Greetings and welcome to Ameren Corporation's first quarter 2024 earnings call. At this time, all participants are on a listen-only mode. A brief question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, 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, Andrew Kirk, Director of Investor Relations and Corporate Modeling for Ameren Corporation. Thank you, Mr. Kirk. You may begin. 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, 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 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 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. Thank you, Andrew. Good morning, everyone, and thank you for joining us today as we discuss our first quarter 2024 earnings results. Our team continues to successfully execute on our strategic plan across all of our business segments, allowing us to deliver for our customers, shareholders, and the environment while laying a strong foundation for the future. Turning now to page five. Yesterday, we announced first quarter 2024 earnings of $0.98 per share compared to earnings of $1 per share in the first quarter of 2023. The key drivers of our first quarter results are outlined on this slide. Overall, our operating performance was strong during the quarter. We had periods of extreme cold weather in January, and our natural gas and electric systems and our operating teams performed well. On balance, however, weather was mild during the quarter, marked by unseasonably warm temperatures in February and March. Despite the mild temperatures, our retail sales grew, driven by encouraging signs of customer growth and usage. While we experienced higher operations and maintenance expenses, that was driven largely by a charge for proposed additional mitigation relief related to the Rush Island Energy Center New Source Review litigation. Despite the year-to-date weather headwinds and the Rush Island charge, our team is taking steps to contain spend, and we remain on track to deliver within our 2024 earnings guidance range of $4.52-$4.72 per share. I will provide an update on our Rush Island Energy Center proceedings, and Michael will cover the first quarter and balance of the year earnings results in a bit more detail later. Moving to page 6. On our call in February, I highlighted some of our top priorities for 2024 as we invest strategically, enhance our operating jurisdictions, and optimize our business processes. Our team's unwavering commitment to these objectives has already begun to produce results, as you can see on page seven. Our investments continue to improve the reliability, resiliency, safety, and efficiency of our service to our customers. In the first three months of this year, we have invested significant capital for the benefit of our customers. During the quarter, Ameren Missouri installed over 55,000 smart meters, 60 smart switches, 15 miles of energized underground cable, 8 miles of hardened overhead lines, and upgraded five substations. In Illinois, our first quarter investments included replacing 550 poles due to standard inspections and storm damage, replacing switch gear at a key substation, and installing 30 miles of underground cable for relocations, new customers, and aged cable replacement. Further, our transmission business is on track to complete over 15 new or upgraded transmission substations and 45 miles of new or upgraded transmission lines in the first half of the year. These critical investments support our commitment to delivering safe and reliable energy for the benefit of our customers, and we are seeing the benefit in 2024 in terms of reduced outages and shorter outage durations as a result of spring storms. For example, during a recent April storm, over 7,500 Missouri customer outages were prevented due to rapid detection, rerouting, and restoration of power by automated switches across our system, and over 2.3 million minutes of customer outages were avoided due to these investments. Moving on to first quarter regulatory and legislative outcomes. In March, Ameren Missouri received Missouri PSC approval of our largest-ever solar investment, three projects representing a total of 400 megawatts capable of powering approximately 73,000 homes. The approval of Certificates of Convenience and Necessity, or CCNs, for these projects is another constructive step along the pathway to executing our Ameren Missouri Integrated Resource Plan, or IRP. On the legislative front, the Missouri General Assembly is addressing power quality and reliability by considering bills to enhance and extend the current plant-in-service accounting, or PISA, legislation that would support investment in dispatchable resources and reliability. PISA has supported much-needed reliability investments in the state's energy grid over the past five years. While these bills, House Bill 1746 and Senate Bills 740 and 1422, have strong bipartisan support, time is short, and the current General Assembly session ends Friday, May 17th. While the legislature has many priorities, we will continue to work with key stakeholders towards passage. At Ameren Transmission, progress continues to be made on the long-range transmission regionally beneficial projects, which I will cover in more detail in a moment. Turning to Illinois electric delivery. We continue to diligently work for approval from the Illinois Commerce Commission, or the ICC, of an electric grid investment plan, revised revenue requirements incorporating ongoing and prospective investments, and an overall improved regulatory environment. In January, the commission granted a partial rehearing of our multi-year rate plan to address the base level of investment needed to operate the grid reliably. Subsequently, in February, we filed an updated plan as part of the rehearing proceeding. In March, we filed our revised multi-year grid and rate plans to address the commission's findings stated in their December order. The rehearing and revised multi-year grid and rate plan proceedings are operating in parallel and would update rates for 2024 through 2027. We expect a decision from the ICC on the rehearing in June, which would provide a 2024 interim rate adjustment by July. We expect an ICC decision on the revised multi-year grid and rate plans by the end of the year, which would revise rates beginning January 2025. We continue to work with all impacted stakeholders to advocate for constructive regulatory frameworks and outcomes that support the state's energy transition goals. Our ability to invest and deliver