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. [Operator Instructions] 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 2 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 4..

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 the series of new rules issued by the Environmental Protection Agency last week.

As you know, Ameren Missouri 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. And 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 has seen 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 will receive 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 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 or awarded approximately 25% of total Tranche 1 portfolio projects addressing the MISO Midwest region in 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 to $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 6% to 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 continue 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 one was first quarter in the past 50 years.

Earnings were also reduced by an increase in O&M and 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 to $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 to 2025 planning year, which assesses seasonal resource adequacy in each zone.

As a result of higher load requirements, changes to the accreted capacity of generation available and reduced import capability, Zone 5, Ameren Missouri’s territory showed a model capacity shortfall and prices went through the cost of new entry or CONE for the non-peak load fall and spring seasons.

Clearing prices in all other zones within MISO remained relatively flat.

Unlike what Ameren Illinois experienced a couple of years ago, we do not expect to see material customer bill impact at Ameren Missouri resulting from this auction because our generation resources 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 is a strong need for us to continue to execute the generation plans called for an IRP.

And 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 megawatts and natural gas issues by 1.6 million tons 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 on location in our service territories including large low 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 multiyear rate plan rehearing as well as a revised grid and rate plan filings. Starting with the 2023 annual reconciliation.

Under Illinois formula ratemaking, 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 costs.

In April, we filed our electric distribution annual rate reconciliation requests for $160 million adjustment for the 2023 revenue requirement to reflect actual costs. 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 once ahead with a decision expected in December of this year and new rates effective in early next year. Turning to the multiyear rate plan for 2024 through 2027 on Page 18.

In January, Ameren Illinois has granted a partial rehearing by the ICC to address a base level of grid reliability investment and 2023 rate base additions. We filed our revised request enable for a cumulative annual revenue increase from 2023 rates of $305 million by 2027.

Our request, which includes investments and costs related to preventive 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 renewal of other post-employment benefits and certain 2023 projects from rate base, the latter of which the staff deemed to be outside the scope of this rehearing.

We expect an ICC decision on the rehearing proceeding by June 20, which will allow new 2024 interim rates to be effective by July. Moving to Page 19. In March, Ameren Illinois filed its revised electric multiyear grid plan and revised multiyear rate plan.

Our request for a $321 million cumulative annual revenue increase from 2023 rates with 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 based on actual recoverable costs, 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 1, 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 9, Ameren Missouri issued $350 million of 5.25% first mortgage bonds due 2054.

And on April 4, Ameren Missouri issued $500 million or 5.2% first mortgage bonds due 2034. Net proceeds from both issuances were used to fund capital expenditures and/or refinance shorten 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 base 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. That concludes our prepared remarks. We now invite your questions..

Thank you. At this time, we’ll be conducting a question-and-answer session. [Operator Instructions] Our first question comes from Shar Pourreza with Guggenheim Partners. Please proceed with your question..

Hey, guys. Good morning..

Good morning, Shar..

Good morning, Marty. 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 Island – rush decision. Thanks..

Well, Shar, 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 will be over the coming weeks, really trying to assess what the potential impacts are on our IRP. And certainly, that could mean, as you know, 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 is it really ready for prime time today.

And the things that would impact we have, as you know, in our IRP planned combined cycle facility, 1,200 megawatts plan for the 2032, 2033 time frame, which is really important from a reliability perspective as we expect to retire our Sioux power plant, our coal-fired power plant in that 2032 time frame.

And 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. So that certainly has significant implications as it relates to that planned combined cycle facility. And we’ll have to reassess and thinking 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 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 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 proposes challenges as well. And so I highlighted those in my prepared remarks today.

So at the end of the day, Shar, I think as we look at these rules, we do have concerns about the feasibility and ultimately the reliability of our system. Those were 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 PI auction in Zone 5. I mean, obviously, it’s quite a large breakout for you, 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 should expect it again or really kind of an administrative or design error? Thanks..

Hey. Shar, 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 719. 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 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 material, if any impact to customers as well. And it gets a little complicated. I mean the MISO model is a revenue neutral model and so it will be some shifting that goes on.

We have 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 meeting additional dispatchable generation that you just spoke about.

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. They 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.

And also, I think there’s probably some transmission opportunities there that would relieve that. So I think, again, it does speak to what we’re trying to do from a dispatchable perspective. And I think, Shar, 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, Shar..

Our next question is from Jeremy Tonet with JP 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 and I think the session is ending soon. And so any thoughts there would be helpful..

Yes, Jeremy, you got it. I think that as we sit here today, the legislation that is most likely to get across the finish line, is that a piece of legislation. And 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 that could be brought up at any time and 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 #1 on House Bills for third reading. So things are well positioned.

The challenge that I highlighted in the prepared remarks, however, is the time is short. The legislative session ends in two weeks on 17, and the legislature does have some significant things to get done, including the budget. So that’s really the concern is just whether time will run short.

But 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. And then maybe just pivoting towards Illinois. As far as the regulatory processes are concerned with the electronic 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 if Marty wants to come on the legislative one, you can certainly do that. I think – but 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. [Indiscernible] has been working really hard going through a number of public hearings, a number of workshops, et cetera, 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 in early – sometime in June with a great effective in July, and this will be an interim adjustment. And then obviously, we’ll have the more comprehensive multiyear 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 it sits at 283 today. It really comes down to 2 issues there.

The OpEx 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, we feel as good as you can feel at this point in time. And team is focused on it and getting some stability put back in that process..

Yes, really, Jeremy, 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 a right of first refusal legislation in both states.

