Ameren Corporation (NYSE:AEE) Q3 2024 Earnings Call Transcript

Ameren Corporation (NYSE:AEE) Q3 2024 Earnings Call Transcript November 7, 2024

Operator: Greetings and welcome to the Ameren Corporation Third Quarter 2024 Earnings Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. If anyone should require operator assistance, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Andrew Kirk, Director of Investor Relations, Corporate Modeling for Ameren Corporation. Mr. Kirk, please proceed.

Andrew Kirk: Thank you, and good morning. On the call with me today are Marty Lyons, our Chairman, President, and Chief Executive Officer, and Michael Moehn, our Senior Executive Vice President and Chief Financial Officer, along with other members of the Ameren management team. This call contains time-sensitive data that is accurate only as of the date of today’s live broadcast, and redistribution of this broadcast is prohibited. We have posted a presentation on the amereninvestors.com homepage that will be referenced by our speakers. As noted on page two of the presentation, comments made during this conference call may contain statements about future expectations, plans, projections, financial performance, and similar matters, which are commonly referred to as forward-looking statements.

Please refer to our SEC filings for more information about the various factors that could cause actual results to differ materially from those anticipated. Now, here is Marty, who will start on page four.

Marty Lyons: Thanks, Andrew. Good morning, everyone. Thank you for joining us today as we cover our third quarter 2024 earnings results. I will begin today on page four. We are focused on delivering strong long-term value for our customers, communities, shareholders, and the environment. By investing in rate-regulated infrastructure, enhancing regulatory frameworks, and advocating for responsible energy policies, we are positioning ourselves to take advantage of future opportunities to benefit all of our stakeholders. Through a disciplined approach to optimizing our operating performance, we have been able to keep our customer rates low in comparison to the national average as we transform the energy grid, enhance reliability, and provide cleaner energy to our communities. We remain excited for the future, and we see strong growth opportunities unfolding over the next decade.

Turning to page five. Yesterday, we announced third quarter 2024 adjusted earnings of $1.87 per share, compared to earnings of $1.87 per share in the third quarter of 2023. These comparable adjusted earnings results were in line with our expectations. The third quarter and year-to-date 2024 adjusted results exclude two charges related to separate proceedings that have been ongoing for over a decade. The first related to an agreement in principle to settle the Rush Island Energy Center New Source Review and Clean Air Act proceeding, and the second, for customer refunds required by the Federal Energy Regulatory Commission’s (FERC) October 2024 order, which established a new base return on equity within the Midcontinent Independent System Operator (MISO), that was applied retroactively to certain periods extending back to 2013. Key earnings drivers are highlighted on this page. Mike will discuss the factors driving the quarterly results in more detail in a moment.

Q&A Session

Our strong investment pipeline continues to drive earnings growth, and I am excited about the significant economic growth opportunities in the communities we serve. The Greater St. Louis region is experiencing some of the highest employment growth we have seen in the better part of three decades. In August, the region was ranked fourth among large metro areas in the country for employment growth, and we are seeing this strength in our region reflected in strong weather-normalized retail sales growth year-to-date across all customer classes in Missouri.

Turning now to page six. Thanks to our team’s execution of our strategy over the course of this year, we have a strong foundation as we head into the final months of 2024. We expect to deliver 2024 earnings within our adjusted guidance range of $4.55 per share to $4.69 per share. We expect our 2025 earnings per share to be in the range of $4.85 and $5.05, with the midpoint representing a 7.1% increase over the midpoint of our 2024 adjusted guidance range. While our historical practice has been to provide initial earnings guidance on our fourth quarter earnings call in February, we are issuing this 2025 guidance now to reinforce our confidence in our ability to deliver on our 6% to 8% earnings per share growth guidance expectations. We expect to provide our long-term earnings growth guidance and capital and financing plans on our year-end call in February.

On page seven, we highlight the latest advancements across Ameren as we execute our strategic objectives for the year. Our infrastructure investment plan is designed to improve the reliability, resiliency, safety, and efficiency of our system. As we remain focused on a reliable clean energy transition, year-to-date, we have invested $3 billion to replace aging infrastructure and also build the new infrastructure needed to meet our customers’ growing demand for a diverse mix of energy resources. Just last week, we announced that we have now closed on three solar energy centers this year, totaling 500 megawatts of new generation, which are undergoing final testing and are expected to be in service by the end of the year.

On the regulatory front, MISO’s long-range transmission planning process is progressing toward approval of the tranche 2.1 portfolio by the end of the year. In September, MISO released additional tranche 2.1 project details, which included approximately $3.6 billion of transmission investment needed in our Missouri and Illinois service territories to support reliability for the region.

At Ameren Missouri, we are working to bring more dispatchable generation onto the grid. In October, the Missouri Public Service Commission (Missouri PSC) approved a certificate of convenience and necessity (CCN) and post-construction cost deferral for the 800-megawatt simple cycle natural gas energy center, Castle Bluff. This $900 million investment in dispatchable generation will support energy reliability in our region and will also create hundreds of construction jobs, several new permanent jobs, and additional tax revenue for the region. In addition, in November, we reached an agreement in principle with the US Department of Justice to settle the Rush Island Energy Center New Source Review and Clean Air Act proceeding. I will cover the details of the agreement in a moment.