reliable and affordable energy is essential for our customers and the communities we serve and will support continued growth in our region. Moving on to operational matters. We remain committed to maintaining disciplined cost management to hold operations and maintenance expenses flat in 2024 to 2023 levels. I'd like to express my sincere appreciation to our Ameren team members who are working efficiently, collaboratively, and safely to serve our customers. Now moving to page 8 for details on the Rush Island securitization case at Ameren Missouri. Our request with the Missouri PSC to securitize the remaining balance of the Rush Island Energy Center and other related costs continues to make progress. In March, the Missouri PSC staff recommended securitization of $497 million as compared to our request of $519 million. Refinancing these investments through the issuance of securitized bonds versus financing and recovery through traditional rate making will save our customers millions of dollars. Hearings were completed in April, and we expect the PSC's decision by June 21st. Now turning to page 9 for an update on the New Source Review proceeding for Rush Island. As previously reported in 2017, the U.S. District Court of Eastern Missouri issued an order requiring the installation of a flue gas desulfurization system, or scrubbers, on our Rush Island Energy Center for violating New Source Review provisions of the Clean Air Act and install a dry sorbent injection system at our Labadie Energy Center as mitigation for excess emissions at Rush Island. Upon appeal, the Eighth Circuit upheld the district court's ruling with respect to the installation of scrubbers at Rush Island but overturned the decision with respect to Labadie. Subsequently, we made the decision to accelerate the planned retirement of our Rush Island Energy Center, which was more economic for our customers than installing scrubbers. The district court approved Ameren's retirement proposal and established a retirement date of no later than October 15th, 2024, to allow for the completion of various transmission reliability projects. The U.S. Department of Justice is seeking additional mitigation relief beyond the retirement of the energy center. In March of this year, the district court ordered both parties to file proposals outlining additional mitigation relief for the court to consider. On Wednesday, Ameren Missouri and the DOJ filed their respective mitigation proposals. Ameren's mitigation proposal consists of four essential elements: retirement of Rush Island, which eliminates all emissions through its previously planned 2039 retirement date, a school bus electrification program, including buses and charging stations, an air filter program geared towards underserved residential customers, and surrender of sulfur dioxide allowances. Collectively, these programs are estimated to cost approximately $20 million, which resulted in a first quarter charge to earnings. The Department of Justice mitigation proposal includes a significantly greater number of buses, charging stations, and advanced filters. The DOJ estimates their aggregate program cost to be approximately $120 million. We expect an evidentiary hearing will be scheduled sometime this summer, and we expect the district court will issue a final ruling during the second half of 2024 that could be subject to further appeals. Before moving on, I'd like to provide an update on a series of new rules issued by the Environmental Protection Agency last week. As you know, at Ameren Missouri, we remain committed to investing in a clean energy transition in a responsible manner, balancing reliability and affordability. The new rules expect generators to rely heavily on carbon capture and storage technologies, which are not ready for full-scale, economy-wide deployment. These new rules apply not only to existing coal-fired units but new gas-fired units with greater than 40% capacity factors as well, which would include the gas combined cycle facility called for in our current IRP in the early 2030s to maintain system reliability. In addition, for coal units retiring between 2032 and 2039, the rules will require natural gas co-firing by 2030. As we noted in our comments to the proposed rules, co-firing with natural gas presents challenges from a permitting and construction standpoint. These requirements would most directly impact our Labadie Energy Center, which has units scheduled to retire in 2036 and 2042. While we are still assessing the impact of the rules on our integrated resource plan, these new rules are making it more challenging and costly to maintain existing dispatchable generation or build new dispatchable generation. These challenges come at a time when supply and demand is tight, and the industry is seeing significant potential load growth, particularly from data centers, the manufacturing industry, and through the electrification of transportation. We will continue to closely review the final regulations and, as with many environmental regulations, litigation by various stakeholders is likely. These rules, if not modified, would require significant investments beyond what's in our current 10-year pipeline to meet compliance obligations and maintain a reliable system. Moving to page 10, we look ahead to our future renewable generation developments. As I mentioned, in March, the Missouri PSC approved CCNs for three Ameren Missouri solar projects totaling 400 megawatts: Split Rail, Vandalia, and Bowling Green, all located in Missouri. The Missouri PSC, in its March order, also set terms upon which a fourth solar facility, the 150-megawatt Cass County, Illinois project, could be approved if it is fully subscribed under Ameren Missouri's Renewable Solutions Program. The Renewable Solutions Program is a subscription-based program that allows eligible businesses and organizations to manage their carbon footprint by replacing up to 100% of their total energy use with renewable sources. The online auction for customers to subscribe to the Cass County solar project is expected to take place in mid-May with Missouri PSC approval of the Cass County CCN expected following full subscription. Initial non-binding notices of intent for the subscription auction were received from interested businesses in early April and reflected strong interest. Investing in solar energy is part of Ameren Missouri's plans to affordably meet the long-term energy and reliability needs of our customers. The IRP also calls for new dispatchable energy