Ameren Corp (AEE) — Q2 2024 Earnings Call Transcript

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 amerenvestors.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 cause actual results to differ materially from those anticipated. Now here's Marty, who will start on Page 4.

Thanks, Andrew. Good morning, everyone. We're pleased to have you joining us today as we cover our second quarter 2024 earnings results and recent developments across our business segments. Overall, it was a very productive and positive quarter. As always, our dedicated and experienced management team remained laser-focused on executing our strategic plan, positioning us well to take advantage of future opportunities to drive significant value for our customers and shareholders. Speaking of opportunities, I'm tremendously excited about the investment opportunities ahead for us in this dynamic period for the utility industry. In my 20 plus years with the company, our economic development and sales growth pipeline is the most robust I have seen, which I'll touch on more in a moment. First, let me cover our earnings and operations results for the second quarter. Yesterday, we announced second quarter 2024 earnings of $0.97 per share compared to earnings of $0.90 per share in the second quarter of 2023. Key drivers of these strong results are highlighted on this page. And for the six months of the year, our results have been solid, driven by infrastructure investments made for the benefit of our customers, encouraging weather-normalized retail sales, and disciplined cost control. We remain on track to deliver earnings within our guidance range of $4.52 per share to $4.72 per share. Turning to Page 5, our strategic plan is designed to deliver on our steadfast commitment to providing safe and reliable energy in a sustainable manner. We do this by investing in rate-regulated infrastructure, enhancing regulatory frameworks, and advocating for responsible energy policies, while optimizing operating performance through ongoing continuous improvement in order to keep rates affordable. I'd like to express appreciation for my Ameren coworkers' unwavering commitment to our strategy. On Page 6, we highlight our key accomplishments in the second quarter as we execute our strategy to deliver on our 2024 objectives. The strategic infrastructure investments we have made in the first six months of the year are designed to maintain the safety and reliability of the energy grid, to modernize the grid, and to harden against more frequent severe weather events. Over Memorial Day weekend, severe thunderstorms swept through Missouri and Illinois, bringing strong winds, flooding, and golf ball-sized hail. As always, our teams quickly and safely assessed the damage, cleared trees, and worked long hours to make repairs to restore power as quickly as possible, allowing critical infrastructure to continue operations, businesses to remain open, and homes to stay cool and safe. But even better, during the first half of 2024, over 22,000 Missouri and 11,000 Illinois customer outages were prevented during storms due to rapid detection, rerouting, and restoration of power by automated switches across our system, and over 6.4 million minutes of customer outages across both states were avoided due to investments to modernize the grid. As we look ahead to future investment for the benefit of our customers, it's important to operate under constructive regulatory jurisdiction and legislative policies. This quarter, we've made significant regulatory advancements, which Michael and I will cover in more depth on the coming slides. At Ameren Missouri, our largest business segment, we continue to make regulatory progress with the Missouri Public Service Commission for new solar and natural gas generation, which supports our integrated resource plan. Our Cass County solar project was approved in June and is expected to be one of three solar projects placed in service this year, which collectively, along with Huck Finn and Boomtown, represent an investment of approximately $1 billion. The Commission also approved a constructive order for the securitization of costs associated with our Rush Island Energy Center in connection with its retirement in October of this year. And finally, regarding generation updates, in June, we filed the CCN with the Missouri PSC for our dispatchable Castle Bluff Energy Center. Overall, we continue to make significant progress on our smart energy plan in Missouri, a combination of distribution, transmission, and generation projects to bolster reliability and empower our customers. In late June, Ameren Missouri filed its electric rate review request with the commission, which is substantially driven by infrastructure improvements made under this plan. If approved, Ameren Missouri customer rates would still remain well below national and Midwest averages. Turning to transmission, the Midcontinent Independent System Operator, or MISO's long-range transmission plan continues to evolve. In April, MISO concluded the bid evaluation process for the Tranche 1 competitive projects in our service territory, ultimately awarding all three competitive projects to Ameren. They continue to develop the $23 billion to $27 billion Tranche 2.1 project portfolio, which promises meaningful brownfield and greenfield investment opportunities within our service territory. Finally, in Illinois, the Illinois Commerce Commission issued an order on the rehearing of Ameren Illinois' multi-year rate plan for 2024 through 2027. Importantly, the order supports our planned base level of grid reliability investment that is reflected in our 2024 earnings guidance. Further, the ICC order reflects 94% of the rate base in our ongoing multiyear rate plan proceeding. We look forward to an ICC decision on the multiyear grid investment and rate plans by the end of this year. In addition to these significant regulatory advancements, we have seen strong operational performance across the business with a focus on delivering safe, reliable, affordable energy service through enhanced automation, optimization, and standardization, which Michael will cover in more detail. Moving now to Page 7 for an update on our expanding customer growth opportunities. On the first quarter call, we touched on economic development opportunities in our service territory. Since then, collectively across Ameren Missouri and Illinois, we have seen a significant increase in the number of data center inquiries and formal engineering reviews underway, which combined would represent thousands of megawatts of additional demand. Our teams, along with a variety of state and local stakeholders, are working aggressively to attract these and manufacturing and other economic development