Utility Companies Report Mixed Q2 2024 Results Amid Challenging Economic Environment

WEC Energy Group, Inc. (WEC) Q2 2024 Earnings Call Transcript

WEC Energy Group, Inc. (NYSE:WEC) Q2 2024 Earnings Conference Call July 31, 2024 2:00 PM ET Company Participants Scott Lauber - President and CEO Xia Liu - CFO Conference Call Participants Shar Pourreza - Guggenheim Partners Julien Dumoulin-Smith - Jefferies Michael Sullivan - Wolfe Research Durgesh Chopra - Evercore ISI Carly Davenport - Goldman Sachs Andrew Weisel - Scotiabank Neil Kalton - Wells Fargo Securities Jeremy Tonet - JPMorgan Paul Patterson - Glenrock Associates Operator Good afternoon and welcome to the WEC Energy Group's Conference Call for Second Quarter 2024 Results. This call is being recorded for rebroadcast and all participants are in a listen-only mode at this time. After the presentation, the conference will be opened to analysts and questions-and-answers. In conjunction with this call, a package of detailed financial information is posted on wecenergygroup.com. A replay will be available approximately two hours after the conclusion of this call. Before the conference call begins, please note that all statements in the presentation, other than historical facts are forward-looking statements that involve risks and uncertainties that are subject to change at any time. Such statements are based on management's expectations at the time they are made. In addition to the assumptions and other factors referred to in connection with the statements, factors described in WEC Energy Group's latest Form 10-K and subsequent reports filed with the Securities and Exchange Commission could cause actual results to differ materially from those contemplated. During the discussions, referenced earnings per share will be based on diluted earnings per share unless otherwise noted. And it's now my pleasure to introduce Scott Lauber, President and Chief Executive Officer of WEC Energy Group. Scott Lauber Good afternoon, everyone, and thank you for joining us today as we review our results for the second quarter of 2024. Here with me today are Xia Liu, our Chief Financial Officer; and Beth Straka, Senior Vice President of Corporate Communications and Investor Relations. As you saw from our news release this morning, we reported second quarter 2024 earnings of $0.67 per share. We're firmly on track to meet the full-year 2024 guidance of $4.80 to $4.90 a share. This, of course, assumes normal weather for the balance of the year. We continue to see strong foundational growth in our regional economy. The unemployment rate in Wisconsin stands at 2.9%, continuing a long-running trend below the national average. The pipeline of economic activity is particularly strong in what we call the I-94 corridor between Milwaukee and Chicago. For example, just last month, WestRock broke ground on a new facility at the former site of our retired power plants. WestRock is a leading company in paper and packaging solutions with 50,000 employees and 300 plants worldwide. The company called the cutting-edge facility a super plant, stating it will be one of their largest and most advanced plants. And Microsoft is making good progress on the construction of a large data center complex in Southeast Wisconsin. In May, Microsoft announced a broad investment package to strengthen our region as a hub for AI economic activity, innovation and job creation. These investments include a planned $3.3 billion to be spent in cloud computing and AI infrastructure between now and the end of 2026. Microsoft has stated that it expects to bring 2,300 construction jobs to the area by 2025 and 2,000 permanent jobs over time. These developments highlights the strength and the potential of our local economy and underscores the need for the investments in our capital plan. During the second quarter, we continued to move forward on major projects in our capital plan. It's the largest five-year investment plan in our history totaling $23.7 billion for efficiency, sustainability and growth. As we've discussed, the plan is based on projects that are low-risk and highly executable. At the end of May, we closed on our second option at West Riverside Energy Center for $100 million. This adds a 100 megawatts of efficient combined-cycle natural gas generation to our portfolio. You'll recall that last year, we discussed several filings or last quarter we discussed several filings for major projects to support economic growth and reliability in Wisconsin. This includes approximately 1,200 megawatts of efficient natural gas generation at our Paris and Oak Creek sites as well as 2 billion cubic foot liquefied natural gas storage facility and a 33 mile gas lateral to serve the Oak Creek site. In total, these projects combined represent $2.1 billion of investment. Our proposals were submitted to the Wisconsin Commission in April and we expect a decision in approximately a year. Also under review, we filed an application in February to purchase a 90% ownership interest in High Noon Solar Energy Center in Southern Wisconsin. With an expected investment of approximately $580 million, the facility is expected to provide 300 megawatts of solar generation. We have asked the commission to make a decision before the end-of-the year. As a reminder, we expect these investments to earn AFUDC during the construction period after commission approval. And in our WEC Infrastructure segment, the Delilah I solar project is now expected to go into service at the end-of-the year, delayed from June due to a weather event. We plan to invest approximately $460 million for a 90% ownership interest in this project in Northeast Texas. And we still expect our Maple Flats solar project to be in service by the end-of-the year. As you recall, we're investing an additional $560 million this year in our Infrastructure segment. We reallocated away from our operations in Illinois a total of $800 million in our five-year capital plan. Overall, our plan fully supports our long-term earnings growth rate, which we project to be in the 6.5% to 7% range on a compound average annual basis. We're also on schedule with the development of our next five-year plan. And as usual, we expect to share the details with you in the fall. Now I have a few updates on the regulatory front. In Wisconsin, we filed new rate reviews for test year 2025 and 2026 on April 12th. Our request focused on addressing three major areas of need. First, improving reliability and reducing outages from increased storm activity. Second, supporting Wisconsin's economic growth and job creation through investments in new-generation and distribution projects. And lastly, continue the transition from coal generation to renewables and natural gas. Commission staff and intervenor testimony is scheduled for August 21st, we expect a decision by the end-of-the year with new rates effective January 1st, 2025. We have smaller rate reviews and progress at Michigan Gas Utilities and Upper Michigan Energy Resources. We also expect decisions on these reviews by the end of the year. And in Illinois, we've been engaged in three dockets. The Illinois Commerce Commission issued its decision on the first of these, a limited rehearing on the commission's rate order for Peoples Gas at the end of May. The commission had agreed to reconsider our request to restore $145 million for safety modernization program in 2024. This mostly related to emergency work, unfinished projects and work driven by public entities like the City of Chicago. The commission granted $28.5 billion concentrating on what they deemed emergency work. We have appealed this decision to the Illinois Appellate Court along with other items in the rate order, including the commission's previous disallowance of investments in new service centers. We are also actively involved in two remaining dockets. One is the review of the safety monetization program. Staff and intervener rebuttal testimony are expected by August 21st with a commission decision expected in the first quarter of 2025. The other docket is the evaluation of the future of natural gas in Illinois, which is expected to conclude in about a year. Of course, we'll keep you updated on any further developments. Across our business, we continue to make good progress towards our goals of reducing greenhouse gas emissions. In May, we retired units five and six at our Oak Creek power plant. Together, those made up over 500 megawatts of coal-fired generation. Including these units since 2018, we've retired nearly 2,500 megawatts of older fossil fuel generation. Finally, a quick reminder about the dividend. We continue to target a payout ratio of 65% to 70% of earnings. We're tracking in that range now and expect the dividend growth will continue to be in line with the growth of our earnings per share. Now, I'll turn it to Xia to provide you more details on our financial results and our guidance for the third quarter. Xia Liu Thank you, Scott. We earned $0.67 a share for the second quarter. While this was a decrease of $0.25 quarter-over-quarter, we exceeded our Q4 guidance -- Q2 guidance range of $0.60 to $0.64 per share, driven by favorable O&M and financing compared to guidance. As Scott indicated, we're on-track to meet our 2024 earnings guidance. As I reminded you on the last couple of calls, with the redesign changes at Peoples Gas, base revenues are now more concentrated in the first and fourth quarters when natural gas usage is the highest. This earnings shift has impacted our second quarter and will impact our Q3 guidance, which I will discuss in a few minutes. Now, let's look at our quarter-over-quarter variances. Our earnings package includes a comparison of second quarter results on Page 15. I'll walk through the significant drivers. Starting with our utility operations, earnings were $0.19 lower compared to the second quarter of 2023 as a result of higher O&M, fuel, depreciation and amortization, interest and other expenses. A couple of drivers for the day-to-day O&M variance are worth noting. One, we experienced higher storm costs in the current quarter compared to Q2 last year. And two, we benefited in Q2 last year from a land sale at a retired plant site in Wisconsin. Looking ahead, I now expect overall day-to-day O&M in 2024 to be 2% to 3% higher compared to 2023. This is a 4% improvement compared to our initial expectation due to our continued O&M savings initiatives that we expect to realize late this year. The impact of weather was flat for the quarter. Compared to normal conditions, we estimate that weather had a $0.02 negative impact for the second quarter in both 2023 and 2024. Our weather normal electric sales in Wisconsin are relatively flat quarter-over-quarter and are overall in line with our forecast. Looking at ATC, continued capital investment contributed an incremental penny to Q2 earnings compared to 2023. And in our Energy Infrastructure segment, earnings improved $0.02 in the second quarter of '24 compared to the second quarter of '23, driven partially by higher production tax credit at WEC Infrastructure. Finally, you'll see that earnings at our Corporate and Other segment decreased $0.09 as a result of the impact of tax timing and higher interest expense. Now turning to guidance, for the third quarter, we are expecting a range of $0.68 to $0.70 per share. This accounts for July weather and assumes normal weather for the rest of the quarter. As I mentioned earlier, it also accounts for the shift in Illinois revenue recognition pattern. Our third quarter 2023 earnings were $1 a share. Once again, we are reaffirming our 2024 earnings guidance of $4.80 to $4.90 per share, assuming normal weather for the rest of the year. Before I turn back to Scott, let me quickly remind you that we continue to utilize dividend reinvestment and employee benefit plans to issue common equity. Also, as we said before, we plan to set up an ATM program. Overall, we still project that our common equity issuance will be up to $200 million for 2024. Post 2024, our equity issuances will be tied to our capital spending ratably with approximately $500 million expected per year in the current plan. We look forward to updating you in the fall as we refresh our capital and financing plans. With that, I'll turn it back to Scott. Scott Lauber Thank you, Xia. Overall, we're on track and focused on providing value for our customers and our stockholders. Operator, we're ready now for the question-and-answer portion of the call. Question-and-Answer Session Operator [Operator Instructions] Our first question comes from Shar Pourreza with Guggenheim Partners. Your line is open. Shar Pourreza Hi guys, good afternoon. Scott Lauber Hi, good afternoon, Shar. Shar Pourreza Hi, Scott. Just -- starting off just on sort of the perennial Microsoft opportunity that always seems to be asked. It's obviously becoming even more kind of topical now. Just remind us on what portion of Microsoft's land acquisition and build is kind of layered in your current plan? And the reason why I ask is that it's obviously now kind of public that they bought a bit more land. And I guess, when do you see this hit your plan more materially? Thanks. Scott Lauber Thank you, Shar. So just as everyone -- update everyone, they announced spending $3.3 billion through 2024 through 2026, which is on that first about 315 acres that they purchased. And then last fall, they purchased another 1,030 acres. And, of course, we pulled our capital plans together before that 1,000 acres were purchased. And then just this morning, there's been a couple announcements in the paper where they purchased another 173 acres in Southeastern Wisconsin. So we are currently in the process of working with Microsoft and developing our plans for our next five-year plan that we'll roll out this fall in the development. But currently, we really only have the energy and the capacity needs for that first 315 acres. Shar Pourreza Got it. Okay, that's perfect. So more to come there. And then just lastly on the Delilah I solar project delay, it's roughly six months. I guess, can you just -- maybe a question for Xia is how to think about the offsets around the potential headwind there versus your kind of prior assumption? Thanks. Xia Liu Yes. We took that into consideration as we reaffirmed the annual guidance of $4.80 to $4.90. So as I mentioned, we continue to focus on O&M management and financing costs and tax and others. So we're confident that we can offset the downside from the delay. Shar Pourreza Okay. That's perfect. Thanks, guys. Appreciate it. And hopefully Gale is somewhere tropical listening to this earnings call. Thanks. Appreciate it. Scott Lauber He probably is. Operator Our next question comes from the line of Julien Dumoulin-Smith with Jefferies. Your line is open. Julien Dumoulin-Smith Hi, good afternoon, team. Can you guys hear me okay? Scott Lauber Yes, we can hear you fine. Welcome back, Julien. Julien Dumoulin-Smith Awesome. Thank you. I appreciate the time, guys. It's a pleasure to chat here. So perhaps just to kick things off here, look, nicely done all-around. In fact, I wanted to just focus on the infrastructure segment. Obviously, you guys are planning well against those targets. I'm curious as you think about the totality of the data center opportunities, what does that mean as you think about the opportunities that you're seeing on that side of the