resources, including an on-demand 800-megawatt gas simple cycle energy center by 2027, which could be turned on as needed in a matter of minutes to ensure reliability of the energy grid during periods of peak energy demand. Later this month, we expect to file a request for a CCN for this simple cycle plant, Castle Bluff Energy Center, to be located on the site of our retired Meramec Energy Center. Moving to page 11. The Midcontinent Independent System Operator, or MISO, continues to advance its long-range transmission planning and project approval processes. For Tranche 1, we were pleased to be selected in April to develop the third and final competitive project in our service territory, which again emphasizes our track record of being able to deliver cost-effective, high-value projects to our communities. Ultimately, Ameren was assigned to build approximately 25% of total Tranche 1 portfolio projects addressing the MISO Midwest region and 100% of the projects in our service territory. We expect Tranche 1 construction to substantially begin in 2026, with completion dates through 2030. Looking ahead to Tranche 2, in March, MISO announced a long-range transmission Tranche 2 proposed project portfolio estimated to cost $17 billion-$23 billion, which included significant investments within our Ameren Missouri and Ameren Illinois service territories. Since then, we and other key stakeholders have been working with MISO to evaluate and comment on the portfolio of projects to assist MISO in ultimately approving the most appropriate path forward. MISO expects to vote on Tranche 2 in the third quarter of 2024. Moving to slide 12. Looking ahead over the next decade, we have a robust pipeline of investment opportunities of more than $55 billion that will deliver significant value to all of our stakeholders by making our energy grid stronger, smarter, and cleaner. Of course, our investments also create thousands of jobs for our local economies. Maintaining constructive energy policies that support robust investment in energy infrastructure and a transition to a cleaner future in a responsible fashion will be critical to meeting our country's growing energy needs and delivering on our customers' expectations. Turning to page 13. In February, we updated our five-year growth plan, which included our expectation of a 6%-8% compound annual earnings growth rate from 2024 through 2028. The earnings growth is primarily driven by strong compound annual rate base growth of 8.2%, supported by strategic allocation of infrastructure investment to each of our business segments based on their regulatory frameworks. Combined, we expect to deliver strong long-term earnings and dividend growth, resulting in an attractive total return. I'm confident in our ability to execute our investment plans and strategies across all four of our business segments, as we have an experienced and dedicated team to get it done. Again, thank you all for joining us today. I'll now turn the call over to Michael. Thanks, Marty, and good morning, everyone. Turning now to page 15 of our presentation. Yesterday, we reported first quarter 2024 earnings of $0.98 per share compared to $1 per share for the year-ago quarter. The key factors that drove the overall $0.02 per share decrease are highlighted by segment on this page. We delivered solid earnings performance during the quarter as we continued to execute our strategy, including making infrastructure investments for the benefit of our customers. The first quarter included new service rates in Ameren Illinois Natural Gas and Ameren Missouri. In addition, strong customer growth and usage contributed to 3% higher electric weather-normalized retail sales at Ameren Missouri across all customer classes, which were partially offset by milder weather impact, in fact, the third warmest first quarter in the past 50 years. Earnings were also reduced by an increased O&M in Ameren Missouri, largely driven by a $0.04 charge for proposed additional mitigation relief related to the Rush Island Energy Center. Moving to page 16. As we think about the remainder of the year, we remain confident in our 2024 guidance range, and we continue to expect earnings to be in the range of $4.52-$4.72 per share. As we think about the first quarter results versus our expectations, we lost $0.07 compared to normal for weather and $0.04 for the charge related to Rush Island, but experienced $0.02 of favorable weather-normalized sales beyond our expectations. As we look ahead, we expect to see meaningful year-over-year O&M reductions in the second half of the year, reflecting several cost savings initiatives instituted in 2024, which are expected to build throughout the year. This includes hiring restrictions, reducing our contractor and consultant workforce, and deferring or eliminating discretionary spend. As we've discussed before, we have been actively managing costs for years and continue to create opportunities for further cost reductions through process redesign and digital technology investment, leading to increased productivity and better experiences for our customers. In addition, we expect to benefit from higher earnings in Ameren Transmission over the balance of the year due to timing of financing and project expenditures. I encourage you to take these supplemental earnings drivers into consideration as you develop your expectation for quarterly earnings results for the remainder of the year. Finally, late last week, MISO concluded its planning resource auction for the 2024-2025 planning year, which assesses seasonal resource adequacy in each zone. As a result of higher load requirements, changes to the accredited capacity of generation available, and reduced import capability, Zone 5, Ameren Missouri's territory showed a mild capacity shortfall, and prices went to the cost of new entry, or CONE, for the non-peak load fall and spring seasons. Clearing prices in all other zones within MISO remain relatively flat. Unlike what Ameren Illinois experienced a couple of years ago, we do not expect to see material customer bill impacts at Ameren Missouri resulting from this auction because our generation resource is available to serve customers, nor do we see any issues with providing reliable electric service throughout the year for our customers. The MISO auction results do reinforce a couple of things. First, there's a strong need for us to continue to execute the generation plans called for in our IRP. Second, the integration of new large electric loads and