American Electric Power Company Inc (AEP) — Q1 2025 Transcript

Good morning and welcome to American Electric Power's first quarter 2025 earnings call. A live webcast of this teleconference and slide presentation are available on our website under the Events and Presentations section. Joining me today are Bill Fehrman, President and Chief Executive Officer, and Trevor Mihalik, Executive Vice President and Chief Financial Officer. In addition, we have other members of our management in the room to answer questions if needed, including Kate Sturgess, Senior Vice President and Chief Accounting Officer. We will be making forward-looking statements during the call. Actual results may differ materially from those projected in any forward-looking statements we make today. Factors that could cause our actual results to differ materially are discussed in the company's most recent SEC filings. Please refer to the presentation slides that accompany this call for a reconciliation to GAAP measures. We will take your questions following opening remarks. With that, please turn to Slide 4, and let me hand the call over to Bill.

Thank you, Darcy, and good morning, everyone. Welcome to American Electric Power’s first quarter 2025 earnings call. We are off to an exceptional start to the year, having delivered strong results and advanced our long-term strategy to drive robust growth, enhance the customer experience, and achieve positive regulatory outcomes. We remain committed to investing $54 billion of capital over the next five years, an impressive amount close in size to our current market capital. This investment is to meet the needs of 5.6 million customers across 11 states. We actively manage our supply chain to ensure we deliver on our commitments, specifically related to current fine tariffs. We estimate that the direct tariff exposure on our $54 billion base capital plan for 2025 to 2029 is minimal at approximately 0.3%. Our company has a sizable generation portfolio and one of the largest transmission and distribution businesses in the nation. In fact, AEP owns and operates more 765kV transmission lines than all other utilities in the United States combined. Recently, we were awarded construction to build one of the first 765kV lines in Texas. We are enabling extraordinary economic development in high growth states like Indiana, Ohio, Oklahoma, and Texas and stand to benefit from these once-in-a-lifetime opportunities presented by the associated load growth. Trevor will go into this in more detail shortly. Our story continues to be one of consistency and commitment to delivering for our customers, states, regulators, and investors as we focus on execution and accountability and offer a compelling value proposition to our investors as we target 10% to 12% total annual shareholder return. We have a lot of exciting ground to cover today. I'll begin with a recap of our financial results at a high level before turning to strategic growth opportunities ahead and our recent regulatory and legislative successes. I'll then hand the call over to Trevor to walk through our financial results in more detail. Please refer to today's presentation for our quarterly business highlights and achievements starting on Slide 5. This morning we announced first quarter 2025 operating earnings of $1.54 per share or $823 million. With this strong performance, we are reaffirming our 2025 operating earnings guidance range of $5.75 to $5.95 per share and long-term operating earnings growth rate of 6% to 8%. This guidance is reinforced by a balanced and flexible $54 billion five-year capital plan with the potential for incremental investments of up to $10 billion over that same period. As we have communicated in the past, maintaining a strong balance sheet is vital to funding these capital spending needs. Later in the call, we'll go into more detail about AEP's commitment to credit quality and proactive actions we have taken in the first three months of 2025 to address AEP's equity needs. Moving forward, we will remain disciplined in sourcing efficient forms of capital to manage our needs in support of incremental investment opportunities. We are excited about the significant growth opportunities ahead, including the load growth in many parts of our service territory. This growth is not a hypothetical story; it is happening. AEP's total retail load growth has already been favorable over the past few years, primarily driven by commercial customers. In the first quarter of 2025, our commercial load grew 12.3% compared to the first quarter of last year. As we look ahead, AEP is extremely well positioned to participate in future growth across our footprint. We see opportunities to invest in critically needed infrastructure to support increasing electric demand. Our current capital plan includes customer commitments for over 20 gigawatts of incremental load by 2030, driven by data center demand, reshoring, manufacturing, and continued economic development. This incremental 20 GW is about a 55% increase over 2024 system-wide summer peak load. As we have consistently stated, we are absolutely committed to fair cost allocation associated with this large load growth. To that end, we proactively filed the data center tariff in Ohio and large load tariff modifications in Indiana, Kentucky, Virginia, and West Virginia. In the first quarter, we received commission approvals in Indiana, Kentucky, and West Virginia related to large load tariffs. The data center tariff hearing in Ohio also concluded in January, and we expect to have a commission decision in the second half of this year. These are all strong indications of our states' continuing commitment to attracting large loads with their economic impacts on local communities while also protecting our existing customer base. As we have previously discussed, meeting this incredible demand could require incremental investments of up to $10 billion underpinned by four