Ameren Corporation

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 cell phone 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 and Corporate Modeling for Ameren Corporation. Mr. Kirk, please proceed.

Thank you, and good morning. On the call with me today are Marty Lyons, our Chairman, President, and Chief Executive Officer, and Michael Main, our Senior Executive Vice President and Chief Financial Officer, as well as 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 amarininvestors.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 the forward-looking statements section in the news release we issued yesterday, as well as our SEC filings for more information about the various factors that could cause actual results to differ materially from those anticipated. Now here's Marty, who will start on page four.

Thanks, Andrew. Good morning, everyone. Thank you for joining us today as we cover our third quarter 2024 earnings results. I'll begin today on page four. We're 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. And 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 to 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 had 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 commissions first October, 2024 order, which established a new base return on equity within the mid continent independent system operator or 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. Our strong investment pipeline continues to drive earnings growth, and I'm 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've 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're 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 and $4.69 per share. and 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're issuing this 2025 guidance now to reinforce our confidence in our ability to deliver on our six 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've invested $3 billion to replace aging infrastructure and also build the new infrastructure needed to meet our customers' growing demands with 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 AMRA Missouri, we're working to bring more dispatchable generation onto the grid. In October, the Missouri Public Service Commission, or Missouri PSC, approved a certificate of convenience and necessity, or 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 U.S. Department of Justice to settle the Rush Island Energy Center New Source Review and Clean Air Act proceeding. I'll cover the details of the agreement in a moment. And finally, at Ameren, Illinois, in October, the Administrative Law Judge, or ALJ, issued a proposed order regarding our revised 2024 through 2027 electric distribution multi-year rate plan. Importantly, the ALJ proposed order supports 99% of our requested rate base when excluding the impacts of other post-employment benefits or OPEG. Following our team's extensive engagement with key stakeholders, all intervenors support the Illinois Commerce Commission's or ICC's 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 multi-year 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 8 for an update on Ameren Missouri's new generation projects. We continue to execute our Ameren Missouri Integrated Resource Plan, or IRP, Which focuses on maintaining and building a diverse cleaner generation portfolio portfolio to ensure a 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 and that are expected to be in service by the end of this year. We're 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, the 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 Merrimack 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 or 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 10 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've 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 2200 jobs. We expect these new and expanding customers to be fully ramped up by 2028. We're 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 construction agreements. We're 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, we look forward to finding solutions for the significant potential new customers turning then to page 11. After almost 50 years of providing cost effective energy to our customers, a rush island energy Center was safely retired on October 15. We are grateful to our co workers 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 costs related to retirement of Rush Island through the issuance of securitized utility tariff bonds and we are working through the next steps to execute that issuance. In addition, in November, Ameren Missouri and the U.S. 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 12 months, Tad Piper- total $64 million and the charges recorded this year related to this agreement are excluded from our adjusted earnings results. Tad Piper- The agreement between the do J and amber 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. Tad Piper- Moving to page 12. 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 10-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 10-year investment pipeline will be reflected in our February earnings call update. Moving to page 13. 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-based 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'm 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'll now turn the call over to Michael. Thanks, Marty, and good morning, everyone. I'll begin on page 15 of our presentation with an earnings reconciliation for the two earnings adjustments that Marty mentioned earlier. Yesterday, we reported third quarter 2024 gap 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, AMER 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 17 cents per share in 2024 related to our Rush Island Energy Center reflects the estimated cost of the mitigation relief programs agreed to with the U.S. Department of Justice. This includes the 4 cents per share charge recorded in the first quarter of 2024. Subject to approval by the district court, we expect this 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, pulling an after-tax impact of 4 cents 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. Turn to page 16 for detailed earnings results for the third quarter. Our adjusted earning performance during the quarter was driven primarily by strategic infrastructure investment and disciplined cost management, offset by changes in return on 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 26 of today's presentation. Before moving on, I'll touch on sales trends for Air and Missouri and Air and Illinois electric distribution. While model of weather this quarter compared to the year ago period created 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. Year-to-date increase in industrial sales reflect 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, Illinois electric sales, no matter the cost, do not affect earnings since we have full revenue to cover. On page 17, 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 supplementary earnings drivers noted on the slide into consideration as you develop your earnings expectations for the remainder of the year. Turning to page 18, where we provide detail on our expectations for 2025 earnings per share. 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. This 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 detail by segment as compared to our 2024 expectations are highlighted on this page. Beginning with Aaron 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. Earnings in Ameren transmission and Ameren Illinois electric distribution are expected to rise driven by higher infrastructure investment. Earnings in Ameren Illinois natural gas are expected to be lower due to cost recovery impacts between rate reviews. In Ameren wide, we expect increased weighted average common shares outstanding to unfavorably impact earnings per share. Robust infrastructure investment in 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. Bring to page 19 for a brief update on the Missouri regulatory matters. In August, the Missouri PSC set the procedural schedule for our ongoing Air Missouri electric rate review. Interveneer testimony is due in early December, and we expect a decision by the Commission by May 2025 with newer rates affected by June. Recall that approximately 90% of this request is driven by investment center and Missouri 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 20. 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 requirements, 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 1.5% increase in total average residential customer bill. An ICC decision is expected by December with new rates effective in 2025. Turning to page 21 for an update on the multi-year 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 were requested in a revised multi-year rate plan. This would allow us to invest in the energy grid to maintain safety, reliability in 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 will reflect a multi-year 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 1st, 2025. Under the multi-year rate plan framework, 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 22, we provide a financing update. We continue to feel very good about our financial position. Our annual parent long-term issuer credit ratings of BAA1 and BBB plus 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 for approximately $230 million of the expected 300 million through the at the market or 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 and DRIP Plus programs, our ATM equity program is expected to fulfill our 2024 equity needs. Additionally, as of September 30th, we've 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 continue to be thoughtful about strategically financing our robust capital plan. Going to page 23, 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 resolving several regulatory and legal proceedings. 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 allow us to deliver strong earnings growth in 2025. Looking beyond, we expect consistent strong earnings per share growth driven by robust rate-based growth, disciplined cost management, and a robust customer growth pipeline. As we've 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.

