important decisions to be made that haven't yet been made, how much of those will be competitively bid. How much will be noticed precede projects given a short-term reliability time line, that will have implications. And also what the ultimate time line is to build. A big chunk of those are 765 lines. which are certainly more efficient relative to the overall cost and land usage if you're going to have to build two 345s. But how much precedent for building those yet, certainly across our service territory.

So there's still some work to do. I would describe it as long-term upside. It's not in our current capital plan. And as we described, there are some significant drivers of additional upside in the capital plan that we see. So there's potential opportunity into the 2030s. I've been around long distance and long-term transmission build earlier in my career. So I shared with you it's likely into the 2030s. So I view it as something that could be a driver in not only incremental ESAs, carries in the decade. That's also when we get into the retirement phase for some of our older coal units. We have a number of wind and ruble PPAs will roll off in the time frame. I expect electrification will be a driver. And this transmission is another piece. It's a part of the overall long-term tailwind that outside.

Our next question comes from the line of Steve D'Ambrisi from RBC Capital Markets.

Just to add a quick one or maybe two. On the $4 billion of upside capital to serve potentially this 1.4 gigawatts of Digital Realty LOI. Can you talk a little bit about the resource mix that you think is appropriate to serve that? And then I just have a follow-up.

Sure. I think if you -- you'll see in our slide a listing of the things that are included in our most recent integrated resource plan. Now those are our resources that are serving the agreements that we've already signed. But the mix that you'll see, I think, is pretty representative of what we'd look for going forward. there's a need for dispatchable baseload generation. So highly efficient natural gas resources that we've been committed to investing in so far and then receive approval, we expect to continue to be an important part of the mix.

But along with that, solar and storage, it's possible that over time, some of the large customers will bring resources in the system. But most of the customers with whom we're having discussions now are looking for us to provide the capacity in a system resource. So I think that mix of renewables and natural gas with a little bit of a balance towards dispatchable generation to make sure that we can meet the capacity energy needs to large customers. I expect you'll see that as pretty representative going forward as well.

Yes. And Steve, just to add to that. If you think about the ramp rate for Digital Realty, it probably started in 2029, really kicks in, in earnest in 2030 and then ramps up each year thereafter through 2033. So as David mentioned, you're looking at something that looks like solar and battery storage by 2030, 2031. So some of that capital would come in service within our new 5-year plan that will roll out February or whenever we update the 5-year plan for digital really could be a few months after February. But that's a mix that all -- you'll see once we finalize that ESA come into a 5-year view. And we kind of just have a rule of thumb. When you think about a 1 gig customer and whether it's Digerati or others, we could have several of those type projects going forward.

The rough math on that is about $3,000 at KW. That's kind of going rate for a combined cycle today, which continues to go up. But think about it, we use about a $3 billion per CapEx per gigawatt of customer, and we expect to have multiple of those over time and are adding up to multiple over time and roll thumb to our rate base CAGR, that would roughly equate to about 200 basis point increase to rate base growth.

Very helpful. And Bryan, you kind of -- maybe I bury the lead or you kind of answered my next question, but with the rest of the expansion opportunities bucket, if Digital Realty is $1.4 million and then you've got the 140 megawatts. I mean we've been tracking, obviously, a very large opportunity in Missouri that we think is in that bucket. Just can you talk a little bit about -- I guess, can you talk a little bit about what is the rest of that to 2.5 expansion opportunities bucket look like? And then what are the gating items to converting that into ESAs because it does seem like there's a significant amount of activity at some of these sites.

Yes. Steve, I think it's similar to what David described around digitally. The -- those -- that pipeline is real. They have real sites. They still need to get through their full suite of local permitting for the larger expansion opportunities or new projects, you're going to see those fall under an enhanced type of LLPS, similar to the 1 that we've filed in Kansas and when that David described, that will make sure they're paying their full fair share. It will cover aspects such as CWIP and rates, which will provide, again, additional affordability benefits for customers as well as allow for advanced payments of future revenue streams.

So it's a really broad type of LLPS framework as we move into some of these larger loads for the next wave of customers. We feel great about them across both states. The pipeline, as David mentioned, is deep in both states. And so if we ever -- so I kind of leave it at that, Steve. It's just one that we continue to have a very high level of confidence in achieving the total 5 to 7 gigawatt opportunity, and we'll continue to finance it in a balanced way like we have in the past.

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

It's actually Andrew Kanavy on for Shar. So with the large load pipeline additions and some possibility of having some advanced payments. Can you talk about maybe the impact that might have on your equity issuance plans moving forward? And could that also maybe push out some future rate cases?

So I'll ask Bryan to supplement, but you hit on it. I think there are several features of the enhanced LPS that are attractive. One is that it's in effect adding to the LPS structure, given that the cost of new build is rising. We're making adjustments to the LPS to take account of those higher costs and making sure the new customers are paying for that and paying their fair share. And there's also a feature that has advanced payments. That mitigates the financial impact of CWIP, potential financial impact of CWIP during the build-out phase before the compressors reach their full ramp. And as a knock-on effect also helps from an overall cash flow perspective, because you're making sure that you're receiving some cash payments as you're going through that build-out phase.

So I think it is, most importantly, a set of enhancements that ensure that we have protections for existing customers and are delivering benefits for existing customers. and we're adjusting to market circumstance that has evolved. But I think it's also a mechanism that can allow for a little bit more efficient overall financing strategy. And as we announced CSAs and potential expansions to capital plans associated with them. Obviously, we'll talk about the net strategy associated with it. I don't know if there's anything you'd add?

Nothing to add. Andrew, did that answer your question?

Yes, very helpful. And then we've seen weather be both a headwind and a tailwind for Evergy. With the data center load ramping, does the cooling load that brings online, does that increase EPS sensitivity to weather? Or would the higher baseline kind of reduce that sensitivity?

Well, I think net overall will likely reduce the sensitivity. You're going to have some high -- a significantly higher percentage of high load factor customers whose load levels are going to be more consistent than the current mix, which is still relatively highly weighted as legacy [indiscernible] business. We've got a pretty high mix of residential and commercial. It's more sensitive to weather. So I think as we add the higher load factor customers, they were not immune to the temperature, but their load factors are more driven by the underlying demand for the servers and other equipment that they're running. So we think it will reduce over time.

We'll continue to evaluate as it makes sense in our jurisdictions, whether there are mechanisms to sort of dampen the impact of weather. I've now been at Evergy is my sixth year. And there have been some significant volatility in weather, and that can go to customers' benefits in years like '24 and '25 when it's a milder summer and lower bills. And then when the years like '22 and '26 when it's a hot summer, it just creates a little more volatility. So they're many jurisdictions that have opted for some dampening or smoothing, not something that's been of interest in the past for our regulators, but that may be a conversation to have over time. But to your point, the mix overall will shift in a way that will reduce the overall sensitivity at least on a percentage basis.

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

Great. Thank you, Kelly, and thanks, everyone, for your -- I think the mic would have been on there for someone. Thank you, Kelly, and thanks, everyone, for your participation in today's call. We look forward to seeing you at EEI, and have a great day. We'll wrap up there.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

Good day, and thank you for standing by. Welcome to the Quarter 2 2026 Evergy Inc. Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would like to now hand the conference over to your first speaker today, Senior Director of Insurance and Investor Relations, Peter Flynn. Please go ahead.

Thank you, Courtney, and good morning, everyone. Welcome to Evergy's Second 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 second quarter highlights, economic development, our planned resource additions and our regulatory agenda. Bryan will cover our second 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.

Thanks, Pete, and good morning, everyone. I'll begin on Slide 5. This morning, we are pleased to report second quarter adjusted earnings of $0.88 per share compared to $0.82 per share a year ago. Our results were driven primarily by the recovery of regulated investments, load growth and revenues from our large load customers, partially offset by higher operations and maintenance and depreciation expense. Our solid results through June put us on target for the midpoint of full year 2026 adjusted EPS guidance of $4.14 to $4.34 per share. Bryan will cover our results in more detail.

Safety is a core value within our organization, and I'm also pleased to report that our 2026 safety performance is trending favorably to target. This result reflects the commitment of our employees and the effectiveness of our efforts to drive continuous improvement through training, accountability and operational discipline. We are encouraged by our progress, and it's imperative that we remain disciplined going forward with the goal of sending every employee home safely every day. I also want to recognize our employees for their relentless efforts to keep the lights on during a very active Q2 storm season.

In early June, we experienced back-to-back severe storms that generated straight-line winds [indiscernible] of miles per hour and multiple tornadoes that caused extensive damage across our service territory, ranging from Central and Southeastern Kansas through the Kansas City metro area. Despite these challenging conditions, our team safely restored power to more than 300,000 customers over the course of the week following the storms.

We are proud of the extraordinary efforts of our transmission and distribution teams, contractors, call center representatives and customer service and communications teams and their hard work, commitment to safety and focus on serving our customers throughout the restoration process. Their dedication reflects the very best of our company. In fact, we had a major storm go through part of our territory today and they're hard at work again this morning restoring power.

In terms of reliability, we have demonstrated solid performance through the first half of the year. Our added duration and frequency metrics are tracking well relative to target, demonstrating the benefits of our continued grid investments and the efforts of our transmission and distribution teams. I'd also like to recognize our generation team for the strong operational performance of the nuclear fossil and renewable fleet during the first 6 months of the year.

In addition to our confidence in hitting our 2026 earnings guidance, our long-term fundamentals as a company continue to strengthen. That starts with the outstanding work that our employees do every day to deliver safe reliable power. Building off of that foundation, our customer and economic development prospects continue to be exceptionally strong, as I'll speak to momentarily. When we put it all together, we have high confidence in our plan, and we are 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 and through 2030. Slide 6 summarizes our data center announcements to date. In aggregate, we have executed ESAs for 5 data center projects under our LLPS tariffs, securing the strong protections that the tariff requires for current customers. These 5 ESAs include steady-state peak load of approximately 2.5 gigawatts, when including the 500 megawatts of steady-state peak load from non-LLPS large customers, such as Panasonic and smaller data centers, the total reaches 3 gigawatts.

We continue to make progress towards agreements on expansion projects and are highly confident that we'll execute at least 1 more ESA in 2026. We anticipate providing more details on our third quarter call in November. Momentum with our customer pipeline and discussions on new projects is outstanding, and we expect that to continue into 2027. As a reminder, any additional ESAs would represent further upside and/or extension to the remarkable load growth and business expansion created by the 3 gigawatts of large customer saves already signed. These economic development wins solidify Kansas and Missouri as premier destinations for data center customers and will empower growth, enable investment and help drive prosperity for our region.

Slide 7 summarizes the progress we've made in converting our large customer pipeline and just 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 for Evergy, supporting our expected 7% to 8% annual retail load growth through 2030. This total consists of projects already in operation, progressing towards a steady state of 1.3 gigawatts as well as 1.7 gigawatts of additional projects that have executed ESAs, contractually requiring minimum monthly bill provisions spanning 16 to 17 years, whether or not the capacity is fully utilized.

Regionally, these will deliver significant benefits, including supporting a leading-edge digital economy, creating jobs and significantly expanding the local tax base, while enabling us to spread systems costs, over a broader load profile to main affordability for all customers. In the next category, we highlight approximately 2.0 to 2.5 gigawatts of expansion opportunities, up from the 1 to 1.5 gigawatts we disclosed last quarter. These expansion opportunities are at or adjacent to our existing customer sites.

Further agreements -- or excuse me, future agreements related to these opportunities would require amending load ramps and existing ESAs or new ESAs and we are working on the transmission and generation solutions to enable them. And to be clear, our 5-year financial plan does not incorporate any impact from these potential expansion projects, which would create upside in the near term and well into the 2030s depending on individual product timing. Additionally, we are in advanced discussions with multiple new customers in our Tier 2 category, representing approximately 1 or 2 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 Tier 1 expansions and Tier 2 customer opportunities reflect strong momentum with multiple additional projects that would further extend our exceptional earnings and load growth well into the next decade. The remaining pipeline totaling well over 10 additional gigawatts highlights a robust activity and sustained interest in our region. Serving this load will require working in tandem with our customers 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 a C evolves.

Slide 8 provides an overview of our expected resource addition that will support this load growth. First, resource additions reflected in the table are consistent with our February 2026 CapEx plan of $21.6 billion over the next 5 years. Informed by our 2026 IRP preferred plan in Kansas and Missouri, we now expect approximately $1 billion of incremental capital driven by the generation resources needed to serve the customer agreements we have secured. In total, the preferred plans through 2032 include more than 5 gigawatts of new additions with approximately 3.9 gigawatts of natural gas, nearly 800 megawatts of solar and 450 megawatts of battery storage.

This resource mix reflects an all-of-the-above approach that supports reliability, affordability and long-term customer needs while positioning Evergy to serve significant economic development across Kansas and Missouri. Of note, additional load beyond the 3 gigawatts signed to date is expected to require incremental generation resource needs and incremental CapEx as a result. The 2026 IRP planning process involved identifying the most cost-effective plan that reliably serves our customers across uncertain future scenarios. These natural gas additions, combined with solar and battery storage, are planned in a manner that will allow Evergy to take advantage of best-in-class efficiency and technology and support economic development in our service territory while at the same time helping to advance our strategic objectives of affordability and reliability.

Moving to Slide 9, I'll provide a brief update on our regulatory priorities in Kansas and Missouri. On the Kansas side, we have filed notice for an upcoming predetermination application which is planned to include 3 generation assets, a new natural gas plant, a solar farm and a battery storage facility. These new additions are consistent with the 2026 IRP preferred plan. We look forward to sharing more specifics when the application is filed later this year. Pivoting to Missouri, we continue to work through our pending Missouri metro rate cap.