opportunities to our service territories. Of course, Ameren has a strong track record of reliable infrastructure development, and we have the people, resources, expertise, and partnerships needed to go after these opportunities. Further, our Missouri and Illinois territories offer an attractive value proposition for commercial and industrial customers. This includes sites with transmission, fiber, and water access, coupled with competitive rates and tax incentives. In Missouri, we also have reliable generation with a growing portfolio of clean and dispatchable assets and the ability to expand in order to serve these economic development opportunities. So far this year, a construction agreement has been executed for a 250 megawatt data center, which would represent an approximate 40% and 5% annualized increase to Ameren Missouri's industrial megawatt hour sales and total megawatt hour sales respectively upon completion and full ramp-up. Our construction to extend transmission and distribution services to support this data center is expected to be completed in December of 2025, with the customer ramping up operations from 2026 through 2028. In addition, we've received expansion commitments or executed new contracts for over 85 megawatts of additional load for manufacturing, smaller data centers, and other industries across both states. We would expect these new and expanding customers to be fully ramped up by 2028 with sufficient generation to serve them, creating value for all customers over time. We're excited about these opportunities, which will bring jobs and additional tax base to benefit our state and local communities. Importantly, the new data center and other customer commitments were not reflected in the weather-normalized sales expectations included in our five-year earnings per share growth guidance issued in February. Of course, the ultimate net impact of any incremental load will be dependent upon a variety of factors, including customer ramp-up time, additional generation investment needs, timing of rate reviews, and tariff structures. To that end, we currently expect to update our Ameren Missouri Integrated Resource Plan or IRP by February 2025, following a careful evaluation of potential load growth and our planned generation portfolio. We will work with all stakeholders to bring the economic benefits of these customer expansion opportunities to all customers, our communities, and shareholders. Turning to Page 8. We continue to execute our Missouri IRP, which focuses on maintaining and building a diverse generation portfolio to ensure a reliable, low-cost, and cleaner mix of energy resources to serve our customer needs. We had two key developments this quarter. First, in June, the Missouri PSC approved the CCN for the 150 megawatt Cass County solar facility, which is expected to begin serving customers in the fourth quarter of this year. This facility will serve business customers who subscribe through our Renewable Energy Solutions program to receive all or part of their energy needs from renewables. The Missouri PSC approval followed a successful auction held in May, where customers across Missouri signed up to take part in the Renewable Energy Solutions program expansion. Demand remains strong for programs that bring businesses readymade solutions to help them reach their sustainability goals. Second, in June, we also filed a CCN with the Missouri PSC for our Castle Bluff Energy Center, an on-demand 800 megawatt natural gas simple cycle facility to serve as a reliable backup source of energy ready to operate on the most extreme winter nights and summer days. Moving now to Page 9 for an update on the MISO long-range transmission projects. MISO and its transmission owners continue to engage in economic analysis of the Tranche 2 proposed set of projects. In June, an initial set of Tranche 2 projects, now referred to as Tranche 2.1, were proposed with a cost estimate of $23 billion to $27 billion. The portfolio identifies a need for a mix of brownfield and greenfield transmission lines of varying voltage levels and new or improved substations in both our Missouri and Illinois service territories. Ultimately, we won 100% of the Tranche 1 projects in our service territories, reflecting our ability to deliver timely, cost-effective, high-value projects to our communities. We expect we’ll be able to compete for Tranche 2 greenfield projects in a similarly competitive manner to better serve our customers. MISO expects to approve the Tranche 2.1 projects by the end of the year. Once approved, MISO plans to propose a second set of Tranche 2 projects, or Tranche 2.2, in 2025 to address further transmission needs in the North and Midwest regions. Turning to Page 10, looking ahead over the next decade, we have a robust pipeline of investment opportunities of well over $55 billion that will deliver significant value to our stakeholders and create thousands of jobs for our local economies. In addition, we see several tailwinds forming across our business segments. Specifically, we are seeing significant sales growth potential, which I discussed a few moments ago, and this may require us to reassess our Ameren Missouri IRP and further expand our generation investment pipeline. We're seeing a growing focus amongst Missouri stakeholders on generation planning and reliability, and we see a strong need to embrace enhanced reliability-focused policies in legislative sessions to come. Further, MISO's analysis of transmission needs in the Midwest region will likely identify additional opportunities to improve the ability to move electricity across the region. Maintaining constructive energy policies that support robust investment in energy infrastructure and to maintain reliability while transitioning to a cleaner energy future in a responsible fashion will be critical to meeting our country's growing energy needs and delivering on our customers' expectations. Moving to Page 11, in February, we updated our five-year growth plan, which included our expectation of a 6% to 8% compound annual earnings growth rate from 2024 through 2028. This 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. Investment in Ameren presents an attractive opportunity for those seeking a high-quality utility growth story. Combined, our strong long-term 6% to 8% earnings growth plan and an attractive and growing dividend, which today yields 3.4%, result in a compelling total return story. We have a strong track record of execution, a strong balance sheet, and an experienced management team. I'm confident in our ability to execute our investment plans and strategies across all four of our business segments. Again, thank you all for joining us today, and I'll now turn the call over to Michael.