carbon-free renewable generation to the grid will require significant transmission expansion, with some projects needed locally to ensure reliable service. We stand ready to work with stakeholders in our region to address the capacity needs. Before moving on, I'd like to provide an update on economic development. Through mid-April, we have successfully supported 21 new projects that have selected locations in our service territories, which are expected to increase electric demand by almost 45 MW and natural gas usage by 1.6 million therms within the next few years. These projects will add an estimated 950 jobs across our service territories. The majority of these projects are existing customer expansions in the manufacturing, aerospace, data center, food processing, and mining industries. Ameren Missouri and Ameren Illinois are actively working with state, regional, and local partners on more than 150 economic development projects that are considering a location in our service territories, including large load data centers and manufacturers in the automotive, aerospace, and agricultural industries, among others. We will continue to work on development opportunities to build thriving communities in our service territory. Moving to page 17 on Ameren Illinois regulatory matters. We have several Ameren Illinois electric distribution regulatory updates to cover with you, including the 2023 annual reconciliation, the 2024 through 2027 multi-year rate plan rehearing, as well as revised grid and rate plan filings. Starting with the 2023 annual reconciliation. Under Illinois formula rate making, which expired at the end of 2023, Ameren Illinois is required to file annual rate updates to systematically adjust cash flows over time for changes in cost of service and to true up any prior period over or under recovery of such cost. In April, we filed our electric distribution annual rate reconciliation request for a $160 million adjustment for the 2023 revenue requirement to reflect actual cost. The full amount would be collected from customers in 2025, replacing the prior period reconciliation adjustment of $110 million that is being collected during 2024 for a net customer impact of $50 million or an approximately 1.5% increase in the total average residential customer bill. The ICC will review the matter in months ahead with a decision expected in December of this year and new rates effective in early next year. Turning to the multi-year rate plan for 2024 through 2027 on page 18. In January, Ameren Illinois was granted a partial rehearing by the ICC to address a base level of grid reliability investment and 2023 rate-based additions. We filed our revised request in April for a cumulative annual revenue increase from 2023 rates of $305 million by 2027. Our request, which includes investments and costs related to preventative and corrective maintenance, inventory, metering, new business, and customer relocations, would allow us to appropriately maintain the energy grid to preserve safety, reliability, and day-to-day operations of our system. The ICC staff recommends a cumulative increase of $283 million, with the variance driven primarily by the removal of other post-employment benefits and certain 2023 projects from rate-based, the latter of which the staff deem to be outside the scope of this rehearing. We expect an ICC decision on the rehearing proceeding by June 20th, which will allow new 2024 interim rates to be effective by July. Moving to page 19. In March, Ameren Illinois filed its revised electric multi-year grid plan and revised multi-year rate plan. Our request for a $321 million cumulative annual revenue increase from 2023 rates would supersede revenues granted through rehearing. Request is based on a return on equity of 8.72% and an equity ratio of 50%. Annual revenues will be based on actual recoverable cost, year-end rate base, and a return on equity adjusted for any performance incentives or penalties provided the actual revenue requirement does not exceed the reconciliation cap. Our plans, as proposed, support an affordable, equitable energy transition, which we'll advocate for over the remainder of the year. We expect the ICC staff and intervenor testimony in May, and we expect an ICC decision by December with rates effective January 1st, 2025. In other regulatory matters, last week, Ameren Missouri filed a 60-day notice with the Missouri PSC for our next electric service rate review. Moving to page 20 to provide a financing update. We continue to feel very good about our financial position. On January 9th, Ameren Missouri issued $350 million of 5.25% first mortgage bonds due 2054. On April 4th, Ameren Missouri issued $500 million of 5.2% first mortgage bonds due 2034. Net proceeds from both issuances were used to fund capital expenditures and/or refinance short-term debt. Further, in order for us 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 2024. We sold for approximately $230 million under our At-the-Market, or ATM, program, consisting of approximately 2.9 million shares, which we expect to issue by the end of this year. Together with the issuance under our 401(k) and DRPlus programs, our ATM equity program is expected to support our equity needs in 2024 and beyond. Finally, turning to page 21. We're off to a solid start in 2024 and well positioned to continue executing our plan. We expect to deliver strong earnings growth in 2024 as we continue to successfully execute our comprehensive business strategy. Looking to the longer term, we continue to expect strong earnings per share growth driven by robust rate-based growth and disciplined cost management. We also believe this growth will compare favorably with the growth of our peers. Ameren shares continue to offer investors an attractive dividend. In total, we have an attractive total shareholder return story. I conclude our prepared remarks. We now invite your questions. Thank you. At this time, we'll be conducting a question-and-answer session. If you'd like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you'd 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. One moment, please, while we pull for questions. Our first question comes from Shahriar Pourreza with Guggenheim Partners. Please proceed with your question. Hey, guys. Good morning. Morning, Shah. Morning, morning. Marty, can you just maybe elaborate a bit more on the recent EPA regs? I mean, you touched a bit on the fleet impact, like Labadie, but maybe expand on potential shifts to timing and scale