business? And how do you think about the scope of that business in turn? You guys are obviously focused on contracted opportunities. By contrast, a lot of these potential customers would be in a similar manner focused on these kinds of counterparties. Curious as you think about that opportunity set on that front first. Scott Lauber Sure. And we've been working with Microsoft on the needs for the area and Wisconsin has got a lot of development opportunities and we want to make sure we hit the capacity requirements we need for the area to support the growth, not just Microsoft, but all the other growth that we're seeing in the region. So that's why we've added the -- and you'll see more filings shortly on renewable projects in the next month or so that we're proposing to help beat the capacity and the energy needs in the region. So we think there's a lot of opportunity not only from generation of renewables, some capacity needs, some distribution needs also, but also American Transmission Company and investment in the transmission in the region. So we're factoring all that in as we pull together our five-year plan here. Xia Liu And Julien, all those filings will be in the regulated area, as you know, in Wisconsin. Julien Dumoulin-Smith Yes, absolutely. Indeed. I know you're pursuing this on multiple fronts. Absolutely. And then team, just maybe to tackle on the regulatory front, a couple of questions here. How do you think about this -- the PSC's denial in the AFUDC? Is there anything to read into that here on the pre-construction costs? And just -- I know it's a little bit nit-picky, but I'm just curious if there's anything to tease out of that in terms of direction, strategically or financial? Scott Lauber No, I don't think there's anything to read into that. We, of course, thought if we get approval on that, we'll wait and see what the final written order is. But when you look at the value we're providing our customers getting these orders in early, both from a cost-savings standpoint and a time of delivery standpoint, there's really a lot of value for our customers. So we're going to most likely ask for reconsideration and refile that information with the additional information they're looking for. So stay tuned on that, but we think there's a lot of value. And I know the cost of the projects as the longer you wait would continue to go up as everyone across the country is looking at adding generation. Julien Dumoulin-Smith Yes, that seems pretty transparent as you say. And lastly, I'll just offer this. I traded in the dog, the equity, traded him in and I got a little boy now. So I appreciate you guys looking for it all along. Scott Lauber Congratulations. Excellent to hear. Julien Dumoulin-Smith Thank you. Absolutely. All right, guys. I'll see you soon, alright? Appreciate it. Scott Lauber It sounds good. Operator Our next question comes from the line of Michael Sullivan with Wolfe Research. Your line is open. Michael Sullivan Hi, good afternoon. Scott Lauber Good afternoon, Michael. Michael Sullivan Hi, Scott. Just as we look forward to your kind of usual plan refresh with Q3 and CapEx has usually been biased higher, how should we think about incremental equity needs associated with that? Should it just be any incremental CapEx is financed consistent with your utility capital structures or any different way to think about it? Scott Lauber No, I think you got it right in line. I mean, of course, we'll put everything together and look at it, refresh it again, but similar to what Xia has been talking about, we'll just look at the equity needs in-line with the capital spend and be very excited about the long-term growth that we have available on the capital and the insights we have looking-forward on additional capital. Michael Sullivan Okay. That makes sense. And then shifting over to Illinois, I was just maybe hoping you could frame some bookends for potential outcomes of the still pending docket, namely the pipe program review. What's the range of outcomes there? And then also really, is there anything -- any loose end still tied to like the QIP Rider reconciliations from prior years that could move numbers around at all? Scott Lauber Sure. So let's look at both of them. So the QIP Rider is from other years. Right now, 2016 Rider has been queued up I think for a decision hopefully I would expect by the end-of-the year. Decision will be made in that. As you know, it's 2016 Rider, so it's been a while. And then, of course, we have those other years under the QIP still to look at. So remember the requirements there is prudency and we think we've been very prudent specifically after the Integrys acquisition where we really took a look at the program and factored in a lot of information that we received from the audits of the Liberty Audit and staff recommendations from that audit. So those are still more to come on there. And then under the current S&P, remember, the S&P in our last rate case, no one requested a pause in the program at all during the rate case. And now in looking at the testimony for the first set of testimony that came through, there is no one also recommending a pause in the case. The range that our people are talking about that was in the testimony is from including emergency work to working with the City of Chicago and emergency work. There, the City of Chicago, I think he said he should lift the pause for at least two years with a cap of about $245 million all the way to the other extreme where I think staff recommending that you accelerate the program and actually get it done faster by 2030. So there's quite a range in the middle there. But once again, none of the interveners in the initial testimony, they all said they should lift the pause and get some work done specifically related to the emergency work and working with the City of Chicago as they do their capital work. Michael Sullivan Okay. Yes, just on that, I mean, I think as we've seen with some of the recent orders there, the ICC has come out worse than every single other intervener. So how do we just think about that risk in these dockets that you could get more of the same when it actually comes down to the final order? Scott Lauber Yes. And we're going to have to wait-and-see and see what they say. I think when you look at it from every intervener group though, they are saying we need to work with the City of Chicago, including the City of Chicago to help them with their capital programs and everyone even there on the rehearing talked about the emergency work. So on that low end, you're talking between $60 million and $100 million a year. So I don't think anyone is disputing that. And I understand what the commission is, but they're taking some time. And I think when you look at that last S&P case or the rehearing we asked for, they are concentrating on purely emergency and wanted to wait for this order to look at the entire program. So I wish I knew the answer, but that's why we're going to the case. Michael Sullivan Okay. No, that is super helpful context. Thank you. Scott Lauber Thank you. Operator Our next question comes from the line of Durgesh Chopra with Evercore ISI. Your line is open. Durgesh Chopra Hi, good afternoon. Scott Lauber Hi, Durgesh. Durgesh Chopra Hi, good afternoon, Scott and Xia. Thanks for giving me time. Hi, just on the safety modernization program review in Illinois. So obviously, you had a decision on the $145 million, you got $28 million. Can you just remind us what is baked into the plan '25 and forward on that -- on the safety program? Scott Lauber Sure, and I'll let Xia go through the details. But in general, we took about $800 million out. And as we look at our plan, we'll reevaluate it based on the testimony we're seeing here as we look at the next five-year plan. But Xia, can you tell us what's in the current? Xia Liu Yes, it's between $100 million to $120 million a year, Durgesh. And as Scott mentioned, we are in the process of refreshing the capital plan. So we're working with the team in Illinois to reflect the latest development from the commission's decision on the approval of the $28.5 million. So likely that number could potentially come down over the next five years, but we're still working through the details right now. Durgesh Chopra Got it. Thank you. That's very helpful. And just to be clear, first quarter of next year, we're going to get a decision on the spending relative to what you have in the plan, right? I'm assuming you've asked for anywhere between $100 million to $120 million and then the commission is going to come back with a recommendation. Is that fair? Scott Lauber Yes. We expect to hear a recommendation in the first quarter of 2025 from the commission. Durgesh Chopra Yes. Okay. Thank you. And then just can I quickly follow up on Delilah I? Any color you can share? I know you mentioned weather event. I'm just wondering if it's -- it could be more than six months? Just what caused it? Was it just equipment or something else? Any color you can share there? Thank you. Scott Lauber Yes, sure. There was -- and remember, we haven't purchased it yet. We have a commitment to, but it was during construction and there was a hail event there. So there was some hail damage. We want to work with the developer as they are repairing it to make sure the fields in full shape before we purchase it. We anticipate based on all the latest discussions that it will be in by the end-of-the year. And we get weekly updates on the progress going there. And right now that is still the plan to be in by the end-of-the year assuming no other events happen. Durgesh Chopra Thank you. I appreciate it. Thanks, Scott. Thanks, Xia. Scott Lauber Thank you. Operator Our next question comes from the line of Carly Davenport with Goldman Sachs. Your line is open. Carly Davenport Hi, good afternoon. Thanks for taking the questions. Scott Lauber Hi, Carly. Absolutely. Carly Davenport Just wanted to ask a quick one on transmission and ATC. We've obviously seen the sizing of MISO Tranche 2 moving higher here. So just curious how you're thinking about the opportunities around transmission there both from a size and a timing perspective. Scott Lauber Sure. I think Tranche 2 from everything I've seen and heard is going to be larger than Tranche 1 and you've talked about that. I think it will be probably about proportionately larger for ATC. So a lot of good opportunities there, but that spending probably won't actually occur to like 2030 plus, right, because they're still working through Tranche 1. I think the other big driver for American transmission company is going to be the economic development in the region and putting in renewables in the system. So last year, Tranche 1 had an effect on our capital plan, but the biggest drivers were economic development and continuing renewables in Wisconsin. So I consider both of those to be additional drivers. And remember that Tranche 1 was in 2020. So as they go through and reprice all of that, when you think about inflation in the last several years, it's going to be -- it's going to most likely be bigger than the original amount. Carly Davenport Great. I appreciate that color. I'll leave it there. Thank you. Scott Lauber Thank you. Operator Our next caller comes from the line of Andrew Weisel with Scotiabank. Your line is open. Scott Lauber Hi, Andrew. Andrew Weisel Hi, everybody. Hi. First question on Illinois. Just a question of timing. So you mentioned the uncertainty will last for about a year. At what point might you start to consider reallocating capital into this state? Could we see some CapEx go back into Illinois with the update in three months or would it be unlikely to show up until the fee update in the fall of 2025 when all of those dockets are wrapped up? Scott Lauber Well -- and we'll look at it. When you think about Illinois, we'll know more on the S&P program in the first quarter of next year. There's also a -- there's the future of natural gas that's being looked at and there's also an IRP process where we get stakeholders involved and our first filing will be in 2025. So, as you know, as we pull our capital plans together in the fall of this year, we're going to be pretty conservative as we look at that until we have a little more clarity. And when we think about it, there's just a lot of opportunities outside of Illinois for the additional capital and growth. Andrew Weisel That makes sense. Next question for Xia. If I heard you right on the O&M, you're now projecting it to be up 2% to 3%. Last quarter, you said up 3% to 5%, originally it was up 6% to 7%. So this is really good progress. Can you just give us a little bit of detail on those moving parts? How is it that the outlook is getting better and better? What are some examples? Xia Liu Oh, there -- every manager in the business unit understands that we had a very mild first quarter. So we made it very clear that we need to be highly focused on O&M to offset the weather headwind in the first quarter. Benefits are lower, expected to be lower. We're also looking at all the angles about using contractors versus internal labor and we -- it's across-the-board, I would say, so... Andrew Weisel Okay. Relative to the original budgets, would you call most of these savings one time then or is some of it going to be sustainable? Xia Liu I think it's a combination of one-time initiatives, but also continued focus on driving efficiency across-the-board which is also sustainable. It's a combination of both. Scott Lauber And also when you think about it, having a warm first quarter, you don't have like the number of leaks as you would in the gas system. So some things are naturally less now. So we've got a little bit less O&M in the gas system and we had some significant storms. So between the storms and the warmer weather, we've asked everyone across the business unit to really control cost and really kind of do some one-time things here. On the other hand, we are making sure we are actively responding to storms because the storms have had bigger and actually continuing to work on our forestry program because of some of the damage some of the storms have had to the system. So we want to really balance customer reliability along with our savings? Andrew Weisel Got it. That's very helpful. Then just one very nit-picky one. Corporate and other minus $0.06 for taxes this quarter, I think it was plus $0.09 in the first quarter. Will you just remind us what's the expectation for the full-year? Should that net up to zero or something else? Xia Liu It would be slightly positive. If you think about the reason why we had a large timing -- tax timing in the first quarter and the opposite in the second quarter. Part of that is driven by the earnings pattern shift in Illinois, so tax dollars follow the earnings pattern. And two, we had a deferral -- I'm sorry, the delay of the Delilah. So part of that is reflected in the second quarter. But as we put Delilah online end-of-the year, we expect the tax dollars to follow. Andrew Weisel Okay, very helpful. Thank you so much. Operator Our next question comes from the line of Neil Kalton with Wells Fargo Securities. Your line is open. Neil Kalton Yes, hi, guys. Thanks for taking my call. Two questions. Just on the Microsoft opportunity, a lot of acreage here. As we think about the CapEx refreshes going-forward, at what point in time do you think you'll have clarity to start