Ladies and gentlemen, if you would like to ask a question. please press star one on your telephone keypad and the confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. And our first question comes from the line of Jeremy Tonnet with JP Morgan.

Please proceed. 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 amidst several ongoing regulatory proceedings? And specifically, how should we think about the 2025 range relative to potential regulatory outcomes?

Yeah, sure. Well, you know, first of all, as you look back on some of the comments we made at the second quarter, you know, we have a long history of, you know, growing at 7% or above. You know, our goal as we go into each year, of course, is to deliver at the midpoint or even higher within our range. And you know, some of the things that we pointed to last quarter that, you know, just giving us more long-term conviction have to do with, you know, inflation cooling, strong local economy, demand improving, some of the things we've talked about even on this call with respect to customer growth opportunities and great investments that we've got across all of our operations, whether it's distribution, transmission, and generation, and of course, a strong balance sheet. So, You know, we have strong conviction in our ability to grow long-term. And as we looked at 2025, we certainly have confidence in our ability to deliver within the range that, you know, we pointed out to today. And, you know, as we look ahead, you know, over the next few months, typically we have delivered this guidance in February. You know, we're delivering it now because we do have strong confidence and we believe that, you know, whatever unfolds in the months ahead, that we'll be able to adjust our plan and hit the mark in terms of the guidance that we delivered.

Great, thanks. And then maybe just to follow up on the mentioned economic development opportunities, you mentioned you've 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?