Finally, at Ameren Illinois, in October, the administrative law judge (ALJ) issued a proposed order regarding our revised 2024 through 2027 electric distribution multiyear rate plan. Importantly, the ALJ proposed order supports 99% of our requested rate base when excluding the impacts of other post-employment benefits (OPEB). Following our team’s extensive engagement with key stakeholders, all interveners support the Illinois Commerce Commission’s (ICC) approval of a revised grid plan with limited adjustments. We look forward to an ICC decision by the end of this year, which we expect to be consistent with the multiyear capital plans we issued in February.

Last, operational performance across our company remains strong, with a focus on delivering safer, more reliable, and affordable energy through grid hardening, enhanced automation, optimization, and standardization.

Turning to page eight for an update on Ameren Missouri’s new generation project. We continue to execute our Ameren Missouri Integrated Resource Plan (IRP), which focuses on maintaining and building a diverse, cleaner generation portfolio to ensure our reliable and low-cost mix of energy resources to serve our customers’ needs. As I mentioned, we have three solar projects in the later stages of commissioning and testing that are expected to be in service. We are also working toward the successful construction of another 400 megawatts of solar generation across three additional projects, which we expect will be ready to serve customers in late 2025 and 2026. Further, as I mentioned, in October, Missouri PSC approved the CCN for the dispatchable 800-megawatt simple cycle natural gas energy center Castle Bluff, following a constructive settlement with the commission staff and other interveners.

The order also includes post-construction cost deferral to reduce unrecovered costs by allowing us to defer and recover the depreciation expense from the Castle Bluff Energy Center and an adjusted weighted average cost of capital return on the investment from the time it is placed in service to when it is incorporated into base rates. As solar energy predictably rises and then falls every day, it is vital to have Castle Bluff Energy Center to bolster grid reliability for our customers. Prep work has begun on Castle Bluff, which will be located on the site of our retired Meramec Energy Center, allowing us to cost-effectively expedite the construction by leveraging an existing site with infrastructure in place. The energy center is expected to be in service for our customers by the end of 2027.

We look forward to continuing to work with key stakeholders to bring additional generation online as quickly as possible to meet the needs of all customers, including businesses looking to relocate or expand in Missouri.

Moving now to page nine for an update on the MISO long-range transmission projects. In September, MISO provided additional detail and individual project cost estimates underlying the almost $22 billion tranche 2.1 portfolio, which is expected to drive significant reliability and capacity benefits for the region. The portfolio includes three projects in our Missouri and Illinois service territories that collectively represent an investment opportunity of approximately $3.6 billion. We await MISO’s determination of which projects will be directly assigned and which will go through a competitive bidding process. MISO expects to approve the tranche 2.1 projects by the end of this year. Once approved, MISO plans to commence work in 2025 on the tranche 2.2 portfolio to address further transmission needs in the North and Midwest regions.

As we continue to see substantial load growth across the country, MISO and its transmission owners will continue to assess whether the current long-range transmission future scenarios will be sufficient to support our region’s energy needs in the years ahead.

Moving now to page ten for an update on our expanding customer growth opportunities. Our service territories have a broad-based, diverse economy, which continues to expand across a variety of manufacturing sectors, including aerospace, agriculture, and food processing, to name a few. So far this year, we have received expansion commitments or executed new contracts for approximately 350 megawatts of new load from data centers, manufacturing, and other industries, 90% of which is located in Missouri. These projects are expected to create more than 2,200 jobs. We expect these new and expanding customers to be fully ramped up by 2028. We are excited about these opportunities and see tremendous additional opportunities for growth over the next five to seven years, which will bring jobs and additional tax base to benefit our state and local communities.

Through ongoing collaboration with a variety of state and local stakeholders, we continue to attract new business and data center interest. Over the last few months, our economic development pipeline of potential additional demand has doubled in size, and we are making meaningful progress with several potential customers. These customers, representing several gigawatts of interest, have completed transmission engineering studies, and over the coming months, each will further evaluate the site locations and determine whether they will move forward with agreements. We are pleased to offer reliable service and competitive rates, as well as the people, resources, expertise, and partnerships needed to deliver for these customers. The ultimate net financial impact of any incremental load will be dependent upon a variety of factors, including customer ramp-up time, additional generation or grid investments needed, timing of rate reviews, and tariff structures.

To that end, we are in the process of carefully evaluating potential load growth opportunities and our associated generation portfolio needs and would expect to update our IRP by February of 2025. This is an exciting time in our industry, and we look forward to finding solutions for these significant potential new customers.

Turning then to page eleven. After almost fifty years of providing cost-effective energy to our customers, our Rush Island Energy Center was safely retired on October fifteenth. We are grateful to our coworkers who made this plant a reliable and low-cost energy source for our customers for many decades. Careful planning over several years enabled us to ensure that every employee impacted by the retirement of Rush Island had an opportunity with the company as we continue to thoughtfully transition our generation resources while retaining our talented workforce. The Missouri PSC has authorized recovery of approximately $470 million of cost related to the retirement of Rush Island through the issuance of securitized utility tariff. We are working through the next steps to execute that issuance.