flowing some of that potential spend related to incremental opportunities into the plan? Is that like potentially '24 we could see some or is this more like '25 or '26? Scott Lauber Sure. And actually, thanks, Neil and thanks for the question. So we're actually -- between us and American transmission company, we're actually spending some money now on some of the substations and we have those orders in for some of the generation and it's to support the economic development across-the-board. So it's going to be '24, '25 and then even more in '26 as we get those orders released at the commission and approval for that generation. We're also -- in the next month or so, you'll see some filing on additional renewables that support the generation needs as we continue to add renewables to our portfolio. So that spending, it will be probably in that '26, '27 timeframe. Neil Kalton Okay. So it's kind of like broadly overall, it's not just tied to the Microsoft thing, sort of overall you have this need and kind of anticipate things happening that we start to kind of flow it in over time. And as we get more clarity, more comes in, is that right? Scott Lauber Exactly, exactly. And remember, the growth that they provided us is really only through their capital plans through '26. I imagine once they get it in, they'll continue to ramp up. But we'll continue to work through it. And I think our plan is extremely long as we start adding 2029 to our five-year plan. Neil Kalton Okay, perfect. Thank you. Scott Lauber Thank you. Operator Our next question comes from the line of Jeremy Tonet with JPMorgan. Your line is open. Jeremy Tonet Hi, good afternoon. Scott Lauber Hi, Jeremy. Jeremy Tonet I just wanted to come back up to Wisconsin if I could with the recent commission vote here. Just wondering with the split vote, what you take from that, I guess, any thoughts on the direction of the commission at this point? Scott Lauber No, I think it's kind of early to tell. I think they were just looking for some additional information and I don't think they had the full information on and they mentioned on the economics and the benefits of this. So this is maybe a communication between our staff and their staff and we just got to understand it. So we'll get the order, we'll review it. We'll pull the information together and ask for a reconsideration. I'm not overly concerned on this. And in the end, when you listen to their comments, if they didn't have all the information, you know they have to make the right decision for what they think is right too. So I appreciate them really evaluating each case. So I won't over -- read into this over too much. Jeremy Tonet Got it. That's helpful. I'll leave it there. Thanks. Operator [Operator Instructions] Our next question comes from the line of Shar Pourreza with Guggenheim Partners. Your line is open. Shar Pourreza Hi, guys. Thanks for taking my follow up. Scott, I know we're getting closer to the back-half of the year. Just on Point Beach PPA, I know you've talked about sort of this coming potentially too ahead as we're getting to the year-end. I guess how are sort of conversations going with NextEra and a new PPA or sort of another path forward there? Any updates? Scott Lauber Yes, it's really -- we've had really good productive conversations with NextEra, but really nothing to report at this time. So still in discussions, but stay-tuned to this. And we'll -- we're working on it. Shar Pourreza Okay. I appreciate it. Thanks so much guys for taking my follow up. Appreciate it. Scott Lauber Absolutely. Operator Our last question comes from the line of Paul Patterson with Glenrock Associates. Your line is open. Paul Patterson Hi. Scott Lauber Hi, Paul. Paul Patterson Good afternoon. How are you doing? So just one question at this point and that is the Illinois Gas Appeal at the Appellate Court in Illinois, just any frame of timing when you think you might get a resolution to that? Scott Lauber I apologize. It didn't come too clear on -- the future of gas? Paul Patterson No, no. So you guys appealed the order to the Illinois field court. And I was just wondering when you think a decision from that might be happening? Scott Lauber I anticipate it's going to take a year or two. Paul Patterson Okay. A long-time. Okay. Thank you. That's it from me. Scott Lauber All right. Thank you. Well, that concludes our conference call for today. Thank you for participating. If you have any questions, feel free as always to call Beth Straka at 414-221-4639. Thank you.

CenterPoint Energy, Inc. (CNP) Q2 2024 Earnings Call Transcript

Shar Pourreza - Guggenheim Partners Steve Fleishman - Wolfe Research Jeremy Tonet - JPMorgan Securities Nicholas Campanella - Barclays Durgesh Chopra - Evercore David Arcaro - Morgan Stanley Julien Dumoulin Smith - Jefferies Anthony Crowdell - Mizuho Good morning and welcome to CenterPoint Energy Second Quarter 2024 Earnings Conference Call with senior management. During the company's prepared remarks, all participants will be in a listen-only mode. There will be a question-and-answer session after management's remarks. [Operator Instructions]. I will now turn the call over to Jackie Richert, Senior Vice President of Corporate Planning Investor Relations and Treasurer. Ms. Rickert? Jackie Richert Good morning and welcome to CenterPoint Energy's second quarter 2024 earnings conference call. Jason Wells, our CEO, and Chris Foster, our CFO, will discuss the company's second quarter results. Management will discuss certain topics that will contain projections and other forward-looking information and statements that are based on management's beliefs, assumptions, and information currently available to management. These forward-looking statements are subject to risks and uncertainties. Actual results could differ materially based upon various factors as noted in our Form 10-Q, other SEC filings, and our earnings materials. We undertake no obligation to revise or update publicly any forward-looking statements. We will be discussing certain non-GAAP measures on today's call. When providing guidance, we use the non-GAAP EPS measure of diluted adjusted earnings per share on a consolidated basis, referred to as non-GAAP EPS. For information on our guidance methodology and reconciliation of the non-GAAP measures discussed on this call, please refer to today's news release and presentation on our website. We use our website to announce material information. This call is being recorded. Information on how to access the replay can be found on our website. Thank you, Jackie, and good morning, everyone. Before spending most of my time discussing the impacts of and our response to Hurricane Beryl, I will very briefly touch on our results for the second quarter. I'll then turn it over to Chris for a regulatory update and a more detailed recap of our financial results. For the second quarter, we reported GAAP and non-GAAP EPS of $0.36 per share. In addition, we are reaffirming our full year 2024 non-GAAP EPS guidance range of $1.61 to $1.63. Beyond 2024, we are also reaffirming our long-term guidance, where we expect to grow non-GAAP EPS and dividend per share growth at the mid-to-high end of our 6% to 8% range annually through 2030. Now, to turn to our primary area of focus. Earlier this month, Hurricane Beryl impacted our entire 5,000-square-mile service territory in the greater Houston area, causing power outages for nearly 2.3 million of our customers, or approximately 80% of our Houston electric customer base. We began tracking Hurricane Beryl and preparing for a possible impact nine days before Beryl made landfall. Initial forecasts showed that our service area in greater Houston would be spared a direct impact by the worst of the hurricane. Nonetheless, we remained vigilant and planned for impact. We initially secured 3,000 mutual assistance crew members from locations safely outside of the projected path of the storm. We also coordinated with utilities across Texas and the region to ensure resource availability. As the forecast trajectory changed, we quickly called on additional mutual assistance resources, ultimately activating and deploying over 15,000 CenterPoint mutual assistance crew members. Early in the morning on Monday, July 8, Hurricane Beryl made landfall as a powerful Category 1 hurricane with heavy rains, flooding, and up to 97-mile-hour winds that reached further inland than any storm experienced in Houston since 1983. As part of our response, we restored power to over 1 million customers within 48 hours, replaced over 3,000 distribution poles on our system, walked over 8,500 circuit miles to repair damage, and deployed mobile generators at 28 sites across the greater Houston area to various critical facilities. Impacts to our distribution lines and facilities from vegetation, such as uprooted trees and related debris carried by the very high winds, were the primary cause of customer outages. In recent years, trees in the Houston area have been weakened due to a combination of high rainfall, prior drought conditions, as well as winter freezes. We trimmed or removed approximately 35,000 trees during our restoration process. Through discussion with one of our largest vegetation management companies, 60% of the vegetation it removed were trees that had fallen from outside of our rights-of-way. Over the last 18 months, we proactively worked to address the challenges these conditions present to our distribution system through increased vegetation management. In fact, in 2023, our Houston Electric business increased its vegetation management spend by over 30% from the prior year. We continue to execute and invest at a similar, higher level of vegetation management as we recognize the impacts of the challenging growing seasons experienced in the Houston area over the last three years, and the resulting threat they could have on our lines and infrastructure. In addition, Hurricane Beryl's destructive winds, in combination with already weakened trees, highlighted not only the urgency with which we need to execute on our vegetation management plan, but also the scope. As a result, we have doubled our vegetation management resources and are aggressively tackling the riskier line miles with trees nearby. We will trim or remove trees related to an incremental 2,000 miles of our system by December 31st of this year. This represents a nearly 50% increase compared to our planned work for 2024. The vegetation work we have begun is only a part of a more comprehensive plan to improve customer outcomes and directly address the customer concerns and frustrations voiced with respect to critical aspects of our emergency response. This plan will also help us better prepare our response in key areas to future storms or hurricanes. I will walk through the three pillars of our comprehensive action plan to address our customers' concerns. Our first pillar relates to our resiliency investments. By accelerating the adoption of advanced construction standards, retrofitting existing assets on an accelerated basis, and using predictive modeling and AI, as well as other advanced technologies, we will harden our distribution system to help withstand more extreme weather and improve the speed of restoration. This is in addition to proactive steps we took nearly two years ago when we moved to constructing at the new national standard for high wind and extreme ice loading. Second, we will build a best-in-class customer communications program. Since the derecho that impacted Houston in May, our outage tracker has not been available for our customers. The tracker we previously used was hosted on a physical server that was not able to accommodate the demand of millions of users at one time. To keep our communities informed, we provided daily restoration updates, but we understand that for many, this was insufficient. As one component of our customer communication action plan, we are launching a new, more customer-oriented outage tracker later this week. Our new outage tracker will help provide our customers more of the information they need in a timely fashion. It will also be comparable to what our Texas Peer Utility customers experience. The new tracker is cloud-based, which will also allow us to scale to high levels of demand. Third, we will strengthen our partnerships with government and community leaders. Effective emergency preparedness and response requires close coordination with government officials. We will hire a seasoned emergency response leader to help the company rapidly accelerate its planning capabilities and to develop close community partnerships to help ease the burden of storm events on our more vulnerable communities. We believe the work underlying these three pillars will support our efforts to build and operate a grid that meets the demands of one of the most dynamic economies in the United States here in Houston. The initial set of specific actions we are taking is laid out on slide three. We will also be taking additional actions as we continue to learn from our internal reviews and external independent review, as well as through engagement with emergency response experts, our customers, elected officials, and community stakeholders. Our singular and overarching goal is to improve in every area of our emergency preparedness and response. Whether it is before, during, or after any future storm, we will be better prepared to support, communicate with, and serve our customers in these times of emergency. As we begin to execute this initial plan, we will work to consistently provide updates on our progress. The men and women at CenterPoint go to work every day with an unrelenting focus on delivering safe, reliable, and resilient energy to our customers, while also striving to improve their experience. We will continue to make customer-focused capital investments to achieve better outcomes for the nearly 3 million electric customers and over 4 million gas customers across our six-state footprint. Thanks, Jason. Before I get into my updates, I want to echo Jason's gratitude to our customers and our communities. Our team is focused on improving our resilience and emergency response capabilities, and I will speak to our financial plan to support those efforts in my remarks today. Today, I'd like to cover three areas of focus. First, the details of our second quarter financial results and guidance. Second, I'll provide a brief update of the progress we're making on our regulatory calendar. Third, I'll touch on our capital deployment status this quarter and forecasted storm costs. And finally, I'll provide an update on our financing plan. Again, as Jason noted, today we are reaffirming our full year 2024 non-GAAP EPS guidance range of $1.61 to $1.63. Which represents 8% growth at the midpoint from our 2023 actual results of $1.50. Beyond 2024, we are also reaffirming our guidance, where we expect to grow non-GAAP EPS at the mid to high end of the 6% to 8% range annually through 2030, as well as targeting dividend per share growth in line with earnings per share growth. Let's now move to the financial results shown on slide four. On a GAAP EPS basis, we reported $0.36 for the second quarter of 2024. On a non-GAAP basis, we also reported $0.36 for the second quarter of 2024, compared to $0.28 in the second quarter of 2023. Diving into more detail of the earnings drivers for the quarter, growth and rate