Yeah, sure. And look, I think you're absolutely right. You know, 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, you know, a lot of these folks are looking at the same properties and you've got developers as well as hyperscalers. And so, yeah, there's certainly duplication in there. So what we're doing is really working through with each of those counterparties in a methodical way. We mentioned that we've had progress with potential counterparties representing several gigawatts of demand. And we're working through with them on evaluating the sites, the transmission access, the generation that might be needed to serve them. And eventually we expect that to be narrowed down. You know, it's one of the reasons why, you know, we, we have been cautious about not, you know, really announcing any of this load till we get a construction agreement, because these conversations have to progress to the point where we have a construction agreement. You know, the other thing to keep in mind is we've mentioned on our, in our prepared remarks. that we expect that over the coming months we'll get even greater visibility. We'll 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'll be in a position to

know update some of those sales forecasts and update our irp great thank you appreciate the color and the next question comes from the line of paul patterson with glenrock associates please proceed hey good morning hey paul good morning um so just a few quick questions on the refill group plan um

It looks like, I guess they're going to have oral arguments, I guess, based on what the AG wanted. Um, any thoughts about, um, about that? I mean, um, at this late date that they're, they're looking at doing that.

Yeah, Paul, I don't think I, you know, read anything into that. Obviously there are, you know, some, you know, differences, which I think because of the hard work of our, our teams, along with various stakeholders in this, uh, cases, We've really narrowed down the potential adjustments that folks have argued for. If you look on slide 21 in our materials, we laid out where the proposed rate base would be taken into consideration, potential adjustments that have been advocated by various parties. You see where the staff is and where the ALJ came out. I think it's normal that you'd have oral arguments over the remaining differences. But again, I'd 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. Yeah, hey, Paul, this is Michael. I was just going to add, hey, Paul, I think these oral arguments have been scheduled for a long time. You know, it's fairly typical, and they're actually being held November 20th. So as Marty said, I think, you know, what we have today is, you know, a constructive data point from the ALJ. I think all the interveners are, you know, recommending approval of the grid plan at this point, and we'll just see where the arguments take us.

Okay, great. And then on slide 9, you mentioned... the transmission projects and the, you know, the reliability and also the lowering customer costs. I was wondering if you just could elaborate a little bit more on the customer cost side, like what this might mean to customers, because we don't see them. Go ahead. I'm sorry.

Yeah, no, it's okay, Paul. I mean, we're really referring to, and we added a bullet, which we haven't had in the past, about the customer benefits in a range of 1.3 to 5.6 times in terms of the portfolio cost. And that relates to the overall approximately $22 billion of projects. So 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've 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. And 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's what we're really trying to point out.

Okay, but there's not going to be some dramatic costs, I guess, when these new lines show up and cheaper stuff comes in? Or is it, I mean, I'm just sort of, I'm wondering if there's any quantification on a rate impact or is it sort of just, it's sort of all mixed up together and it's going to take some time for it all to show up kind of thing?

Yeah, I mean, I think it'll show up over time. I don't have any, you know, exact rate impact to point to. 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. And I guess I was wondering, when people are looking to, you know, with all these robust discussions that you're having, is there one service territory that's more attractive or that's more interesting versus another? Or is there any flavor as to, if there is, what might be driving that?

Yeah, look, we have data center interest really in each of the states. So, you know, if you look, you know, over to the right, you know, on that slide 10, we talked about tens of thousands of megawatts of potential new demand. And you see various elements of that. And I would say, you know, today in our pipeline, about 75% data centers, 15% manufacturing, and 10% other is probably how that breaks down. Within that data center interest that we've got, About 65% of it is Missouri and 35% of it is Illinois today in terms of what's in our pipeline. So there's clearly data center interest in each of the states. And, you know, each of the states is attractive for various reasons and in some cases different reasons. But, you know, what we have announced to date with respect to these construction agreements, which is moreover on the left where we have 250 megawatts of data center demand, 100 megawatts of additional load from a variety of sources, You know, it just so happens that 90% of that is actually in Missouri and about 10% of that is Illinois today in terms of those agreements that, you know, that we have in place. Now, you know, as we look ahead, you know, 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. You know, in Missouri, which is, you know, vertically integrated, you know, we also have the impact of the opportunity to earn on any incremental generation.

Okay. But there's no, that's not the way it fell out, I guess. Okay. I appreciate it. Thanks so much and have a great one.

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

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 25, you know, growth at just over 7% relative to the midpoint of 24, 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've highlighted and if there's any potential upside to that range going forward?