In addition, in November, Ameren Missouri and the US Department of Justice reached a settlement agreement in principle requiring Ameren Missouri to fund two mitigation relief programs in addition to retiring the energy center. The cost of these programs, which will provide for the electrification of school buses over a three-year period and air purifiers for eligible Ameren Missouri residential customers over twelve months, totaled $64 million. The charges recorded this year related to this agreement are excluded from our adjusted earnings results. The agreement between the DOJ and Ameren Missouri is subject to approval by the US District Court for the Eastern District of Missouri, which is expected by the end of the year.

Moving to page twelve. Looking ahead over the coming decade, we have a robust pipeline of investment opportunities of more than $55 billion that will continue to deliver significant value to our stakeholders, create thousands of jobs, generate tax revenue for our local economies, and support economic growth in our region. Importantly, our ten-year investment pipeline does not reflect possible additional generation as we evaluate our needs to serve potential additional load growth. Any such changes to our ten-year investment pipeline will be reflected in our February earnings call update.

Moving to page thirteen, our five-year growth plan released last February included our expectation of a 6% to 8% compound annual earnings growth rate from 2024 through 2028. This earnings growth is driven by strong compound annual rate base growth of 8.2% and strategic allocation of infrastructure investment to each of our business segments based on their regulatory frameworks. Investment in Ameren presents an attractive opportunity for those seeking a high-quality utility growth story. Combined, our strong long-term 6% to 8% earnings growth and an attractive and growing dividend, which today yields 3.1%, result in a compelling total return story. We have a strong track record of execution, a strong balance sheet, and an experienced management team. I am confident in our ability to execute our investment plans and other elements of our strategy across all four of our business segments. Again, thank you all for joining us today, and I will now turn the call over to Michael.

Michael Moehn: Thanks, Marty, and good morning, everyone. I will begin on page fifteen of our presentation with an earnings reconciliation for two earnings adjustments that Marty mentioned earlier. Yesterday, we reported third quarter 2024 GAAP earnings of $1.70 per share, which included a charge for additional mitigation relief related to the Rush Island Energy Center and a charge for the October 2024 FERC order on MISO’s allowed base ROE. Both of these charges related to matters outstanding for the last decade. Excluding these two charges, Ameren reported third quarter adjusted earnings of $1.87 per share, compared to earnings of $1.87 per share for the year-ago quarter. The total after-tax charge of $0.17 per share in 2024 related to our Rush Island Energy Center reflects the estimated cost of the mitigation relief program agreed to with the US Department of Justice.

This includes the $0.04 per share charge recorded in the first quarter of 2024. Subject to approval by the district court, we expect a settlement agreement to resolve the proceeding related to the new source review provisions of the Clean Air Act.

Turning to the charge for the FERC order, recall, since November 2013, the allowed base ROE for FERC-regulated transmission rate base within the MISO has been subject to review. In FERC’s October 2024 order, it established a new base ROE of 9.98% for the periods of November 2013 through February 2015, and September 2016 forward, which decreased the allowed base ROE from 10.02% and will require refunds with interest for these periods, totaling an after-tax impact of $0.04 per share. The return on equity from MISO projects is now 10.48%, including the 50 basis point adder, and we do not expect a four basis point decrease in ROE to have a material impact on earnings expectations going forward.

Turning to page sixteen for detailed earnings results for the third quarter. Our adjusted earnings performance during the quarter was driven primarily by strategic investments and disciplined cost management, offset by changes in return equity for Ameren Illinois Electric Distribution and rate design at Ameren Illinois Natural Gas. Additional factors that contributed to the year-over-year earnings per share results are highlighted on this page. Year-to-date results are outlined on page twenty-six of today’s presentation.

Before moving on, I will touch on sales trends for Ameren Missouri and Ameren Illinois Electric Distribution. While miles were lower this quarter compared to the year-ago period, creating some earnings drag, our third quarter weather-normalized retail sales remained strong at an overall increase of approximately 1.5% compared to the year-ago period. Year-to-date, weather-normalized kilowatt-hour sales to Missouri residential, commercial, and industrial customers increased approximately 2%, 1%, and 3%, respectively, compared to last year. The year-to-date increase in industrial sales reflects production growth driven by new industrial plant additions and additional shift work in our service territory. Year-to-date, weather-normalized kilowatt-hour sales to Illinois customers were flat compared to last year. Recall that changes in electric sales, no matter the cost, do not affect the earnings since we have full revenue decoupling.

On page seventeen, we summarize select earnings considerations for the balance of the year. We expect our 2024 adjusted earnings to be in the range of $4.55 to $4.69 per share. Notably, we expect a positive year-over-year earnings impact in the fourth quarter driven primarily by strategic infrastructure investments, strong cost management programs, and lower charitable trust contributions compared to the year-ago period. I encourage you to take the settlement-arranged drivers noted on this slide into consideration as you develop your earnings expectations for the remainder of the year.

Turning to page eighteen, where we provide detail on our expectations for 2025. As we head into 2025, we feel confident that strong execution of our strategic plan this year will position us to deliver on our expected long-term earnings growth. With that in mind, we expect 2025 earnings per share to be in the range of $4.85 and $5.05. The midpoint of this range represents a little above 7% earnings per share growth compared to the midpoint of our 2024 adjusted earnings guidance range. Expected 2025 earnings detailed by segment as compared to our 2024 expectations are highlighted on this page. Beginning with Ameren Missouri, earnings are expected to benefit from new electric service rates effective by June 2025 and higher investment eligible for plant and service accounting.