recovery contributed $0.10, which is primarily driven by the ongoing recovery from various interim mechanisms for which customer rates were updated last year, as well as the interim rates in our Minnesota gas business that went into effect on January 1 of this year. In addition, the Houston area continues to see strong organic growth, extending the long-term trend of 1% to 2% 3average annual customer growth. This sustained growth has been beneficial for our customers and investors alike. O&M was $0.02 favorable for the quarter. This favorable variance was driven primarily by the fact that we incurred more of our expenses in the first quarter and had some of our scheduled activities diverted to attend to restoration efforts related to the major HO storm. Partially offsetting the favorable items from rate recovery in O&M were unfavorable weather and increased interest expense. Weather and usage were $0.01 unfavorable when compared to the comparable quarter of 2023, driven primarily by a milder spring in our Minnesota gas service territory. Interest expense was $0.06 unfavorable, primarily driven by the new debt issuances since the first quarter of last year to fund customer-driven work across our electric and gas territories at a higher relative cost of debt. I now want to turn to an update on our broader regulatory calendar in progress, and I'll cover these sequentially from the dates filed. Starting with Texas Gas, where last month, we received Railroad Commission approval of our now final settlement. As a reminder, our four Texas gas jurisdictions will now be consolidated on a go-forward basis for our ongoing rate adjustments. This new consolidation should benefit many customers through a lower impact on their bills from certain investments, and also a reduced administrative burden for other stakeholders. Moving next to the filed Minnesota gas rate case. And as a reminder, we filed our rate case on November 1st of last year. As discussed on the last call, the interim rates for 2024 were approved in mid-December and went into effect on January 1st. The Minnesota Commission will consider interim rates for 2025 toward the end of this year, depending on how far along we are in the case. Hearings are scheduled to occur in the middle of December of this year. Ahead of those hearings, we intend to engage in settlement discussions with parties involved in the case. And as you may recall, we have settled our previous three rate cases in our Minnesota gas jurisdiction. Now, turning to the Indiana electric rate case. We currently have a non-unanimous settlement pending approval. Hearings on this settlement will begin the first week of September with a new statutory deadline for a final order of February 3rd. We look forward to continuing to work with stakeholders to achieve what we believe to be a reasonable outcome for all parties. I'll now touch on our largest jurisdiction, Houston Electric. Over the last month, we have been engaged with many stakeholders as part of settlement discussions in our pending rate case. Those discussions are ongoing, and we continue to provide regular updates to the ALJ in the case. In addition, as we execute on the actions we've laid out following Hurricane Beryl, we intend to work with stakeholders on how to amend our system resiliency plan with the PUCT. The process is fluid, but at this stage, we have abated the schedule on the underlying system resiliency plan, which all parties have agreed to. This allows us to take the coming months to reflect stakeholder input and additional potential system resiliency concepts that emerge from our after-action review and the review of the PUCT. We currently anticipate filing a revised plan later in Q1 2025. Lastly, I want to briefly mention that next month we will file a notice of intent for our upcoming rate case for our Ohio gas business, which is approximately $1.4 billion in rate base. Next, I'll touch on our capital investments thus far in 2024, as shown on slide 6, including the anticipated impact of storm costs and their associated recovery. In the second quarter of 2024, we invested $800 million of base work for the benefit of our customers and communities. This excludes spending related to storm restoration. We now have a little less than 60% of our original 2024 capital expenditure target of $3.7 billion to be invested over the remainder of the year, excluding storm costs. We remain on track to meet our capital investment target, despite the interruptions of normal capital deployment from the storms we've experienced this year. Maintaining our target as we consider a revised version of the resiliency work is a reflection of the conservatism with which we plan each and every year. Although the cost invoicing is not final, total spending associated with the May storm events and Hurricane Beryl are currently estimated to be approximately $1.6 billion to $1.8 billion. We currently anticipate that we will securitize both the capital and non-capital portion of the $1.5 billion to $1.7 billion distribution costs to limit the impact to our customers on their bills, and will include approximately $100 million of transmission investments within the next T-cost recovery filing. Based on the total current average residential electric bill, we estimate that these costs could result in an increase of a little more than 2%. As a reminder, the mechanism to recover storm costs in the state of Texas is very constructive and cost-effective for customers. Texas TDUs are able to securitize non-T-cost storm-related costs in excess of approximately $100 million under existing statutory authority. As a result, we anticipate filing for securitization in the fourth quarter of this year, with securitization bond proceeds expected to be received towards the end of next year. Finally, I want to touch on our balance sheet and how we're thinking about funding the storm costs I just discussed. As of the end of the second quarter, our calculated FFO-to-debt was 13.3%. Based on our calculation aligning with Moody's methodology as shown on slide 7, the second quarter tends to be our lightest quarter due to the timing of incremental financing relative to interim recovery mechanisms. This quarter also had a temporary cash flow item that we expect to normalize through the next quarter. Taking a step back, as we continue to see the need to fund growth we are experiencing in Texas, we remain focused on the balance sheet. And with respect to our financing plans through the end of the year, we have evolved our approach. Recognizing the storm impacts. As we remain committed to maintaining our current credit metrics in light of these incremental costs, we intend to pull forward $250 million of equity planned for 2025 into this year, which is in addition to the $250 million issued to date. This does not change our long-term equity guidance, rather should only be considered as an acceleration. We will also incorporate higher equity content into our upcoming debt issuances to enhance credit metrics until the anticipated securitization proceeds are received. We would also see this as pulling forward instruments we've been considering in our long-term plans as mentioned in recent quarterly calls. We remain confident in the continuation of our long-term execution. The last thing I want to mention is we are making good progress related to the sale of our Louisiana and Mississippi gas LDCs. We, along with the filings, including filings with the Louisiana and Mississippi public service commissions, and we look forward to working constructively with the commissions to facilitate the approval proceedings. We still anticipate closing the sale late in the first quarter of 2025, and it is anticipated to result in after-cash tax proceeds of approximately $1 billion. As a reminder, a majority of these proceeds will be used to fund our capital investments at Houston Electric for the benefit of customers. And with that, I'll now turn the call back over to Jason. Jason Wells Thank you, Chris. Regardless of the challenges we face, this management team remains firmly committed to delivering for all of our stakeholders, our customers, our communities, our regulators, our legislators, and our investors. Jackie Richert Thank you, Jason. With that, operator, we're now ready for Q&A. Thank you. At this time, we will begin taking questions. [Operator Instructions]. Thank you. One moment for the first question. The first question will come from Shar Pourreza with Guggenheim Partners. Your line is open. Morning. Jason, maybe a little bit of a tough question to answer, but I guess, how do you see the commentary that we've all been listening to from customers, legislators, and kind of stakeholders impacting the current settlement negotiations in the Houston Electric rate case? Jason Wells Yeah, thanks for the question, Shar. Clearly, as I've said in a number of different forums, we can and will be better. These are important issues for the greater Houston region, for Texas. Ultimately, though, the answer for getting better is continued investment and resiliency of our system. I think that needs to or will be reflected in the continued negotiations that are occurring from a settlement standpoint. There's, again, clear demand that we need to communicate better, that we need to mitigate the risk of these outages moving forward. And I think, ongoing settlement discussions are all just part of putting the company in a position to continue to be able to make that progress. Shar Pourreza Okay. Got it. Then, just lastly, obviously, Hurricane Beryl certainly highlighted more work needs to be done, and you had a level of resiliency spending bucketed as upside to the $44.5 billion CapEx plan. I guess, how do the recent events impact that bucket even directionally? How fast do you plan to ramp up in light of the increased urgency with the current regulatory construct that's out there? Thanks. Jason Wells Yeah, I think it's definitely an area of focus. We were investing in resiliency prior to that resiliency legislation. I think we heard loud and clear at the PUCT meeting last week that we need to continue to move forward. We've made commitments to move forward. Ultimately, while we've pulled down the system resiliency plan, and we are working with outside experts, taking feedback, we'll obviously work with parties in the case, we plan to rapidly refile it. I think the short of it means there's probably more support for incremental resiliency investments. I'll give you one example. In the filing, we proposed continued sectionalization of our system, which is an important part of isolating outages, helping minimize the overall number. We proposed a pace of about 20 years in that program. I think that's a program that we need to revisit. I don't think the 20-year pace is no longer a pace that folks expect of us. If anything, I think the bias will be towards accelerating incremental resiliency investment as opposed to delaying it. Shar Pourreza Got it. Okay. Appreciate it. I'll pass it to someone else. Thank you, guys. One moment for the next question. The next question comes from Steve Fleishman with Wolfe Research. Your line is open. Good morning. So, just on the, I guess, first, a question on the financing plan, the comment on the equity content in the upcoming refinancing, should we assume that's more like a junior subordinated, or could that be like a convertible? Any more color on the likely type of financing there? Chris Foster Morning, Steve. It is fair to say that we're certainly looking at different versions of hybrids to pull in more equity content into the plan. And as I mentioned this morning, the other piece is just to pull forward $250 million. Again, to be clear, that doesn't change the overall guide from 2024 to 2030 of the $1.75 billion total. It's just a pull forward of that piece. And as you can imagine, the point there is to just be able to have that in place to comfortably position the balance sheet until we get the anticipated securitization proceeds. Currently thinking those are probably going to be end of year next year. Steve Fleishman Okay. And then maybe you could just give us some color on how the rating agencies are reacting to this event and spend in your updated plan. And it's going to be a little while before we know and see the securitization, so just thoughts on kind of their willingness to be patient. Chris Foster Sure thing. I think it's fair to say we're having a conversation, Steve, obviously, about both how we're thinking about the plan that Jason has referenced, where we're going to aggressively move forward here in 2024 to do some critical work in the immediate sense. Longer term, we're also talking about some initial thinking on moving forward, ideally in Q1 with a subsequent revised system resiliency plan filing. I think in this case, Texas has had a consistent construct in the state for utilities to securitize costs above the $100 million point. Certainly, that's the case here. And so, sharing certainly that history and consistent history of the state as well in terms of its overall construct. So, fairly fluid conversations, you can imagine, just given how quickly we're moving on a few fronts, but certainly sharing all of our different activities. Our next question comes from Jeremy Tonet with JPMorgan Securities. Your line is open. I wanted to pick up on the storm commentary. Thank you for the detail today. Just pulling it all together, looking at your post-hurricane action plan in the items you laid out here, how do you feel about, I guess, how Houston Electric can respond to the next storm out there? Do you think you have the pieces in place now to see a better response, even if everything's not in place altogether? Just wondering how you guys think you stand now. Jason Wells Yeah, no, thanks for the question. I do feel confident. As I mentioned yesterday in the Senate hearing, it offers no relief to the customers impacted by Beryl. We were moving with pace and urgency after the derecho to move to a fully scalable outage tracker platform that would offer estimated times of restoration consistent with industry-leading practices and had begun the work to overhaul our communications. That's why I feel confident that if a named storm threatens the Texas Gulf Coast region, we'll be in a much better position to communicate before, during, and after that storm. I think giving our customers the information they unfortunately lack during Hurricane Beryl, but it's that work that we've been doing in advance that I think helps on the communication front. Equally, it offers no relief to the customers that experienced this pain during Beryl, but we had been working on bringing a lot of the innovative predictive modeling to target enhanced vegetation management and resiliency investments for work. That's why I'm confident that as we execute on the incremental resiliency commitments that we've made to Governor Abbott and others, it will have a meaningful impact for our communities. The last month has been tough on the City of Houston. We understand the role we play, but that's also why I have confidence looking forward. Jeremy Tonet Got it. Thank you for that. Just to follow up here, you mentioned that 60% of the downfall came from outside of your right-of-ways. What can you do about that going forward? Also, I guess just the assets overall, how did the hardened assets perform during the