the spending opportunities versus last year's IRP, if it makes it through the courts. I mean, could we see some pull forward of generation spend? What do you see as kind of an updated pathway here? Should we be thinking of an IRP update like you did with the Rush decision? Thanks. Well, Shah, you've outlined a number of the considerations. I mean, first of all, we're all just still absorbing the rules. And so our teams are studying the new rules thoroughly, and we'll be, over the coming weeks, really trying to assess what the potential impacts are on our IRP. And certainly, that could mean, as you note, a revision to the IRP. But of course, too, we'll expect these rules to likely be litigated, and so we'll have to take into account that litigation and the uncertainties that it creates. In my prepared remarks, I noted a couple of the more notable concerns that we have, the first being that the rules do really rely on carbon capture and sequestration, which I think we all recognize isn't really ready for prime time today. The things that would impact, we have, as you know, in our IRP, a planned combined cycle facility, 1,200 megawatts planned for the 2032-2033 time frame, which is really important from a reliability perspective as we expect to retire our Sioux Energy Center, our coal-fired power plant, in that 2032 time frame. Certainly, new combined cycle that would operate with greater than a 40% capacity factor, which we would expect this one to, would be impacted by that carbon capture and sequestration. That certainly has significant implications as it relates to that planned combined cycle facility, and we'll have to reassess and think through that. The other one I mentioned is our Labadie Energy Center. That plant is scheduled to retire really in phases, with about half of it in 2036 and the other half of it in 2042. So the rule would have implications for the ultimate retirement date, pulling that forward a little bit. But in order to be able to maintain the life of that facility out through 2039, the rules would require co-firing with natural gas in the 2030 time frame. And of course, trying to get things permitted and constructed in that amount of time certainly poses challenges as well and so highlighted those in my prepared remarks today. So at the end of the day, Shah, I think as we look at these rules, we do have concerns about the feasibility and ultimately the reliability of our system. Those are our primary concerns. But you're absolutely right. As we think about these rules, it certainly could cause revisions to the IRP and, on balance, suggest a greater level of investment that would be required to maintain reliability of our system over the next 10 years. Got it. And then just a bit nuanced, but what exactly was going on with the PRA auction in Zone 5? I mean, obviously, it's quite a large breakout for you. It's net neutral from a customer impact perspective, which you just highlighted. But maybe just some color on the backdrop. Is this kind of structural? Should we expect it again, or really kind of an administrative or design error? Thanks. Hey, Shah. It's Michael. Good morning. A couple of things. I mean, as you noted, I mean, obviously, Zone 5, we've moved to this new seasonal construct. We did see quite a bit of variability. You had $30 in the summer and $0.75 in the winter and then CONE in the fall and the spring at $7.19. So as you note, I mean, this is a capacity issue. It's not an energy issue. And so I think it's always important to just start with that. We expect to have, obviously, enough energy available for customers. We don't foresee any issues with respect to providing reliable service, which I think is important. Also, from a customer impact standpoint, we really don't see any, if any, impact to customers as well. And it gets a little complicated. I mean, the MISO models are revenue-neutral model, and so there'll be some shifting that goes on. Missouri owns generation in Zone 4. We're able to point to those as hedges, and so it helps offset all that. But I think when you step back, I mean, it is right trying to send a price signal with respect to needing additional dispatchable generation as Marty just spoke about. And I mean, there were a couple of things I noted in my prepared remarks. I mean, it was due to increased load. There were some accreditation issues with respect to some generation that got dinged for some past performance. That should go away over the next couple of years. And then there was a reduction in import capabilities. That also, I think there's probably some transmission opportunities there that would relieve that. I think, again, it does speak to what we're trying to do from a dispatchable perspective. I think, Shah, there's a way to work around this and see some relief over the next couple of years. Okay. Perfect. I appreciate it, guys. Thank you so much. Thanks for the question, Shah. Our next question is from Jeremy Tonet with J.P. Morgan Chase. Please proceed with your question. Hi. Good morning. Hey, Jeremy. How are you today? Good. How are you? Good. Just wanted to go to Missouri and as far as legislative initiatives there, if you could provide us, I guess, thoughts on the environment there, what you're looking for, and specifically PISA legislation. I think the session is ending soon, and so any thoughts there would be helpful. Yeah, Jeremy, you've got it. I think that as we sit here today, the legislation that is most likely to get across the finish line is that PISA legislation. So, as you know, and I'm sure you've been following House Bill 1746 and Senate Bills 740 and 1422, I would say at this point in session, they're probably as well positioned as you could be for passage. Senate Bill 1422 and Senate Bill 740, they're on the Senate informal calendar. They could be brought up at any time. House Bill 1746, which passed out of the House with a very strong supportive vote of 119-17, is also now passed through the Senate Commerce Committee. It's listed as number 1 on House Bills for third reading. Things are well positioned. The challenge that I highlighted in the prepared remarks, however, is that time is short. The legislative session ends in two weeks on May 17th, and the legislature does have some significant things to get done, including a budget. That's really the concern, is just whether time will run short. In the meantime, we'll continue to work with key stakeholders towards passage if we have a window to get it done. Got it. That's helpful. Thanks. And then maybe