Yeah, Carly, look, I mean, You know, in terms of our range, we've said, you know, 6% to 8% is our EPS CAGR that we're targeting for the period 2024 to 2028. You know, as I mentioned earlier, you know, when we look back, we've got a strong track record of delivering above the midpoint, above 7%. And our goal as we look ahead is to deliver at or above 7%. You know, as you said, I mean, we have some positive data points we're seeing today. You know, again, one of the things is this load growth, which we just talked about, some potential load growth. We're working hard to bring that to fruition for the benefit of our customers, our communities. And, you know, we're going to work hard to do that. But at this point, I'd say that's where we're at now. We'll come out in February. We'll provide our perspectives on load growth going forward, update our investment plans, and we'll note any potential implications on our guidance. But feel good about the 6 to 8 and, again, our target of hitting at or above that midpoint. Michael, anything to add? Hey, Carly. It's Michael. I think it's well said. The only thing I might add is just, again, the overall backlog of investment opportunities. Marty spoke about this earlier. We got to 55 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's those additional investment opportunities over time. I think there's also opportunity, as Marty said, you know, not only just from the data centers, but the underlying economic data within, you know, certainly in the Missouri Territory is very strong today. Just looking at the overall unemployment, the GDP rate, we're seeing customer growth, which we just alluded to. We're seeing customer account growth, population growth, and all of those things I think are a great backdrop. And then we continue to think about just how do we optimize the financing in this going forward. So that's where I'd probably leave it at this point.

Got it. Great. That's super helpful. And then maybe just another quick one. You've previously talked about some O&M reductions coming in the second half of the year. It looks like 3Q was still up year over year, but then you called out some efficiencies in the earning driver slides for 4Q. Are you able to give some color on what types of programs you're sort of pursuing there and if what you've called out on the slides is all inclusive of what you're looking at on O&M?

Yeah, yeah, you bet. And you're right. We have been pointing to this, you know, towards the beginning of the year, said it was me in the back half. And I think, you know, you're certainly seeing that show up. You know, in Missouri, you look specifically, you know, five cents. You look at what we're pointing to in the fourth quarter. You know, year over year, expecting three cents and one cent in Missouri and one on natural gas, respectively. And again, you know, just consistent with some of the things I've talked about in the past. I mean, this is not something that's new to us. We've 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 spending coming out of some of the Illinois decision. I think we've continued to lean into that and continue to find more opportunities. looking at spans and layers, looking at simplification. I mean, we just, we have an opportunity for us to just be more consistent across our platform, which drives efficiencies back in reduction, overhead costs, et cetera. And so 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. And so wherever we're benchmarking, we're constantly looking, how do we move up a quartile? And I think the team is absolutely committed to this. And, you know, we have not exhausted all the opportunities at this point.

Got it. Great. Thanks so much.

Ladies and gentlemen, as a reminder, if you would like to ask a question, please press star one on your telephone keypad. And the next question comes from the line of Julian Dumoulin-Smith with Jefferies. Please proceed.

Yeah. Hi. Good morning. It's actually Brian Roussel on for Julian. Brian. All right. Hey, just to follow up on Emarin Transmission, you know, it looks like just the assumption in the 25 versus 24, it looks like growth in rate base is, you know, pushing 9%. And it seems that, you know, the growth there is accelerating, right, as we move through the five-year plan approaching, I guess, the double-digit overall. rate-based growth CAGR. Is the near term in 25 and 26 really just the prior MISO tranche projects that have been approved and that you're developing? And then is there any possibility of these tranche 2 projects being pulled forward versus the early to mid 2030s target dates?