The procedural schedule calls for rebuttal testimony by August 11, and server bottle and true-up direct testimony on September 10, settlement conferences commencing September 23 and hearings beginning October 5. We look forward to working collaboratively with our regulators and our stakeholders to achieve a constructive outcome for our metro customers. Similar to Kansas and Missouri, we have filed notice for an upcoming Certificate of Convenience and Necessity Request or CCN, related to a new natural gas plant, a solar farm and a battery storage facility. We will share more details once the applications are filed.

Separately, we are having -- we have a pending CCN request for the planned Mullen Creek #2 facility, a 440-megawatt simple cycle gas turbine located in Notaway County, Missouri. STAT report is due September 15, followed by a settlement conference on September 22, with hearings beginning October 19. I'll conclude my remarks on Slide 10, which highlights the core tenets of our strategy. We remain committed to keeping customer rates affordable while making the investments necessary to support reliability, economic development and long-term growth. We have delivered significant improvements in regional rate competitiveness since our company was formed in 2018 and are today, averages average residential customer rates are below national and below Midwest averages.

Consistent with this ongoing focus, we signed on to the White House's rate payer protection pledge last week. Our large low tariff framework is well aligned with the principles in the pledge and is designed to ensure that new large customers pay their fair share of the infrastructure and generation costs required to serve them while at the same time helping to protect affordability for existing customers. This ensures alignment across stakeholders so that we can turn generational investment and growth opportunities into demonstrable benefits for all in our region. While our capital investment plan is higher than historical levels, it is supported by unprecedented load growth.

New large load customers contribute premium revenues that helped cover the cost of serving them and the investments required to support growth, while increasing energy sales allow us to spread system costs across a larger base. We expect to see customer rate increases over the next several years being in line with or below inflation for the significant majority of our residential customers. Missouri West is our smallest utility today, 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, new dispatchable baseload generation.

As a result, as new generation plants come online to serve Missouri West, 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 our market provided energy making rates more stable for our Missouri West customers. Longer term, as the full benefits from large 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.

As outlined in our capital plan, we will continue to invest in grid modernization to ensure reliability as well as grid resiliency, strong customer service, and generation availability. Our primary sustainability goal is to execute a cost-effective, all of the above generation strategy, as reflected by our planned investments in natural gas, solar and battery storage to support our Kansas and Missouri customers. We look forward to continuing to advance a mix of resources over the coming years to support growth and prosperity in our states. I will now turn the call over to Bryan.

Thank you, David. Thank you, Pete, and good morning, everyone. Let's begin on Slide 12 with a review of our results. For the second quarter of 2026, Evergy delivered adjusted earnings of $209 million or $0.88 per share compared to $191 million or $0.82 per share in the second quarter of 2025. As shown on the slide from left to right, the year-over-year drivers are as follows: First, margin from loan growth resulted in a $0.10 per share increase for the quarter. We recorded higher revenues this year from the March 2026 start of operations of a large data center and from Panasonic's ramp of operations. Combined, these 2 customers had an approximate $0.04 benefit to EPS compared to the prior year quarter.

Overall, weather-normalized demand grew 1.8%, primarily driven by commercial and industrial demand. We also had a warmer start to the summer, resulting in an increase in cooling degree days compared to prior year, with weather essentially normal in the second quarter compared to the mild weather in Q2 2025. Next, recovery of and return on regulated investments, driven by new retail rates in our Kansas Central jurisdiction and FERC regulated investments contributed $0.10 of EPS. Offsetting these favorable drivers the combination of higher O&M and increased depreciation and interest expense net of AFUDC drove an $0.08 decrease in EPS.

And finally, other items netted a decrease of $0.06, inclusive of $0.02 of dilution from convertible bonds. It has been a very solid start to the year, and we are in good shape to meet the midpoint of our 2026 EPS guidance range of $4.14 and to $4.34. To assist investors and analysts with the modeling, we are providing third quarter adjusted EPS guidance of 50% to 53% as measured against the $4.24 midpoint of our 2026 adjusted EPS guidance range.

Turning to Slide 13. I'll provide more detail on our sales trends. On a year-to-date basis, weather-normalized demand has grown 3.3% and remains on track with our full year expectations. This is driven primarily by higher commercial and industrial usage. Commercial demand grew 4%, reflecting the initial ramp-up and higher usage associated with data center projects. Industrial demand grew 6.2%, buoyed by Panasonic's continued ramp. At a macro level, the robust customer demand in our service areas is supported by a solid labor market as Missouri, Kansas, Kansas City metro area unemployment rates remain below the national average with a healthy increase in residential customer and migration.

We are fortunate to be able to serve in these Kansas and Missouri communities. Few regions in the United States are as well positioned to benefit from the accelerating national investment cycle and power infrastructure and data centers at the Kansas City metropolitan area. The region's deep concentration of EPC firms and highly skilled engineering talent creates a competitive advantage that should drive sustained economic development, employment growth and increased electricity demand in both Kansas and Missouri for years to come.

Moving to Slide 14. We highlight our large low demand growth profile. As indicated on the chart, the large load customer rents are already underway and are expected to continue building in aggregate through 2030 and beyond supporting our retail load growth CAGR of approximately 7% to 8% through 2030. This reflects the impact of Digital Realty, the fifth ESA customer announced on our first quarter call. This chart illustrates a powerful period 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 the ESA LLPS contract firms that generally span 16 to 17 years.

In addition, we continue to make strong progress with several other large customers. While not reflected in the chart, we continue to execute at least -- we expect to execute at least 1 additional ESA in 2026 and and keep this strong momentum going in 2027. The associated load and capacity that would be served under these potential incremental ESAs would represent further upside to low growth in the near term, and importantly, it has the potential to extend our exceptional load growth well into the 2030s. As David described, we will continue working in a measured and disciplined manner through our substantial pipeline of prospective customers to build on the success we have achieved to date.

Let's close on Slide 15 by recapping our strong growth outlook. First, based on ESAs already signed, we currently project load growth of 7% to 8% through 2030. As I just mentioned, we are working with several customers on potential projects at existing and new sites that could have significant positive impacts of lower growth well into the 2030s. Secondly, the foundational earnings power of the company will be fortified by our $21.6 billion capital investment plan. Based on our filed 2026 IRPs, we see incremental investment of approximately $1 billion to that forecast. With further upside potential as we signed more of large load customer ESAs.

We plan to update our capital plan during the fourth quarter call in February. As I mentioned on our first quarter earnings call, this $1 billion increase in generation investments is projected to raise our rate base CAGR through 2030 to approximately 12% compared to our previous disclosure of 11.5%. Additionally, ESAs are expected to require further capacity resources and related investment. As our capital investment plan grows, we will utilize a prudent mix of debt and equity financing to support our strong investment-grade credit rating and FFO to debt that we currently project to be in the range of 14% to 15% from 2026 to 2028 with further strength in the outer years.

On the equity front, we continue to make progress utilizing our ATM program having priced approximately $425 million through forward sales agreements as of June 30 that will be settled later in 2026. This represents more than half our expected $700 million to $900 million of equity we expect to issue during the year. As we look to the remainder of the year, our remaining equity needs are addressable through our ATM program, and we currently have no plans for a block issuance.

Turning to our EPS outlook. We are reaffirming the midpoint of our 2026 adjusted EPS guidance at $4.24. Beginning in 2028 and through 2030, we expect annual earnings growth to exceed 8%. As we have discussed on prior calls, we continue to forecast an approximate 250 basis point delta between rate base growth and EPS growth, which is now compared against a 12% rate base CAGR discussed earlier. In summary, continued execution on our large customer opportunities is further strengthening our financial outlook, supporting long-term growth while delivering meaningful affordability benefits for our customers. 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 on 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.

[Operator Instructions] Our first question comes from the line of Steve ’Ambrisi with RBC Capital Markets.

Just had a quick one. Obviously, there's a lot of moving pieces here, and I appreciate that you laid out the incremental capital from the IRP as well as kind of what could be further upside. But can you just -- if we take a step back and think about potentially what could be signed from the Tier 1 bucket in this year that you've talked about having an additional signing? And just what type of generation requirements would be needed and capital requirements we need, where we think rate base growth could go? Obviously, you took it from 11.5% to 12% with this upside $1 billion. But just trying to understand kind of where growth is going here? .

Sure, Steve. I'll take a whack at and Bryan, feel free to supplement it. We've laid out we've got a really exciting set of discussions that are underway with our Tier 1 -- in the Tier 1 and Tier 2 categories that we lay out on the slides. There's 2 to 2.5 gigawatts of expansion opportunities that are at or adjacent to existing sites. So we're really excited about those because we know the customers. We've got a good sense for what the needs are from a transmission and distribution infrastructure perspective. So very excited about those. And we're also excited about the Tier 2 advanced discussions as well. So there's meaningful expansion opportunity around the 3 gigawatts that we described.

Now in terms of timing, what we've laid out is we expect to sign at least 1 additional ESA this year. We didn't specify what the timing is, but you can -- we have 5 signed ESAs, amount of load on those ESAs is about 2.5 gigawatts. That gives you a sense of rough sense it how big these typically are. They're not all the exact same size. That gives you a rough sense. To serve incremental load, we do expect that there are going to be additional resource requirements, primarily generation-related. We're seeing cost trends that are in line with what you're seeing for other utilities. So the capital investment that would follow is pretty meaningful. So it would drive, we expect incremental CapEx.

Most of the customers that we've worked with to date and the discussions that are underway today. They're looking for being provided firm power from our resources. Our LLPS tariff allows us to make sure that we're charging them for their fair share and that they're paying a premium rate. We can accommodate folks for example, signed PPAs in the marketplace or bring generation, but most of our customers have been looking to us to provide firm power out of system resources so that we expected that to be the general trend line. So we see meaningful upside, again, we said expect at least 1 additional ESA this year, but we expect the momentum from these discussions to continue into 2027.

So we haven't quantified the exact amount -- we expect signing this other than saying we do expect we have high confidence signing on additional say, this year, and we do think it will drive incremental capital requirements. And if you look at our how the capital is ramped over time as we've added investments, that gives a good sense for what the potential knock-on effects would be. How it really summarizes our confidence in the pipeline and the really high interest in our customers in our territory, and that's under that LLPS framework to make sure that they were charging them an appropriate rate.

That's very helpful, David. And then just I have a follow-up to not to get ahead of myself and ask for more disclosures early. But clearly, as you sign options to the pipeline and just that ends up adding capital to the Beyond 2030 plan. Any thoughts on providing a longer-term look you've seen some of your peers give capital plans or illustrative growth rates into the middle of the next decade just to highlight the confidence in the duration of the growth profile?

I think that, that's a fair point, Steve. We certainly want to lay out what our expectations are or even from the material that we have in the ESAs we've signed. You'll see that we give a ramp of those ESAs over time. When you get out to 2030, the total amount of the peak load we expect is between 2.05 and 2.2 gigawatts, that obviously is indicative of $750 million to nearly a gigawatt of incremental road ramp beyond 2030. While the expansion opportunities have some potential impact in the 5-year window, both the expansion opportunities in the Tier 2 have a ramp that's well into the 2030s and the resource needs will be in that time frame as well.

So we know that, that visibility is going to be important. What I'd express today is -- and as you've heard us describe, we believe that this momentum in our pipeline, if we're able to convert as we expect to have at least 1 ESA, and we don't expect to stop there. That has upside potential both over the near term and well into the 2030s. But we know that you all will be looking for more specificity on that, and we'll certainly plan on giving that level of specificity as we capitalize on the momentum in our pipeline.

Our next call comes from Shar Purreza with Wells Fargo. .

Actually, it's Andrew Kadavy on for Shar. I was wondering, could you maybe characterize the customer profile for the pending 2026 CSA? Is it another half or scaler?

You see the mix of customers we have today. We've got 2 ESAs with Google, 1 with Meta, 1 with Digital Realty, which is a very large data center developer, 1 with Bell, which is an enterprise with a lot of experience in this arena. I think it's -- we won't get ahead of saying what customer signing. We've got high interest from all of our customers and expansion opportunities. I think if you consider what our Tier 1 expansions and Tier 2 profile looks like, it's probably a mix that's reasonably consistent with the mix we've had today. So high-quality, hyperscaler counterparties or data center developers who are experienced in this space.

And we have visibility that they're obviously aligned with hyperscale customers on their own. That's confidential. We won't share it, but visibility in the customers they are serving. So I think you can view the profile that we've disclosed today to the customers that we've signed up and that going forward, it will be a similar kind of profile.

And then on the political side, can you comment on kind of the data center moratoria campaign issue for the Kansas governor's race. Is the noise there affecting your commercial discussions with potential customers?

So there's a lot there. Let me comment on on elections and local sensitivity of data centers broadly because I do think that how you approach data centers is important for every local jurisdiction. But first, I'll just comment only on election. Data centers compared to certainly some other states were not as prominent in the primaries in the Kansas side. There are no major statewide races in Missouri this year. Only the state auditors up for reelection on the Kansas side, there is a gubernatorial election current governor's term limited and not standing preelection on the Republican side, Tim Masters the Senate President, on the primary. He's an experienced legislative leader as Senate President, who's been supportive of economic development and infrastructure investment, needs certainly going to be attentive to the rate payer protection pledge understands the LLPS tariff and making sure that large customers pay their fair share, but it's been a constructive.

