Evergy (NASDAQ:EVRG) reported third-quarter financial results on Thursday. The transcript from the company’s third-quarter earnings call has been provided below.
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Summary
Evergy Inc. reported third quarter 2026 adjusted earnings of $2.58 per share, up from $2.03 per share a year ago, driven by warmer weather, load growth, and large customer revenue.
The company announced expansions with large customers, including a 1.4 gigawatt project with Digital Realty, demonstrating strong customer relationships.
Evergy increased its 2026 EPS guidance to $4.35 to $4.50 per share and reaffirmed long-term EPS growth targets of 6% to 8% through 2030.
Operational performance was strong with favorable safety, reliability, and generation availability metrics, and the company’s rate competitiveness remains a focus.
Management highlighted progress in converting its large customer pipeline into signed agreements, supporting a transformative growth opportunity with a forecasted 7% to 8% annual retail load growth through 2030.
Full Transcript
Kelly (Moderator)
Good day, and thank you for standing by. Welcome to the Q3 2026 Evergy Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again.
Please be advised that today’s conference is being recorded. I would now like to hand the conference over to Peter Quinn, Senior Director of Investor Relations and Insurance. Please go ahead.
Peter Quinn (Senior Director of Investor Relations and Insurance)
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 Brian Buckler, Executive Vice President and Chief Financial Officer. David will cover third quarter highlights, our economic development progress, and our regulatory agenda. Brian 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.
David A Campbell (President and CEO)
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. A 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 over the 2027–2030 period and beyond. Additionally, we signed a letter of intent with Digital Realty for a 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. Operational 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 operation through hot weather and record peak demand for both Evergy and the Southwest Power Pool. Their execution helped ensure that we reliably served 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%+ 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 of moving toward a payout ratio of 50% to 60% over time. Turn to slide 6. We highlight the major gains in regional rate competitiveness Evergy has achieved over the past nine 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 LLPS. 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 cost, 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 LLPS Customer Affordability Enhancement Plan, a new vintage of tariff 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 Lech Holzer, who we know from her service to Kansas as a collaborative legislator of 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.
Turn to slide 7. Execution of our large customer strategy continues to deliver tangible progress for Evergy customers and the communities we serve. The amendments we announced today add approximately 110 megawatts of incremental peak load across two existing large load ESAs. As a result, the five executed ESAs now represent approximately 2.6 gigawatts of steady-state peak load, and together with non-LLPS large customers, we expect these projects to require approximately 3.1 gigawatts of peak load over time.
Additionally, we executed a third agreement for a 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 a signed 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 five ESAs operates under the Large Load Power Service tariff, or LLPS, 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 a 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 announced ESAs.
These agreements would further establish Kansas and Missouri as premier destinations for infrastructure investment and contribute 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 into signed agreements and provides an update on activity further down the queue. Starting at 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, as well as 1.7 gigawatts of additional projects that have executed ESAs, all of which require minimum monthly bill provisions spanning 15 to 17 years whether or not the capacity is fully utilized. Regionally, these will deliver significant benefits including supporting a leading-edge economy, creating jobs, and significantly expanding the local tax base while enabling us to spread system costs over a broader load 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 and existing ESAs or new ESAs in tandem. We are working on the transmission and generation solutions to enable them.
And to be clear, our five-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 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 and Advanced Discussions categories made meaningful progress in recent months. We look forward to converting a large portion of these prospective customer initiatives into 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 queue 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 5–7 GW of large load 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’s testimony return on capital is used—a 9.7% return on equity with a 52% equity ratio—we expect the revenue increase would equal approximately $118 million before the impact of new large load.
In addition, we filed a partial stipulation agreement related to the LLPS tariff. If approved, this 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% annual annualized impact relative to the end of 2017. The annualized impact is just 0.7%—an 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 is the first rate case that we’ve advanced with LLPS customers delivering $6 million annually to the benefit of existing residential and industrial customers. It 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 that 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 City. Since the approval of the LLPS 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 our 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 for Missouri West on November 3rd. This case is primarily driven by new generation investments for which we’ve received CCN approvals as well as beneficial grid modernization projects that improve 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 load growth. Importantly, our request also reflects approximately $61 million of revenue offset from large load customers, demonstrating how the benefits of load 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, 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 load 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 our Missouri customers. Our CCN request includes a new natural gas plant, solar farm, and battery storage facility. A settlement conference is scheduled for January 14th and evidentiary hearings on February 24th. And lastly, we were able to reach a non-unanimous 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 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 load growth supporting it. Large customers pay premium rates and fund the direct costs required to serve them while their additional usage spreads 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.
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 advancing a cost-effective, all-of-the-above generation portfolio.
Our planned investments in 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 Brian.
William Bryan Buckler (Chief Financial Officer)
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 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. Weather 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.