Earnings are also expected to benefit from higher weather-normalized retail sales, primarily to Missouri’s commercial and industrial customers, which are expected to increase by 1% and 2%, respectively, driven primarily by the expansion and growth from our existing customers. We expect to update our long-term sales forecast in February. Further, we expect higher interest expense in Ameren Missouri and Ameren Parent, Transmission, and Ameren Illinois Electric Distribution, driven by higher infrastructure investment. Earnings in Ameren Illinois Natural Gas are expected to be lower due to cost recovery impacts between rate reviews. Ameren-wide, we expect increased weighted average common shares outstanding to unfavorably impact earnings per share.

Robust infrastructure investment and economic growth opportunities, coupled with identified business process optimization opportunities and continued strong strategic focus, give us confidence in our ability to grow in 2025 and the years ahead.

Turning to page nineteen for a brief update on Missouri regulatory matters. In August, the Missouri PSC set the procedural schedule for our ongoing Ameren Missouri electric rate review. Intervenor testimony is due in early December, and we expect a decision by the commission by May 2025, with new rates effective by June. Recall that approximately 90% of this request is driven by investments under Ameren Missouri’s Smart Energy Plan, including major upgrades to the electric system and investments in generation. If approved as requested, new electric service rates would remain well below the national and Midwest averages.

Turning to Ameren Illinois regulatory matters on page twenty. Under Illinois formula rate-making, which expired at the end of 2023, Ameren Illinois was required to file annual rate updates to systematically adjust cash flows over time for changes in the cost of service and to true up any prior period over or under recovery of such costs. For the final electric distribution reconciliation of 2023’s revenue requirement, in August, the ICC staff recommended approval of our proposed $158 million reconciliation adjustment. The full amount would be collected from customers in 2025, replacing the prior reconciliation adjustment of $110 million that is being collected during 2024. This will result in a net increase in cash flow of $48 million, or approximately a 1.5% increase in the total average residential customer bill. An ICC decision is expected by December, with new rates effective in 2025.

Turning to page twenty-one for an update on the multiyear rate plan covering 2024 through 2027. In October, the ALJ recommended a cumulative revenue increase of $315 million based on an average rate base of $4.9 billion by 2027. Excluding the OPEB issue, the ALJ’s proposed order supports 99% of the rate base that we requested in a revised multiyear rate plan. This would allow us to invest in the energy grid to maintain safety, reliability, and the day-to-day operations of our system, while also making progress towards an affordable, equitable, clean energy transition. Following constructive engagement with the interveners to narrow the remaining issues, their latest proposals reflect a multiyear grid plan that is largely consistent with our guidance laid out in February.

We expect an ICC decision by December, with new rates effective January 1, 2025. Under the multiyear rate plan, any annual revenues will be based on actual recoverable costs, year-end rate base, and a return on equity, provided they do not exceed 105% of the approved revenue requirements after certain exclusions.

Moving to page twenty-two to provide a financing update. We continue to feel very good about our financial position. Ameren’s parent long-term issuer credit ratings of Baa1 and BBB+ at Moody’s and S&P, respectively, compare favorably to the peer average, providing us with financial flexibility. To maintain our credit ratings and strong balance sheet while we fund our robust infrastructure plan, we expect to issue approximately $300 million of common equity in total in 2024. By the end of 2023, we sold approximately $230 million of the expected $300 million through the at-the-market (ATM) program, consisting of approximately 2.9 million shares, which we expect to settle by the end of this year. Together with the issuance under our 401(k) and DRIP plus programs, our ATM equity program is expected to fulfill our 2024 equity needs.

Additionally, as of September 30th, we have entered into forward sales agreements under our ATM program for approximately $155 million to support our 2025 equity needs, with an average initial forward sales price of approximately $82 per share. As always, we are thoughtful about strategically financing our robust capital plan.

Turning to page twenty-three. We remain confident in our long-term strategy, which we expect to continue to drive consistent superior value for all of our stakeholders. As highlighted today, we have made significant progress towards our goals. We have strong infrastructure investment opportunities to benefit our customers and attract new businesses, and we continue to see signs of an attractive regional economy, including solid retail sales growth, strong employment growth in the St. Louis region, moderating interest rates and inflation, and a robust economic development pipeline that will deliver strong earnings growth in 2025. Looking beyond, we expect consistent strong earnings per share growth driven by robust rate base growth, disciplined cost management, and a robust customer growth pipeline.

As we said before, we have the right strategy, team, and culture to capitalize on opportunities to create value for our customers and shareholders. We believe this growth will compare favorably with the growth of our peers, and shares continue to offer investors an attractive dividend. In total, we have an attractive total shareholder return story. That concludes our prepared remarks. We now invite your questions.

Operator: Ladies and gentlemen, it may be necessary to pick up your handset before pressing the star keys. Our first question comes from the line of Jeremy Tonet with JPMorgan. Please proceed.

