Conferencia de resultados del 3T 2026 de Evergy (EVRG): eleva su previsión de BPA, amplía su cartera de proyectos de gran carga

Puntos clave

• Evergy reportó un beneficio ajustado de 610 millones de dólares en el tercer trimestre de 2026, o 2,58 dólares por acción, frente a los 475 millones de dólares, o 2,03 dólares por acción, registrados en el tercer trimestre de 2025.
• La demanda minorista ajustada por clima aumentó un 4,5%, impulsada por un crecimiento comercial del 8,7%, un avance industrial del 3,0% y un mayor consumo por parte de centros de datos y Panasonic.
• La dirección elevó sus previsiones de BPA ajustado para 2026 a un rango de entre 4,35 y 4,50 dólares, frente a los 4,14-4,34 dólares previos, lo que refleja principalmente unas condiciones climáticas favorables en el tercer trimestre y un sólido desempeño operativo.
• Se prevé que cinco acuerdos de suministro eléctrico para grandes cargas ya formalizados, junto con clientes no acogidos al programa LLPS, respalden 3,1 GW de demanda máxima a lo largo del tiempo. La dirección prevé un crecimiento de la demanda minorista de aproximadamente el 7%-8% anual hasta 2030.
• Evergy firmó una carta de intenciones con Digital Realty para una ampliación de 1,4 GW adyacente a su proyecto actual de 600 MW. Esta potencial ampliación podría requerir una inversión de capital de aproximadamente 4.000 millones de dólares, aunque no está incluida en el plan financiero quinquenal vigente.
• La empresa elevó su dividendo trimestral un 4%, situando el dividendo anualizado en 2,89 dólares por acción, al tiempo que reafirmó su objetivo de crecimiento del BPA ajustado a largo plazo del 6%-8%+ hasta 2030.

Datos financieros clave

Desempeño comercial y operativo

Evergy señaló que la seguridad, la fiabilidad y la disponibilidad de generación evolucionaban favorablemente respecto a los objetivos. Su parque de generación mantuvo operaciones fiables durante las altas temperaturas y los picos récord de demanda registrados tanto para Evergy como para el Southwest Power Pool.

La demanda de electricidad comercial aumentó un 8,7% sobre una base ajustada por clima, principalmente debido al consumo de los centros de datos. La demanda industrial creció un 3,0%, impulsada sobre todo por el continuo aumento operativo de Panasonic. Por su parte, la demanda residencial repuntó un 0,8%.

Se espera que la demanda agregada de los grandes clientes con contratos firmados aumente desde aproximadamente 350-400 MW en la actualidad hasta unos 2.250 MW en 2030, alcanzando los 3.100 MW con posterioridad a ese año. Los cinco acuerdos LLPS formalizados suelen contemplar plazos de 16 a 17 años, requisitos de facturación mensual mínima y coberturas crediticias y de garantías.

Evergy anunció modificaciones contractuales que añaden aproximadamente 110 MW de carga máxima en dos acuerdos existentes. Otra enmienda de ampliación por 140 MW está condicionada a un estudio de transmisión que se prevé para finales de 2026.

La carta de intenciones con Digital Realty contempla una ampliación de 1,4 GW junto a un proyecto existente de 600 MW, lo que elevaría el total potencial en el emplazamiento a 2 GW. La dirección prevé formalizar un acuerdo de suministro eléctrico en el primer semestre de 2027, sujeto a las aprobaciones pendientes y a la adecuación con el marco tarifario mejorado propuesto para Kansas.

Más allá de los proyectos firmados, Evergy identificó entre 2,0 y 2,5 GW de oportunidades de expansión de Nivel 1 y entre 1 y 2 GW en conversaciones avanzadas con potenciales nuevos clientes. La dirección mantiene la confianza en alcanzar con el tiempo entre 5 y 7 GW en acuerdos totales con clientes de gran carga.

Evergy también destacó la asequibilidad de sus tarifas. La dirección señaló que las tarifas integrales acumuladas han subido aproximadamente un 7% desde 2017, frente al 25% de sus homólogas regionales y al 33% de inflación general registrada durante el mismo periodo.

Previsiones de la dirección

Evergy elevó sus previsiones de BPA ajustado para 2026 a un rango de 4,35-4,50 dólares, frente a los 4,14-4,34 dólares previos. El rango revisado refleja principalmente unas condiciones climáticas favorables en el tercer trimestre e incluye inversiones selectivas en O&M en el cuarto trimestre destinadas a la fiabilidad de la distribución y al parque de generación.

La dirección reafirmó su objetivo de crecimiento del BPA ajustado a largo plazo del 6%-8%+ hasta 2030, calculado a partir del punto medio de la previsión original para 2026 de 4,24 dólares por acción. La compañía prevé un crecimiento del BPA ajustado del 6%-8% en 2027, seguido de un avance anual superior al 8% entre 2028 y 2030.