He's demonstrated support for economic development and structured investments. Cindy Holster, on the Democratic primary, She's a state center from Johnson County, and we've worked with her in the past. In the past in Kansas, we've been able to advance constructive measures relating to structure investment with support from leaders in both parties, and we're confident that we'll continue our focus. So it has not been nearly the prominent issue as in some of those states. But what I'd emphasize is that -- as you think about citing data centers, it's really similar to all major projects. You have to move forward in the right spots. It's not going to work everywhere.

Some places won't be well suited for data centers, but for some others, with the right kind of land set up, with the right kind of infrastructure setup, with the appetite for the economic development, the jobs, the expansion of tax base, it can move forward. So we have some places that are well suited. So we are working with high-quality developers, hyperscale customers who know how critical it is to develop facilities in areas where the communities are receptive, and we'll be working with them to move it forward. So we're confident in that issue. It's obviously a sensitivity point that gets a lot of commentary in the market today.

But I would describe that if you've been in this business, if you've been in the utility business, the transmission line siting and facility siting, you always have to be sensitive to it. And we're certainly very focused on that as our the customers who are at the top of our Q.

Our next call comes from Paul Patterson with Glenrock Associates. .

All right. So just most of my questions Vans actually asked, but just if you could you go over the rate increase impacts. You guys went a little quickly, and I apologize, but you mentioned that you guys expect to go, I think, in the rate of inflation or lower. Is that a floating number? Or is that basically based on a specific idea about what inflation will be. And then secondly, with respect to -- you mentioned that there was a difference in 1 jurisdiction. And if you could just go over that again, I apologize, but if you could clarify that for me. I appreciate it. .

Sure. Next, Paul. It's obviously a very important topic. We've been focused on affordability. It's been at the forefront of our discussions really since the merger in 2018 that formed Evergy. And we're proud of the trajectory that put us on. So we've been focused on the topic and to be able to demonstrate real benefits and regional rate competitiveness and getting our rates below Midwest and national averages over the past several years and we've proven that to our customers. The comments that I laid out are based on our modeling of what we expect rate impacts to be and the impact of the LLPS tariff, which is set up to make sure that the large customers pay their fair share.

So what I described was we expect that rate increases for residential customers will be in line with or below inflation for the majority of our residential customers. Now where inflation is, we all track the Fed. I know that inflation currently is a little north of 3%, which is a little bit's point. The Fed is helping -- as its target of 2% over time. So we certainly hope that the inflation will get more to that 2% range. But right now, inflation is trending in the 2% to 3%. We're not modeling it at some level. higher than that. The jurisdiction that I spoke to was Missouri West. So Missouri West has the lowest rates in our system today, some of the lowest rates in the nation. And part of the reason for that is it has relatively less infrastructure.

So our customers have benefited from that in Missouri West for many years, but we're in a position where there are a couple of factors that relate to that. One is that they're more exposed to market energy prices, so when there's volatility in a winter storm firm or a winter storm Yury, there's more volatility in the fuel costs that get -- that can lead to some variability in Missouri West rates. The second factor is as capacity becomes tighter, we need to make investments in Missouri West, so that they're well situated to be able to meet their needs. So we do expect over the coming years the Missouri West residential rates will be over inflation over time, we expect those to stabilize. We certainly expect that they'll remain competitive within our system and within our region, and will lead Missouri West customers we think in a much better place with resources that will benefit them for decades to come.

On the affordability front and data centers, 1 thing I'd emphasize, we are in only 1 rate case currently. That's in Missouri Metro. In our Missouri Metro rate case, as part of our initial filing, we actually reduced the revenue requirement we would otherwise have requested by $25 million, about a 15% decrease in our requested revenue requirement because of data centers. This is in advance of even generation investments having an impact in Missouri West. So it's a demonstrable impact of the -- how these large customers, how the LLPS tariff can drive knock-on benefits for all of our other customers. We actually expect that $25 million amount or that 15% reduction. That amount is -- that relative reduction is going to even increase further as we get to the true update because that large customer continues to ramp.

In other words, the beneficial impact of that data center will be even more consequential in terms of it's helping our customers. So this $40 million rate is 1 that we model carefully. We think about systematically and we'll continue to do so going forward because we know -- we really think actually this opportunity with large load is unique in how it not only will drive prosperity in terms of tax base and construction and a digital economy, but helping to drive affordability benefits for all our customers. So I know it's a long answer, but obviously a very important topic and 1 that we'll continue to focus on.

Awesome. Just on the metro rate case. Do you think there's a potential for a settlement or anything now that testimony has been filed and I guess we thought all testimonies coming up pretty soon. But I'm just wondering, is there any -- what are your thoughts about that? .

We've been able to successfully settle our last couple of Missouri rate cases, asset, many other utilities date, including Amarin. I went over the procedural schedule. So these -- the rate case in Missouri tends to follow a specific schedule, including for a settlement conference. So that -- we'll have a few more rounds of testimony filings in that settlement conference is scheduled in the late September time frame. So we look forward to working with staff, with other stakeholders and working towards the constructive resolution. It's pretty straightforward rate case in the sense that it's largely infrastructure investment and then a unique feature that is actually with a positive benefit from our data center customer.

Our next question comes from Anthony Crowdell from Mizuho .

David, Bryan, just 2 quick questions. I guess, one, you give us the -- I don't know the right term is maybe the 250 basis point maybe, if I call it, financing lag between rate base and earnings growth. I guess, does that fluctuate? Or is that pretty consistent? Is it dependent upon maybe rate outcomes or capital getting into rate base? Just how, I guess, linear or stable is the 250 basis points. .

Well, that's a great question. We will obviously give an annual view of guidance over time as we get closer to each year. What we've described as we expect in our 6% to 8% plus long-term earnings growth target that we expect earnings growth greater than 8% annually starting in 2028, and we're starting from '27 to '28. We'll see that increase afterwards. There's some impacts that come from when plants are online and the trajectory of the load profiles of our large customers, we've given a sense for when the plant schedules are and also what the annual contractual terms under our ESAs.

So there's a -- it's a steady progression as you see in those charts, but there's inevitably some impacts that come from the rate case will typically follow when some of these large generation projects come online. In terms of that general rule of thumb, the 250 basis point difference between our average annual rate base growth and earnings growth, we view that as pretty steady. What's effective here is that while you have some lag from your investments to when they're reflected in earnings power as well as impacts from financing over time. You're also having load growth over time. So given that the load growth is increasing pretty steadily, we do see that as a pretty stable relationship over the trajectory.

Great. And then just lastly, you 1 of the few utilities that I think most of the coverage I have, there's kind of like a utility type jurisdictions of kind of like a have and have nots, where there's an aggregation of some of the large load to maybe 1 of their service territories, but the other 1 maybe is not as desirable. You guys seem to be doing very well with the large low tariffs in both Missouri and Kansas. And I'm just curious when you talk to your customers, what are some of the positive attributes that make them choose Kansas or make them choose Missouri? Just why is load maybe lean more towards 1 state or the other? .

Well, I think you captured it accurately that both states are viewed very attractive as very attractive by our large customers. So individual customers will come down to where do they have the land prospects, where do they -- where have they found the most specific opportunity, but the general setup in both states is viewed as constructive and positive. And the tariffs are pretty similar between the 2. So it was first approved on the Kansas side subsequently approved on the Missouri side, they're pretty similar provisions so that LLPS tariff that sets a premium rate to make sure they pay their fair share pretty consistent terms. So the ability to had that predictability, attractiveness of our region. If you've ever been to Kansas City, the state line just goes to the middle of the city in many ways.

So the attributes that make our region attractive are similar between the 2 states. There some differences, of course. But the fundamentals are such that our customers like both states, that's reflected in the project that we've signed. Initially, the rally a little ahead, but Kansas got the LLPS tariff approved. And right now, what I describe is it comes down to where you're finding local communities that meet those criteria that I described earlier, where it makes sense for that local community, and we see this in both states and certainly our customers do as well.

And I guess for you guys, it really wherever the cheap move, it's going to be in your service territory, right? .

Our service territory is -- I think it's fair to say, overlaps heavily with Chief Nation. We've got some munis and co-ops across our territories, so that can have some impact. But yes, we whether either side of the state line, you're going to see some rapidly parts in our service territory, yes, we're pretty consistent.

This concludes the question-and-answer session. I'd like to now turn it back to the President and CEO, Mr. David Campbell.

Vision today, thank you very much, everyone, for your interest in Evergy. With that, we will conclude today's call. Thank you.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.

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.

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.

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.

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.

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

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?

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.

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?

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.

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?

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.

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.

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

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.

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.

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.

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.

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

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?

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.

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?

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.

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.

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

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?

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.

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.

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.

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

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?

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.

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?

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.

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

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.

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.

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

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

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

Good day, and thank you for standing by. Welcome to Evergy's Fourth Quarter 2025 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I'd now like to hand the conference over to Peter Flynn, Senior Director, Investor Relations and Insurance. Please go ahead.

Thank you, Liz, and good morning, everyone. Welcome to Evergy's Fourth 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 our 2025 highlights and recent economic development activities. Bryan will cover our full year results, electric load growth potential 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 by first thanking our employees who worked tirelessly throughout the year to advance our strategic objectives of affordability, reliability and sustainability. The team's hard work and execution laid the foundation for the transformative growth opportunity before us.

Today, we are raising our long-term adjusted EPS growth target to 6% to 8% plus through 2030 off of our 2026 guidance midpoint of $4.24 per share. We expect EPS growth to exceed 8% annually beginning in 2028 and through 2030. Our updated growth outlook is bolstered by the recent execution of electric service agreements for 4 data center projects that I will discuss shortly.

With respect to 2025, we executed on our capital investment plan to improve reliability and resiliency, investing $2.8 billion in infrastructure to modernize our grid and replace aging equipment. Our financial results in 2025 were negatively impacted by weather and weak industrial demand throughout the year. Despite meaningful results and cost and mitigation actions, we were unable to fully offset these impacts. While the negative drivers were outside of our control, we fully understand that consistent financial performance is a hallmark of long-term value creation. We have confidence in our updated financial outlook, which has been tested against a range of outcomes, and we are committed to delivering against our objective of sound financial execution. Bryan will discuss earnings drivers in more detail later in his remarks.

In 2025, we made significant progress in advancing economic development opportunities, growing our pipeline to over 15 gigawatts. A major milestone involved approval of new large load power service tariffs, the LLPS, in both Kansas and Missouri last November. These tariffs established a framework under which new large customers will pay a premium demand rate to locate in our service territories while adequately paying their fair share of existing and new system costs. This, in turn, will drive affordability benefits for existing customers and support economic growth in Kansas and Missouri.

In Missouri, the passage of Senate Bill 4 in 2025 marked another successful legislative outcome that signaled strong support for infrastructure investment and growth. Among other features, SB 4 includes provisions that enhance our ability to invest in and timely recover costs associated with new natural gas generation while also extending the PISA sunset provision of 2035. SB 4 reflected the support and combined efforts of the Missouri Public Service Commission, legislative leadership, the Governor's office, commission staff and many other key stakeholders, and we appreciate their leadership and collaboration.

In Kansas, we are pleased to reach a unanimous settlement agreement in our Kansas Central rate review. The settlement provided a balanced outcome for our customers and communities and reflects broad alignment around our infrastructure investments while ensuring we continue to provide reliable and affordable electric service. We also received approvals from the KCC and MPSC to construct 3 new natural gas facilities and 3 solar farms totaling nearly 2,200 megawatts. These projects further advance our all of the above generation strategy to support rising customer demand.

Safety is at the core of everything we do, and I'd like to thank our generation, transmission and distribution teams for their commitment to safety and a significant reduction in the injury rate last year. Reliability performance also improved as we achieved the strongest results in the company's history for SAIDI, with reductions in both average outage duration and frequency. Our infrastructure investments and the hard work of our operations teams continue to drive benefits and enable us to deliver affordable and reliable power to customers no matter the conditions or the weather.

In November, we raised our dividend 4% to an annualized $2.78. As our dividend continues to grow, we expect the payout ratio to decline over time to a revised target of 50% to 60%. As Bryan will discuss, this target is part of our financing plan as we enter a period of elevated growth and investment and is similar to the approach of many peer utilities.

Moving to Slide 6. I'm very pleased to announce new electric service agreements for 4 major data center projects. This includes 2 new data centers and significant expansions of 2 existing projects. In aggregate, these 4 projects represent 1.9 gigawatts of steady-state peak demand. Taken together, these projects alone amounts to nearly 20% increase in our total peak system demand and an even higher level of usage growth given high expected load factors. As these customers ramp up, we'll be able to deliver affordability benefits for our customers and communities to the strong LLPS tariffs. Of course, these facilities will take time to construct and reach their maximum megawatts. We've included 1,300 megawatts in our retail load growth forecast in 2030, with the remainder ramping up after that year. This outlook reflects our expected case, which is informed by the specific load ramps as outlined as part of each customer ESA.

And finally, we're making strong progress with several additional large customers and expect at least 1 more executed ESA in 2026. This upside is not captured in either financial outlook or sales forecast we're sharing with you today. These commitments solidify Missouri and Kansas as premier destinations for data center customers, now the product of strong partnerships with world-class customers in Google, Meta and [ Bill ]. We'd like to thank for their investments in Kansas and Missouri.

As customers complete construction, they are responsible to pay their fair share of costs incurred to serve them, including the LLPS premium pricing. As an additional protection, if their actual usage falls short of annual expectations, they are subject to minimum bill provisions, which provides strong visibility to our -- through our 6% to 8% plus EPS growth outlook and the affordability benefits we can expect to provide our current customers.