Thanks, Marty, and good morning, everyone. I'll begin on Page 13 of our presentation. Yesterday, we reported second quarter 2024 earnings of $0.97 per share compared to $0.90 per share for the year-ago quarter. We delivered strong earnings performance during the quarter, driven primarily by strategic infrastructure investments and disciplined cost management. While earnings saw a strong benefit from favorable weather, we also continue to see encouraging levels of customer growth and energy usage. Further, through disciplined cost controls, operations and maintenance expenses companywide were flat for the quarter when excluding the impacts from non-reoccurring items as part of the 2023 Ameren Missouri rate order. Additional factors that contribute to the overall $0.07 per share increase are highlighted on this page. Year-to-date results are outlined on Page 24 of today's presentation. Notably, year-to-date 2024, we've experienced strong weather-normalized industrial sales growth of 3% as compared to the prior year period. This has been driven primarily by significant growth from our existing large primary service customers in the digital and data analytics industry. We expect to see continued growth as we bring on new customers and support existing customers' expansions in the coming years. Further, we continue to see strong weather-normalized kilowatt hour sales growth across all rate classes in Missouri. Moving to Page 14, as we think about the remainder of the year, we remain confident in our 2024 earnings guidance range and continue to expect earnings to be in the range of $4.52 to $4.72 per share. The warmer spring and early summer temperatures experienced this quarter offset the mild first quarter, as we are flat year-to-date for weather. In addition, as we outlined in our first quarter call, we expect to see meaningful year-over-year O&M reductions in the second half of the year, reflecting several cost savings initiatives implemented in 2024, the benefits of which continue to build throughout the year. I encourage you to take these and other supplemental earnings drivers noted on the slide into consideration as you develop your expectations for quarterly earnings results for the remainder of the year. Moving to Page 15, Ameren Missouri Regulatory Matters. In June, the Missouri PSC approved the securitization of approximately $470 million of costs associated with the scheduled retirement of our Rush Island Energy Center on October 15. We expect the difference between our original ask of $519 million and the final order to be reflected in future rate proceedings. Turning to Page 16. In late June, Ameren Missouri filed for a $446 million electric revenue increase with the Missouri PSC. 90% of this request is driven by increased capital investment under Ameren Missouri Smart Energy Plan to recover investments in major upgrades to the electrical system and investments in generation. The request includes a 10.25% return on equity, a 52% equity ratio, and a December 31, 2024 estimated rate base of $14 billion. We expect a decision from the Missouri PSC by May 2025 with new rates effective by June of next year. Turning to Ameren Illinois on Page 17. Under Illinois formula rate making, which expired at the end of 2023, Ameren Illinois was required to file annual rate updates to systematically adjust cash flows over time for changes in cost of service and to true up any prior period over or under recovery of such costs. For the final electric distribution reconciliation of 2023's revenue requirement, in July, the ICC staff recommended a $157 million base rate increase compared to our updated request of $158 million. The full amount would be collected from customers in 2025, replacing the prior reconciliation adjustment of $110 million that is being collected during 2024. This will result in a net customer impact of $48 million or an approximately 1.5% increase in the total average residential customer bill. The ICC will review this matter in the months ahead with a decision expected by December of this year and new rates effective early next year. Turning to Page 18 for an update on the multiyear rate plan covering 2024 through 2027. We are pleased to receive a constructive decision from the ICC in the rehearing of our multiyear rate plan. Recall in January, the ICC upon approving our rehearing request had ordered that we identify a base level of investment needed to adequately operate the grid safely. In June, after extensive stakeholder engagement and additional analysis provided by our team, the ICC approved a $285 million cumulative revenue increase from 2023, representing approximately 94% of our rehearing request and a 1% average residential bill increase for 2024. Excluding OPEB, the order represents approximately 99% of our rehearing rate base request and also 96% of the rate base included in the revised multiyear rate plan, which will be reviewed by the commission later this year. Interim rates for this order were effective in late June and will remain in effect until superseded by a revised MYRP order. The approval was a positive first step in getting a base level grid investment approved. However, there is still much work to be done in the State of Illinois to achieve the objectives laid out in The Climate and Equitable Jobs Act passed in 2021. Approval of our revised multiyear grid plan and rate plan will allow us to appropriately invest more in the energy grid to preserve safety, reliability, and day-to-day operations of our system, and make progress towards an affordable, equitable clean energy transition. In July, the ICC staff recommended a cumulative revenue increase of $302 million versus our July 2024 updated request of $334 million, with the variance driven primarily by the renewal of OPEB and certain capital projects from the rate base. Annual revenues will be based on actual recoverable costs, year-end rate base, and a return on equity adjusted for any performance incentives or penalties provided they do not exceed 105% of the approved revenue requirement. Lastly, with the narrowing of remaining issues, cross-examination was waived for hearings earlier this week, and we expect an ICC decision by December with rates effective January 1, 2025. Moving to Page 19, we provide a financing update. We continue to feel very good about our financial position. Our Ameren parent credit ratings of Baa1 and BBB+ at Moody's and S&P, respectively, compare favorably to the peer average, providing us with financial flexibility. To maintain our credit ratings and a strong balance sheet while we fund a robust infrastructure plan, we expect to issue approximately $300 million of common equity in 2024. By the end of 2023, we had sold forward approximately $230 million of this $300 million through the 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 DRIP plus programs, our ATM equity program is expected to support our equity needs in 2024. Turning to Page 20. Ameren continuously strives to find ways to work more efficiently to reduce costs for our customers. At the start of the year, we instituted several cost savings initiatives, including a detailed review of all hiring with a focus on spans and layers, reducing some of our contractor and consultant workforce, and deferring or eliminating discretionary spending while we identified further opportunities for sustainable cost reductions. Since then, we have enhanced our continuous improvement and disciplined cost management efforts through numerous customer affordability initiatives that will provide greater collaboration and coordination across our business. Through company-wide automation, standardization, and optimization, we are streamlining processes, leveraging shared capabilities, and eliminating redundant work to provide sustainable cost savings. Our leadership team is committed to prudently managing costs on behalf of our customers while providing quality service and reliability. Turning to Page 21. We're off to a solid start in the first half of the year and expect to deliver strong earnings growth in 2024 as we continue to successfully execute our comprehensive business strategy. We continue to expect strong earnings per share growth driven by robust rate base growth and disciplined cost management. As Marty mentioned, we see several tailwinds forming in the months and years ahead. We have the right strategy, team, and opportunities to create value for our customers and our shareholders. We 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.