Sobre la base de una TCAC estimada de la base tarifaria de aproximadamente el 12%, la dirección prevé un crecimiento medio anual del BPA de alrededor del 9,5% durante el periodo 2028-2030. Esta previsión incluye únicamente los acuerdos de suministro eléctrico firmados hasta la fecha.

El plan de capital quinquenal establecido por la empresa asciende a 21.600 millones de dólares. La dirección indicó que su plan de recursos integrados de 2026 añade aproximadamente 1.000 millones de dólares en inversiones incrementales, lo que eleva el gasto de capital estimado hasta 2030 a 22.500 millones de dólares. Este plan no incluye la posible ampliación de 1,4 GW con Digital Realty ni la ampliación contingente de 140 MW.

Evergy espera una relación de fondos de las operaciones a deuda del 14%-15% entre 2026 y 2028, con mejoras en 2029 y 2030. La empresa ha captado aproximadamente 700 millones de dólares en acciones ordinarias a través de su programa at-the-market, frente a su necesidad media prevista de entre 700 y 900 millones de dólares anuales hasta 2029.

Riesgos y aspectos a vigilar

• La ampliación de 1,4 GW con Digital Realty sigue sujeta a un acuerdo definitivo de suministro eléctrico, a las aprobaciones locales y a los avances regulatorios en la propuesta de tarifa LLPS mejorada de Evergy para Kansas.
• La ampliación independiente de 140 MW depende del resultado de un estudio de transmisión previsto para finales de 2026.
• El crecimiento de grandes cargas requiere inversiones considerables en generación y transmisión. La dirección prevé que el grueso de la ampliación de Digital Realty y las necesidades de capital asociadas se materialicen en la década de 2030.
• El plan propuesto para mejorar la asequibilidad para los clientes de Kansas requiere aprobación regulatoria. Evergy prevé una resolución para mediados de 2027, aunque aún no se ha fijado un calendario procesal definitivo.
• Los litigios tarifarios y los procedimientos de generación en Misuri siguen sujetos a las decisiones de la comisión, los procesos de acuerdo y las vistas probatorias.
• El clima sigue siendo un factor de volatilidad en los beneficios, aunque la dirección confía en que una mayor proporción de clientes de centros de datos con alto factor de carga reduzca con el tiempo la sensibilidad porcentual.

Puntos destacados de la sesión de preguntas y respuestas con analistas

Los analistas se centraron en las necesidades de capital y en el calendario de la ampliación de Digital Realty. La dirección afirmó que el incremento de carga del proyecto podría comenzar en 2029, acelerarse en 2030 y continuar hasta 2033. Evergy prevé poseer la gran mayoría de los recursos de generación necesarios, con un requerimiento de capital indicativo de aproximadamente 4.000 millones de dólares.

La dirección describió un mix de generación centrado en capacidad eficiente de gas natural, energía solar y almacenamiento en baterías, con especial énfasis en recursos gestionables. El director financiero, Bryan Buckler, aportó una estimación orientativa de unos 3.000 millones de dólares de capital por cada 1 GW de demanda de clientes y afirmó que dicha escala podría sumar aproximadamente 200 puntos básicos al crecimiento de la base tarifaria.

En cuanto a las coberturas regulatorias, la dirección señaló que el marco mejorado de LLPS procuraría mayores contribuciones de los clientes a la nueva generación, posibles pagos por adelantado y mecanismos para abordar las obras en curso. Estas disposiciones buscan proteger a los clientes existentes y mejorar la eficiencia financiera durante la fase de construcción de los proyectos.

Respecto a los cambios políticos y regulatorios en Kansas, la dirección afirmó que mantiene la confianza en la solidez de la cartera de proyectos de gran carga. Destacó la continuidad de un gobierno estatal dividido, una cartera equilibrada entre Kansas y Misuri y la concentración de oportunidades en instalaciones de clientes ya existentes o adyacentes.

La dirección describió la potencial inversión en transmisión en el Southwest Power Pool como un catalizador positivo a más largo plazo que no está contemplado en el plan de capital actual. Los plazos, la estructura de licitación competitiva y la selección final de proyectos siguen sin definirse, y es probable que gran parte de esta oportunidad se extienda a la década de 2030.

Transcripción completa de la conferencia de resultados

Transcripción completa de la conferencia de resultados

Comentarios de la dirección

Operator

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.

Peter Flynn

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.

David Campbell

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.

W. Buckler

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

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

Preguntas y respuestas

Unknown Analyst

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.

David Campbell

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.

Unknown Analyst

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.

David Campbell

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.

Operator

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

Nicholas Campanella

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?

David Campbell

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.

Nicholas Campanella

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?

David Campbell

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.

Operator

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

Stephen D’Ambrisi

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.

David Campbell

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.

W. Buckler

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.

Stephen D’Ambrisi

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.

W. Buckler

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.

Operator

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

Andrew Kadavy

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?

David Campbell

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?

W. Buckler

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

Andrew Kadavy

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?

David Campbell

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.

Operator

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 Campbell

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.

Operator

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