major large loads in some of our bigger service territories, continued economic development in our states, investment across the system in our transmission and distribution infrastructure, and new generation. One of the reasons we are seeing such growth now is due to investments we made over the past decade to build an advanced 40,000-mile transmission system that can help support current large loads. Our transmission system also includes the nation's largest network of 765kV and 345kV lines. These ultra-high voltage lines position us extremely well in attracting hyperscalers to our system, who need consistent large load bulk power. We continue to invest in our distribution system, which is one of the nation's largest at approximately 225,000 miles. This includes work to harden infrastructure, build or rebuild poles, conductors, transformers, and other assets, as well as deploying automated technologies for enhanced operational performance. These efforts will help to increase customer satisfaction, strengthen our systems' resilience to weather events, and enhance the efficiency of our operations. As our generation needs increase to meet growing demand, we are engaging with key stakeholders and making thoughtful investments in new generation to align with their needs and state policies. Our team has worked diligently to develop creative energy solutions that keep our customers' needs top of mind. We have already shared our plans to begin the early site permit process in Indiana and Virginia for small modular reactors, or SMRs, that can generate clean, reliable energy to support significant load growth in our service territory. Additionally, we filed integrated resource plans, or IRPs, in both Arkansas and Indiana. These IRPs, in addition to other planned IRP filings over the next year in Kentucky, Michigan, Virginia, and West Virginia, will help meet our customers' energy needs and support AEP's generating capacity obligations, reinforcing our incredible growth. The fact is that demand for power is growing at a pace not seen in decades, and our expansive footprint enables us to significantly participate in this electric infrastructure super cycle. Now let's pivot to some traditional regulatory and legislative updates. In my nine months here at AEP, I have been actively engaged with stakeholders to underscore the importance of our customers and communities and how we work to meet their needs. Following meaningful progress in achieving positive regulatory developments in the second half of 2024, we are off to a great start in 2025 with approximately 80% of our rate-related revenue already secured for this year. In fact, AEP's first quarter earned ROE for our regulated businesses was 9.3%, up from 9.05% at year-end. As a reminder, some recent regulatory successes include a Commission decision approving construction in ERCOT's Permian Basin for one of the first 765kV transmission lines in Texas, opening up tremendous investment opportunities for AEP Texas; PJM transmission system upgrades awarded to AEP affiliates, including Transource Energy and our Transmission Companies; system resiliency plans approved at AEP Texas; a unanimous settlement reached at SWEPCO Texas; base cases approved in Oklahoma and Virginia; and recovery of annual transmission expense approved in Kentucky. In late March, we also filed a new base case in Arkansas requesting a rate increase of $114 million. This ask is primarily to align regulatory recovery of certain wind projects, including the rate implementation of the diversion and wagon wheel projects. Our application includes an ROE request of 10.9%, and SWEPCO anticipates an order and new rates effective in the first quarter of 2026. Previously, APCO filed its base case in West Virginia while offering securitization of up to $2.4 billion as a tool to mitigate the bill impact of a proposed $250 million base rate increase. The procedural schedule just kicked off last month, with intervener testimony and rebuttal testimony expected later this month. The hearing is set to start in mid-June. We look forward to working with everyone in this case to achieve a positive and balanced outcome later this year. We are intently focused on reducing regulatory lag and have made a number of other timely filings so far in 2025, including the AEP Texas TCOs and DCRF biannual filings, as well as SWEPCO's annual Foreign Reload Rate Plan in Louisiana. For I&M, the team recently filed to acquire an 870-megawatt natural gas plant in 2026, located in Oregon, Ohio, that will help I&M customers continue to benefit from reliable and affordable resources. We are also working diligently at the legislative level in several jurisdictions to advance policy changes to improve both recovery and customer affordability. For example, in Ohio, the recent passage of House Bill 15 positively results in multi-year forward-looking test years for future rate cases and includes grandfathering language for two behind-the-meter fuel cell contracts. Trevor will go into further detail on the OVEC-related impacts. In Virginia, we supported securitization legislation that will both reduce customer bills and support critical investments in the system. You can expect to see us continue to work with federal policymakers, regulators, and state legislators as we further modernize our energy grid. We firmly believe that the best way to create value for investors is by delivering safe, affordable, and reliable energy to our customers and communities, and we are engaging with stakeholders to support efforts to do just that. I am increasingly confident in our exciting growth potential as opportunities to benefit our customers, communities, and investors come into focus, and I look forward to building on our track record of value creation in the months and years ahead. With that, I'll turn it over to Trevor, who will walk us through AEP's first quarter performance, drivers, and other financial information.