So just real quick on Rush Island kind of the bid-ask saw you guys got a third-party media a few days ago. Any sort of read through from that to timing or where the process could land within that $100 million range?

Yes. Thanks, Shar. We posted a slide in the appendix, Slide 27. It just provides a little bit of background in the case. But we were pleased that the judge ordered mediation, which hopefully will lead to some constructive settlement negotiations between the parties. We expect the mediation to take place this summer, and in the event that mediation isn't successful in reaching a settlement between the parties, we would expect that the judge would likely have evidentiary hearings in September, and we'd still get a resolution of the case this year. So I don't think any read-through on exactly where we'll end up between that bid-ask spread, but nonetheless, we think it's a positive step forward.

Okay. Perfect. And then just on the transmission side, and obviously, it was a little topical as part of the on Tranche 2.0, 2.1. Any color at this point on how to think about the competitive allocation within that? Is it line by line, greenfield versus brownfield? And just remind us on potential timing of spend associated with these, what are in-service dates.

Yes, Shar. All good questions. So when you look at Tranche 2.1 and you look at the map that we provided on Page 9, you see a breakdown between the 765 kV lines and the 345 kV lines, and you see some of those in Missouri and Illinois. We're pretty excited about the way this is shaping up overall. With respect to the red lines, we see those as being more likely brownfield; the green dotted lines are more likely greenfield. So you see a mix of those things there. At this point, no specific cost estimates for those lines that run in our service territory. The $23 billion to $27 billion numbers we give overall are MISO's estimates for the total portfolio, but I can't give you a breakdown right now on those that are in our footprint. Of course, if they are brownfield, we would expect them to be allocated to us. If they are greenfield, we would expect to compete for those. And we were very pleased with our ability to compete for the Tranche 1 projects. As noted in our prepared remarks, we won all three that were in our service territory. At the end of the day, we think it speaks to our ability to deliver these projects in a timely and cost-effective way. Again, we feel like we are good at constructing these and great at operating them. We've done a great job partnering with munis, co-ops, contractors, and others to ensure we can deliver. Now with respect to the timeline on the Tranche 1 projects, we expect the construction of those to extend from 2026 to 2030. I think we have about $1.6 billion or so in our five-year plan for those Tranche 1 projects. With respect to the Tranche 2.1 projects, that spend is probably outside of our five-year plan. However, there's really no reason that these have to happen sequentially, to the extent that any of these Tranche 2.1 projects can be started and overlap with some of the work on Tranche 1, no problem there. Again, excited about this Tranche 2.1, but also expect in Tranche 2.2 that we'll see even more projects in our Missouri and Illinois footprint. Overall, we are very pleased with the work MISO is doing here and the responsiveness to stakeholders in the process.