In either states 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 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 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 is Michael. With the second part first, no, I think at this point, the expectation is kind of a little on 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 that would have to just step back and look at it from a rate base 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 into hearing there this summer..

Yes, you’re talking about which one were you asking about? Were you asking about NSR case, Carly? Yes. I think, you were.

Listen, as it relates to the NSR, as we outlined in our slide prepared remarks, we’ve proposed a program set up a value of about $20 million and the Department of Justice is outlined a series of programs that they’ve estimated at $120 million.

And when you look at the components of the two programs that are very similar in terms of electric school buses, air filtration programs, charging infrastructure, so 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 and the proposed orders that sort of just book ends for the degree of mitigation relief that was either ultimately reached through a settlement between ourselves and the Department of Justice for 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 reliability things you might have to do for reliability and stuff.

Could you just sort of give us a general sense of what would happen? I mean, because as you mentioned, I think that carbon capture and sequestration is – 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, it just 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. And I’ll go back to what I said before. It’s 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.

And 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 megawatts of renewables planned by 2030.

We got 400 megawatts of battery storage planned between now and 2030. We’ve got 800 megawatts of simple-cycle generation plan 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 plan for 2032 generally in line with the rules. The Labadie Energy Center, I mentioned earlier, half of it retired in 2036, half of it 2042, again, if that need 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 of the cost of doing carbon capture, you really have to reassess that, 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.

So that – but those are – I think you’ve got your sort of finger on the things that you 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 transition, there’s been a lot of focus on the part of officials in Washington and other places on great 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..

Maybe we’ll let Shawn Schukar who runs our transmission operations comment on that..

Yes. Thanks for the question. So the grid-enhancing technology, generally allow 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 talk to you guys..

Thanks, Paul..

[Operator Instructions] 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, 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 the DOJ is asking for $120 million. And obviously, we’ll see where this goes at the end of the year.

But like 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’d look to overcome the cost of that with respect to ongoing operations savings.

However, again, as I outlined, the $20 million we proposed and the $120 million of the DOJ propose probably bookends as we think about settlement and an ultimate potential court order here.

But like I would agree with you that ultimately, whatever this cost is non-recurring in one-time and won’t be something that affects ongoing operations or earnings..

Hey, I really appreciate that. And 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 mid-point? Or I guess any comments there?.

Yes. Hey Nick, it’s Michael here. Good Friday to you. Yes, look, I mean, we obviously reiterated our range of $450 million to $472 million really focused on the mid-point 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 and 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. 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 and technology investment perspective. We’ve now fully deployed AMI [ph] and we feel we have distribution automation.

We’ve done a great deal of stuff from the back office perspective in terms of accounting systems, HR systems, all of those are driving productivity improvements and we’re taking full advantage of.

And I was sort of reflecting on the situation and thinking about 2020, that terrible COVID year, we only lost 15% of sales within about a week, and the team came together and really looked for tens of millions of dollars worth of opportunities that will really 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. And ultimately, we’re going to make the decisions right for the long-term at the end of the day, but we do have the ability to flex out as we not 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 2024 equity needs are basically done outside of internal programs and maybe some DRIP, but just for 2025 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?.

Yes, yes, that’s correct. That still stands we delivered back there in February..

All right. Have a great day. Thanks..

Okay. Thanks for the questions..

Our final question is from David Paz with Wolfe Research. Please proceed with your question..

Good morning..

Good morning, David..

Could you maybe expand on the data center opportunities? I know you mentioned them, mentioning centers along with some other large customers.

But just what opportunity are you seeing there, particularly on the investment side, and maybe any sense of the size of the projects that potentially could come down the pipe and just how much would an incremental investment from Ameren for a typical size project? Thank you..

Yes. Hey, good morning, David. I’ll start here. And certainly, Marty, I’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 the Midwest and national average went well below. We presented a number of sites in both states that can ramp up quickly, sewer water transmission capabilities, et cetera.

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 we use taxes, development grants for workforce development, et cetera.

We have a number of incentives in place here that are available to customers based on location and size. As we sit here today, Dave, we’ve executed a construction agreement for one data center and it’s got an estimated 250-megawatt lows. 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-plus megawatts 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 in 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.

And beyond data centers, there’s just a tremendous amount happening in the manufacturing side as well. I mean, Boeing is the largest manufacturer here in the state of Missouri, started a $1.8 billion expansion here in Jefferson City is also doing a very large expansion, Illinois Wieland rolled products of $500 million expansion.

I mean there are a number of projects here that continue – 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? Because it’s going to make it obviously more affordable for all customers at the end of the day..

Great. Thank you for that color. Maybe just sneak a quick one. I think you sounded like your tranche, the Tranche 2 initial concept map suggests that there will be some opportunities in your service areas.

Any sense how to compare that to what the initial concept at Tranche 1 looks for you guys? Is it roughly the same in terms of potential dollar either size or dollars?.

Yes. David, this is Marty. I’ll tell you, well, first of all, the map is encouraging as we shared. And 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. And 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 show 1 was about a $10 billion portfolio. We ended up having about 25% of that, as we talked about on the call and 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. So we certainly feel good about the way Tranche 1 turned out. It’s too soon to really say what level of investments would be in our service territory from Tranche 2 for really a couple of reasons.

One, I would say that the – while 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 while they came up with an overall portfolio investment of $17 billion to $23 billion, it really didn’t put any particular quantification of investment value on any particular substations or lines, et cetera.

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.

So – 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 the Tranche 2 portfolio by mid-September. And so – and it should be pretty exciting over the next few months as we see how this unfolds..

Great. Thank you..

Thanks, David..

We’ve 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 9. 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..