Slide 7 summarizes the progress we've made in converting our Tier 1 large customer pipeline to signed agreements. Starting in the top row, the 2.4 gigawatt includes the 4 [ ESAs ] announced today and the large customers that have already commenced operations. This Tier 1 demand enables a transformative growth opportunity for Evergy, supporting our expected retail load growth of 6% annually through 2030, well above the historical 0.5% to 1%.

Moving to the section shaded in green. We remain in advanced discussions with multiple customers whose load represents a 2 to 3.5 gigawatt opportunity. We expect to execute at least 1 more large customer ESA in 2026 from this group. In aggregate, these potential customers have executed various service agreements, posted financial commitments and otherwise demonstrated their significant interest in locating in our service areas. The remainder of our pipeline totaling over 10 additional gigawatts highlights the robust activity and sustained interest in our region. The opportunity to serve this load will require creative solutions. And the ongoing dialogue also underscores the readiness of customers to step in, should others exit the queue. The announcements we've made today serve as clear proof of concept that Evergy is well positioned to capitalize on this historic opportunity, reflecting the geographic advantages of our region, support of business and energy policies and a shared approach amongst our many stakeholders to capitalize on economic growth.

On Slide 8, we summarized key customer and shareholder protections as provided by our LLPS tariffs. Early last year, we set out on a cross-functional effort to address a key opportunity and challenge: how can Evergy serve new large loads while supporting affordability for existing customers and fairly addressing cost allocation related to new infrastructure investment to serve these large loads. The follow-up work culminated in the approval of settlement agreements in both Kansas and Missouri on a tariff that addresses this challenge. It reflects significant collaboration with commission staff, consumer advocates, industrial groups, the data center coalition, Google, Meta and others and ultimately garnered strong support, as reflected by the approvals of both the Missouri and Kansas commissions.

As outlined in the tariff, new large customers are committed to minimum term lengths and minimum monthly bills regardless of usage shortfalls that cover no less than 80% of their contracted capacity at a premium demand rate. Additionally, customers must meet creditworthiness standards and collateral requirements. Termination fees are required should the customer decide to cancel a project or leave early, and these fees would cover the remaining minimum monthly bills for the term of the contract. All told, these tariffs established the framework through which new large customers will pay their fair share for capital investment while bringing massive new projects to Kansas and Missouri.

Slide 9 is illustrative and expands upon how the provisions of the LLPS tariffs will work in practice and critically, mitigate impacts on existing customers. Customers taking service under the LLPS tariff will pay a premium demand rate 15% to 20% higher than the rate for existing industrial customers, as well as all the direct costs to serve them. This premium in the revenue is driven by the customers' high load factors will generate significant benefits for existing residential, commercial and industrial customers. As laid out in the flow chart, our future rate requests will be reduced by the revenues generated from LLPS customers. As the higher load from these customers is factored into our requests, system costs are then spread over a higher base, which in turn puts downward pressure on future rate requests. This is a critical aspect of our affordability proposition, as over time, we will be investing at higher levels to serve growing demand.

Our existing customers will share in all the benefits of a modernized grid and new best-in-class generation technology without encountering the same level of costs they otherwise would have faced without large new customers. In short, we have a unique opportunity to upgrade the grid and replace aging infrastructure much more affordably than we could without this robust level of load growth.

Moving to Slide 10, we highlight a few of the expected benefits of data centers. It's important to recognize that these projects deliver substantial long-lasting value to the communities we serve. Beyond the benefits and protections of the LLPS tariffs, these projects generate tax revenues typically far in excess of the local services needed to serve them. These tax revenues in turn support local budgets for education, infrastructure, parks and other community services. Data centers also strengthen the economic ecosystem, given the growing importance of automation and low latency. These attributes will likely feature more and more prominently in sectors such as health care, finance, transportation, logistics and advanced manufacturing. By enabling leading applications in these industries, data centers will help to attract and support high-quality job creation.

These data center projects also represent multibillion-dollar capital investments, with construction job growth often sustained by ongoing equipment upgrades. They drive the need for new and updated fiber optic infrastructure, which can then create a virtuous cycle for additional data-focused industries. In summary, data centers are major investments that can also serve as powerful engines for economic development. They support affordability, generate long-term tax revenue, expand industries, support job creation and catalyze infrastructure investment. This is the kind of growth that strengthens communities for decades, and we are proud to do our part.

On Slide 11, we highlight the major gains in regional rate competitiveness our company has achieved since 2017. This success directly supports the growth opportunities that we're discussing today. Since 2017, our rate trajectory has remained well below regional peers and far below inflation. The cumulative change in Evergy's all-in rates over that time is approximately 4.9% compared to our regional peer average of 19% and inflation of 29%. Holding rate increases to a 0.5% annual rate reflects the scale benefits and cost savings from the merger that created Evergy, promises we made and promises we kept. As we enter a new era of economic development, we'll maintain our relentless focus on cost discipline, affordability and competitiveness of our states.

Slide 12 lays out our updated capital forecast. Our rolling 5-year investment plan totals approximately $21.6 billion from 2026 to 2030, equal to a $4.1 billion increase over the prior plan. The increase includes over $3 billion of new generation investment to support growing customer demand and meet higher generation reserve margin requirements in the Southwest Power Pool. Our 5-year investment program is expected to result in an 11.5% annualized rate base growth through 2030, which compares to our prior forecast of 8.5%. We'll take a flexible approach to financing our capital plan, utilizing a prudent mix of debt and equity with optionality around timing and execution, as Bryan will describe.

I'll conclude my remarks on Slide 13, which highlights the core tenets of our strategy. I'll focus specifically on affordability. Keeping rates competitive and affordable has been a strategic priority since our company's formation in 2018. Evergy stands out as one of the best utilities in the country in managing customer rates and keeping rate increases well below inflation. We will continue to prioritize affordability in our long-term plan. While capital investments are higher than historical levels, so too is load growth, which will allow us to spread system costs over significantly higher kilowatt-hour sales. We expect to see customer rate increases over the next several years being in line with or below inflation for the majority -- the significant majority of our residential customers.

Missouri West is our smallest utility today 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, new dispatchable baseload generation. As a result, as new generation plants come online to serve that jurisdiction, customers may see rate increases above inflation over the next 5 years. However, these investments will help to reduce the rate volatility that Missouri West customers have experienced as a result of utilizing more market-provided energy. In addition, 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 Missouri West customers will benefit for decades to come.

By prioritizing affordability, we contribute to the robust economic development pipeline ahead of us and support the substantial economic potential within our states. As outlined in our capital plan, we will continue to invest in grid modernization to ensure reliability as well as grid resiliency, strong customer service and generation availability. Our primary sustainability goal is to execute a cost-effective all of the above generation strategy, as reflected by our planned investments in natural gas, storage and solar to support our Kansas and Missouri customers. We look forward to continuing to advance a balanced mix of resources 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. Let's begin on Slide 15 with a look back at our financial results. For the full year 2025, Evergy delivered adjusted earnings of $894 million or $3.83 per share compared to $878 million or $3.81 per share for the same period last year. As shown on the slide from left to right, the year-over-year drivers are as follows: first, 0.3% growth in weather-normalized demand primarily driven by the commercial class resulted in an increase of $0.04 per share margin. These results were weaker than projected for both residential and industrial, including in the fourth quarter, which led to our final 2025 adjusted EPS results falling short of the guidance we provided on our third quarter call.

Regarding residential and industrial load, early indications in 2026 are strong in comparison to 2025, and we expect to return to normal residential load growth in 2026. Secondly, recovery of and return on regulated investments, driven by new retail rates and FERC regulated infrastructure investments, contributed $0.56 in EPS in 2025 as compared to 2024. Unfavorable variances for the year included higher operation and maintenance costs and depreciation and interest expense due to increased infrastructure investments, which drove a $0.43 decrease in EPS. Other items had a negative $0.10 impact for the year. And finally, dilution from our convertible notes led to a $0.05 decrease for 2025.

Let's move to Slide 16 to lay out how we expect to deliver on our 2026 EPS guidance midpoint of $4.24. Again, starting on the left side and beginning with 2025 adjusted EPS of $3.83, [ which ] modeled a reversion to normal weather in 2026, which would add approximately $0.13 per share. Next, we expect a $0.26 increase from demand growth in 2026, which reflects a forecasted 3% to 4% increase in weather-normalized retail sales. This exceptional level of load growth is driven primarily by the continued ramp of the Panasonic advanced manufacturing facility as well as the ramp up of the data center customers with signed ESAs in our Metro and Missouri West jurisdictions.

Next, updated recovery of costs and return on our regulated investments are expected to contribute $0.35 of EPS for the year, primarily related to new rates at Kansas Central that went into effect in the fourth quarter of 2025, as well as the recovery of FERC regulated infrastructure investments. Offsetting these positive drivers is an increase in O&M as well as the combined impact of higher depreciation and interest expense net of AFUDC earnings and PISA deferrals, which is expected to drive a $0.20 unfavorable impact. Lastly, we assume $0.08 of drag related to dilution from convertible notes and expected common stock equity issuances, as further described in a moment. We have high confidence in this 2026 guidance, and it is bolstered by the execution of electric service agreements that we've announced today.

Moving to Slide 17, we highlight our large load demand growth profile in our financial plan. Over the past 2 years, we've been hard at work to advance competitive frameworks for capital investment in Kansas and Missouri that would enable 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.

The passage of the LLPS tariffs, our operational team's execution on transmission and generation capacity planning, as well as strong collaboration with customers and local stakeholders and legislative efforts have all culminated in what we believe is one of the most compelling growth stories in the sector. As indicated on the chart, the large load customer ramps are already underway and will continue building through 2030 and beyond, supporting our retail load growth CAGR of approximately 6% through 2030. 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.

We are able to share this level of detail with you because our teams are no longer just talking about a pipeline. Now they are also talking about the successful inking of actual electric service agreements with the very high-quality customers David described earlier. To drive home this point further, the execution of these ESAs was the milestone needed to solidify Evergy's growth trajectory as a company, as these were the final binding agreements to be signed between Evergy and these customers.

The numbers on Slide 17 that you see reflect our planning assumptions around the capacity demand that will drive revenue during our planning period, growing from 350 to 400 megawatts of served capacity by year-end 2026 through up to approximately 1,700 megawatts of served capacity by 2030. As a reminder, this plan reflects the contributions from customers under signed ESAs for 4 major projects. Furthermore, we are making strong progress with several additional large customers and expect at least 1 more executed ESA in 2026, whose load would represent upside to the back end of this forecast. As David described, we'll continue working in a measured fashion through our 10 gigawatt plus balance of pipeline to build on the success we're sharing with you today.

Okay. So Slide 18 converts that megawatt capacity usage you see on Slide 17, along with our broader customer base, which is also expected to grow, into a view of the strong load growth profile we see ahead. In particular, it highlights generally accelerating annual load growth from 3% to 4% in 2026 to an average annual rate of 7% per year from 2027 through 2030. It also highlights the growth we're seeing across our entire system, growth that will ultimately drive affordability benefits for our customers in every jurisdiction. We believe the ranges on this page will assist analysts and investors in the modeling of our 6% load growth CAGR over the next 5 years across jurisdictions and importantly, reflects the positive momentum we expect to build in our financial results throughout the 5-year planning period.

On Slide 19, I will briefly highlight our 5-year investment plan. As David referenced earlier, our $21.6 billion capital investment plan represents a $4.1 billion or 24% increase compared to the prior 5-year plan. A key feature is higher generation investment, which captures approximately $3.4 billion of the total increase and largely consists of new natural gas power plant investment needed to serve growing demand and to meet SPP reserve margin requirements.

The T&D portion of our plan emphasizes strengthening system reliability through grid modernization efforts, including replacing assets that are at or near the end of their useful lives. Deploying these critical infrastructure investments to the benefit of our grid operations and for our customers and communities is expected to result in a rate base CAGR of 11.5%.

Let's now turn to our updated financing plan on Slide 20. As mentioned on Slide 19, our projected capital investments over the 5 years through 2030 now stands at $21.6 billion. We'll utilize a prudent mix of debt, equity and hybrid securities to finance our capital investments, targeting an FFO to debt ratio of approximately 14% through the forecast period, with strong annual growth in FFO that will provide the potential for even stronger metrics towards the end of the 5-year plan.

Moving from left to right, we expect $13.5 billion of cash flow from operations. Our $3.6 billion dividend assumption reflects our expectations of growing the dividend throughout the period while targeting a 50% to 60% payout ratio. Recently, our dividend payout ratio has been in the 65% to 70% area, and we plan to grow the dividend annually at a rate below our EPS growth projection of 6% to 8% plus. We expect to achieve the 50% to 60% ratio in the latter half of the plan. And retaining more of our earnings and equity in the business allows us to efficiently fund our capital investments and keep the level of common equity issuances at lower levels than would otherwise be needed.

Next, we forecast $8.4 billion of incremental debt and hybrid securities, net of upcoming maturities. Our plan incorporates $1 billion of equity credit from hybrids, which may assist you in your modeling. Finally, our expected common equity need across 2026 to 2030 is forecasted to be a total of approximately $3.3 billion and now incorporates the benefits of operating cash flow that comes from customers taking service center to LLPS tariff, as well as our revised nuclear [ PTC ] assumptions. Of note, we currently assume no equity issuances of our plan in 2030 as the cash flow generation of our business improves and improves. This results in an annual need of $700 million to $900 million from 2026 to 2029. Of course, we'll continue to evaluate the appropriate level of equity funding, particularly as upside capital opportunities make their way into our plan.