I wanted to ask about the data center construction slide. It appears that you're primarily focusing on the areas where there is third-party involvement, but it seems there are significant opportunities available. The Missouri system appears capable of supporting this with over 85 megawatts, if I’m not mistaken. What do you believe is the tipping point for accelerating procurement in the next Integrated Resource Plan? Additionally, how many more megawatts do you expect to have clear visibility on by the time you reach that critical point?

Yes. Nick, those are all good observations and takeaways from the information we provided on Slide 7. When you look at that graph on the right, we talk about the economic development pipeline which presents thousands of megawatts or gigawatts of opportunity, and that is indeed the case. We have several parties conducting engineering reviews and interconnection studies, which is a positive development. These are initial steps. However, as you mentioned, when we talk about construction agreements, it signifies that we have a formal agreement between ourselves and a data center, confirming transmission capacity, costs to extend service, timelines, and importantly, committing the customer to pay for that service extension with down payments for equipment. You're right; developments have started to materialize. At that point, we feel it's appropriate to discuss the timeline and how it may scale in size. We are quite optimistic about having a 250-megawatt data center expected to start using service in 2026 and ramping up through 2028. This presents a favorable outlook as we consider usage over that timeframe. Additionally, the 85 megawatts we referenced encompasses more than just data centers in terms of economic development. We are targeting manufacturing and other sectors as well. This 85 megawatts includes a combination of manufacturing and smaller data centers. We are very enthusiastic about this. There's a clear interest concentration in Missouri. If this load continues to grow, we may need to provide an update to our integrated resource plan. We anticipate that over the next six months, we will see solidification of these other economic development opportunities. As we evaluate that load and its implications for our sales, we will consider what it means for our generation portfolio. We expect that we would need to update our integrated resource plan, currently aiming for February of next year.

Nick, this is Michael here. I might just add that it’s a great update from Marty. From an overall macro perspective, the backdrop in the St. Louis region is positive, even putting aside this data center opportunity. We've noted this in the slide: year-to-date sales residential up 2.5%, commercial 1.6%, industrial 3.1%. So a little over 2% year-to-date, which is a marked change from where we've been in the past. There are really positive things happening, about 25,000 jobs created in the past year in the St. Louis region. It's one of the hotter job markets here, with unemployment rates running below the national average. All of those things bode well with respect to all the things that Marty talked about as well.

And I guess just to count a few things that have changed in the fourth quarter when you kind of set this guidance of the 6% to 8%. The IRP is coming. You have this Tranche 2 visibility to MISO. I understand that's a little bit more longer dated. Obviously, we have more clarity on Illinois with the rehearing process. But your stock is also up year-to-date, and that should also help your kind of financing accretion, if you're still doing that $600 million a year through the plan? And in the fourth quarter, you kind of talked about tracking towards the 6.2%. You said 6.2% when discussing the 6% to 8%. Just how do you feel about your position within the 6% to 8% now? Has that improved a bit, with some of these tailwinds? How should we think about that?

Yes. Yes, Nick. I'd tell you that was a great question/statement. I think you got it right. If you look back at our track record over the past 10-plus years, we've been growing EPS at north of 7%. Our goal is to deliver at or above the midpoint of our earnings-per-share growth range. As I sit here today versus where we were six months ago, I agree with you that there are a number of tailwinds forming. Inflation and interest rates have been moderating. The stock price has been improving. You're right on all those things. Our demand outlook has been improving with data centers and other factors. Michael just talked about some of the job growth we're witnessing in the Greater St. Louis region. We're really excited about these transmission investment prospects we have with Tranche 1, Tranche 2.1, and Tranche 2.2; all very exciting. We still have tremendous investment needed for grid modernization and the clean energy transition, and we've got a robust balance sheet to achieve it. We're very excited about those prospects, and again when we look back at what our team accomplished in the second quarter, I'm very proud overall. We continue to make great investments for the benefit of our customers. Page 6 outlines half a dozen initiatives we completed during the second quarter that position us for success in the years ahead. This was all accomplished by a team that is truly focused on customer affordability. We implemented numerous cost-savings initiatives this year, and the team overcame that challenge to deliver a strong quarter from both an operational and earnings standpoint. Again, I think you're right; we're set up very well for the future given some of the tailwinds we have.

I wanted to start by asking about the Chevron doctrine. With the recent changes, does that influence your thinking moving forward? Are there any insights you could share on that?