hurricane? Just want to see what value you think has been delivered with prior hardening here. Jason Wells Yeah. Again, it offers no relief to the customers, but we are seeing the value of resiliency investments. We saw very minimal structural damage on our transmission system substations. Strategically, it makes sense to put the first investments in the backbone of the system from a resiliency standpoint. We've begun some of the incremental sectionalization work and hardening of distribution circuits. That work saved over 150,000 outages in the communities that we deployed that. I think moving forward from a resiliency standpoint, it's the acceleration of that work on the distribution grid that will have the most meaningful impact to minimizing outages going forward. The key issue, though, at the end of the day was, candidly, there was little structural damage on the system. It was well less than even 0.5% of our poles failed. But what really caused the outages were, as you pointed out, 60% of the trees impacting our lines were outside of our right-of-way. Candidly, we don't have any authority today to trim and manage those trees. We are doing the work to identify the trees that create those hazards. We are proactively trying to work with property owners to access that property and address those trees, which are a safety issue, obviously, for the residential homeowner, as an example. A tree can just as easily fall into their home as it could into the power line. But we don't have authority today unless granted by the homeowner. So, looking to work with community leaders, our regulators, elected officials to make sure that we can continue to work at pace to address this vegetation that threatens our system moving forward. And our next question comes from Nicholas Campanella with Barclays. Your line is open. Nicholas Campanella Hey, good morning. Thanks for taking my questions this morning. I appreciate all the details. Morning. Just wanted to follow-up. As we kind of contemplate pulling forward some of this equity from '25 into '24, and then you also talked about doing this equity content financing as well, I know you talked about some kind of one-time issues in the 12-month episode of debt. Where do you think you kind of end at the base year, just based on the current plan today? Chris Foster Sure. Good morning. I think if you saw this report this morning, as you can imagine, some of this is just the differing methodologies. But from this standpoint, in the S&P methodology, there's the assumption that the securitization proceeds do come through, which moves us up to well above the downgrade threshold, up to 12.9%. At Moody's, right, they treated slightly differently, so it takes us from that roughly 14% to 13.3% where we are this morning. I do have to emphasize, though, Nick, keep in mind that last year this was the same situation. This is a bit of the trough that occurs in Q2 before we pick back up. And we've got a one-time item that we believe in Q3 that you'll be able to see come through further improving FFO to debt. Hard for me to be specific about year end, but just you can imagine where we are at this point is it's a transitory impact year of the time period that will pass between now and the securitization proceeds. Nicholas Campanella Okay. Thanks for that. And then I guess you spoke about doubling some of the labor efforts around the tree trimming. Can you remind us, because you do have this 1% to 2%, I think it's an O&M reduction forecast in the long-term plan? Does that need to be reassessed? Can you execute on that, even net of these veg management increases? How do we think about that? Does that stuff get deferred? I'll leave it there. Thanks. Jason Wells Thanks for the question, Nick. I think we continue to see opportunity to drive efficiency in our O&M practices to help support that overall 1% to 2% reduction in O&M. We continue to highlight, as we have in the past, a classic example of that is the benefit of deploying the next generation of smarter meters on the gas side. So, we see plenty of opportunity to continue to be efficient, which is, I think, obviously in our customers' interest, but also helps free up some opportunity to accelerate in other areas. As I highlighted, we increased proactively our vegetation management over 30% last year in 2023, and we still achieved that 1% to 2% reduction year over year in 2023. We will always make the investment that's needed to drive an improvement in service, but I still feel like we've got a number of opportunities across the full scope of the company's operations to achieve on a consolidated basis that 1% to 2% O&M reduction. And our next question comes from Durgesh Chopra with Evercore. Your line is open. Durgesh Chopra Hey, team. Good morning. Thank you for giving me time. I think, Chris, you mentioned 2% will increase from the securitization of the distribution spending. I have two questions related to that. First, the confidence level in $1.6 billion to $1.8 billion, I guess where I'm getting at with that is have you basically taken a deep dive of your costs? Are you still incurring costs? And the number could be significantly higher. That's one. And second, what that 2% is over -- you're assuming, I guess, cost recovery over a time frame, over multiple years. Maybe just if you could elaborate on that, please. Thank you. Chris Foster Sure thing. Happy to. Good morning, Durgesh. I think there's really two pieces there. I think the first is -- I'll hit the second one first in terms of time frame. At this stage, we would be compiling the costs. The thing to keep in mind is that the existing construct in the state does allow for the entity to combine events that occur, including multiple events over a calendar year, into one securitization. So, again, we would seek to file that and ultimately assume, in this situation, end of year 2025 time frame for recoveries there. As it relates to the overall kind of profile itself, the thing to keep in mind here is that we do already have a good feel of the asset-based costs associated with both the derecho and Hurricane Beryl. The primary driver beyond that is most commonly the labor costs, right? The costs associated with nearly 15,000 individuals that were doing work on our system. And so, we do have a pretty good feel of how those are forecasted at this stage, which informs the disclosure this morning at the high end of $1.8 billion. So, again, it's going to be a somewhat similar profile, just given the crews and the associated contracts are very similar as to what we saw in the situation with the derecho, and we're well over 75% of those costs already in. So, it gives us confidence to inform the profile that you see today. Durgesh Chopra Excellent. Thank you. Just one quick clarification, Chris. The 2%, I think you mentioned the 2% impact on customer bills. I guess where I was going with the time frame is that assumes that $1.8 billion is collected over how many years? Chris Foster Sure. Traditionally, in the statutory requirement in Texas, it's 15 years. Our next question comes from David Arcaro with Morgan Stanley. Your line is open. Morning. I'm wondering if you might be able to comment on the legislative outlook from here. I'm curious if there are legislative initiatives that you might pursue or support, just any ideas that may be being explored by lawmakers in the state to help improve resiliency? Jason Wells A couple of the topics that have come up early on are consistent with my previous discussion around vegetation management. I think the question is, does the state of Texas, do we need to do something different to be able to attack these hazard trees that are outside of right-of-ways and do so in a manner that is obviously constructive with property owners? I think that's obviously a place to look. The other thing that's come up is sort of the unique aspect of the market here in Texas, the fact that we have a service relationship with customers but not a commercial relationship. It's, at the end of the day, inexcusable that we don't have customer contact information at each address since we have that service-related responsibility. There may be something around that as well. Clearly, yesterday, there was a lot of feedback on mobile generation. Right now, we want to be constructive with the policy objectives of the state. As I mentioned in the Senate hearing, we have an order by the PUCT that we cannot allow a customer to go more than 12 hours without power in a load shed event. Those assets are necessary to comply with that order, but if policymakers want to change that direction, obviously, we will work to support the policy direction of the state. There's a lot of different things being discussed now, and I think that they will come into greater focus as we approach the end of the year and, obviously, the start of the legislative session next year. David Arcaro Okay. That's helpful. Thanks. Maybe, Chris, just wondering if you might be able to clarify, is there a target for when you would expect to get back. At the FFO/Total debt level, you would expect to get back into the target range and get above 14%? For example, at Moody's? Chris Foster Sure, David. I think what you'll see there naturally is that you'll have the adjustment upward from S&P that will take place, and then Moody's does so upon receipt of proceeds. Again, so you'd be looking at roughly Q4 of next year in this timeframe. And the next question comes from Julien Dumoulin Smith with Jefferies. Your line is open. Julien Dumoulin Smith Hey. Good morning, team. Thank you, guys, for the time. I hope you guys are hanging in there. Just maybe on the puts and takes, obviously, you talked about some of the accelerated equity here on '24. Just can we talk a little bit about your thoughts on the positive offsets here to the pressure points, whether it's additional OpEx in the form of these storms, to the extent to which there's any realized interest expense or ultimately just lost sales? How do you think about the good guys and bad guys in the offset there to maintain the outlook here in the very near term? Chris Foster Sure thing, Julien. In the very near term, as you can imagine, there was a usage impact associated with the storm itself. We also had a situation where we were having to adjust work temporarily as it related to the literal storm response and restoration. But ultimately, as we're looking through the remainder of the year, as you saw, we reaffirmed this morning, gives us confidence that we've got both two things going on. One, the ability for the mutual aid and other crews who joined our colleagues to really effectively work to restore customers quickly. But also, as I mentioned, we have been able to retain confidence in achieving the base CapEx plan as well. So net of the different factors, including interest expense, we're confident that we're still able to reaffirm this morning. Julien Dumoulin Smith All right, fair enough. And then just coming back to the mobile gen, I mean, that's been getting a certain amount of attention here. And obviously, perhaps they were contemplated for a slightly different circumstance. How do you think about developing a more refined program here to target more of these localized distribution-related outages with vegetation management issues that you've encountered here? And ultimately, how does this work in, because of which you evaluate this or otherwise, into a revised timeline on the resiliency filing here? I know that there's various permutations there as well. Jason Wells Yeah, I mean, I strongly believe we have the most comprehensive mobile gen program consistent with what has been asked of us by the state and its policy objectives. The legislation was passed in 2021, and there was a focus on load shed events. Those are sort of larger units tied to substations. And as I mentioned yesterday, there's been 115 instances since that legislation started to be discussed where there were tight system conditions on our cotton. Those systems, those units may be to be utilized. We had also utilized in 2021 one of the medium-sized units for storm restoration and got a significant amount of pushback. And I think the legislature clarified that in 2023. And as soon as we got that clarification in the fall of 2023, we increased the number of small units. And so, I'm proud that we were able to scale to 18 small units out of a total of 30. The other 12 we borrowed from our utility peers to be part of the storm response. And so, as I said yesterday, we manage a number of different risks, whether those are load shed events or storm response. We've got a portfolio of assets to kind of meet those needs. Now, obviously, as I said, if the policy objectives of the state change, we will change with them. But I think today we are maintaining a diversified portfolio for the diversified set of risks that we manage. Jackie Richert Operator, I think we're going to have time for one more question. Okay. And our last question will come from Anthony Crowdell with Mizuho. Your line is now open. Anthony Crowdell Hey, thanks for squeezing me in. I appreciate it. Just two quick ones. I'm not sure if one was answered. If I look on slide 3 and the plan and everything else, if I remember correctly, your system resiliency plan was between $2.2 billion and $2.7 billion. $2.2 billion was the base case. Then, what's on slide 3 be accomplished as a $2.7 billion number, or that would be above the $2.7 billion number? Chris Foster Anthony, morning. I was thinking about it within the $2.7 billion. Keep in mind that we provide that higher end as an articulation of the ability to accelerate some work, and that's really what you're seeing here is a pretty aggressive acceleration here in 2024 to make sure we're doing more work on the system. Anthony Crowdell Great. And then a follow-up to an earlier question, you guys identified a lot of the outages occurred due to, I think, trees that are on customer's property. You guys didn't really have any responsibility over it. I mean, does undergrounding become more of a solution in your service territory than maybe years past? Jason Wells Yeah, thanks, Anthony. It's a great question, and I think one where there's certainly going to be a greater push for undergrounding, and it will play probably an even more prominent role in our resiliency efforts going forward. But what I think is important as well as to kind of balance it, about 60% of our customers today receive service through underground lines. It's a pretty significant penetration of undergrounding already in the system. But the point of weakness is those communities are often fed with overhead lines kind of at the feeder level. That's where we saw the tree damage. And so, I think we have to find a balance between undergrounding where it makes sense and where we have overhead lines, making sure that they are hardened and more resilient so that they're not the single point of failure, so to speak, from an outage standpoint. So, it's a little bit of an all of the above, but I would imagine that undergrounding takes an even greater prominence moving forward. Great. Operator, with that, that will now conclude our Q&A for the day. I appreciate everyone dialing in. I think with that, we'll conclude the call. This concludes CenterPoint Energy's second quarter 2024 earnings conference call. Thank you for your participation and have a good day.