Now let's close on Slide 21. It's a recap of our growth outlook summary for the next 5 years. First, with the successful execution of electric service agreements with large load customers, we expect strong load growth through 2030 and beyond as the initial 1,700 megawatts will support a 6% consolidated retail load growth CAGR through 2030. This provides us with a visible runway of predictable earnings and cash flow growth into the next decade. As a reminder, this forecast includes load from 4 projects under ESAs and other non LLPS large customers already announced. And we're making strong progress with multiple additional large customers and expect at least 1 more executed ESA in 2026 that is not yet captured in our financial plan today.

We continue to believe Evergy has one of the most compelling customer growth opportunities in the industry that could drive robust growth not just in our 5-year forecast, but well into the next decade, resulting in sustainable growth and affordability benefits for our customers and communities and a great long-term outlook for all of our employees. Next, I'll reiterate our capital investment and rate base growth outlook. The foundational earnings power of the company will be fortified by our $21.6 billion capital investment program. Our higher levels of infrastructure investment are in large part related to supporting economic development in Kansas and Missouri and will drive grid modernization and the addition of incremental generation capacity to support our growing customer demand and SPP reserve margin requirements.

Our capital plan is expected to drive a 11.5% rate base growth through 2030, fortifying our earnings foundation. Our projections of regulatory lag and financing costs convert this 11.5% rate base growth to an earnings growth projection exceeding 8% annually beginning in 2028. We plan to file rate cases on a time frame corresponding to the in-service states of new generation projects to ensure the financial strength of our utilities while incorporating the affordability benefits of large loads. It is critical that we deliver on our forwardability and reliability objectives for the benefit of our customers.

And as our capital investment plan grows, we will utilize a prudent mix of debt and equity financing to support our strong investment-grade credit rating and FFO to debt target of 14%. We will take a flexible approach and evaluate all available financing options, including the use of hybrid debt securities that receive equity credit, to meet our financing needs. We anticipate approximately $700 million to $900 million of equity annually from 2026 through 2029 and currently assume no equity needs in 2030 due to improving cash flows from operations. That being said, upside capital opportunities do exist, and we'll continue to evaluate the appropriate level of equity funding.

Altogether, this plan lays the foundation for a transformative growth phase ahead as we expect annual adjusted growth of 6% to 8% plus through 2030 off of our 2026 midpoint guidance of $4.24 per share. As an additional note for the analyst community, we currently expect 2027 EPS growth in the lower half of our 6% to 8% range before accelerating to a level in excess of 8% beginning in 2028.

I speak for the entire leadership team in saying that we are excited about the future at Evergy, and all of our employees are deeply committed to successfully executing our business plan and delivering results for our customers, communities, employees and shareholders. And with that, we will open up the call for your questions.

[Operator Instructions] Our first question comes from Stephen D'Ambrisi with RBC Capital Markets.

Just had a couple -- I mean it's a great update, and thank you very much for giving all the color on the added ESAs. Just the one thing that took out to me was on the equity issuances in 2030, that you have no planned equity issuances beyond '29. So can you just talk a little bit about what that means for steady-state equity needs for the company? Obviously, there's upside capital that we can talk about. But just to the extent we roll forward a year, what do equity needs look like in '31 and '32?

Yes, it's a great question, Steve. It's a plan that we're really excited about. And our metrics really are fortified by the ESAs you mentioned. They have that level of predictability. And your future revenue outlook really, really just strengthens our profile as a company.

When we look at $21.6 billion that's currently in our 5-year plan, this is definitely an elevated CapEx level of CapEx compared to what we've had in the past. But as David mentioned, we also have an elevated level of load growth. So in this big construction phase, these next few years, we certainly have an equity need like many of our peers, and we're excited to be able to issue that kind of growth equity.

So just as we see it today, no need for equity in 2030 because our FFO just greatly improves each year, kind of is illustrative -- or illustrated, rather, quite well by that Slide 17, where you can see the megawatts grow each year of capacity served. There's a potential we win more ESAs. I think we have high confidence in that. And what comes with a growing company like that is often more capital. So we'll have to reevaluate 2030 as more capital opportunities come into plan. But Dave and I were just talking yesterday, when you get into the early 2030s and when we finish our full infrastructure build out, you're going to have some tremendous FFO in the plan and really will make an even stronger balance sheet.

Yes. To build on that, I think -- we expect at least 1 more ESA to sign this year with -- that's not in our plan currently. That's not in our sales outlook or the earnings outlook we described. There'll be capital [ serve ] those customers will be in an environment where we've got strong FFO to debt levels, but we do expect incremental upside capital investment opportunities. And with that, we'll come up with a financing strategy alongside it. So we won't get ahead of what that update will be when we have those additional ESAs, but we're really excited that it will be an upside potential for our customers and communities and for the company.

Okay. That's very helpful. And just not -- again, not to get ahead of the -- front run the update, I guess, but can you just give a little bit of flavor of the 2.0 to 3.5 gigawatt potential for advanced discussions where you expect 1 more ESA? Like how many customers does that represent? Or how many sites? Just so that we can maybe -- any way we can get some type of idea of what an additional ESA could potentially mean for you guys?

Sure. And it's -- I would describe it as -- we want to be purposeful in saying we do expect at least 1 more executed ESA in 2026. So each one of those words, at least and 1 more, are purposeful. So we've worked hard to identify potential transmission, distribution solutions, capacity opportunities. So we feel like we're really tracking well for at least 1 more this year. You can have a sense for the potential size of these customers from the first 4 ESAs that we've signed. We're talking about additional sizable opportunities in that category and we haven't yet included in our plan.

So we're -- the team is working hard, and we're -- our confidence is based not only on our assessment of the capacity in the transmission and generation side, but also the status of our discussions and where those customers stand with respect to lining up land permits and advancing commitments to us. So we're optimistic we'll be there. I think it's fair to say that the bulk of the impact from additional ESAs will come after 2030, but there's some additional potential before the bulk of the impact after -- in 2030 and beyond. But what we like about that, of course, is the ESAs we've announced today are transformative for our company in our service territory. The additional ESAs will help to sustain and extend and expand that opportunity well into that next decade. So we're really excited about the pipeline, and we're committed to executing on that and really do expect at least 1 more sizable large customer ESA executed this year.

Our next question comes from Paul Zimbardo with Jefferies.

Thanks for all the disclosure. So much to ask, but I'll keep it concise. And thank you for the commentary on what '27 looks like as well. Is it fair to think you're targeting like an 8% plus CAGR as well? I know it accelerates in the back half, but should we think about better than 8% as we look 2026 to 2030 as well?

I think, Paul, we've tried to be pretty explicit in how we've described it. So I won't change how we describe it, but kind of reiterate. So let me just walk through it again. The overall formulation, 6% to 8% plus. As Bryan described, '26, '27 in the bottom half of the 6% to 8% range. For that, we expect to accelerate to exceed 8% annually beginning in 2028 then through the 2030 time frame. So I think that gives you a sense for how we see that earnings power and how it evolves over that time period.

The overall rate base growth is in the 11.5% range annually. As we think about the gap between rate base growth and earnings growth, the historical guidance we provided was about 8.5% rate base growth, and we were in the top half of the 4% to 6% range. It was about 300 basis points. We expect that to be in the range of a 250 basis point gap over time. There's a lag that comes from issuing equity and regulatory lag as you -- in a heavy investment mode. But that's what we're looking at over time is that sort of that range of a 250 basis point gap between rate base growth and earnings growth. But the formulation, we tried to be explicit in that 6% to 8% plus, what you see in '26, '27, and then we expect that to accelerate to -- in 2028 and beyond.

Okay. I understand that part. And then just on the credit metric discussion, apologies if it was clear to others. But the 14%, is that an average that you're targeting over time? Because I know you emphasize things get stronger in the back end, just -- any kind of color on the shaping or just how to think about the 14%, if that's kind of a trough or an average, that would be helpful.

Yes. Paul, I think of it as an average, it's pretty consistent throughout the 5-year plan. We do see it getting a bit stronger in year 4 and 5 of the plan. There's just such a heavy [ cat ] construction phase, '26 through '29, and doesn't really abate that much in 2030. But the level of FFO certainly is just building on itself each year and getting stronger and stronger.

So what I would just point out is just our cash flow projections we believe are some of the most predictable in the industry. They're fortified with these electric service agreements with top quality counterparties underpinned by that strength of the LLPS tariffs in Kansas and Missouri, including the minimum monthly bill provisions that escalate over time in conjunction with that rising capacity levels, which are actually spelled out in those ESAs that we're mentioning. So you put all that together, it's a really strong, consistent plan throughout the 5-year period with consistently strong EPS growth and very solid metrics throughout.

Our next question comes from Shar Pourreza with Wells Fargo.

Actually, it's [ Andrew Cataby ] on for Shar. So on the ESAs, how prescriptive are the -- is the ramp rate? How much clarity do you get on how much load you'll be serving on a year-by-year basis? And then when do the minimum monthly bills begin to kick in? Do they kick in during the ramp period or once the customer is fully ramped?

So the ESAs, the great thing about the electric service agreements that we've signed is that they include a schedule, which includes an annual capacity levels that are specified by year starting in the first year. And the -- they'll be charged the levels that they use. But if they don't meet the minimum levels, then they'll be charged at that 80% level based on the schedule of contracted capacity that's laid out in the ESA. So it's a level of specificity and commitment that's laid out contractually with these counterparties. So we're really excited to reach the agreements with Google for 2 of these, 1 new and 1 expansion of a previous project. With Meta, also an expansion, and then with [ Beale Infrastructure ], which is a [ blue oil ] company.

So these ESAs include those ramps. They're specific. They're [ 5 megawatts ] by year. And the LLPS provisions on minimums and on requirements are tracked directly with that schedule.

Great. And then just changing gears a little bit. You mentioned that weak industrial demand played a part in the results for this quarter. What gives you confidence that will turn around in 2026? How much of your overall industrial load is represented by the Panasonic project?

Yes. Andrew, this is Bryan. Thanks for the question. Industrial load in 2025 was -- we're kind of fighting it all year long. January and February of 2025, we had massive snowstorms in Kansas City and some of our largest businesses closed their doors for many days. And then we had a large oil refinery to add an outage early in the year. And then industrial demand picked up with Panasonic and -- but ultimately, by the end of the year, fourth quarter, it was a disappointing level of industrial demand again. And with industrial demand, there's a price component to lower price if you hit a lower peak demand. So that had a kind of a double effect on our '25 earnings.

Now we've embedded all this recent weakness in industrial load into our 2026 model already. So we -- our forecasting team, we kind of did a gut check and said, how comfortable already with these load numbers in 2026. We did modify them down, and that's fully reflected in the $4.24 of guidance for EPS in 2026. So we feel like we're in good shape there.

The January '26 books, we just closed maybe 10 days ago, and those numbers came in really strong. So we're pleased with our start to '26. It's only 1 month, of course. And then lastly, I'll just say with Panasonic, they certainly started out '25 at a slower pace than we had hoped. But in recent months, they're drawing a considerable amount of load, more and more each month. We certainly expect the load in '26 to be within the range of our planning assumptions. In a recent press release, a Panasonic executive mentioned that they plan to start 2 new production lines at their Kansas facility this year, and we'll wrap up the kind of 50% of total capacity early this year.

So I don't know that we've given explicit megawatt numbers for Panasonic. And so I can't really give you that kind of detail around its percentage of industrial load.

Our next question comes from [ Michael Sullivan ] with Wolfe.

Wanted to try just -- I know there's moving pieces and it might be tough, but just in terms of like sensitivities or rule of thumb, can you give us any sense of incremental load growth, what does that do for CapEx and earnings? And then how much of incremental CapEx needs to be financed with equity? Any help you can give us there?

Michael, just to clarify, are you talking about additional CapEx and load growth beyond what we're describing today?

That's right. Yes. So if you get another customer, that ESA, what does that do to CapEx and earnings? And then how do you finance the associated CapEx?

Yes. Well, I'll put the how do we finance question to Bryan in terms of if we had $1 billion of additional capital, what would the general rule of thumb be. I'd say, Michael, it's -- every ESA is going to be dependent on what you ultimately reach with that customer. As I described, we expect at least 1 more ESA in 2026. We think it will be in the general size range that was reflected in the 4 we've announced today, at least at large. I also described, there's some upside in the '29-'30 time frame, but the bulk of the impacts are in '30 and beyond, so we end in the next decade. So I would really describe it as much powering -- it certainly reinforces the plus and it also helps to extend and fortify that growth trajectory into the 2030s.

So I won't get ahead of the specific announcements, that will all depend. The great thing about these ESAs and why we were able to provide the level of detail that we did on Pages 17 and 18 is they do include specific schedules. They do include annual ramps in them. So we'll give that specificity when we announce specific customer. Hope that makes sense. And Bryan, how would you describe if we have incremental capital with the general financing rules that that might be?

Yes, absolutely. And so Michael, we've kind of historically cited 50-50 on debt equity funding of incremental capital, which over the long term is a rule of thumb used by many in the industry. So I think that is fine for you to use as a rule of thumb still for us. Being mindful, of course, that the addition of more ESA customers, like David mentioned, could still benefit the very back end of the plan, '29, 2030, think of it, a potential benefit there. And the ramp rates of existing customers could also play a factor.

In addition, as we move into future years beyond 2030, these ESAs will reach their peak capacity levels in that early 2030s, maybe in the mid-2030s for the next round. But these contracted cash flows will be correspondingly higher levels throughout that period of time really, in the next 10 years. So super powerful to our cash flows as we think ahead. So irrespective, we do expect this CapEx plan to grow, and it would be accretive and we'll be prudent with our mix of debt and equity in hybrids because we want to continue to create incremental value, not only for you, our investors, but also for the economic growth of our communities.