Yes, Nick, I don't know that it really changes our thought process going forward. Obviously, Chevron is going to probably have far-reaching implications for federal agencies and core proceedings going forward. Of course, it doesn't affect any prior cases. I think when the Supreme Court ruled on Chevron, they basically said, 'Hey, this doesn't call into question any prior cases.' My sense is it will impact ongoing rulemakings and court reviews as related to things coming out of FERC or EPA, etc. So again, I think there will be far-reaching impacts, but I'll leave it to the lawyers that are working through those matters to assess how it may impact things.

Got it. This is Jeremy. Nick is a friend, so we're all good here. To follow up, it seems like there is a vast opportunity set with the multiple gigs you're discussing and your thoughts on the conversion rate there. It appears to still be a sizable opportunity. However, are there discussions about double counting? I'm curious about how you view that entire process.

Yes, Jeremy. I don't think I called you Nick, but if I did, I apologize. In any event, Jeremy, it's a good question. I think, again, when I responded to Nick earlier, I think that we're going to be conservative in how we bring these things into our guidance. Obviously, when we gave our guidance at the beginning of the year, none of this was in our load growth projections. We're going to be thoughtful about it. As I said earlier, we thought it would be good to share with you all the economic development pipeline we have, and it's robust. But again, a large amount of this is still in the process of engineering reviews and interconnection studies, so we're truly excited. Our team, along with state and local stakeholders, is working hard to bring these initiatives to fruition. We believe that both of our states, Missouri and Illinois, should be very competitive with respect to these opportunities. Again, access to transmission, fiber, workforce, water, all those factors both of our states have good sales and use tax incentives. We're two of just 26 states that have these, and our incentives are very competitive with those that do. We feel we are well positioned to convert these and bring them to fruition. But to your point, Jeremy, it's hard to know with some of these groups; they’re evaluating our sites as well as sites in other states. We're going to be conservative about how we bring those into our guidance. Just to reiterate, we felt comfortable talking about this 250-megawatt data center because we have a construction agreement. That puts us in a firmer position. As we update our sales guidance again in February, we'll incorporate those opportunities we perceive as firmer like this one with a construction agreement.

Got it. That's helpful there. Maybe just picking up real quick with stakeholders in the state, our conversations with stakeholders in Missouri seem to indicate a view of constructive commentary, I guess, coming out of the commission there, and we've seen some kind of changes over time with the composition. I'm just wondering, any updated thoughts you could share on Missouri? Any changes you see there?

Well, I would just say that I'd refer you back just to even this past quarter, Jeremy, and some of the things that we accomplished from a regulatory standpoint, which is back on Page 6. The approval of the Cass County project. We filed the CCN for the 800-megawatt Castle Bluff natural gas energy center, and some of the commentary coming out of the commission suggests a desire for more dispatchable resources and understanding that we need that for reliability. So we're excited to make that filing. We got the approval of the securitization. What we're seeing is a continuation of constructive regulatory results in Missouri; the commission is going to have a forum to discuss reliability in the state looking forward, and we think that's a constructive thing. We're seeing exciting economic development opportunities, and we need to ensure Missouri has the resources to serve our existing customers and those additional economic development opportunities. So we think, again, that's a good constructive forum setting up for the future.

Maybe just to start to go quickly back to the IRP update that you guys expect to file early next year. Recognize you've got the low growth element that could have an impact there. But could you also talk a little bit about the expectations around resource mix as you sort of have some more time to work through the EPA regulations?

Yes. Carly, it's a good question. It's something we file in February; there is a lot of work to be done, as I mentioned. We're really assessing the load growth, getting a handle on which of these will come to fruition, and how we want to serve it. I think when you look at the IRP that we filed back in September 2023, it was a good mix of resources, maintaining our existing dispatchable assets while thinking about bringing in a mix of renewables, dispatchable resources like simple cycle gas, combined cycle gas, and battery storage technologies. My sense is that if we see load growth that we're going to build into our plans going forward, it probably means in the short term an acceleration of some of the renewables, batteries, and very possibly additional simple cycle natural gas. When you look longer term, we will have to give some thought as we file that and, to your point about how we think about the EPA's proposed greenhouse gas rules. That may be impacted by whether the Supreme Court issues a stay of those later this year. I would just say we have to think about the implications of those rules for carbon capture at our planned combined cycle facility, as well as co-firing with gas at our Labadie Energy Center. Those are some of the things we'll be reflecting on. Given the uncertainty of whether that greenhouse gas rule will ultimately come into effect, we'll have to think about how we do or don’t reflect that in our plans going forward. So, there's a lot to ponder, and I appreciate you teeing it up. I don't have any firm answers for you today, but those are some of the considerations.

Yes, Carly, it's Michael. The only thing I might add to that is with respect to some of these environmental rules, there are probably some best moves that we'll continue to look at. Marty mentioned this co-firing issue, trying to ensure we have access to gas at some of these facilities that we don't have today. We are taking some prudent steps there that we think provide us with additional flexibility, not knowing exactly where these rules will wind up.