just pivoting towards Illinois, as far as the regulatory processes are concerned with the electricity hearing, the grid plan refiling, any incremental thoughts you can share with progression versus expectations there. And really, I guess the question is more on the other side with the legislature. Do you see any potential there to maybe secure more constructive development? Hey, Jeremy. It's Michael. Good morning. Maybe I'll handle the regulatory one. If Marty wants to come on the legislative one, he can certainly do that. I think, look, things are continuing to move along there. I think we mentioned this in our prepared remarks. I mean, from a rehearing process, feel good about where we stand today. Again, just really proud of the work the team has done. Lenny and his team have been working really hard, going through a number of public hearings, a number of workshops, etc., just getting this prepared. And I think you're seeing that producing results here as we kind of work through this rehearing process. And so we should have a decision here sometime in June with rates effective in July. And this will be an interim adjustment. And then, obviously, we'll have the more comprehensive multi-year rate plan, grid plan piece in the back half of the year. It's great to have a procedural schedule around that, have some finality around this in the December time frame with rates in January. With respect to the rehearing piece, the differences between us and staff are fairly minimal at this point. As we indicated, we were at 305, and staff is at 283 today. It really comes down to two issues there, the OPEB issue that we've spoken about in the past. We still are continuing to advocate for that. We think it's the right thing. I think our range accommodates that if it goes in a different direction. And then there were some projects that were really deferred into the grid plan itself. And so we'll have another opportunity to advocate for those. So again, it feels good as you can feel at this point in time, and the team is focused on it and getting some stability put back in that process. Yeah, really, Jeremy, nothing to add at this point. I mean, in terms of legislative initiatives, nothing to point to. Of course, this year, both in Missouri and Illinois, we have supported right of first refusal legislation in both states. In neither state do we see those as moving forward at this time, but continue to advocate for the benefit of those for our customers and for the reliability of the grid broadly, but nothing to tack on right now. Got it. That's helpful. I'll leave it there. Thanks. Our next question comes from Carly Davenport with Goldman Sachs. Please proceed with your question. Hey. Good morning. Thanks so much for taking the questions today. Maybe just to follow up really quickly on the Illinois rehearing process. First, can you just remind us what of that $305 revenue increase requested there is embedded in the 2024 guidance and the kind of flexibility there to the extent there's some gap? And then is there any potential for that decision to come earlier than the late June time frame that you laid out? Hey, good morning, Carly. This This is Michael. With the second part first, I think no. I think at this point, the expectation is kind of move along that time frame and should have a decision here in July. In terms of sort of what's embedded, that $305 is obviously over that four-year period. And so there's a component you can see that we have broken out for 2024. Again, feel good about what we have embedded in there and just sort of where the positions are. To the extent that something ended up changing from that, we'd have to just step back and look at it from a rate-based perspective to the extent that it's capital. Again, I mean, you're earning 8.72%. So I mean, that obviously minimizes the impact, and we just have to see what our options are. I mean, we do have flexibility with some additional capital there, but really just looking to see the process move along and feel better about the framework first. Got it. Thank you. That's super helpful. And then maybe just on Rush Island, you talked a bit about the delta between Ameren's proposal and the DOJ proposal there. Is that just a matter of sizing the program that you expect to be the piece of debate? Or is there anything else that sort of sticks out as a point of debate as you think about going into hearings there this summer? Yeah. You're talking about which one were you asking about? Were you asking about NSR case, Carly? Yeah, I think you were. Listen, as it relates to the NSR, yeah, as we outlined in our slide prepared remarks, we've proposed programs that have a value of about $20 million. And the Department of Justice has outlined a series of programs that they've estimated at $120 million. And when you look at the components of the two programs, they're very similar in terms of electric school buses, air filtration programs, charging infrastructure. It's very similar. So it really is seemingly not a matter of the program mix, but sort of the extent of them and the cost of them. So we can't predict what mitigation the court would ultimately order. We would generally expect, though, that the positions I just talked about that the parties have in the proposed orders would sort of just bookends for the degree of mitigation relief that was either ultimately reached through a settlement between ourselves and the Department of Justice or a court order. But really can't speculate further at this point. Got it. Okay. Thank you so much for the color. Our next question is from Paul Patterson with Glenrock Associates. Please proceed with your question. Hey. Good morning. Hey, Paul. So I just wanted to follow up on the EPA rule. It seems so challenging, I guess. I'm just wondering, assuming that it's largely in place or something, when you mentioned different things you might have to do for reliability and stuff, could you just sort of give us a general sense what would happen? I mean, because as you mentioned, I think that carbon capture and sequestration has got so many challenges associated with it. Would you just start running the plants lower? Would there be more batteries? Would it be what would be sort of the remedy that might be thought about? And also, would there be any change in depreciation schedules? Or I'm just sort of wondering. I mean, this sounds like a very difficult thing to sort of talk about potentially changing the IRP with a plan that seems so radical, kind of, if you know