Okay. That's very helpful. And then just -- this was kind of asked, but in terms of what you're embedding in terms of the ramp rates here, are you assuming the like 80% minimum bill level or the full ramp? Or is that basically what the range is between those two?

Michael, I will give you a sense of the general approach we've taken to these, and that is that we typically in the first couple of years of the ESA, we look to the 80% minimum level. And again, if the customer uses more, they'll be billed more there. Different sites listening here at -- minimum build does not mean if you use more electricity, you only build the minimum. That's what you'll be billed if you use less.

But we -- typically in the first 2 years, we'll bill -- we model it in our plan at the 80% level. And then in the third year and beyond, we use more of an expected case, given what we've seen and what we expect from the customer. So it's more of an expected case. There's a range of upsides and downsides as you move out further in time. But the first couple of years across ESAs, we typically are using that 80% level to be a little more on the conservative side.

Our next question comes from Paul Fremont with Ladenburg Thalmann.

I guess my first question is, can you tell us roughly what your industrial rate is in terms of dollars per megawatt hour?

Well, so it varies by jurisdiction, Paul, and it's in a typical range. I don't know if, Chuck, do you want to comment on one of our typical industrial ranges again, with the varies by jurisdiction?

Paul, I'll let these guys jump in. I'll just remind you that our LLPS rate is a premium, 15% to 20% premium on the demand charge on the rate that we're about to give you.

Okay.

Go ahead, Chuck.

Yes. Our typical range is in the vicinity of $0.06 to $0.07 a kilowatt hour. Yes. So we -- [ $60 to $70 ] a megawatt hour if you want to use that metric, if set it in set. But yes, $0.06, $0.07.

Perfect. And then if there's a cancellation, is that rate essentially sufficient to allow you to recoup all of the costs? Or would there be any exposure in the event of an early cancellation?

So the provisions of the LLPS are quite specific on what the results are of a cancellation. So it's an effect through the term of the agreement, the counterparty is responsible for the minimum bill. So that will depend on what the total megawatts are of the contract. In general, that's a very strong protection if you think about size of these customers because we -- the rates from the LLPS under the large load power service tariff, our demand rate is 15% to 20% higher than the standard industrial rate, which you just heard from Chuck Caisley, is the standard rate of $0.06 to $0.07. So you've got very good protections for your customers.

Also in that scenario, Paul, which is a great situation, you will have a set of infrastructure, new infrastructure that you built in place for existing customers, and you've effectively had customers alongside who funded a very large portion of it. And again, the exact math will depend on the size of that customer, the specific ramp they have over time. But we -- these LLPS provisions are strong. The customers with whom we've contracted. One of the hyperscaler customers put out a statement last week, their commitments around meeting their incremental costs are high. Their interest in being in our region and in having as much capacity as we're able to serve them is very high. So we're -- we feel great about the benefits that these contracts will offer for our existing customers and the protections that are embedded on the explicit terms of the LLPS.

And then for the contract that's in late-stage negotiations, is that -- would that be a new customer? Or would that be an expansion of an existing customer?

It could be either one.

Okay. And last question for me. With respect to the ESAs, are the 4 signed contracts roughly equivalent in terms of megawatts? So should we assume like an average of 300 megawatts per ESA?

Well, so we won't disclose the size by customers, but the total steady state is 1.9 gigawatts. So obviously, the average of the 4 is -- comes close to 500. But we're not -- we haven't broken it out by individual customer, and we want that -- that is confidential. But the total size we have described not only in aggregate, but how we expect that to feather in over each year, and that's laid out in our slide presentation.

Our next question comes from Anthony Crowdell with Mizuho.

I appreciate the detail. I just wanted to jump on Paul Zimbardo's question earlier. Just if you could help me out, where did you end the year on an FFO to debt basis? And then thoughts -- and this maybe was the heart of Zimbardo's question. Just as you're going into very significant CapEx cycle, thoughts of maybe adding a cushion to the downgrades right -- to your downgrade threshold?

Anthony, our FFO to debt 2025 was right around that 14% area as well. And that was despite the weakness we had with weather and the industrial demand weakness. We talked a lot about the 14% FFO to that target. And -- this will be a little bit repetitive to what I said to Paul, but we really do expect this growth in cash flows from operations each year throughout the 5-year plan to be quite robust. And with the CapEx plan at the level it is to, we have inserted planned common equity issuances of $3.3 billion. So this is a robust equity issuance plan, and one that we believe will be appreciated by the rating agencies.

We're also moderating our level of annual dividend increases, allowing us to retain higher levels of earnings within equity each year. These are 2 very meaningful steps that our Board supports to the benefit of our balance sheet. So keeping a strong balance sheet and our credit ratings is really important to us. And as I pointed out earlier, we believe we absolutely have some of the most predictable cash flow projections in the industry because they are fortified by those ESAs with top quality counterparties with that strong LLPS tariff protection and inclusive of monthly minimum bills that David mentioned. And those escalate over time with the annual -- those -- the ESA agreements are very specific each year, what those minimum bills will be based on. It's an expanding capacity level each year to 5-year ramps and then a 12-year contract at a steady state peak after that.

So just we're in a little better position than I think many peers, Anthony, in the sense that our revenue stream is just 4 to 5 of those ESAs are more predictable than they've ever been with just tremendous counterparties. So that went into our thinking too when we targeted the level of 14%.

And just apologies, is that a change in the third quarter, your FFO to debt target?

Yes. Moody's lowered our downgrade threshold a year ago from 15% to 14% after our February call. So this is our first update -- comprehensive update that we've given since last February.

Our next question comes from Ryan Levine with Citi.

Is Evergy seeking DOE energy-dominant financing capital for its transmission plan? Or any color you could share around maybe alternative subsidized forms of capital outside of capital markets?

So as of today, the plan that we announced today is through the traditional financing mechanisms that are available to the utility and will be, as Bryan described, we have a prudent mix of debt and equity with some optionality around how we things forward, but with a real commitment to a strong balance sheet. For that next tier in our pipeline, we're absolutely open to and will be considering different paths. That could be in the form of some of the creative ideas that are coming out of Washington now and presenting that. It could be participating more directly with large customers. The LLPS tariff actually is embedded within it.

If customers bring their own capacity solutions, explicitly contemplated, if they are amenable to man response, it could reduce the capacity requirements. That's also [indiscernible] feature in the LLPS, that both those factors could positively impact the rate. So I think particularly getting into that next year that beyond the first 2 categories we list on Slide 7, the next 10 gigawatts, creative approaches are going to be important.

We're committed to exploring those. And I think a range of different options will be there. I think the size and scale of the opportunity before our country as well as our company is such that it warrants exploring those opportunities. But I would emphasize, though, is just with the announcements we've made today, it's a transformative growth opportunity for our company, backstopped by ESAs with large customers, great customers. We really appreciate their commitment to our region. So Google and Meta and [ Beale ]. But we're excited that we think we can assign at least 1 more this year and keep moving beyond that. And as we go further and further, I think those kind of creative options are absolutely things that we'll be open to and we'll continue to explore.

And then a follow-up on that. Does that imply that you looked at the [ Kayak ] structure for the existing deals but passed on it and maybe would we consider that on future deals? Am I reading too much into that?

Could you expand on your question a little bit? [indiscernible] that are different from the ones I'm typical used to, but go ahead.

Yes. Just in terms of having some of the customers prepay for some of the associated capital in advance in terms of the [ Kayak ] structure, but just in terms of just that concept.

I got it. So that's -- the LLPS tariff does not go down that route. But it certainly, as I mentioned, that for additional potential opportunities in down the road, either that kind of setup or customers bringing their own -- potentially their own generation solutions that either brought directly or contracted for, those kind of approaches are absolutely things we're open to and the tariff explicitly contemplate. So that could be a direct -- an SPP, and we're part of the process there is looking at different ways for large loads to bring their own generation on different products that they've advanced and we'll be advancing with FERC.

And so it could range from customers bring their own generation to bringing their own capacity they've contracted and thereby reducing their LLPS rate. Those are all different mechanisms we could use. What we've announced today is under the structure of the LLPS and supported by generation that we're bringing, but some of our current customers. And if you look in past announcements have are contracting with potential resources. And if they bring those, then those will be things that we'll contract for and will be an offset for the rate.

That concludes today's question-and-answer session. I'd like to turn the call back to David Campbell for closing remarks.

Thank you, Liz. I want to thank everyone for participating in the call today. I want to thank our customers for their commitment to our region. With that, have a great day. That concludes our call.

This concludes today's conference call. Thank you for participating. You may now disconnect.

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

Thank you, Haley, and good morning, everyone. Welcome to Evergy's Third Quarter 2025 Earnings Conference Call. Our webcast slides and supplemental financial information are available on our Investor Relations website at investors.evergy.com. Today's discussion will include forward-looking information. Slide 2 and the 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 third quarter highlights and provide updates on economic development activities and our regulatory agenda. Bryan will cover our third quarter results, retail sales trends and our financial outlook. Other members of management are with us and will be available during the Q&A portion of the call. I'll now turn the call over to David.

Thanks, Pete, and good morning, everyone. I will begin on Slide 5. This morning, we reported third quarter adjusted earnings of $2.03 per share compared to $2 and $0.02 per share a year ago. The increase over last year was driven by a recovery of regulated investments and growth in weather-normalized demand, partially offset by higher interest and depreciation expense and dilution from convertible debt. .

Our year-to-date adjusted earnings are $3.41 per share compared to $3.46 per share a year ago. With these results year-to-date, we are narrowing our 2025 adjusted EPS guidance range to $3.92 to $4.02 per share from our original 2025 adjusted EPS guidance range of $3.92 to $4.12 per share. The lower midpoint is primarily due to weather headwinds from below normal cooling degree days in the second and third quarters, which negatively impacted our results by $0.13 per share. I would like to compliment the team for implementing mitigating actions across the business, offsetting more than half of the weather headwinds.

However, we have not been able to offset the full magnitude in what has otherwise been a strong year of regulatory and operational execution, while advancing our strategic objectives. Our fundamental long-term outlook remains very strong, bolstered by tailwinds from a generational economic development opportunity and the investment needed to enable it. Brian will discuss the quarterly drivers and our earnings outlook in more detail in his remarks. We've achieved strong operational and reliability performance through September.

Year-to-date, our generation availability as measured by the forced outage rate as well as our overall grid reliability, as measured by SAIDI, are both favorable to target. These results demonstrate the benefits of our continued infrastructure investments and the hard work of our operations teams. I'd also like to recognize Wolf Creek as it nears completion of our 27th refueling outage with strong safety and overall performance. Wolf Creek generates around 1,200 megawatts of noncarbon meeting energy enough to power more than 800,000 homes. I'd like to thank everyone on our nuclear team for their hard work and focus on sustaining the excellent operational performance of the plant.

I'm happy to announce a 4% increase in our quarterly dividend or $2.78 per share on an annualized basis. This increase is consistent with our updated growth outlook and working toward the midpoint of our 60% to 70% target payout ratio. Looking ahead, we will provide a comprehensive financial outlook update on our year-end call in February. We will include refreshed views on our low forecast based on large customer impacts, our 5-year capital investment plan, the related financing plan and our long-term adjusted EPS growth outlook.

The 5-year capital plan will incorporate expected generation investments to serve load and meet SPP's increasing reserve margin requirements as well as transmission and distribution projects to support reliability. As Bryan will discuss with respect to the long-term update, we believe there are noteworthy tailwinds to earnings power as we advance our plans to support growth and economic development that will benefit our Kansas and Missouri customers and communities.

Slide 6 outlines our economic development pipeline and opportunities over 15 gigawatts switch relative to our size, represents 1 of the most robust backlogs in the country. Reflecting the geographic advantages of our region, the overall pipeline is strong in both Kansas and Missouri, and we are well positioned to continue to attract new businesses. Large customer interest in the energy service territory remains very strong.

Focusing on the top 3 categories of the pipeline we outlined a 4 to 6 gigawatt opportunity, large new customer load that represents the most active part of our Q. This Tier 1 demand represents a transformative 10-year growth opportunity for Evergy. When executed, we expect these products will deliver significant regional benefits across our states, supporting a leading-edge digital economy, creating jobs and expanding the tax base, while enabling us to spread system costs over more megawatt hours helping to maintain affordability for all customers.

We continue to work closely with Tier 1 large low to develop and implement transmission and distribution solutions to serve their expected ramp rates over the coming years. We are confident that we will be successful in winning and serving a large portion of this queue, which would in turn transform the size and growth of our company and enhance the economic prosperity of our region. The remaining pipeline totaling well over 10 additional gigawatts highlights the robust activity and sustained interest in Kansas and Missouri.

Many customers have already secured land or land rights, finalized site plans and are actively participating in capacity study. While not all of this load will ultimately be addressable, the ongoing dialogue underscores the depth of engagement and the readiness of customers to step in should others exit the queue. Slide 7 expands upon the 4 to 6 gigawatt Tier 1 large customer load opportunity. Beginning with the actively building category, I'm happy to report that last week, Lambda announced its plan to transform an unoccupied data center located in Kansas City, Missouri into a state-of-the-art AI factory in data center.