Got it. That context is super helpful, and we'll stay tuned there. The follow-up is just on MISO Tranche 2. I know you guys addressed kind of Tranche 2.1 a bit earlier. But could you talk a little bit about 2.2? How did the split of the tranches come about? Ultimately, do you have any views on what that could look like from a sizing perspective relative to Tranche 2.1 and also Tranche 1?

Yes, Carly. This is Marty again. I'll start. As MISO looked at these projects and heard from stakeholders, there was some logical order in terms of how you might want to build out some of the infrastructure that we believe is ultimately required in the Midwest region given all of the region's goals regarding the clean energy transition and what MISO sees in terms of potential relocation of generation facilities and loads. So I think it’s more or less what's a logical order to build some of these things out and then to step back and use the expectation of these investments to guide the consideration and planning for the next set of projects. That said, for example, we have this 345 line that's planned in Missouri. It may or may not preclude the need for a 765 line, which was in the last presentation. We are also not seeing a lot of investment on the current map in the southern part of Illinois and extending into Indiana, so we may see more investment there. Again, it’s premature. MISO is still working on the potential for 2.2, and there's a lot more work to be done, which is why they don't expect to get those approved until sometime in 2025. So it’s really premature to speculate on what those might be and what their size could be.

Just to follow up on the weather and the sales growth and what have you. Correct me if I'm wrong, but absent you would be up 2% and with EMEA, it's flat. Is that pretty much right? Or if you could just elaborate a little bit on that. I apologize for not being completely clear.

Paul, this is Michael. From a year-to-date standpoint, again, residential is up 2.5%, commercial 1.6%, industrial 3.1%. So about 2.2% overall. With EMEA impact, it is a little bit less than that. I don't have it right here in front of me. Overall, it's just been much stronger than it has historically been.

I apologize. I was looking at Slide 24, and it seems to indicate that compared to normal, it was zero in terms of the EPS impact. If I'm interpreting this correctly, it sounds like you are making significant efforts to maintain efficiency. Am I correct in that understanding?

Well, I mean, there certainly is some impact from an energy efficiency standpoint. Although I think it's less than that. The one thing that you're not seeing in here a little bit is a bit of price variance. So as you're switching kind of between summer and winter rates, you get some different price variances in the block sales. When you strip that out, that’s masking a little bit of the growth, and that should, like it typically does, flip around as you move through time. But energy efficiency does have an impact.

Yes. I think, Paul, if you're looking at that zero versus normal, what that's meant to say is that the weather to date has been normal. In the first quarter, weather was weak; second quarter weather was strong. What we're saying here is year-to-date there's been no weather impact versus normal conditions.

I apologize for the confusion. Regarding your low forecast and the upcoming refresh of the Integrated Resource Plan, could you provide a bit of insight into the positive developments you have in place? Specifically, what kind of range might we expect for the potential increase in the plan when it is updated?

Yes, Paul, Michael here again. It's a bit premature, I think, to get into that conversation. Again, as we came out in February, we've been seeing historically flat to up, maybe 0.5% in terms of growth. I think there's been some positive updates as we've moved through the year. I just went through the year-to-date statistic. We'll absolutely do it. I think we just want to ensure we feel good about the confidence level around, as Marty mentioned, around a number of these data centers, etc. As we progress, we're going through our typical update and planning processes right now, and we'll be in a better position to refresh that IRP and sales forecast as we get closer, probably into the fall.

Yes. And I think, Paul, following up on Michael's comment, we have the ability to serve that data center today with our existing mix of resources and the planned additions that we've got. As we set up that IRP update, it’s really about thinking about those thousands of megawatts that are in the queue today, doing their engineering studies, interconnection studies, and working with them while considering what changes to the IRP might need to be made in light of those.

Okay. And then just should we think of this as sort of a consumer that the existing resources can serve all this? Is this basically going to be something that would help customers or even near-term at least in terms of just more cost being spread over more megawatt hours? Or is there an economic development issue that's happening here? What I'm trying to say is, how should we think about this impacting rates vis-a-vis earnings, if you follow what I'm saying, at least in the near-term?

Yes. The customers that are signing on today, the 250 megawatts as well as the 85-plus megawatts are really utilizing existing tariffs that we have in place today that have been vetted by the commission. The goal of any of these tariffs is to ensure that costs are allocated appropriately. As I sit here today, I think we're fine. As we move through time, if we have thousands of megawatts that come to fruition and start to think about the different resources we may need to put in place to serve them, we're going to have to be thoughtful about what the appropriate tariffs are for those customers to ensure they pay a fair price, and that value accrues to all our customers and communities.

I have a follow-up question that might be a bit challenging to answer. Reflecting back 10 to 15 years ago, when we saw significant increases in capacity prices, utilities in that region responded with higher capital expenditures, and regulators supported those moves. However, looking ahead to last December, it seemed like Illinois began to slow down on capital spending. Although you may not be directly impacted by PJM capacity prices, do you think the Illinois regulators might reconsider their stance and recognize the importance of additional infrastructure to provide more electricity to customers?