what I'm saying. Well, Paul, it's Marty. I think you hit on a number of the considerations. I'll go back to what I said before. It was early days. We just got in the rules. We're going to go through a thorough assessment of the rules and reassessment of the IRP. Again, you've got the likelihood of litigation, which will have to be factored in as well to our considerations. But I think when you look at the steps we're taking between now and 2030, as we currently have outlined, I think the EPA rules underscore the importance of these. We've got 2,800 MW of renewables planned by 2030. We've got 400 MW of battery storage planned between now and 2030. We've got 800 MW of simple cycle generation planned between now and 2030. And I think given these rules, certainly, it underscores the importance of all of those things. I think the broader implications that are down the line, I think with respect to the retirement of the Sioux Energy Center that we have planned for 2032, generally in line with the rules, the Labadie Energy Center I mentioned earlier, half of it retiring in 2036, half of it in 2042. Again, if that needed to be retired by 2039, maybe a little bit of a change in depreciation there, recovery. But I think the bigger thing for Labadie then would be getting gas into Labadie and the ability to be able to co-fire with natural gas so that we've got that. And then I think when you think about that combined cycle facility and again, first of all, the feasibility of doing carbon capture, much less the cost of doing carbon capture, you really have to reassess that plan in light of these rules. But you're right. What it might mean otherwise is more simple cycle gas-fired generation, more battery storage technology, more renewables. Because again, anything, if you're going to operate a combined cycle over 40% capacity factor, it calls for carbon capture. But those are, I think, you've got your sort of finger on the things that you'd have to consider, which is what would be an alternative mix of renewables and dispatchable resources that can maintain reliability for the system. Okay. So we'll just, I guess, monitor this. Okay. That's very helpful. And then with respect to transmission, there's been a lot of focus on the part of officials in Washington and other places on grid-enhancing technologies. And I was just wondering how you thought about those and the potential deployment at Ameren and just any thoughts you might have on that. Yeah. Let me let Shawn Schukar, who runs our transmission operations, comment on that. Yeah. Thanks for the question. So the grid-enhancing technology generally allows us to flow more across the system. They don't take care of some of the capacity needs. And we see those as complementary as we transition through the grid investments, which means that we'll be making some enhancements like you see from the MISO. But we also look at those grid-enhancing technologies to support the system, and we'll be utilizing a combination of both. Okay. Thank you. Good talking to you guys. Thanks, Paul. As a reminder, if you'd like to ask a question, please press star one on your telephone keypad. One moment while we poll for additional questions. Our next question comes from Nick Campanella with Barclays. Please proceed with your question. Hey. Good morning. Happy Friday. Hello, Nick. Same to you. Hey. Hey. So I just wanted to ask quickly on the mitigation proposal on Rush Island because I know that you booked this $20 million figure, which was an ongoing hit in your O&M line. But then you kind of mentioned the risk of the DOJ is asking for $120 million. And obviously, we'll see where this goes at the end of the year. But if it does go against you, is that still an ongoing item in your view, or is that kind of more one-time in nature? Nick, it's a great question. And I think ultimately, wherever this settles, it really is a one-time item. It is non-recurring. Given the size of it today, we didn't think it appropriate to sort of carve it out. And as we talked about on our call, we looked to overcome the cost of that with respect to ongoing operations savings. However, again, as I outlined, the $20 million we've proposed and the $120 million that the DOJ proposed are probably book ends as we think about settlement and an ultimate potential court order here. But I would agree with you that ultimately, whatever this cost is, it's non-recurring in one time and won't be something that affects ongoing operations or earnings. Hey. I really appreciate that. As it just relates to 2024, I know you're highlighting that you kind of have this line of sight to O&M in the back half of the plan. So just any comments on how you feel like you're trending versus your full 2024 number at this point? Are you at the midpoint? Or I guess any comments there? Yeah. Hey, Nick. It's Michael here. Good Friday to you. Yeah. Look, I mean, we obviously reiterate our range of $4.52-$4.72, really focused on the midpoint of that range. The team is completely aligned on flexing what we need to flex here from an O&M perspective. We talked about a number of programs. I think the first part of the year that we put in place with respect to some hiring freezes, looking at discretionary spending, looking at contractors, travel, all those kinds of things. And again, those programs are fully ramped up at this point and feeling good about it. Look, when we have a long history of this, you've heard us talk about this. I mean, we've been doing a number of things really from an automation, a technology investment perspective. We've now fully deployed AMI in the field. We have distribution automation. We've done a great deal of stuff from the back office perspective in terms of the accounting systems, HR systems. I mean, all of those are driving productivity improvements that we're taking full advantage of. I was sort of reflecting on this situation and thinking about 2020, that terrible COVID year. We lost 15% of sales within about a week. The team came together and really looked for $10s of millions' worth of opportunities that we were able to flex and continue to end up hitting our guidance for that year. I don't see this as any different. We'll continue to look for these opportunities. Ultimately, we're going to make the decisions right for the long term at the end of the day. We do have the ability to flex up and down as needed. That's really helpful and definitely acknowledge the ability to flex here, especially based on past one more thing. Just, you're very