Robin (for Jeremy Tonet): Hey, this is Robin on for Jeremy. How are you? Oh, great. Good morning. So maybe just to follow-up, you mentioned providing 2025 guidance at 3Q to underscore your confidence in your earnings trajectory. Could you elaborate on that strategy given several ongoing regulatory proceedings? And specifically, how should we think about the 2025 range relative to potential regulatory outcomes?

Marty Lyons: Yeah, sure. Well, you know, first of all, as you look back on some of the comments we made at the second quarter, we have a long history of growing at 7% or above. Our goal as we go into each year, of course, is to deliver at the midpoint or even higher within our range. Some of the things that we pointed to last quarter that are just giving us more long-term conviction have to do with inflation cooling, strong local economy, demand improving, some of the things we have talked about even on this call with respect to customer growth opportunities and great investments that we have got across all of our segments, whether it is distribution, transmission, and generation, and, of course, a strong balance sheet. So we have strong conviction in our ability to grow long-term.

As we looked at 2025, we certainly have confidence in our ability to deliver within the range that we pointed out today. As we look ahead over the next few months, typically, we have delivered this guidance in February. We are delivering it now because we do have strong confidence, and we believe that whatever unfolds in the months ahead, we will be able to adjust our plan and hit the mark in terms of the guidance that we delivered.

Robin: Great. Thanks. And then maybe just a follow-up on the mentioned economic development opportunities. You mentioned you have gotten some interest from an impressive several gigawatts of potential opportunities. Just any high-level thoughts on how you factor in potential double counting, like, say, if those customers are also submitting those inbounds to other utilities or service territories?

Marty Lyons: Yeah, sure. And look, I think you are absolutely right. We pointed out on our slide that we have tens of thousands of megawatts of potential new demand, so a significant amount. We certainly expect that, if we call it double counting, but a lot of these folks are looking at the same properties. You have got developers as well as hyperscalers. And so, yeah, there is certainly duplication in there. What we are doing is really working through with each of those counterparties in a methodical way. We mentioned that we have had progress with potential counterparties representing several gigawatts of demand. We are working through with them on evaluating the sites, the transmission access, the generation that might be needed to serve them.

Eventually, we expect that to be narrowed down. It is one of the reasons why we have been cautious about not really announcing any of this load until we get a construction agreement because these conversations have to progress to the point where we have a construction agreement. The other thing to keep in mind is we have mentioned in our prepared remarks that we expect that over the coming months, we will get even greater visibility. We will have a better sense of what the demand might be over the coming years and be able to incorporate that into our plans for incremental generation. So expect to put a greater stake in the ground, if you will, in February, which is when we believe we will be in a position to update some of those sales forecasts and update our IRP.

Robin: Great. Thank you. Appreciate the color.

Operator: The next question comes from the line of Paul Patterson with Glenrock Associates. Please proceed.

Paul Patterson: Hey. Good morning.

Marty Lyons: Hey, Paul. Good morning.

Paul Patterson: Just a few quick questions. On the refilled group plan, it looks like, I guess, they are going to have oral arguments, I guess, based on what the AG wanted. Any thoughts about that? I mean, at this late date that they are looking at doing that?

Marty Lyons: Yeah. Paul, I do not think I would read anything into that. Obviously, there are some differences, which I think because of the hard work of our teams along with the various stakeholders in these cases, we have really narrowed down the potential adjustments that folks have argued for. If you look on slide twenty-one in our materials, we laid out where the proposed rate base would be taking into consideration potential adjustments that have been advocated by various parties. You see where the staff is and where the ALJ came out. But I think it is normal that you would have oral arguments over the remaining differences. But again, I would point to the ALJ’s proposed order, which certainly gives us confidence in terms of where this may land with the commission when they ultimately decide in December.

Michael Moehn: Hey, Paul. This is Michael. I was just going to add that these oral arguments have been scheduled for a long time, so that is fairly typical, and they are actually being held on November twentieth. So as Marty said, I think what we have today is a constructive data point from the ALJ. I think all the interveners are recommending approval of the grid plan at this point. We will just see where the arguments take us.

Paul Patterson: Okay. Great. And then on slide nine, you mentioned the transmission projects and the reliability and also the growing customer calls. I was wondering if you could elaborate a little bit more on the customer call side, like what this might mean to customers. Because we do not see them. Go ahead. I am sorry.

Marty Lyons: Yeah. No. It is okay, Paul. I mean, we are really referring to, and we added a bullet which we have not had in the past, about the customer benefits in a range of 1.3 to 5.6 times in terms of the portfolio cost. So that relates to the overall approximately $22 billion of projects. When MISO goes through these and they propose these various projects, one of the things they do is obviously estimate the cost of these projects, which we have listed, at least for the projects in our service territory down below. But they also do an assessment of what the benefits to the customers are going to be in relation to those costs. Each of these projects has the positive math behind it, if you will, that suggests that customers’ costs over time will be lower as a result of these investments. So that is what we are really trying to convey.

Paul Patterson: Okay. But there is not going to be some dramatic cost, I guess, when these new lines show up and cheaper stuff comes in? Or is it sort of all mixed up together and it is going to take some time for it all to show up kind of thing?

Marty Lyons: Yeah. I think it will show up over time. I do not have any exact rate impact to point to.