Yes. Look, I think in both states, I mentioned earlier about the commission having a forum on reliability and resource adequacy. The same concerns exist in Illinois. We'll see how policies shift and change over time. But I think at the end of the day, all stakeholders in both states, and certainly us as a utility and other service providers are concerned and mindful of resource adequacy, reliability, affordability, and a clean energy transition. I think your intuition is right; as cost pressures grow, due to factors like capacity prices, or the need to support economic development and growth logically, you have to start considering policies that support those things and resource adequacy. Your intuition is correct.

So one thing came to mind while listening to your responses. Have you provided a simple rule of thumb for how EPS is affected by every 1% increase in industrial sales?

Yes. We have historically, David. For every 1% on the industrial side, it's about $0.05. Here's a good way to think about it. Now that change will fluctuate over time as you move through and you need to change the generation mix, etc. But I think it’s a decent rule of thumb today.

And just on the discussions, and I know there have been plenty of questions here on attracting large load and the efforts you're making. But what have you told rate stakeholders and leaders about what you need from a ratemaking standpoint? Could we see efforts to add trackers or riders to expedite amortization of the large load, or maybe an expansion of piece? What are you telling them?

Yes. I think, David, all things are on the table for consideration. As I mentioned a few moments ago, with respect to the data center that we show on Page 7, this 250-megawatt data center and the other 85 megawatts of load, they're able to use our current industrial tariffs, and we're able to serve them with our current generation and planned generation. No need for any special tariff there. Over time, to the extent that these other opportunities come to fruition, we may need to think about special tariffs. One thing to point to is we just had that Cass County solar project approved. There, we did put a special sort of tariff arrangement in place to ensure that there was an appropriate apportionment of cost among our customer base as well as those industrial customers that are going to take power from Cass County. We do have some experience working with the commission to put special tariffs in place. We'll be giving thought to that as we move forward with additional data centers that we may be able to serve. To your point on PSA, certainly, one of the things we pursued legislatively last spring had very good support; it was the extension of the PSA to dispatchable generation such as the simple cycle assets that we're planning and the combined cycle asset that we're planning. We had strong support for that but the legislative session ended without it crossing the finish line. We expect strong support as we enter next year.

I want to follow up on the process regarding the shorter-term procurement potential. You mentioned earlier that you have adequate resources to manage the initial 250. However, I'm interested in your overall perspective on the process. Typically, these Integrated Resource Plans are conducted at consistent intervals, accompanied by a Power Supply Coordination process. You also mentioned the potential for shorter-term needs alongside medium-term needs. How do you view the possibility of speeding up that process? We've observed similar scenarios in adjacent jurisdictions. Additionally, would you anticipate that some of the tariff dynamics will play out in the upcoming rate case beyond the current situation?

Yes. All good questions, Julien. First of all, as I mentioned with respect to these opportunities, we're certainly not waiting. Our team, along with other stakeholders in both states, is actively interacting with these parties performing engineering reviews, interconnection studies, and doing everything we can to support them in locating these facilities either in Missouri or Illinois as suitable. When you look at some opportunities, think about this 250-megawatt one specifically. They're going to start service in 2026, ramping up usage through 2028. We're hearing from any of these facilities that there’s a desire to ramp up over time. The idea is that would dovetail with an update to the IRP, where we would potentially accelerate some planned additions and perhaps add new resources for service to fulfill this load as it grows. Keep in mind there are some limitations. The 800-megawatt simple cycle we are putting into our plans today, Castle Bluff, has a construction timeline of about four years for turbines, transformers, construction, etc. We believe we can work with these data center opportunities, get the IRP updated and filed, and hopefully align these elements together at the right pace and speed. To address tariff changes, we think those can happen both inside the context of a rate review or outside of a rate review. We believe we have flexibility there.

Okay. Even outside of the rate review. Nice. It sounds like you've got something in mind already. All right. And then separately quickly, just coal ash new regulations here in the last few months. I'm curious about AROs accumulating and just thoughts about some of the twists here.

Hey, Julien, Michael here. It's really not a significant issue for us. I mean, we did go through a couple of AROs, but a really immaterial amount. If you think about our exposure from a coal ash standpoint, we got in front of this issue probably 7 or 8 years ago. All of our ponds are closed or in the process of closure. There is just not a lot of additional exposure, just a little bit around the edges.

Yes. Thanks, everybody, for joining us today. Some great questions. I appreciate the dialogue. Overall, we are really pleased to share our updates with you, and we remain absolutely focused on strong execution for the remainder of this year. We look forward to seeing many of you in the coming months. So with that, thanks. Have a great day and a great weekend.