American Electric Power Company, Inc. (AEP) Q2 2024 Earnings Call Transcript

American Electric Power Company, Inc. (NASDAQ:AEP) Q2 2024 Earnings Conference Call July 30, 2024 9:00 AM ET Company Participants Darcy Reese - VP, IR Ben Fowke - Interim President, Interim CEO & Director Peggy Simmons - EVP, Utilities Charles Zebula - EVP & CFO Conference Call Participants Shar Pourezza - Guggenheim Partners Jeremy Tonet - JPMorgan Steven Fleischman - Wolfe Research Carly Davenport - Goldman Sachs Andrew Wiesel - Scotiabank Durgesh Chopra - Evercore ISI Sophie Karp - KeyBanc Capital Markets William Appicelli - UBS Julian Smith - Jefferies Paul Patterson - Glenrock Operator Thank you for standing by. My name is JL and I'll be your conference operator today. At this time, I would like to welcome everyone to the American Electric Power's Second Quarter 2024 Earnings Call. All lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question-and-answer session. [Operator Instructions] I would like to turn the conference over to Darcy Reese, President of Investor Relations. You may begin. Darcy Reese Thank you, JL. Good morning, everyone, and welcome to the second quarter 2024 earnings call for American Electric Power. We appreciate you taking time to join us today. Our earnings release, presentation slides, and related financial information are available on our website at aep.com. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for discussion of these factors. Joining me this morning for opening remarks are Ben Fowke, our President and Interim Chief Executive Officer; Chuck Zebula, our Executive Vice President and Chief Financial Officer; and Peggy Simmons, our Executive Vice President of Utilities. We will take your questions following their remarks. I will now turn the call over to Ben. Ben Fowke Good morning, and welcome to American Electric Power's second quarter 2024 earnings call. Shortly, Peggy will provide a regulatory update, followed by Chuck, who will review our financial results in more detail. A summary of our second quarter 2024 business highlights can be found on slide 6 of today's presentation. Before I dive into our results, I would like to start by welcoming Bill Furman to AEP as our new President and CEO, effective August 1st. Bill brings decades of utility operational leadership experience and in-depth knowledge of the energy industry, most recently serving as President and CEO of Century Holdings, and prior to that, President and CEO of Berkshire Hathaway Energy. With Bill's expertise and diverse background, you can anticipate a smooth transition and continuity of strategic direction. Expect more focus on execution, and Bill has the background to do just that, including capturing growth, listening and responding to our regulators and investors, and using innovation to mitigate inflationary pressures. While I will be serving as Senior Advisor for several months to ensure a smooth transition, it's been an honor to lead AEP as Interim President and CEO, and I'm proud of what the team has accomplished so far this year. Now, turning to AEP's financial results. Today, we announced second quarter 2024 operating earnings of $1.25 per share, a $0.12 increase over one year ago. Our operational execution through the first half of the year, combined with our efforts to efficiently manage the business, have put us well on track to achieve our targets. Today, we reaffirm our 2024 full-year operating earnings guidance range from $5.53 to $5.73, and our long-term earnings growth rate of 6% to 7%. Regarding data center load, we have commitments from customers for more than 15 gigawatts of incremental load by the end of this decade, mostly driven by large load opportunities. To put this in perspective, AEP's system-wide peak load at the end of last year was 35 gigawatts. We continue to work with data center customers to meet their increased demand, while ensuring contracts and new initiatives are fair and beneficial for all of our customers. In the fall, we will provide an update on what this large load opportunity means for our capital spend, including generation and transmission investment, and on our plan to responsibly finance this growth initiative. While we certainly encourage innovation when it comes to meeting the energy needs of our customers, data centers included, I want to emphasize that it is critically important that costs associated with these large loads are allocated fairly, and the right investments are made for the long-term success of our grid. For this reason, we filed new data center tariffs in Ohio and large load tariff modifications in Indiana and West Virginia, and it's the reason why we filed a complaint with FERC related to a co-located load agreement. We will know soon what FERC decides, but this is the rationale we used. Given the co-located load agreement is an active case before FERC, I don't plan on making any further comments. I'd also like to note that large load impacts are already being felt here in AEP's service territories, primarily Ohio and Texas, as our commercial load grew an impressive 12.4% over the second quarter of last year. Looking ahead, we expect the incremental load I just mentioned to move forward in these states and others, including Indiana. Moving to another example of capital opportunities, PSO announced an agreement at the end of June to purchase a 795-megawatt natural gas generation facility conditioned on regulatory approval. The facility, known as Green Country, is located in Jenks [ph] Oklahoma, and will ensure PSO customers continue to benefit from reliable and affordable resources. For this resource adequacy-driven capital, PSO plans to seek regulatory approval this fall, at which time the economics of this acquisition will be made public. As you know, maintaining a strong balance is critical to fund increased capital spend to support our growth initiatives. We will sensibly finance our capital needs, and we're open to incremental growth equity and equity-like tools, in addition to portfolio optimization. On a similar portfolio note, the sale of AEP on-site partners remains on track to close in the third quarter following FERC approval. Now let's move on to the Federal EPA's Coal Combustion Residual Rule, or CCR, which was finalized in the second quarter and expanded the scope of the rule to include inactive impoundments at existing and inactive facilities. We continue to evaluate the applicability of the rule to current and former plant sites, and have developed preliminary estimates of compliance costs. While we are working with others and looking at potential legal challenges to the revised rules, as appropriate, we do plan to seek cost recovery through new and or existing regulatory mechanisms. Chuck will have more information on this shortly. Before I turn it over to Peggy for additional updates, I'd like to thank all of you for your support during my time as AEP's interim CEO. I've been privileged to serve AEP over the past five months, and the board and I are confident that Bill is the right person to build on the momentum underway and to lead AEP into its next chapter. On a related note, we are planning an informal meet and greet in New York City soon, so analyst investors can say hello to Bill in person. We are targeting something in August, so stay tuned for more information coming your way in the next couple of days. Finally, I'm excited about what the future holds for AEP as we execute on our strategic priorities and enhance value for all of our stakeholders. Peggy? Peggy Simmons Thanks, Ben, and good morning, everyone. Now let's turn to an update on several of AEP's ongoing regulatory initiatives. We are engaged in our regulatory and legislative areas, continuing to strengthen relationships, including implementation of our investment in more people and resources at the local level. And as the utility industry is changing, now more than ever, AEP's operating company leaders are staying increasingly engaged with regulators amidst this dynamic environment. Customer bills and affordability remain top of mind for AEP, in addition to system reliability and resiliency. We are focused on advancing interest in each of the states we operate, which includes economic development, work across service or service territory to bring jobs and create Bill headroom from a larger load perspective, and to ultimately achieve the regulatory outcomes that are good for AEP's customers, communities, investors, and employees. We continue to work through regulatory items with the focus on our authorized versus earned ROE gap, which remained flat at 8.9% for the past 12 months as of second quarter 2024. Turning to some positive rate case development, let's start with INM. I'm pleased to report that in May, we received an order in Indiana approving all key items in our settlement, including an improved 9.85% ROE. In June, we received a constructive order in Michigan maintaining our existing 9.86% ROE, with new rates taking effect in mid-July. Just last week for AEP Texas, parties filed a unanimous and unopposed comprehensive settlement with the ALJ increasing our authorized ROE to 9.76%, with rates effective in early October pending commission approval. As you know, earlier this year, we filed an APCo biennial rate review in Virginia and a base rate case for PSO in Oklahoma, where we received intervener testimony in the PSO case last evening. We're at the beginning of the procedural schedules in both cases and expect commission orders in the fourth quarter. We look forward to sharing updates on our progress in the coming months. Relative to future cases, APCo plans to file a base rate case in West Virginia in the next week. While we have many trackers in place to help mitigate regulatory lag, we have not had a rate case here in a few years and look forward to working with the parties to achieve a balanced and fair result. Looking ahead, I am proud of the progress we continue to make on the regulatory front and I remain excited about advancing our regulatory strategies in 2024 and beyond. Let's discuss AEP's recent fleet transformation activities and the progress we made on that important initiative. In May, APCo issued requests for proposals for 800 megawatts of wind or solar owned resources with regulatory filing anticipated in 2025. Finally, as Ben mentioned, PSO signed an agreement in June to purchase Green Country's 795 megawatt natural gas generation facility to help ensure resource adequacy. The agreement is conditioned on regulatory approval and we plan to make the related filings with the Oklahoma Commission in the fall. This is an example of a proactive approach by the team in meeting ever increasing resource needs and we're enthusiastic about the opportunity as we advance our fleet transformation. To wrap up, I'd like to thank Ben for his leadership and welcome Bill to the AEP team. This is an exciting time here at AEP and when I think about the future, I'm motivated by the opportunities we have ahead of us, embracing large loads, advancing our regulatory strategy, and driving overall long-term success. I'll now turn things over to Chuck who is going to walk through second quarter 2024 performance drivers and details supporting our financial results. Chuck? Charles Zebula Thank you, Peggy, and good morning, everyone. Let's jump right into our second quarter results. Slide seven shows the comparison of GAAP to operating earnings for the quarter and year-to-date periods. GAAP earnings for the second quarter were $0.64 per share compared to $1.01 per share in 2023. Year-to-date GAAP earnings are $2.55 per share for this year versus $1.78 per share last year. There's a detailed reconciliation of GAAP to operating earnings for the second quarter and year-to-date results on pages 13 and 14 respectively. Let's briefly highlight a few of the non-operating items for the quarter that mostly make up the difference between GAAP and operating earnings. First, as disclosed in an 8-K in May, an after-tax provision of $126 million for customer refunds was recorded based on recent developments in the remand proceeding related to the cost cap associated with the Turk plant that has been debated over the last decade. Secondly, we incurred a $94 million expense associated with a voluntary severance program that we completed in the second quarter. And finally, as Ben mentioned, the final revised EPA CCR rule became effective in May. We recorded a $111 million accrual for compliance costs largely related to our Ohio properties where generation is deregulated. We also updated our asset retirement obligations for sites in our regulated entities where we intend to seek cost recovery. Let's walk through our quarterly operating earnings performance by segment on slide eight. Operating earnings for the second quarter totaled $125 per share or $662 million compared to $113 per share or $582 million in 2023. This results in an increase of $80 million or $0.12 per share, which is a 10.6% increase over last year. Operating earnings for vertically integrated utilities were $0.46 per share, down $0.05. Positive drivers included favorable year-over-year weather and rate changes across multiple jurisdictions, with the 2022 PSO base case and the 2023 Virginia proceeding being the most significant. These items were offset by higher income taxes, which are largely a reversal of favorable income taxes in the first quarter, lower normalized retail sales, and higher depreciation. Note the year-to-date results in this segment consolidate the income tax loss that is shown in this quarter, resulting in an immaterial year-to-date income tax variance versus last year. The transmission and distribution utility segment earned $0.41 per share, up $0.11 compared to last year. Positive drivers in this segment included favorable weather, increased transmission revenue, rate changes primarily from the distribution cost recovery factor in Texas, and higher normalized retail sales. These items were partially offset by increased property taxes and depreciation. The AEP transmission Holdco segment contributed $0.39 per share, up a penny compared to last year, primarily driven by investment growth. Generation and marketing produced $0.12 per share, down a penny from last year. Recall that AEP renewables was sold in the third quarter last year, which has two impacts, a negative earnings variance due to the business being sold and removal of the interest costs for financing these assets. Additional drivers were lower retail margins offset by higher generation margins and lower taxes. Finally, corporate and other was up $0.06 compared to the prior year, primarily driven by lower income taxes and increased other operating income related to timing in the prior year. These items were partially offset by higher interest expense and lower interest income from the GNM segment. Let's turn to slide nine, which shows weather normalized retail sales of 4% in the quarter from a year ago, headlined by a double-digit 12.4% increase in commercial sales, which is where our data processing customers are classified. I'll note that in our T&D segment, the increase in commercial load was over 20% for the quarter. This is a trend that will continue over the coming years based on already signed customer commitments. Our operating footprint and robust transmission system position us perfectly to