Paul Patterson: I got it. Thanks. Okay. Then finally, on the new customers, you mentioned with one tranche of the new customers that there was 90% Missouri versus Illinois. I guess I was wondering when people are looking to, with all these robust discussions that you are having, is there more interest in one state versus another, or is there any flavor as to if there is, what might be driving that?

Marty Lyons: Yeah. Look. We have data center interest really in each of the states. So if you look over to the right, on that slide ten, we talked about tens of thousands of megawatts of potential new demand. You see various elements of that. I would say today in our pipeline, about 75% is data centers, 15% is manufacturing, and 10% is other, which is probably how that breaks down. Within that data center interest that we have got, about 65% of it is Missouri, and 35% of it is Illinois today in terms of what is in our pipeline. So there is clearly data center interest in each of the states. Each of the states is attractive for various reasons and in some cases, different reasons. But what we have announced today with respect to these construction agreements, which is more over on the left where we have 250 megawatts of data center demand, 100 megawatts of additional load from a variety of sources, it just so happens that 90% of that is actually in Missouri.

About 10% of that is Illinois today in terms of those agreements that we have in place. Now, as we look ahead, certainly, the impact to us from an earnings perspective is going to be differentiated in the two states. In Illinois, obviously, if we have transmission or distribution investment that supports that load growth, we get the earnings impact of that. In Missouri, which is vertically integrated, we also have the impact of the opportunity to earn on any incremental generation.

Paul Patterson: Okay. But there is no specific reason for that? It just that is the way it fell out, I guess. Okay. I appreciate it. Thanks so much. Have a great one.

Operator: You bet. The next question comes from the line of Carly Davenport with Goldman Sachs. Please proceed.

Carly Davenport: Hey. Good morning. Thanks so much for taking my questions. Maybe just to follow-up on an earlier question on the earnings guidance range. As you think about 2025 growth at just over 7% relative to the midpoint of 2024, can you just give us your thoughts on looking forward where you see yourself in the range, just taking into consideration some of the incremental opportunities that you have highlighted and if there is any potential upside to that range going forward?

Marty Lyons: Yeah. Carly, look. In terms of our range, we have said 6% to 8% is our EPS CAGR that we are targeting for the period 2024 to 2028. As I mentioned earlier, when we look back, we have got a strong track record of delivering above the midpoint, above 7%, and our goals as we look ahead are to deliver at or above. As you said, we have some positive data points we are seeing today. Again, one of the things is the slow growth, which we just talked about. Some potential load growth. We are working hard to bring that to fruition for the benefit of our customers, our communities, and we are going to work hard to do that. At this point, I would say that is where we are at now. We will come out in February. We will provide our perspectives on load growth going forward, update our investment plans, and we will note any potential implications on guidance.

But we feel good about the 6% to 8% and, again, our target of hitting at or above that midpoint. Michael, anything to add?

Michael Moehn: Hey, Carly. It is Michael. I think it is well said. The only other thing I might add is just again, the overall backlog of investment opportunities. Marty spoke about this earlier. We have got the $55 billion that we continue to point to. I think that pipeline remains robust. We talked about this opportunity just with the data centers. That could potentially drive some additional capital. So, I mean, your question specifically was what could take you to the upside of that? I think it is those additional investment opportunities over time. I think there is also opportunity, as Marty said, not only just from the data center, but the underlying economic data within, certainly in the Missouri territory, is very strong today.

Just looking at the overall employment, the GDP rate, we are seeing customer growth, which we just alluded to. We are seeing customer account growth, population growth, and all of those things, I think, are a great backdrop. Then, yeah, we continue to think about just how do we optimize the financing in this going forward. So that is where I would probably leave it at this point.

Carly Davenport: Got it. Great. That is super helpful. And then maybe just another quick one. You have previously talked about some O&M reductions coming in the second half of the year. Looks like 3Q was still up year over year, but then you called out some efficiency in the earnings driver slides for 4Q. Are you able to give some color on what programs you are sort of pursuing there? And if what you have called out on the slides is all-inclusive of what you are looking at on O&M.

Michael Moehn: Yeah. You bet. And you are right. We have been pointing to this towards the beginning of the year. I said it was going to be in the back half. And I think you are certainly seeing that show up in Missouri. Specifically, you know, $0.05. You look at what we are pointing to in the fourth quarter, year over year expecting $0.03 and $0.01 in Missouri and Illinois Natural Gas, respectively. And, again, just consistent with some of the things I have talked about in the past. This is not something that is new to us. We have been after these programs for a long time. Beginning in the year, we talked specifically about some things that we were doing around just being thoughtful with respect to headcount, discretionary spend coming out of some of the Illinois decisions.

I think we continued to lean into them. We continue to find more opportunities. Looking at spans and layers, looking at simplification. We just have an opportunity for us to be more consistent across our platform, which drives efficiencies, back-end reduction, overhead cost, etc. We do a lot of benchmarking in this. You see some of that public benchmarking, and we benchmark well, but in areas we have opportunities. So wherever we are benchmarking, constantly looking at how do we move up a quartile. I think the team is absolutely committed to this, and we have not exhausted all the opportunities at this point.

Carly Davenport: Got it. Great. Thanks so much.

Operator: The next question comes from the line of Julien Dumoulin Smith with Jefferies. Please proceed.