Their facility is expected to launch in early 2026 with 24 megawatts of capacity and as potential scale up to more than 100 gigawatts, 100 megawatts, excuse me, in the future. This product is a great example of a data center leveraging existing infrastructure with an ability to ramp low relatively quickly with minimal grid investment required and exemplifies why Missouri is an attractive destination for projects of all sizes. For the balance of our actively building customers, Panasonic and Meta are up and running, and our third large customer is making good progress through its heavy construction phase. Inclusive of lambda, we now anticipate peak demand at 1.2 gigawatts from these customers with over 500 megawatts to online by 2029, supporting our demand growth forecast of 2% to 3%.

Moving to the finalizing agreements category. We remain in the final stage of the negotiation with large customers for 2 data center projects. Subject to final agreements and product announcements, we expect to see an impact on our demand growth from these customers of 2027 and '28 and into the next decade which would raise the overall company demand forecast to 4% to 5% load growth through 2029. Approval of the LPS tariffs in both states is a key next step for finalizing the negotiations.

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

Overall, we continue to see an incredible level of interest in our service territories, and we are making progress with potential new large customers across all stages of the discussion. Each category reflects potential new entrants that will empower growth, investment and drive prosperity for our region. Now moving to Slide 8, I'll touch on our latest regulatory developments. 2025, as you know, has been a busy year for our regulatory team, and we've demonstrated considerable progress in advancing our strategic objectives.

The team's results this year reflect the constructive policy framework and economic development opportunities in both states as well as our ability to find alignment with broad groups of stakeholders and achieve constructive settlement agreements. Beginning with Kansas, we filed for and received approval of redetermination to own parcel shares of 2 new combined cycle natural gas units and the solar farm, both are all in Kansas Central. These projects were identified in our IRP preferred plan and reflect our all of the above approach to meeting growing customer demand and higher capacity margin requirements in the SPP.

The Kansas Corporation Commission issued an order approving a unanimous settlement agreement for Kansas Central rate case on September 25. The settlement achieved a balanced outcome for all parties, including adequate recovery for the investments needed to provide reliable and affordable electric service. A key open gen item in Kansas is the unanimous settlement agreement we filed on our large load power service tariff docket on August 18. The proposed tariff applies to customers with demand exceeding 75 megawatts and establishes a rate structure with the focus on large customers paying their fair share and being subject to additional protections that I'll describe later in my remarks.

We believe the LPS establishes a competitive rate at physicians Evergy to attract, serve large new loads, enabling growth and prosperity for our communities. We anticipate an order from the KCC on the settlement agreement as part of the commission's business meeting later today. Pending to Missouri, we've successfully advanced plans to construct new generating resources. The MDSC approved settlement agreements in our CCN applications for 2 solar farms, partial ownership in 2 combined cycle natural gas units and full ownership of a simple cycle natural gas plant.

We believe these projects form a cost-effective package of reliable energy solutions for our customers, and this outcome demonstrates alignment with the Public Service Commission's interest in securing additional generation resources for Missouri utilities. Similar to Kansas, to large load, power service tariff proceeding continues to advance in Missouri. [indiscernible] filed a nonunanimous settlement agreement earlier this fall with terms similar to those filed in Kansas including contractual protections, provisions to ensure that large customers pay their fair share of system costs and a competitive rate that supports economic development.

We anticipate an order from the MPSC by the end of the year. Last, the planning process for our upcoming Missouri Metro rate case is underway, and we expect to file the case in February 2026. Slide 9 highlights legislation and regulatory mechanisms that support growth in our region and helps to position Kansas and Missouri as premier destinations for infrastructure investment to assure reliability and new advanced manufacturing facilities, data centers on the large customers. These mechanisms are the product of broad-based alignment between Evergy, the governor's office, state legislators or regulatory commissions and key stakeholders as well as our shared commitment to seize on the growth opportunities ahead of us for our customers and communities.

Constructive regulatory frameworks that enable timely infrastructure investment to meet the needs of both existing and new customers are critical to our success and the bills passed over the past 2 years in both states advance these priorities. This supportive landscape reinforces our agents position as a top destination for growth. Evergy is committed to delivering safe, affordable and reliable service to our 1.7 million customers. As large new customers join our system, all stakeholders benefit from broader cost sharing and unprecedented economic development. I'll conclude my remarks on Slide 10, which highlights the core tenets of our strategy. I'll focus specifically on affordability.

Since the merger that created Evergy, we have achieved tremendous progress on affordability and regional rate competitiveness, driven by significant reductions to our cost structure and investing at a slower pace than peer utilities. Over that time, our rate trajectory has remained well below regional peers and far below inflation. This requires hard decisions and the full focus and dedication of everyone in our company. I'm very proud of the results that these activities enable us to deliver for all of our customers.

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

Under both LLPS tariff, new large customers, will pay a higher rate than that paid by our existing large customers. As a result, the revenues from new customers will directly mitigate future rate increases for our existing customers as we're able to spread the fixed cost of our system over a broader base. In short, new large customers will pay a reasonable premium to the cost to serve them while also maintaining a competitive rate. And all customers will benefit from a motorized grid and new highly efficient generation resources.

The tariffs are also designed with key safeguards in place. These include, among others, customer commitments of 12- to 17-year terms, an 80% minimum monthly bill requirement, exit fees upon early termination and collateral posting. It's important to note this tariff structure is consistent with the intent of our large new customers to be good stewards as part of our Kansas and Missouri communities. In the LLPS dockets, they were active participants throughout the process and along with many other stakeholders, contributed to and signed on to the settlement agreement.

As I noted earlier, these agreements are currently pending approval by the Kansas Corporation Commission and Missouri Public Service Commission with the KCC's decision expected later today. Collaboration with large customers does not stop at paying their fair share. Their projects will create construction jobs, permanent jobs, and expanded property tax base and community health development benefits. As an example, 1 of our customers announced it will bring its skilled trades and readiness or STAR program to the Kansas City area. The company is collaborating with the Missouri Works initiative and the Urban League to help increase the entry-level pipeline in the skilled trades with a focus on underrepresented communities.

All Star preimplement programs are paid training programs, and offer networking opportunities to help participants move directly to employment on local construction products. We hope and expect that this example will be just 1 of many. The vitality of our region has made it an attractive destination for advanced manufacturing and data center customers and their investments in turn have tremendous potential to drive a virtuous cycle of growth and prosperity in Kansas and Missouri for years to come.

I will now turn the call over to Brian.

Thank you, David. Thank you, Pete, and good morning, everyone. Let's begin on Slide 12 with a review of our results for the quarter. For the third quarter of 2025, Evergy delivered adjusted earnings of $475 million or $2.03 per share compared to $465 million or $2.02 per share in the third quarter of 2024. As shown on the slide from left to right, the year-over-year drivers are as follows: First, a 2% increase in weather-normalized demand growth drove the majority of the increase of $0.06 per share and the margin shown on the slide and recovery of and return on regulated investments contributed an additional $0.11 of EPS.

Offsetting these favorable drivers are higher depreciation and interest expense related to our infrastructure investments, leading to a $0.07 decrease in EPS and dilution from our convertible notes led to a $0.03 decrease for the quarter. Turning to Slide 13, I'll provide more detail on our sales trends. On the left-hand side of the page, you'll see weather-normalized demand increased by 2% in the third quarter as compared to last year, following the 1.4% year-over-year increase we experienced in the second quarter. This continued strong momentum was driven by increases in both residential inimercial usage, including load from the meta data center in Missouri that is reflected in our commercial customer class.

At a macro level, the continued robust customer demand in our service areas is supported by a strong labor market. as the Missouri, Kansas and Kansas City metro area and employment rates remain below the national average of 4.3%. Moving to Slide 14. I'll provide some further detail on our expectations for full year 2021 results. As David mentioned, we are narrowing our guidance range to $3.92 to $4.02 as compared to the original guidance range of $3.92 to $4.12. Our mitigation efforts of approximately $0.10 of EPS benefit are expected to offset a substantial portion of the $0.13 of headwinds experienced by below normal cooling degree days in the second and third quarters. In addition, we now anticipate an incremental $0.02 of dilution related to our convertible notes given our recent strong stock performance. We have forecasted incremental dilution from the convertible notes in our 2026 EPS modeling and continue to expect to achieve the top half of 4% to 6% growth in EPS in 2026, off of the midpoint of our 2025 original guidance range.

As I'll discuss shortly, Evergy's fundamental long-term outlook remains stronger than it has been in decades, bolstered by tailwinds from a generational economic development opportunity and the investment needed to enable it, which will benefit all future years in our financial plan. Slide 15 outlines a recap of our long-term financial expectations. and considerations for our comprehensive growth update, we will share with you during our fourth quarter call in February. First, we highlight our Tier 1 customer opportunity of 4 to 6 gigawatts of peak load. As a reminder, our current 5-year plan incorporates low growth of 2% to 3% annually through 2029, reflecting solid growth in our current customer base and buoyed by the Panasonic, Meta and Google projects.

This loan growth expectation is further bolstered by rapid development data centers, such as the [indiscernible] facility discussed by David earlier, which is able to scale more quickly than the mega data centers via the use of existing buildings and existing electric infrastructure. Also, we are nearing final agreements with 2 data center customers that could drive an incremental 600 megawatts by 2029. And which would raise our loan growth forecast substantially to 4% to 5% on a CAGR basis through 2029.

We've also made great progress with customers in the advanced discussions category which represents a 2 to 3 gigawatt opportunity, driving even more low growth toward the back half of our 5-year plan. We certainly believe we have 1 of the most compelling customer growth opportunities in the entire industry that we expect will drive robust growth, not just in our 5-year forecast, but into the next decade for Evergy and for the communities we serve.

Next, I'll discuss our capital expenditure and rate base growth forecast. The foundational earnings power of the company will be fortified by our capital investment program. Higher levels of infrastructure investment are needed for grid modernization and incremental generation capacity to support the expansion of our existing customer base and new large load customers. These are tailwinds to our current $17.5 billion capital plan and corresponding 8.5% rate base growth through 2029. On the regulatory front, to maintain the credit profile of our utilities, and to incorporate the affordability benefits of large loads, which allow us to spread system costs over a broader base, we plan to be on a somewhat regular cadence of rate case proceedings.

With the large infrastructure plan comes regulatory lag and over the past couple of years, the states in which we operate have taken proactive steps to help utilities better manage elevated depreciation and interest expense through the use of plant and service accounting mechanisms. We also utilized natural gas sale provisions in both Kansas and Missouri. These constructive mechanisms helped to reinforce our solid credit profile. There in this phase of significant infrastructure build out, we will utilize equity and equity content financing options to fund a portion of our capital requirements and to support our strong investment-grade credit rating and FFO to debt threshold of 14%.

It is important for you all to know that we will continually evaluate the overall level of equity funding needs, recognizing that large load customers in our pipeline could significantly improve our cash flows from operations. beginning in 2026 and accelerating throughout the next several years. Thus, there is a real opportunity to moderate our equity needs for the current $17.5 billion capital investment plan. Now our company can only be successful when our communities strive and we maintain affordability for our customers. We are committed to staying laser-focused throughout the years ahead on affordability for our current customers, and we believe our long-term plan will be successful in doing so. As we look to rolling out our updated 5-year plan in February, I'll mention again the many tailwinds to our current adjusted EPS growth outlook and a transformational opportunity for us here at Evergy.

We're excited for us to come and look forward to sharing details with you on our year-end call. And with that, we will open up the call for your questions.

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

Hi. Good morning, team. Thank you very much. The first 1 I wanted to touch on, just as we think about 2026 in Missouri legislative session, obviously, there's been a lot of progress in recent years for all the different flavors of utilities. Do you have any priorities or anticipate efforts for 2026? And could this influence the rate case cadence?

Paul, we were real pleased to work closely with many stakeholders last year in Missouri. It had a list, obviously, the commission Charhon, the Governor's office legislative leadership of the utilities and key stakeholders. So there's a lot of progress they did us before. A lot of next year will be around implementing and following through on the elements of SB4 related rule-makings. .

So I don't anticipate there's I always talk with the team, we always talking to the team about ways that we continue to advance constructive mechanisms. But after such a busy year and such consequential legislation last year, I think you might be able to letter calendar in 2026, but important steps to undertake to advance forward on the constructive mechanisms on S4.

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

Paul, it's hard to answer that question without getting into what will be in our year-end update. So I think that Brian did a nice job of describing the multiple tailwinds that are make us so excited about the prospects for growth in our region and all that's going to bring for our customers and communities, and that's both the low growth element, the investments needed to make sure that we can serve that load and meet SPP's higher reserve market requirements and the benefit of the pacing have enough fnancing plan.

So our prior capital plan, we laid that out by a year, we'll lay it out a year in our upcoming capital plan. there's obviously a significant amount of investment. And you can see what that is by year, but there's also loan growth that helps to mitigate any regulatory lag. So we're really excited about the tailwinds around it, and I won't get ahead around that profile. I think Bryan did describe for 2026 itself. We got we're reaffirming our confidence being the top hat of [indiscernible] 26, and then we'll be talking about the how those tailwinds manifest up themselves and upgraded an updated set of an updated financial plan that will outline recall.

Okay. I understand. I had to try.

We're excited, Paul, as you know, because we're excited because the benefit it's going to rain to our region, our customers and communities and it's a comprehensive set of factors that are driving [indiscernible]. .

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

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

That's a great question. It is a person I'm now nearly 5 years in this region, and I've been very impressed. And of course, our service territory expands over to Central Kansas and Wichita. So we're it's much broader than just the Kansas City or in there are parts of the states that are more distant from the state line. But that's the question narrowly about our region. I'm by Chairman group called the Kansas city area Development Council. It represents counties on both sides of the state line extending all the way from Topica to Kansas City and East toward a Northward and southward.