grow along AI and other technologies and industries in need of access to affordable and reliable power. Through the remainder of this year, data processing gains will remain mostly concentrated in Ohio and Texas. But beyond this year, we are seeing strong commitments from new customers looking to connect at some of our vertically integrated companies as well. Outside of data processors, our industrial sales have remained resilient in the face of a slowing economy. Industrial sales were strongest in Texas, driven by an influx of new customers, mainly in the energy industry. Thanks to our success over the past few years on the economic development front, we expect to see our industrial sales continue to be resilient in the next few years as several new large customers in steel, energy, renewable energy, and semiconductors come online across our footprint. In the residential segment, we continue to see growth in customer count and load in Texas, but residential load remains weak in most of our territories, likely due to the cumulative effects of inflation. Bottom line, the amount of demand from new large loads we're seeing across our system is unprecedented. We are excited, challenged, and poised to embrace this opportunity. Let's move on to slide 10. In the top left table, you can see the FFO to debt metric stands at 14.6% for the 12 months ended June 30th, which is a 40 basis point increase from the prior quarter. Our debt-to-cap decreased slightly from last quarter and was 62.6% at quarter end. We took credit-supportive financing actions in the second quarter by issuing $400 million of equity under our at-the-market program and by issuing $1 billion in junior subordinated notes at the parent, which qualified for 50% equity credit at all three rating agencies. In the lower left part of this slide, you can see our liquidity summary, which remains strong at $5.4 billion and is supported by $6 billion in credit facilities. Lastly, on the qualified pension front, our funding status is near 99%. In summary, our second quarter results provide additional momentum this year, bringing year-to-date earnings up to $2.52 per share, an increase of $0.28, or 12.5% compared to the same period last year. We reaffirm our operating earnings guidance range of $553 to $573 and remain committed to our long-term growth rate of 6% to 7%. And as we move through the balance of the year, our focus is on providing reliable and affordable service to our customers, executing our plan, and embracing the growth opportunities that we have ahead of us. Also, a quick update on the sale of AEP on-site partners. We expect the transaction to close in the third quarter and result in approximately $315 million in net proceeds to the company. I'd be remiss if I didn't acknowledge the skilled leadership of Ben Folk during this time of transition at AEP. Ben told you that this company would not be in neutral during the transition, and I can say that that is absolutely true. Ben, while I know you'll still be engaged as an advisor and board role going forward, I want you to know that the AEP team appreciates your engagement and contributions over the past five months. Finally, the AEP team looks forward to the arrival of our new CEO and President, Bill Furman. We all look forward to Bill bringing his accomplished leadership to AEP and working with him as we take on the exciting opportunities that we have before us. Thank you for your interest in American Electric Power. Operator, can you open the call so we can address your questions? Thank you. Question-and-Answer Session Operator Thank you. [Operator Instructions] Your first question comes from the line of Shar Pourezza of Guggenheim Partners. Your line is open. Shar Pourezza Hey, guys. Good morning. Ben Fowke Morning. Morning. Shar Pourezza Just firstly, obviously, you guys highlighted in the deck, "the direction and strategy" kind of remain on track. I guess how much latitude will Bill have to make kind of strategic changes if need be to accrue value? Or is the plan kind of the plan and any kind of changes you expect will likely be more on the fringe, given your and the board's comfort level with the trajectory, with obviously the latter kind of being a similar situation to one of your other Ohio peers in the state when they had an incoming CEO? Thanks. Ben Fowke Yes. I think that was a lot different circumstance, Shar, but Bill's very familiar with our strategy. We clearly had conversations with Bill about our strategy. So I think it's, I think we're on the right strategic direction. I do think Bill's going to come in and focus very much on execution. He's got a ton of experience, as we mentioned. And so I mean he'll take some time, assess where we are and I'm sure he's going to make some changes, but I don't see significant changes in the strategic direction. It's not like we gave him a plan, a to-do list, and you do all these things. He's going to be a dynamic leader. But the path we're on is, I think we're all in agreement, it's the right path and we need to execute on it. Shar Pourezza Okay, perfect. And then last time, obviously we've talked about higher CapEx coming, driven by customer growth, data centers, etcetera. As we're kind of thinking about that incremental CapEx, potentially with a 3Q update and a funding source, the balance sheet doesn't have a material amount of capacity. You touched on this a little bit on your preparedness, but maybe you can elaborate on how you're kind of thinking about incremental equity versus asset sales, and with asset sales, how you're thinking about distribution versus transmission. Thanks, guys. Ben Fowke Yes, I mean, clearly we're going to have an update in the fall, either at or right before EEI, that incorporates what it means to CapEx to fund this low growth, both in generation and transmission, and of course, what it means to make sure the balance sheet is strong in terms of equity and equity-like products, including portfolio optimization. Regarding portfolio optimization, you've heard me say it before, we're always open to it, but price has to be there, and the ability to execute has to be there. And the regulated utility spaces, those are two hard things to put together at the same time, but we're open to it. Chuck, I don't know if you want to add anything to it. Charles Zebula Ben, the only thing I would add is, right, it's so important as we are a regulated utility and have significant capital needs not only today, but going forward right, to maintain investment credit ratings, and we will defend that right in our plan. Shar Pourezza Got it. Perfect. Thank you. And by the way, just a real big congrats on Bill. He's one of the best hires. Thanks, guys. Charles Zebula Thanks. You did mention, Shar asked the mix between distribution and transmission. So, it's going to, there's obviously going to be a lot of transmission that needs to be built, as well as distribution. Operator Thank you. Your next question comes from the line of Jeremy Tonet of JPMorgan. Your line is open. Jeremy Tonet Hi, good morning. Ben Fowke Hey, Jeremy. Jeremy Tonet Hey, I know you're not going to give us the full details here, but I was just wondering if there's any way you could help us think through size and shaping of this incremental CapEx, as you talked about, with the incremental wires needs here. It just seems like everything is materializing quicker than expected. And so, just wondering if you could comment, I guess, any shaping there that would be helpful. Ben Fowke Yes. Well, as I mentioned, with Shar's comment, I mean, you're definitely going to see a lot of increase in transmission spent. There's got to be something to plug into, so we're going to have generation, as well, and we recognize the need to make sure we have reliable distribution grid. So, I think if I had to rate it, it would be transmission increases, followed by generation, followed by distribution. Charles Zebula Jeremy, I would say you'll note, in our materials that we raised our CapEx this year already by $500 million. That largely is in T&D, right? It's for reliability spend, also customer hookups, and then storm-related capital. So the shape of it right, is going to be as these customer additions, come online. And again, as Ben mentioned, we'll be laying all that out in the fall. Jeremy Tonet Got it. So, it sounds like there's an opportunity for more near-term, as opposed to just later data at this point, if I understand correctly. Charles Zebula I think that that's true. Jeremy Tonet Got it. I was just wondering if you could talk a bit more on PSO's natural gas generation purchase there. To what extent do you see the need for incremental gas generation, across Oklahoma, other service territories? Just wondering if you expect to see more of this. Peggy Simmons So, I would say, this is Peggy, and I would say with the increased reserve margins that we're seeing from the RTOs and the additional load that we're starting to see across our system, we are going to need some additional generation. And this was a very proactive approach that the team took as I mentioned in my comments earlier, to go out and find some affordable assets that we could bring onto the system. And we plan to make that filing at the Commission later this fall. Ben Fowke Yes. Peggy mentioned proactive. It really, I think, was creative. It was outside of the RFP process, but we have an RFP process to compare the pricing to, and it's clearly very favorable. So, we're really excited about it. I think it'll be great for our customers. Jeremy Tonet Got it. Thank you for that. Operator Your next question comes from the line of Steve Fleischman of Wolfe Research. Your line is open. Ben Fowke Hey, Steve. Steven Fleishman Hey, good morning. Sorry, I've got several questions on data center, or data processing, as you called it. So first of all, just in the quarter, you had the very strong commercial sales growth, but then your normalized sales growth between the two subs, I think was actually down $0.04. When you kind of look at both vertical and T&D, could you just talk to how we should think about that? Ben Fowke Yes, in T&D, Steve, normalized sales were up $0.02. Steven Fleishman Right. But then the vertical was down $0.06, I think. So I guess just thinking, when I look at the whole picture, it's not kind of, at least in that line item, doesn't seem to be showing up as a benefit. Ben Fowke Yes. So, let me comment on the negative $0.06 in vertically integrated. That's largely due to in vertically integrated, we had in the quarter, but a 4.9% decrease over last Q2 in residential sales. And that's largely what drove that number. In our SWEPCO territory, we had in kind of mid to late May into early June, we had a number of repeated storm activity, tornadic activity that took, large swaths of customers out for significant amounts of times that drove that number down. We've seen that start to normalize back in June and July. So I expect that to return to a more normal state. Steven Fleishman Okay. Thanks. And then on the 15 gigawatts of committed data center sales to 2030, could you just maybe better define what committed means when you give that data point? Ben Fowke Yes. I mean, it basically means that we have a letter of agreement, and those letter of agreements, Steve, start the clock running, if you will, for us to do work that pretty quickly can go into the millions, which that customer who signed the letter of agreement is required to pay. So that's how we define it. As we look forward, we look at a number of filtering criteria, ownership of sites, etcetera, that we use. So these are far from just inquiries. These are, serious customers that want to get on the grid and are willing to financially commit to do what it takes to get on the grid. Steven Fleishman Okay. And are those customers kind of committing to these new tariffs you filed, or are we not at the point where they've made the agreement that those tariffs work for them when they've kind of done this? Ben Fowke Yes. Those tariffs, as you know they haven't been approved yet, but they will need depends where they are in the signing process as to whether or not they will be held to those tariffs or not. But going forward, customers, if approved, will all be required to step up to the tariffs. Steven Fleishman Okay. And then....yes. Ben Fowke Which, as you know, I mean, well, as Steve was just going to say, it's just, it's really important. We're going to see more growth than we've seen in maybe generations. And it's going to be really important that that growth is beneficial for all customers and at the worst case, at least neutral. And that's exactly why we're trying to, that's exactly why we're so keenly focused on making sure that we have these tariffs and the modifications I mentioned in Indiana and West Virginia. And it's just, we got to get it right. Steven Fleishman Okay. And then maybe just in terms of helping to frame the capital needs, just, can you give us some rough sense of that 15 gigawatts, how much might be related to vertically integrated parts of AEP versus the transmission only parts? Ben Fowke Yes, Steve. So the way to think about it is, think of it as a 50-50 split between Texas and PJM. 50%, or of course, Texas, right, is our wires company and PJM, take that 50% and basically split it 50-50 between INM, which is vertically integrated and AEP Ohio, right, which is wires only. Steven Fleishman Okay. So that would be kind of 75-25, I guess, roughly, I think. Yes. Ben Fowke Okay. I think I've, yes. But we are seeing additional interest amongst other vertically integrated utilities, but that interest is not as firm yet. Steven Fleishman Amongst some of your other vertically integrated. Ben Fowke Yes, that's correct. Steven Fleishman Yes. Okay. Great. I'll leave it there. Thank you very much. Ben Fowke Thanks, Steve. Operator Your next question comes from the line of Nick Campanella of AEP [ph]. Your line is open. Unidentified Analyst Nick Campanella at Barclays here. Thanks for the time. Ben Fowke Did we just hire Nick? Unidentified Analyst I never got the call. I never got the call, but thanks for the time. A lot of my questions have been answered, but I just, curious as we kind of try to think about the magnitude of capital that the plan can handle here. I know that there's financing considerations, but there's also kind of bill growth considerations. Just how high do you think your rate-based growth can get before you have to start thinking about customer bill impact, especially as some of this load should be able to supplement that, but just trying to see, where this rate-based CAGR could go at the end of the day. Thank you. Ben Fowke Yes, I think the incremental CapEx will be driven to support new load growth. And that's why we're just so keenly focused on making sure we get the rules right. And our modeling suggests that it will be good for all customers. And that's, I mean, that's what makes me so excited about this is that everybody can benefit, load's good for all, and it's going to, there are certainly pressures, on the grid and the resiliency and things like that, but I think the load's going to be beneficial to mitigate cost increases. Unidentified Analyst Okay. Thanks. And then I guess, since you've kind of taken over, you have kind of pulled some strings on this involuntary, this voluntary severance