Brian (for Julien Dumoulin Smith): Yeah. Hi. Good morning. It is actually Brian. I am still on for Julien.

Marty Lyons: Brian?

Brian: Alright. Hey. Just to follow-up on Ameren Transmission. It looks like just the assumption in this 2025 versus 2024 looks like growth in rate base is pushing 9%, and it seems that the growth there is accelerating as we move through the five-year plan, approaching, I guess, the double-digit overall rate base growth CAGR. Is the near term in 2025 and 2026 really just the prior MISO tranche projects that have been approved and that you are developing? And then is there any possibility of these tranche two projects being pulled forward versus the early to mid-2030s target dates?

Marty Lyons: As it relates to the MISO projects, the tranche one projects, I tell you, the construction there is really going to take place between 2026 and 2030 is our projection today. Some of these MISO tranche 2.1 projects, those will probably go in service in the 2032 to 2034 time frame. We think most of the expenditures for those are outside of the current five-year period. Although, we will be certainly looking to accelerate those if possible. There is no reason that tranche two project work and tranche one project work cannot overlap. So we will be looking to bring this to fruition for the benefit of our customers and communities as soon as we can once they are approved and once they are assigned to us. Otherwise, we always have ongoing projects in the transmission space that are outside of those that are part of the tranche one or tranche two that are approved through annual MISO processes.

Those continue to be foundational in our overall spending and growth in the transmission space.

Michael Moehn: The only thing I might add to that is, you think about those $55 billion pipeline. We have talked about this, about $5 billion is in there with respect to the LRTP projects. Brian, so you think about tranche one, we had the $1.8 billion assigned, the $700 million on the competitive projects. There will be some variation of those ultimately where they ended up settling out, but then you have tranche 2.1, which will again we will see what ultimately gets assigned or competitive, but there is $3.6 billion of eligible projects. Then you are going to obviously roll into this 2.2 tranche. I am just giving you the math if you kind of want to think about that $5 billion, and it is, yeah, you can see the pipeline associated with getting there pretty easily.

Brian: Okay. Great. And just as we look towards the 2025 Missouri legislative session, how active will Ameren be or involved in any proposed bills that I think might need to be proposed as early as this December, whether it is PISA for fossil fuel or gas-fired generation, any road for or, I guess, expanding expediting the generation review, which would tie into maybe your February 2025 IRP update.

Marty Lyons: Yeah. Look, those are all potential considerations. They are very logical. Last session, we were advocating for things along those lines, which was the expansion of PISA to be able to cover generation assets, extending the sunset date on the PISA, the generation assets that are included in our IRP. We did, and we will continue to advocate for the right of first refusal on transmission because, again, we think it is critical to get these transmission projects done sooner rather than later. Just talked about the great benefit-to-cost ratios they have got. Of course, I think their key as well is building incremental generation to making sure that we have got reliable power, low-cost power here in our region. Those are going to be key things that we focus on, and then my sense is that there will be a variety of other things that might be considered as we focus on, as a state, on economic development, job creation, and making sure that we have got a strong, reliable, affordable, balanced portfolio of energy resources to be able to meet the needs of prospective customers.

Certainly, we will be considering all those things as we move towards that next legislative session.

Brian: Great. Thank you very much.

Operator: Thank you. The next question comes from the line of David Paz with Wolfe Research. Please proceed.

David Paz: Hi there. Good morning.

Marty Lyons: Morning.

David Paz: You may have just hit on this, but let me ask it a little differently. Could you maybe elaborate on how these potential agreements with large load customers may transpire? Could they entail potential new generation that the customer helps cover directly, and then just how are regulators and policymakers facilitating those types of discussions if they are?

Marty Lyons: Yeah. No. Good question. As we look at some of the potential load growth specifically in Missouri where we are vertically integrated, we own generation. We have got to be thoughtful about what incremental resources might be needed to serve some of the incremental load. We mentioned on our last call with respect to the 350 megawatts of additional load that has been announced with the construction agreements. We have the available resources to be able to serve them. But as these load forecasts grow, we are going to need to consider additional resources. That is under consideration now. That is going to be what we will be trying to work through as we think about updating our integrated resource plan early next year.

I think that plan when we file it will deliver more clarity in terms of our thoughts there. With respect to the incremental cost, it is something we need to think through as we think about the incremental investments that we made to serve all of our customers, including these additional customers, just need to think through the appropriate portion of the costs so that all parties are treated fairly. That is ongoing consideration, ongoing dialogue with some of the entities that are looking to expand here. I think those conversations will continue over the coming months.

Michael Moehn: Hey, David. It is Michael. I am just pointing out the obvious. Historically, we were a bit long. Right? We began this transition, and we have some of these plants closing. Obviously, we have less length today. Adding Castle Bluff that Marty spoke about earlier, that is definitely in the right direction. That is exactly what the team is evaluating as part of this IRP evaluation and whether we are going to need to file again, trying to take some various scenarios under these load growth opportunities and match that really up against our generation to see if we need to add additional generation on top of that.

Marty Lyons: Great. I would just say this. When you look at our IRP, you can see the elements that we might bring forward. We had renewable resources in there. We will be evaluating. Can we pull those forward? Can we pull forward battery storage technology? As Michael said, we have got some simple cycle, combined cycle that we need to add some additional gas-fired generation. These are the elements we are looking at as we think about updating that IRP.