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 load 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, weather-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 the Missouri, Kansas, and the Kansas City metropolitan area unemployment rates remain 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. 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, Bonner Springs, 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, and 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 five executed ESA LLPs together with non-LLP customers are expected to support 3.1 gigawatts of peak load 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 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 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 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. Additional 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 plans provide approximately $1 billion of incremental investment, taking our estimate of five-year capex through 2030 to $22.5 billion, which increases our projected rate base CAGR through 2030 from 11.5% to approximately 12%. Additional large load ESAs would provide further investment upside, and we’ll update our capital plan on our fourth-quarter 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 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 priced 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 of 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 of 6% to 8%+, 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 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 compared against an approximate 12% rate base CAGR discussed earlier, driving, on average, 9.5% EPS growth annually in those three years. As a reminder, our financial forecast only incorporates the ESAs we have signed to date, with further upside to and/or extension of our exceptional growth well into the 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 at some of the lowest in the nation. And with that, we will open the call for your questions.
OPERATOR
Thank you. At this time we will conduct the question and answer session. As a reminder, to ask a question, you will need to press Star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press Star 11 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Richard Sunderland of Truist Securities. Your line is now open.
Richard Sunderland (Analyst)
Hey, 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 five-year period and what impact that may have on the kind of 12% upside rate base growth you quantified in the script there?
David A Campbell (President and CEO)
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 plant that’s been remediated, well suited for industrial uses now, but really for that kind of purpose.
So we’re thrilled that DLR has 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 it is aligned with our enhanced tariff that we’re seeking approval for. So we expect to sign an ESA in the first half of 2027. The timeline for it, 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 it on today’s call. And as well, we anticipate that we would be providing the capacity to serve, which, as Brian described, is 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; need to have it in place a little bit in advance. Again, the bulk of this would probably be in 2030 and beyond when it really hits its ramp. But there’d be meaningful capital that would be associated with this and under a structure with enhanced provisions on the LLPs, 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 existing customers, and making sure it’s at sites that really make sense for this kind of activity.
So again, more details when we sign the ESA and give a broader update. But we’re really excited about this partnership and opportunity.
Richard Sunderland (Analyst)
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 it something you could see settled on a more expedited basis than kind of a full procedural schedule contemplates? And I guess if settled, could that also expedite finalizing the DLR ESA?
David A Campbell (President and CEO)
You know, it’s a great question. I do think it is a proceeding that can move under a more accelerated schedule, certainly relative to a rate case. But it is a proceeding where you want to make sure you get full input from stakeholders and 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 signed that first wave of ESAs 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 it will. We do expect it to resolve in the first half of the year. We’re well aligned with Digital Realty and what they’re seeking to approve — you know, 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 protections for existing customers that actually end up delivering benefits for customers, and having a site that everyone’s aligned with.
So we expect those to move in tandem with the ESA in the first half of the year.
OPERATOR
Thank you. One moment for our next question. Our next question comes from the line of Nicholas Campanella of Barclays. Your line is now open.
Nicholas Campanella (Analyst)
Hey, good morning. Thanks for the time and for all the updates.
David A Campbell (President and CEO)
Good morning.
William Bryan Buckler (Chief Financial Officer)
Good morning.
Nicholas Campanella (Analyst)
So hey, I just wanted to ask, just with the new leadership in the state of Kansas, obviously there’s been differing views on large load customers through elections broadly. But you also have many opportunities that are in the tier one 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? Thanks.
David A Campbell (President and CEO)
You bet, Nick. Great question and thank you. So I’ll first note that we look forward to working with Governor LeCoultre in Kansas. We know her from her service in the Kansas Senate, where she was a collaborative legislator and supportive generally of critical infrastructure to serve Kansas. I’ll note that there weren’t really any major statewide elections in Missouri, so Governor Kehoe and 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 hadn’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, the result of those state elections is actually a continuation of the status quo. Outgoing Governor Kelly is a two-term Democratic Governor. We worked collaboratively with her throughout her eight years and we thank her 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 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 5–7 GW of large load customer agreements. So capitalizing on the pipeline that we have — as you noted, a big chunk of that are expansions in existing sites — and it’s a pipeline that’s balanced across both states. Once you take account of the Digital Realty 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 that we’ll continue to take in both states is one that really focuses on making sure that we have a tariff in place that has large load customers paying directly for 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 the best benefits to existing customers. That’s why we filed for the enhanced tariff, and we’re also really focused on sites that work well for local communities, and the Sunflower site for Digital Realty’s LOI is a great example of that.
It’s a site that really is only going to be well suited for industrial applications like this one, in a massive, massive acreage, so you can have it in the right location. So we feel good about our pipeline, the benefits it will deliver as we look across our two states and, as you noted, in particular as we look at a lot of these as expansions and a robust pipeline across both Missouri and Kansas.
Nicholas Campanella (Analyst)
Hey, that’s great. I really appreciate it. And then thanks for the commentary on the $4 billion for Digital Realty. 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 be beyond 2030, but is there a way to kind of put a framework around what the available opportunity set is for the next ITP?
David A Campbell (President and CEO)
Nick, 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 Transmission Plan that SPP released — about $20 billion, about $10 billion of that involving projects that span across our service territory. Now, there can 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 notice-to-proceed projects given a short-term reliability timeline — that will have implications — and also what the ultimate timeline is to build.
A big chunk of those are 765 kV 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 not 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 share with you it’s likely into the 2030s. So I view it as something that could be a driver into the 2030s.