So and it's a collaborative approach. There's actually been legislative truce in the past to mitigate potential poaching of that might go on across state lines. So they really do a nice job of collaborating the in the great state of Texas, I live 50 miles from any state lines, and I was reasonably close to them. Here, I'm a quarter mile from the state line and it's the collaboration that happens when you've got that kind of seamless integration I've been very impressed to see I've got an older brother. There are times when within a family, you might have dynamics and that can happen. But in general, the teamwork is strong in the collaboration time.

Okay. We'll hear more family stories later on. And then other question, in terms of that $17.5 billion CapEx, assuming that you get the large load tariff there, you've got you'll have that, you'll have the PSA, the Quip. How much of that 17.5% would actually be subject to a typical rate case filing, right? I like how much of that can you recover without going through a regular rate case as you call it the cadence of base rate cases.

Yes. So there's ultimately, all of our investments are subject to reviews of to make sure they are prudent and reasonable. There's a set of different mechanisms that help to mitigate the cash fabratorylag. with PSA in both states, that mitigates the earnings lag, but we've got riders in place in both states, a Cisco property taxes to pension to other elements and the CWIP will help with our new natural gas plants. We lay out the different parts of our capital plan in the appendix. So the new generation component is shown like I think it's on Slide 21.

So that could give you a good measure for what which pieces of the capital plan are in the more traditional category versus what's in the new generation category. The SWImechanism is slightly different between Kansas and Missouri. But in both states, we were pleased to get that those provisions introduced to was in Kansas '24 and Missouri '25, reflecting the support of both states. We're building new natural gas generation and recognizing that with the investment programs of that size is important to have some mitigant to lag. So that's out of our total capital plan, you'll see that new generation is about 1/3, 2/3 is in the traditional categories, grid modernization, ensuring reliability keeping the lights on and providing great service to our customers.

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

Yes. And most of the transition Kansas side, you've got that road.

Yes. Okay. Very good. That's all right. Thanks. .

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

Everybody. It's actually Nathan Richardson on for Nick. I just have a quick 1 for you. So I was wondering if you could talk a little bit about the third data center you mentioned and given the 4% to 5% sales growth guidance, I was wondering how impactful that third data center specifically could be in moving the needle for the sales growth.

Nathan, that's a great question, and I'm glad you asked it. So the as you know, we've included in our financial plan that we provided last year, a 2% to 3% annual loan growth, but we have quantified that the 2 customers in the actively building category potentially to raise that annual load growth to 4% to 5%. The addition of the third I'm sorry, the addition of the third customer, and this is in the finalizing agreements category, not mixing up the categories.

So the 2% to 3% low growth is from the actively building category. The potential to go to 4% to 5% is from the first 2 customers in the finalizing agreements category. You're absolutely right, that third data center customer we've now added to the finalizing agreements category would be additive to 4% to 5%. As with the customers in the advanced discussions category. So thank you for that clarification. .

Is there any quantification there or just that it's incremental?

No. The bulk of that, we expect would be post 2029, but we've not quantified it, but that will be part of our obviously, update the year-end call with the overall views on low growth tailwinds. We added it to the category of finalizing given just the sheer amount of progress we've made with that customer in terms of advancing discussions advancing agreements and a commitments related to dose. So it's it makes sense that it included in that category. We've not quantify the incremental amount.

But we just noted that it's those additional customers beyond the 2 that are in the final agreements category would actually be additive to the 4% to 5% annual load growth potential.

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

David, Bryan Yes, I just had a quick 1 on the LLPS tariff discussions. Given you guys have a settlement, I know it's not unanimous, but can you just talk about like effectively at a high level, what's left there, what the main sticking points are? And what you think kind of the time line for resolution around some of this stuff is. I'm pretty sure there's a settlement conferences coming up and then expected time line as the end of February, but just want to hear about that and then how that works into kind of moving some of these finalizing agreement buckets into the actively building bucket or signing ESAs associated with it.

You bet. I'm glad you had the question because I'll clarify because I think you may be thinking about the time line that's occurring on the different side of the state in Missouri. So for us, we have 2 LLPS proceedings. One is in Kansas. We have a unanimous settlement agreement that we signed in Kansas. And there's already been briefing on that.

And it's actually we expect a decision on that by the Kansas Corporation Commission later today. It's on the docket for today. So given that they've already had a hearing on that animal settlement agreement. We actually anticipate a decision in Kansas later today. And that was the unanimous agreement covering all issues, including all parties. In our Missouri LPS proceeding, we did have a partial settlement. We have gone through a hearing.

Not all parties were alignment on that. The structure of the settlement that included many parties, but not all, have terms that are very similar to the ones in Kansas, so it's protections. It has a rate that is higher for the LPS customers. And it's a structure that ultimately like as we saw in Kansas, was a result of robust dialogue and included the large customer.

So I think it's a competitive rate as well. We think it aligns with the governor's policy in the state in support for growth and development. And with the commission's overall focus on that. But we'll have a decision on that. We expect by the end of the year in our case. There are other proceedings in Missouri for other utilities that are a little behind our we filed our first. So hopefully, that makes sense with respect to different contexts in Kansas.

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

I Like you're speaking, I've got some team members in the room now, and I'll tell if they need to be no, all getting tight. Yes, I think the LPS being signed is a very important enabling step. So that's and we do hope Kansas has always been a little bit schedule-wise, but they're not far behind. So we think that the time line sets us up well for what we know is going to be an important update on the year-end call. And it's important for these customers as well. The Q is a very active one. Folks are here to come online. A big chunk of why we have such a big is because we've got customers lined up for any reason, and we don't see those reasons happening. There's tremendous interest in the customers who are in our actively building and finalize agreements category, a lot of momentum. But we've got folks lined up behind them. So we believe that the LPS decisions, meaning on the time they are, should enable us to move on the time line we're hoping to achieve.

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

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

Paul, it's Bryan. Thanks for the question. As a reminder for everyone, our current capital investment plan 5 years is $17.5 billion. In total, we believe that will be funded in part by up to $2.8 billion of equity and equity content capital market instruments, such as JSM, junior subordinated notes. I do think it's important for you to know that we'll continually evaluate the overall level of equity funding needed recognizing that, as you say, that energy usage from customers in our pipeline could significantly improve our cash flows from operations beginning in earnest in 2026 and then accelerating throughout the next several years.

Thus, there's a real opportunity to bring that level of equity down by what I've said before, hundreds of millions of dollars. I should also mention that we continue to see upside bias in our capital investment needs to serve our existing and expected new customers in the year ahead, which will also necessitate a somewhat balanced approach to debt and equity financing. Is that helpful.

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

Yes, that's the way to think of it for modeling for sure.

Okay. And I guess we'll get more clarity, obviously, as time goes on. But and then I guess I wanted to on the 10 of mitigation measures that you guys had with respect to the earnings how should we think about those mitigation measures going forward? Do those are those timing issues and they'll show up next year? Or are those things that you found that you think are more ongoing or some mixture of the two.

Paul, I'll describe those are in-year mitigation measures. So obviously, we are size of the weather headwinds and a little bit of incremental headwind from the convert was we've would hope that we could offset all of it, but we were able to offset $0.10 of it that's really in year mitigation measures. It doesn't impact our lumenalong-term outlook.

I've now been is my fifth year at the company. There were 2 years where we had really warm weather and adjust the range upwards didn't change our long-term fundamentals. This is a year where weather headwind, so it's going to impact our performance this year, but it's both the weather impacts and the mitigation measures are really within the content of this calendar year are the drivers for our fundamental plan, as Brian mentioned, or you on 2026 and then the drivers for our long-term plan remains intact. It's sort of unaffected by the vagaries of weather.

Okay. And then with respect to the Lambda deal, which seems sort of interesting here, I was just wondering, would that I guess, first of all, when would it go what time frame would it go from 25% to the 100? I guess 25%, it sounds like it would the 25 megawatts would be beginning of next year. But then it goes to 100, I'm just wondering how long does that ramp up take'm just curious or is it now?

Yes. We as I described, it's in the 25-megawatt range, sorry, next year, and it's probably in the next 4 to 5 years that it gets to that potential overall size. Really excited about that project need company, deploying advanced technology in their data center and AI factors he described it. So it's a we were pleased to see that announcement. It was timed well with some economic development meetings here in town and reflects how attractive our region is and really impressed by how they leverage an existing building and existing T&D infrastructure largely, and that's how they were able to ramp up to that level.

Historically, a 25-megawatt customer would be considered very large on the new era that is anywhere. But it's still obviously a creative approach we're pleased to have advanced facility like that, taking advantage of a building like that.

Right. That sounds kind of unique. I guess what I also wondered was like in terms of the context of these large low tariffs that you were describing, since it's under 75 megawatts and then going to 100 megawatts would a scenario like that be subject to, obviously, this hypothetical hasn't all been approved. But just wondering how in the context of these settlements that you've had with these large low tariffs how would a customer like that be treated? Would that be a large load it that came in initially below the 75 megawatts but what would pro 100 megawatts do you follow what I'm saying? Or would it be because if final number is 100, it would be a large load it makes sense?

Typically, these customers are focused on what their ultimate loan level is going to be because they want to make sure that they've got the infrastructure and capacity to get there. And this is an example. So the tariff addresses as you ramp up getting up to those higher levels. And again, these customers the ones that go into the large lows definitely want to make sure they've got the capacity and the ability to do this, so they know and are contemplating getting up to the LPS. It's ultimately stayed in the 25-megawatt range to be a different tariff level. But the ones that these customers are very interested in those higher levels of loads. So and they know that as they get there, they get to that tariff rate.

Right. So it's what they ultimately get to, would it be 1 of these like understand.

Our next question comes from the line of Anthony Crowdell from Azuho.

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

Yes. We actively building that was probably my follow-up how I answered it earlier. So if you look at Slide 7, good place to go, the actively building, which is Panasonic and Meta and third customers in the heavy near incompletion of construction, that's in the 2% to 3% low growth rate. .

And in the 4% to 6%, right?

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

Great. Just the 2, not the third.

Correct.

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

Yes. So we haven't given guidance on that specific range. But I think if you look at our the $17.5 billion capital plan, it going back in time, there were higher levels of capital in the out years in that in that plan. We know that we will be presenting as part of the year-end call, an integrated financial plan that reflects the relationship between rate base growth, incremental loan growth is obviously of help in reducing regulatory lag and the relationship that you see between that rate base growth and earnings growth.

And there's a range that you see across different companies, and there's no reason why we would be outside of that range. So obviously, links as well to what the phasing is of both the loan growth and the capital in the plant. So we would we know that that's a question that we'll be addressing as part of our year-end update and the low growth and as we move into higher years in our capital plan, that will be reflected in the update that we provide.

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

I think it's a very insightful question. I think it's something I really like having Bryan and Pete join the team work with a couple of different utilities. I know my background, I like being able to describe to investors here are the factors that we can control and he are the factors that are clearly outside of our control and are readily quantifiable but recognize that the number of our peer utilities and there's a like the investors can like to see, "Hey, you can offset even if it's something easily to easily track and identify like weather, and you find mechanisms in your plan or build in an approach in the plan that can offset that.

So we'll continue to have that discussion internally because we recognize that feedback. We'll always be very transparent, plan to be very transparent with the tax because they as I mentioned, they didn't impact their fundamentals when they were positive. They are not going to impact the fundamentals when it's a year when it's a little more mild. It's a very mild August particular year. But it's something that we'll consider.

And Bryan will be a real helpful thought partner as we consider what the best approach is there. But again, we're very excited about the long-term fundamentals. We're certainly not overreacting to the that was demonstrably a very mild Q2 and Q3, recognizing that we needed to implement the offsets that we did, and we're certainly always going to strive to be within hitting our targets in our range. So it's a good question, we'll continue to think about it.

Our final question comes from Paul Fremont from Ladenburg.

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

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

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

Most of our customers want to expand past the regional peak once up. Some of these projects are similar customers involved. So I don't think there's a fundamental dynamic there. For most of the we obviously track with the other customer announcements are.

And there are a couple of very unique large ones out there. But we're it's an average size is in the 600 to 700-megawatt range is still a very, very large customer and very large data center end. As I noted, the most want to expand best original peak if we're able to accommodate it, but we like some diversification in customers and sites, which is reflected in a robust queue. That helps keep everyone motivated as well.

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

So we that's a great question. And as we noted at the going to be 1 of the factors that's a driver for our plan update that we plan to give. Our integrated resource plan that we filed in '25, and we outlined in the appendix, which projects and the integrated resource plan were in last year's capital plan, which we're not.

As we develop that integrated resource plan, we included because information. We had included the 2 customers that were in the finalizing the agreement the category. You will see in an IRP from last year, a significant amount of incremental generation required to serve that load that was not yet included in the plan. So we have taken steps in terms of long lead time equipment, actions we need to take to be able to serve the customers that we've lined up. So we have some flexibility to do that. But I also note that we're going to be the next update to our capital plan and our integrated resource plan is going to factor in not only low growth expectations in the plants we need to serve those SPPs reserve margin requirements, but also changes in federal local policies impacting renewables.

And if renewables are less economic or harder to build, for example, we'll look at market capacity options, we'll look at potential retirement delays. We're going to look at the whole package to make sure that we are driving reliability and affordability for our customers. But at the end of the day, there's some incremental investments that we expect are going to need to be made, but we're going to look at that package of things in terms of what's that right mix of generation, how do we make sure we ensure reliability, take advantage of the growth opportunity, but also always keep an eye on affordability.

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

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

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

Helen, thanks, everyone, for joining the call today. We look forward to seeing all of you at EEI this weekend and next week. And that concludes today's call. Thank you. .

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