David Paz: Okay. That makes sense. Then just on 2025 quickly, do you anticipate your consistent EPS growth guidance from February to be based off of 2025?

Marty Lyons: Got it. I mean, that has sort of been our historical practice, David. We will update based on whatever that midpoint is for that 2025 we have got. In this case, it is that $4.95. So that would be the expectation.

David Paz: Okay. Great. Thank you.

Operator: Thank you. The next question comes from the line of Nick Campanella with Barclays. Please proceed.

Nick Campanella: Hey. Good morning. Thanks for taking my question. I got up a little late. I will try not to repeat. But clearly, you gave 2025 guidance earlier here, which is a sign of confidence going into next year. Capital is going up. How much capital is going up in the near term versus kind of the long term of your financial plan? Does that impact your equity needs? Do you still just kind of programmatically lean on the ATM, or would you contemplate other mechanisms around that? Thank you.

Michael Moehn: Hey, Nick. Michael here. From a capital perspective, I mean, I just continue to think in terms of the $21.9 billion that is out there. We have talked about a number of factors that we are updating for and just spent some time talking about this IRP. That is the process that we are going through, going through our typical capital planning process as we speak and putting the final touches on that. That is what we will come out with here in February. From a financing perspective, the plan that we put out there last February still stands today, focused on that $300 million. Got that largely done for 2024. Starting to lean into the 2025 piece. Got about $155 million of that done. In terms of ongoing financing assumptions, we have talked about this.

We like our ratings where they are, the Baa1, BBB+. Downgrade threshold of 17 at S&P is, we have got quite a bit of margin there. The threshold metric for us is on S&P. It is 17. That is the one we will continue to watch. From a financing assumption standpoint, I would assume what we have sort of put out there at this point. So maintaining those and that consolidated equity ratio, around 40%, which is where it is today.

Nick Campanella: Thanks a lot. I appreciate that. Then maybe some considerations with the election that just happened. I believe that there are some EPA-driven investments in your plan today. Do you think any of that could change? How would you quantify your positioning around the new candidate? Can you also clarify if you have transferability cash flow in the plan? Thank you.

Marty Lyons: Yeah. There is a lot there. Obviously, the election just happened. When we think about the election, overall, one of the things to keep in mind is our strategy and our priorities of the company certainly do not change. Our focus is on making great infrastructure investments for the benefit of our customers and communities, advocating for energy policies to maximize that value, and, of course, as I mentioned before, seeking great economic development opportunities. We are going to be working with policymakers to make sure we maximize the benefit of those for our communities. While you did not ask about this, I think the most significant area of focus coming out of the federal elections probably could be around tax policy.

As you know, as a fully regulated company, all the increases and decreases in taxes flow directly through to our customers’ rates. Things like the corporate income tax rate, value of tax credits, those are things that have pretty meaningful effects on our customer rates. My sense is with Republican leadership, it is going to certainly be less likely that we see an increase in corporate taxes. I think that is positive for our customers from a bill perspective. I do expect there is going to be a conversation around some of these clean energy tax provisions in the IRA. I think we in our industry will all engage with policymakers on the considerations. My expectation is that Republicans will probably take a surgical approach to adjustments to the IRA given some of the direct customer benefits.

For us, specifically, I would say the most meaningful benefits of the tax credits are around solar, battery storage, nuclear, and wind. Those are some of the things we will be thinking about. You mentioned transferability. Transferability of tax credits is important to us. We will make sure that policymakers are certainly aware of the importance of those too. Frankly, based on our IRP that we have on record, we filed, all of those things have a value of about a billion and a half positive value. Those tax credits do to our customers in Missouri alone. It is a significant benefit, and that is over about a ten-year period, the next ten-year period in our IRP. We will just make sure that as we engage with policymakers, whatever they decide, that at least they have those facts and they are aware of those benefits that we expect to have for our customers.

At the end of the day, you should know that the investments in our system that we are going to make are whatever we think are appropriate from a reliability and affordability perspective and as we continue to adopt some of the new technologies that are out there. I think those are the biggest points with the election. You had mentioned EPA rules. I think that with respect to the EPA rules and the CapEx that we have in our plans today, I do not see those as changing. The EPA’s greenhouse gas rules, on the other hand, that are working their way through the courts, I do expect that, ultimately, those rules would be stayed given some of the provisions that are in them with respect to carbon capture and storage and co-firing with natural gas. We will see what happens with respect to those proposed rules as we go through sort of a change in administration and change in legislature.

But I think those rules, personally, in my mind, are flawed as they stand today. Those would be my comments. Any other questions from you?

Nick Campanella: I would say that you answered the four-part question very well. I appreciate it. Thanks.

Marty Lyons: Thank you.

Operator: Ladies and gentlemen, this concludes our question and answer session. I will turn the call back to Marty Lyons for closing remarks.

Marty Lyons: Terrific. Hey, thank you all for joining us today. As you can tell, we remain absolutely focused on closing out the year very strong, and we look forward to seeing many of you at the conference next week. Again, thank you very much, and everybody have a great day.

Operator: This concludes today’s conference. You may disconnect your lines at this time. Enjoy the rest of your day.