You know, as it relates to the, you know, MISO projects, you know, the Trunch 1 projects, I tell you the construction there is really going to take place between 2026 and 2020-30 is, you know, our projection today. And then, you know, some of these MISO Trunch 2.1 projects, you know, those, you know, will probably go in service in the 2032 to 2034 timeframe. You know, we think most of the expenditures for those are outside of the current five year period. Although, you know, we'll be certainly looking to accelerate those, uh, if possible, there's no reason that, uh, tranche two project work and tranche, tranche one project work can't overlap. Uh, so we'll be looking to bring those to fruition for the benefit of our customers and communities as, as soon as we can, once they're, uh, you know, once they're approved and once they're assigned to us. And then otherwise, you know, 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. And so, you know, those continue to be foundational in our overall spending and growth in the transmission space. The only thing I might add to it, I mean, think about the $55 billion pipeline. You know, we've talked about this. About $5 billion is in there with respect to the LRTP projects, Brian. So you think about tranche one, you know, we had the 1.8 assigned, the $700 million on the competitive projects. There was some variation of those ultimately where they ended up settling out. But then you have this tranche 2.1, which will, again, we'll see what ultimately gets assigned or competitive. But there's $3.6 billion of eligible projects And then they're going to obviously roll into this 2.2 tranche. And so, I mean, I'm just giving you the math. If you kind of want to think about that $5 billion, you can see the pipeline associated with getting there pretty easily.

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 are might need to be proposed as early as this December, whether it's PISA for fossil fuel or gas fire generation, any ROFR, or I guess expanding, expediting the generation review, which would, I think, tie into maybe your February 2025 IRP update.

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

know certainly be considering all those things as we move towards that next legislative session great thank you very much thank you the next question comes from the line of david poss with wolf research please proceed good morning um morning you may have maybe just hit on this but let me ask you a little differently um do you maybe elaborate on how some of these potential agreements with large load customers may transpire. And could they entail like potential new generation that the customer helps cover directly? And then just how are regulators and policymakers facilitating those type of discussions if they are?

Yeah, good question. Yeah, I think that, you know, as we look at some of the you know, potential load growth specifically in Missouri where we're vertically integrated and we own generation, you know, we've got to be thoughtful about what incremental resources might be needed to serve some of the incremental load. You know, we mentioned on our last call with respect to, you know, this 350 megawatts of additional load that's been announced with the construction agreements, you know, we have the available resources to be able to serve them. But as these load forecasts grow, we're going to need to consider additional resources. And so that's under consideration now. That's going to be what we'll be trying to work through as we think about updating our integrated resource plan early next year. And I think that plan, when we file it, will deliver more clarity in terms of our thoughts there. And then with respect to the incremental cost, yeah, it's something we need to think through as we think about the incremental investments that will be made to serve all of our customers, including these additional customers, just need to think through the appropriate apportionment of costs so that all parties are treated fairly. So, you know, that's an ongoing consideration, ongoing dialogue with some of the, you know, some of the entities that are looking to expand here. And I think those, you know, those conversations, you know, will continue over the coming months. Yeah, and David, Michael, just pointing out the obvious. I mean, we obviously historically were a bit long, right? And as we begin this transition and we have some of these plants closing, obviously we have less length today. And adding Castle Bluff that Marty spoke about earlier, that's certainly a step in that right direction. And then you know, that's exactly what the team is evaluating as part of this IRP evaluation and whether we're going to need to file again is 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.

Great.

You know, I would just say this. Yeah, and look, when you look at our IRP, you can see the elements that we might bring forward. I mean, you know, we had renewable resources in there. We'll be evaluating, can we pull those forward? Can we pull forward battery storage technology? You know, as Michael said, we've got some simple cycle, combined cycle. Do we need to add some additional gas fire generation? I mean, these are the elements we're looking at as we think about updating that IRP.

Okay, that makes sense. And then just on 25 quickly, do you anticipate your consistent EPS growth that you give us in February to be based

off of 25 guidance i mean that that's sort of been our historical practice david you know that we'll update based on whatever that midpoint is for that 20 25 we've got you know for in this case it's that 495 so that would be the expectation okay great thank you thank you

And the next question comes from the line of Nick Campanella with Barclays. Please proceed.

Hey, good morning. Thanks for taking my question. I got up a little late. I'll try not to repeat. But, you know, clearly you gave 25 guide earlier here, which is a sign of confidence going into next year. Capital's going up. How much capital is going up in the near term versus kind of the long term of your financial plan? And then has that impact your equity needs? Do you still just kind of programmatically lean on the ATM, or would you kind of contemplate other mechanisms around that? Thank you.