Not only incremental ESAs carry into the decade — that’s also when we get into a retirement phase for some of our older coal units. We have a number of wind and renewable PPAs where we’re off in that timeframe. I expect electrification will be a driver. And this transmission is another piece. It’s a part of the overall long-term tailwind that I’d cite.
Nicholas Campanella (Analyst)
Appreciate all the thoughts. Thanks guys.
David A Campbell (President and CEO)
Thank you.
OPERATOR
Thank you. One moment for our next question. Our next question comes from the line of Steve d’Ambrizzi from RBC Capital Markets. Your line is now open.
Steve d’Ambrizzi (Analyst)
Hey David and Brian, good morning. Thanks for taking my question. 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? Then I just have a follow-up.
David A Campbell (President and CEO)
Sure. I think you’ll see in our slides a listing of the things that are included in our most recent integrated resource plan. Now, those are 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 the highly efficient natural gas resources that we’ve been committed to investing in so far and then received 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 large customers will bring resources into the system, but most of the customers with whom we’re having discussions now are looking for us to provide the capacity and the 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 and energy needs of large customers — I expect you’ll see that as pretty representative going forward as well.
William Bryan Buckler (Chief Financial Officer)
Yeah, Steve, just to add to that, you know, as you think about the ramp rate for Digital Realty, it probably starts 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, you know, within our new five-year plan that we’ll roll out in February, or whenever we update.
The five-year plan for Digital Realty could be, you know, a few months after February. But that’s a mix that you’ll see once we finalize that ESA come into a five-year view. And we kind of just have a rule of thumb when you think about a one gig customer — and whether it’s Digital Realty or others, we could have several of those type projects going forward — the rough math on that is about $3,000 a kW. That’s kind of the going rate for a combined cycle today, which continues to go up. But think about, we use about $3 billion of capex per gigawatt of customer, and we expect to have multiple of those over time and are adding up to multiple over time.
And a rule of thumb to our rate base CAGR is that would roughly equate to about a 200 basis point increase to rate base growth.
Steve d’Ambrizzi (Analyst)
Very helpful. And Brian, you kind of — you know, maybe I buried 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 and then you’ve got 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, you know, I guess can you talk a little bit about what is the rest of that two to two and a half expansion opportunities bucket looks like, and then what are the gating items to, you know, converting that into ESAs?
Because it does seem like there’s, you know, a significant amount of activity at some of these sites. Thanks.
William Bryan Buckler (Chief Financial Officer)
Yep. Steve, I think it’s similar to what David described around digital reality. That pipeline is real, they have real sites. They still need to get through their full suite of local permitting, you know, for the larger expansion opportunities or new projects. You’re going to see those fall under an enhanced type of LLPs similar to the one that we’ve filed in Kansas and one that David described. That’ll make sure they’re paying their full fair share.
It’ll 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 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.
Steve d’Ambrizzi (Analyst)
I appreciate all the time. Thanks very much, guys.
Kelly (Moderator)
Thank you. One moment for our next question. Our next question comes from the line of Char Pereza of Wells Fargo. Your line is now open.
Andrew Kudavian (Analyst)
Hi guys. It’s actually Andrew Kudavian for Char. Thanks for taking my questions.
David A Campbell (President and CEO)
Morning, Andrew. Good morning.
Andrew Kudavian (Analyst)
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?
David A Campbell (President and CEO)
So I’ll ask Brian to supplement, but you hit on it. I think there are several features of the enhanced LLPs that are attractive. One is that it’s in effect adding to the LLPs structure. Given that the cost of new build is rising, we’re making adjustments to the LLPs 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 customers 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 the market circumstances as they evolve. But I think it’s also a mechanism that can allow for a little bit more efficient overall financing strategy. And as we announce CSAs and potential expansions to capital plans associated with them, obviously we’ll talk about the financing strategy associated with it.
I don’t know if there’s anything you’d add.
William Bryan Buckler (Chief Financial Officer)
Nothing to add. Andrew, did that answer your question?
Andrew Kudavian (Analyst)
Yes, very helpful. And then we’ve seen the weather be both a headwind and a tailwind for Evergy. With the data center load ramping, does the cooling load that it brings online, does that increase EPS sensitivity to weather, or would the higher base load kind of reduce that sensitivity?
David A Campbell (President and CEO)
Well, I think net overall will likely reduce the sensitivity. You’re going to have 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 high. Weighted as legacy, the old Great Plains business, we’ve got a pretty high mix of residential and commercial that’s more sensitive to weather. So I think as we add the higher load factor customers, they’re 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, this is my sixth year, and there has 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 there are years like 22 and 26, when it’s a hot summer, it just creates a little more volatility.
So there are 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.
Andrew Kudavian (Analyst)
Great. I’ll leave it there. Thank you.
Kelly (Moderator)
Thank you. This concludes the question and answer session. I would now like to turn it back to David Campbell, Chairman and CEO, for closing remarks.
David A Campbell (President and CEO)
Great. Thank you, Kelly, and thanks everyone for your interest. Sorry, I think the mic might 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.
Kelly (Moderator)
Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.
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