clear. Your '24 equity needs are basically done outside of internal programs and maybe some DRIP. But just for '25 and beyond, is $600 million a year still the kind of right number to be thinking about? I think that's what you guys talked about in the fourth quarter. Yeah. Yeah. That's correct. That still stands, what we delivered back there in February. All right. Have a great day. Thanks. Okay. Thanks. Good questions. Our final question is from David Paz with Wolfe Research. Please proceed with your question. Good morning. Morning, David. Could you maybe expand on the data center opportunities? I know you mentioned them you mentioned data centers along with some other large customers. But just what opportunity are you seeing there, particularly on the investment side? Maybe any sense of the size of the projects that potentially could come down the pike? And just how much would an incremental investment from Ameren be for a typical-sized project? Thank you. Yeah. Hey. Good morning, David. I'll start here. I'm certain Marty'll probably chime in as well. But I mean, I think we have a strong value proposition, right, when it comes to serving both data centers and manufacturers. I mean, we've talked about this. We start from a really strong position just in terms of where our rates are, both on a Midwest and national average, well below. We presented a number of sites in both states that can ramp up quickly, sewer water, transmission capabilities, etc. I've never seen state, local, regional leaders work together as they are right now, really trying to come together on a combined effort, offer various incentives to again, this is beyond just data centers but manufacturers in general in terms of things around state and local use taxes, development grants for workforce development, etc. We have a number of incentives in place here that are available to customers based on location and size. As we sit here today, David, we've executed a construction agreement for one data center, and it's got an estimated 250-MW loads. That's sizable for us. We haven't seen this kind of load growth in a really, really long time. We should be serving that customer by 2026. And I would say we're actively working 1,000+ MW beyond that. And so these are all in different stages at this point. They'll come online differently. But again, I think as we think about the IRP and just adding the renewables and the dispatchable generation that we've been adding the last few years, I mean, this is exactly what we need. And again, all of these projects probably won't come to fruition, but some of them are really, really moving along nicely. Beyond data centers, there's just a tremendous amount happening in the manufacturing side as well. I mean, Boeing, the largest manufacturer here in the state of Missouri, started a $1.8 billion expansion. Unilever in Jefferson City is also doing a very large expansion. Illinois's Wieland Rolled Products, a $500 million expansion. I mean, there are a number of projects here that should continue to add to some significant growth. In terms of what that means from a capital perspective, obviously, it's a net positive. I think we're going to continue to step back and assess that. But it's certainly great to see from an investment standpoint and certainly a customer affordability perspective, right? This is going to make it obviously more affordable for all customers at the end of the day. Great. Thank you for that, color. Maybe just a sneak a quick one. I think it sounded like the Tranche 2 initial concept map suggests that there will be some opportunities in your service areas. Any sense of how to compare that to what the initial concept map, Tranche 1, looked for you guys? Is it roughly the same in terms of potential dollar, either size or dollars? Yeah, David. This is Marty. I'll tell you what. First of all, the map is encouraging as we showed. I think if you look at our slide 11 that we provided, you'll see substantial proposed additional lines both in our service territory and in central Illinois as well as in the eastern half of Missouri. So that's certainly exciting to see. We're excited that the overall project portfolio was about twice the size of Tranche 1. You, everybody else, I'm sure, recalls Tranche 1. It It was about a $10 billion portfolio. We ended up having about 25% of that, as we talked about on the call. We were happy to be awarded some directly. We're very proud to have won all three of the competitive projects that were in our service territory. You certainly feel good about the way Tranche 1 turned out. It's too soon to really say what level of investment would be in our service territory from Tranche 2 for really a couple of reasons. One, I would say that what we're excited about, these projects that were in our service territory, as you well know, right now, the MISO is going through a process of getting input from stakeholders regarding these proposed projects. And we do expect that as MISO considers the input from various stakeholders, that these project plans will be modified. So it's premature there, number one. Number two, when MISO put out these Tranche 2, they really didn't assign well, they came up with an overall portfolio investment of $17 billion-$23 billion. They really didn't put any particular quantification of investment value on any particular substations or lines, etc. So really premature to even say how much these investment opportunities would be that are shown on this map. So for a couple of reasons, I think it's premature to say how much of this would be in our service territory and ultimately how much would be brownfield or greenfield. But I think we will start to see iterations of this through time. And we're excited that MISO seems to be very much targeting an approval of this Tranche 2 portfolio by mid-September. And it should be pretty exciting over the next few months as we see how this unfolds. Great. Thank you. Thanks, David. We have reached the end of the question and answer session. I'd now like to turn the call back over to Marty Lyons for closing comments. Great. Well, hey, I want to thank everybody for joining us today. We invite you to attend our annual shareholder meeting, which is next week on May 9th. And then Michael and Andrew look forward to seeing many of you at the AGA Financial Forum in a couple of weeks. With that, thanks, and have a great day and a great weekend. This concludes today's conference. You may disconnect your lines at this time. We thank you for your participation.