Hey, Nick. Michael here. Yeah, I mean, from a capital perspective, I mean, I just continue to think in terms of the $21.9 billion that's out there, right? And so we've talked about a number of factors that we're updating for and just spent some time talking about this IRP. And so that's the process that we're going through, you know, going through our typical capital planning process as we speak and, you know, putting the final touches on that. And that's what we'll come out with, you know, here in February. From a financing perspective, you know, the plan that we put out there last February still stands today, you know, focused on that $300 million, got that largely done for 2024. We're starting to lean into the 25 piece, you know, got about 155 of that 600 done. You know, in terms of ongoing financing assumptions, you know, we've talked about this. We would like our ratings where they are, the BAA1, BBB+, downgrade threshold at 17 at S&P is, you know, we've got quite a bit of margin there. The threshold metric for us is on S&P at 17. And so that's the one we'll continue to watch. You know, from a financing assumption standpoint, you should assume what we've sort of put out there at this point. And so maintaining those and that consolidated equity ratio over around 40%, which is where it is today.

Thanks a lot. I appreciate that. And then, you know, I just maybe some considerations with the election that just that just happened. You know, I believe that there is some EPA driven investments in your plan today. And just do you think any of that could change? And then how would you kind of, you know, quantify your positioning around, you know, the new candidate? And can you also kind of clarify if you have transferability cash flow in the plan? Thank you.

Yeah, there's a lot there. I think the, obviously, you know, election, you know, just happened. I think that You know, look, 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 don't change. And our focus is on making great infrastructure investments for the benefit of our customers and communities, advocating for energy policies that maximize that value. And, of course, as I mentioned before, seeking great economic development opportunities. And we're going to be working with policymakers to make sure we maximize the benefit of those for our communities. Well, you didn't ask about this, and I think the most significant area of focus coming out of the federal elections probably could be around tax policy. And as you know, as a fully rate-regulated company, all the increases and decreases in taxes flow directly through to our customers' rates. So things like the corporate income tax rate, the value of tax credits, those are things that have pretty meaningful effects on our customer rates. So my sense is with Republican leadership, it's going to certainly be less likely that we see an increase in corporate taxes. And I think that's positive for our customers from a bill perspective. And I do expect there's going to be a conversation around some of these clean energy tax provisions in the IRA. And so I think we in our industry, we'll all engage with policymakers on the considerations and You know, my expectation is that, you know, Republicans will probably take a surgical approach to adjustments to the IRA, you know, given some of the direct customer benefits. You know, for us specifically, I'd say the most meaningful benefits of the tax credits around solar, battery storage, nuclear, and wind. And so those are some of the things we'll be thinking about. You know, you mentioned transferability. Transferability of tax credits is important. you know, is important to us. And, you know, we'll make sure that, you know, policymakers are certainly aware of the importance of those too. You know, 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 to our customers in Missouri alone. So, you know, it's a significant benefit, and that's over about a 10-year period, the next 10-year period in our IRP. So, We'll just make sure that as we engage with policymakers, whatever they decide, that at least they have those facts and they're aware of those benefits that we expect to have for our customers. And at the end of the day, you should know that the investments in our system that we're going to make are whatever we think are appropriate from a reliability and affordability perspective 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 mentioned EPA rules. I think that with respect to the EPA rules and the CapEx that we have in our plans today, I don't see those as changing. The EPA's greenhouse gas rules, on the other hand, that are working their way through the courts, You know, I do expect that ultimately those rules will be stayed given some of the provisions that are in them with respect to, you know, carbon capture and storage and co-firing with natural gas. And, you know, we'll see what happens with respect to those proposed rules as we go through sort of a change in administration and a change in legislature. But I think those rules personally in my mind are, you know, are flawed as they stand today. So, You know, those would be my comments. Any other questions from you?

I would say that you answered the four-part question very well. I appreciate it. And thanks.

Thank you. You bet. Thank you. Ladies and gentlemen, this concludes our question and answer session. I'll turn the call back to Marty Lyons for closing remarks.

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. So, again, thank you very much, and everybody have a great day.

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