program, just where are there other opportunities in the plan to cut costs today, or just things that maybe we're not thinking about that could be incremental to the positive? Ben Fowke Again, as I mentioned, I think, you've got Bill Furman coming in, he's got a track record of innovation. The companies in the Berkshire Hathaway portfolio were extremely well run. Bill is extremely well respected. So I think he's going to bring a lot of great ideas. It's a lot of blocking and tackling, and also taking advantage of innovation, smart technologies, etcetera, that'll get us there. But, the team has done a really good job, if you look back, in keeping O&M in check. So, again, I think the biggest way we keep costs down on our customers is to bring this new load on and bring it on in ways and rules and tariffs that are fair to all. Unidentified Analyst Thank you. Ben Fowke Thanks. Operator Your next question comes from the line of Carly Davenport of Goldman Sachs. Your line is open. Carly Davenport Hey, good morning. Thanks for your time. Just a couple of clarification questions, if I could. First, just on the 15 gigawatts of incremental load by the end of the decade, could you just clarify, is all of that related to data centers, or is there anything else in there? And then, is there anything you can provide on how to think about the cadence of that load materializing from a timing perspective? Ben Fowke Yes, the 15 gigawatts refers to all data centers, and we're not announcing the cadence of that at this time. But it's already, as you can see, it's already showing up in our numbers. So we are hooking up, folks, and you'll see continued increases, over the next several years. Carly Davenport Great. Thank you for that. And then, just a follow-up is just on the earned versus authorized ROE gap. I know you mentioned the earned ROE sort of flatted at 8.9% on a trailing 12-month basis. Do you have that comparable weather normalized number similar to what you've provided in previous quarters? Peggy Simmons Oh, we're looking forward to be at 9.1% for this year. As I mentioned, over the past 12 months, I mean, on a rolling average right now, we're at 8.9% [ph] which is flat to where we were last quarter, but continuing to make progress on that front. Carly Davenport Got it. Great. Thanks so much for the time. Ben Fowke Thank you. Operator Your next question comes from Andrew Wiesel of Scotiabank. Your line is open. Ben Fowke Good morning. Andrew Weisel Hi, good morning. First, a quick governance question. Can you please talk about the outlook for the board, and specifically what roles will Ben and Bill each have? Who will be chair of the board, and will it be executive or non-executive? And how large will the board ultimately be? Ben Fowke Okay. Well, I will go back after my time as advisor, I'll go back to being a board member, and I will keep my independence. Bill obviously will be on the board. He'll be a non-independent director. Sara Martinez Tucker, or Sara Martinez Tucker will be the chair, and she will remain chair, and she's independent. Size of the board, we are basically at full size, and so there won't be any change to the size of the board. I don't know. Did I get all those questions? Andrew Weisel Yes. That's great. Thank you very much. And then just a quick question on the cash flow slide, page 22. Some moving parts in 24 has led to slightly higher equity needs this year by about $100 million. Can you elaborate a little bit on that? And then looking to 2025 and beyond, I see no changes. Would I be right to assume that sort of just waiting for the update in three months? And just to clarify your comment on the equity-like tools, are you referring to the junior subordinates, or could there be something else in there, like equity units perhaps? Ben Fowke So, Andrew, first question. You also note in 2024, we had a $500 million increase in CapEx, and versus our plan for the year, we had additional asset sales that were part of the original plan that ended up changing through the year. So, in our financing, in our cash, we received less proceeds because of that change in plan. So, those two things basically drove the opportunity for the increase in equity, and just being opportunistic in the market as well. You're right, going forward, we have not updated those cash flows yet for our annual update, which we'll do at EEI. Andrew Weisel Okay. The equity-like, was that just referring to the junior subordinates, or was there more to it? Ben Fowke Yes, that refers to the notes that we issued in June. But we would look at various forms of equity alternatives and be holistic in our approach. Andrew Weisel Very good. Appreciate the details. Thank you. Operator Your next question comes from the line of Durgesh Chopra of Evercore ISI. Your line is open. Durgesh Chopra Hey, team. Good morning. Good morning, Ben. Andrew actually asked my question on the financing slide. Chuck, maybe a little sort of more color, there were kind of more negatives to positives in that cash flow slide. I mean, the asset sale proceeds were lower, right, and the CapEx is higher. Just assuming normal weather for the rest of the year, are you going to be below 14.6 where you said, or should we kind of think about 14.6 as strong as going into the end of the year? Charles Zebula Yes, our plan is to be in the 14% to 15% range. I'll just note, right, that we're well above the 13% downgrade threshold. So, yes, we plan to be in that range. Durgesh Chopra Okay. Thank you. Appreciate the time. Operator Your next question comes from the line of Sophie Karp of KeyBanc Capital Markets. Your line is open. Sophie Karp Hi. Good morning. Thank you for squeezing me in. If I could quickly go back to the 15 gigawatts of data center load, I guess, could you provide some color on how much of that can be connected without any incremental investment in your system versus how much would they require incremental investments to facilitate that? Peggy Simmons Right now, none of that can be connected at this point in time, but as we look at our LOA process, that's why we are looking at any initial upgrades that are needed as we prepare to plan the system to connect this load over that period of time. Sophie Karp Got it. Got it. Thank you. And then maybe a little bit more of an open-ended question. Your current outstanding RFPs don't have any gas in them. It's mostly renewables. And I'm just curious of how you think about the cadence of needing to add dispatchable generation there. And when it comes to gas, will you continue to have a bias towards acquiring existing assets or will we see some new builds potentially? Peggy Simmons So, our RFPs are all-source RFPs, so we're evaluating all technologies that come in. And we do believe the dispatchable resources are needed to be added to the grid as well, and they will be part of the plan. Sophie Karp Okay. Thank you. Peggy Simmons You're welcome. Operator Your next question comes from the line of Bill Appicelli of UBS. Your line is open. William Appicelli Hi. Good morning. Thanks for taking my questions. Just want to dig into a little bit more on the sales growth trends. So, on the residential side, you commented that Texas looks strong, but that more broadly, the cumulative effects of inflation have been weighing on it. So, any more color there? Are you expecting an improvement in the second half of the year? Ben Fowke Yes. So, Bill, in Texas, right, there is customer growth as well as, increase in use or as a result, increase in usage. In vertically integrated year-to-date, residential is down 1.3%, and T&D is actually up 0.3%, largely due to Texas. So, we are seeing, I think, in Appalachian Power, in Kentucky Power, in SWEPCO in particular, and I mentioned, some of the weather occurrences that we had in the SWEPCO area, weaker residential sales in those areas in particular. William Appicelli Okay. I mean, I guess we think about the EPA activities here, right, because you've got the, tremendous growth in the commercial side, right, tracking well above plan, but that's going to be lower margin volumes. And then maybe on the residential side, going back sort of four of the last five quarters, sort of as a negative, and that's obviously a bit of a higher margin, but, smaller overall change. What, we sort of reconcile that a little bit as we think about the EPA's impact. Ben Fowke Yes. I mean, clearly the residential sales are higher margin, but, again, I think it's, in particular, the effects of inflation. So, if inflation comes in tame, tamer as we begin to, as we've begun to see if wage growth, continues to close that gap. And as Ben mentioned, right, the opportunity to bring on large loads to spread fixed costs, right, over a much larger denominator, right, should mitigate, right, some of those customer rate impacts as well. So the combination of those things, right, should begin to, slow that decline. But, clearly, the effects of inflation have hit home for a lot of customers. William Appicelli Right. Okay. And then I guess the other question is, it's come up a little bit, but on the episode of debt, under, I guess, the Moody's methodology, do you know what that number would be? Ben Fowke Yes, it's 14.6 under Moody's. William Appicelli Oh, it's under Moody's. Okay. All right. Thank you very much. Operator Your next question comes from the line of Julian Smith of Jefferies. Your line is open. Julian Smith Hey, good morning, team. Thank you guys very much for the time. I appreciate it. Going back. Thank you very much. Appreciate it. Maybe going back to some of the conversation on the layoffs and severance bit. I just want to understand the extent to which this process is finalized, right? You've given very specific jurisdictional level details. And given that, how are you thinking about rebuilding and devolving some decision-making power and some of the roles to the local OpCo's? Can you speak to perhaps what seems like perhaps a strategic shift in looking at local level decision-making and really what level or what quantity of the roles in terms of overall layoffs will actually be ultimately recreated, if you will, at the local level here? So both the financial question in terms of what's the sort of ongoing net savings and B, how do you think about this fitting within the strategic question of devolvement? Ben Fowke Yes, I'm going to turn it over to Peggy in a second. But just as a recap, we did hit our targets that we laid out under that voluntary severance program. And we plan to hold as much of those gains as possible. Probably have to do some hiring back, but try to keep that minimized. Remember, there was two-pronged approach for this. One, we wanted to mitigate some of the inflationary pressures that we were seeing, higher interest rates, just overall increase in supply chain, etcetera, and take a portion of that, albeit a smaller portion, and start putting those, some of those resource, some of that money back into our local communities with more boots on the ground, if you will, more community leadership positions and that sort of thing. So Peggy, do you want to? Peggy Simmons Yes, Ben. So yes, that's exactly, Julian, what we're looking to do. We are, some of those positions were leadership positions that report to some of our Presidents. We are making sure that we are getting those filled and we're adding additional resources in the regulatory and legislative space, because we know that as dynamic as our industry is and as much change as is occurring, we want to make sure that we have that enhanced engagement at those levels. So you'll see more of that. Julian Smith Excellent. All right. Looking forward to that. And then related, you talk about these staggering levels of the 15 gigawatts of firm commitments at this point. How do you think about that marrying up, especially in your wires businesses against an effort to address generation needs? I know this has been an ongoing tension, but given what seems like yet an accelerating backdrop of generation needs, how do you think about your utilities, especially in the buyers only businesses, potentially re-engaging in that narrative? And in what ways? Ben Fowke Well, I mean, I think that would take legislation clearly in Ohio. I guess it would take it in Texas, too, but I don't see that happening. I think it's probably a long shot in Ohio as well. So, we are going to have to rely on the market, but our vertically integrated utilities are all going to need generation and in different timeframes. But I think Peggy mentioned, we've got, we do have more with the changes in the reserve margin requirements, for example, in SPP. It creates a resource need, and we're developing our plans to fill that, which will require increased CapEx, which I think is a good thing. And we're really, again, excited about Green Country. The load is tremendous, and it's primarily data centers, but of course we'd be remiss if we didn't mention we've seen industrial load in Texas as well. And I think when we think about economic development, we're going to continue to look for opportunities to bring industry back on shore. And I'm right here in Columbus today, and the Intel has just been an enormous success, and we're going to keep looking for opportunities for our communities, and, again, all customers benefit from that. Julian Smith All right, guys. Thank you very much. I appreciate it. Ben Fowke Thank you. Operator Your last question comes from the line of Paul Patterson of Glenrock. Your line is open. Paul Patterson Good morning. How are you doing? Ben Fowke I'm doing good. Paul Patterson Great. So I asked this question some time ago about Chevron, and we now have a Supreme Court decision. And I'm just wondering how you guys see it potentially impacting either EPA or FERC regulation or anything else you might, if you think it has any potential impact on AEP, I guess. Ben Fowke I think it's early, but, yes I think it could potentially be helpful as courts have more discretion not to have to rely on the agencies, which that was the whole point of that. And I just think it doesn't bind the courts as much as it probably did in the past. Now, whether that, how the courts interpret it, what, the rulings are, we'll have to wait and see. But Paul, I think in general it's going to be helpful. And we are going to challenge a lot of these EPA rules, as you know, the CCR rule, the ELG rule, the 111 rules. I guess all of the rules that have come out we're going to challenge and for good reason. Paul Patterson Okay, great. And then just on FERC, do you see anything happening there maybe? Ben Fowke I don't know. I think, I know there's some, there's some thought that it would, but I think that really, I'm not convinced it will. So, I think that remains to be seen. Paul Patterson Okay. The rest of my questions have been answered. Thanks so much. Have a great one. Ben Fowke All right, Paul. Thank you. Darcy Reese That concludes it. Thank you for joining us on today's call. As always, the IR team will be available to answer any additional questions you may have. JL, would you please give the replay information? Operator Certainly. Echo replay will be available in two hours until August 6th at 1-800-770-2030. That's 1-800-770-2030 using playback ID 6645529. That's replay playback ID 6645529 followed by the pound key. This concludes today's conference call. You may now disconnect.