Thank you, Bill. Today I'll review our financial results for the first quarter, build on Bill's remarks about our exceptional load growth, comment on our credit metrics, further discuss the recent successful $2.3 billion forward equity issuance that completes our anticipated equity needs through 2029, and address our thoughts on federal tax legislation. Let's go to Slide 7, which shows the comparison of GAAP to operating earnings for the quarter. GAAP earnings for the first quarter were $1.50 per share compared to $1.91 per share in 2024. There is a detailed reconciliation of GAAP to operating earnings for the quarter on Slide 26 of today's presentation. In the quarter, due to the passage of Ohio House Bill 15, we recorded a charge of $28 million related to the write-off of previously deferred OVEC costs, which we no longer believe are probable of recovery. From an operating earnings perspective and effective upon becoming law this summer, House Bill 15 removes AEP Ohio's ability to recover losses or record gains from the sale of OVEC power. Historical losses recovered from customers were approximately $40 million in 2024. However, we expect the earnings impact going forward to be significantly muted given upcoming capacity prices in PJM. Prospectively, the impact is manageable and less than $10 million of earnings on an annualized basis. Let's walk through our quarterly operating earnings performance by segment on Slide 8. Operating earnings for the first quarter total $1.54 per share compared to $1.27 per share in 2024. This was an increase of $0.27 per share or about 20% quarter-over-quarter, highlighting a strong start to the year and creating solid momentum for the rest of 2025. I would note that weather accounted for about $0.18 of the quarter-over-quarter variance, driven by the cold weather that most of our service areas experienced in the first quarter of this year, contrasted with the exceptionally mild weather seen in the same period of 2024. Looking at the drivers by segment, operating earnings for the vertically integrated utilities were $0.66 per share, up $0.09 from a year earlier. Positive drivers included favorable changes in weather and rate changes across multiple jurisdictions. The transmission and distribution utilities segment earned $0.36 per share, up $0.07 from last year. Favorable drivers in this segment included rate changes driven by rider recovery of distribution investments in Ohio and the base rate case in Texas, favorable weather, and higher transmission revenue. The AEP Transmission Holdco segments contributed $0.44 per share, up $0.04 from last year. Our continued investment in transmission assets as new loads are added to our system remained a key driver in the segment. Generation and marketing produced $0.14 per share, up $0.02 from last year. Favorable retail and wholesale margins were partially offset by lower distributed generation margins due to the sale of the OnSite Partners business in September 2024. Finally, Corporate and Other saw a benefit of $0.05 per share, primarily driven by the timing of income taxes, of which $0.03 is expected to reverse by the end of the year. Moving to Slide 9, I want to highlight the significant increases in load we continue to see across our system. As Bill mentioned, the increasing load growth coming to the system is providing the opportunity to add up to $10 billion of incremental capital over the next five years to our already sizable $54 billion plan. Since our last call, both Amazon Web Services and Google have connected hyperscale data centers to our system in Indiana, representing billions of dollars in customer investment. This comes on top of the existing data center customers in Ohio and Texas, who continue to ramp up at a double-digit pace. We also saw new large industrial load continue to come online in Texas across a variety of customers and industries. All of this puts us on track to nearly triple the pace of our retail sales growth from 3% in 2024 to almost 9% in 2025, representing the largest acceleration of load at AEP since the late 1960s—a truly once-in-a-generation opportunity. We expect that step change in growth to be maintained well into the future. Our current forecast supports annual retail load growth of between 8% and 9% through 2027. That's equivalent to roughly 52 million incremental megawatt-hours that we expect to serve relative to our current load of 182 million megawatt-hours, or nearly a 30% increase. More than offsetting the decline in our residential sales is a massive and sustained increase in demand from our C&I customers. Based on our current contracted loads, our C&I sales mix will grow from roughly two-thirds of total retail to nearly three-quarters over the next several years. There is a slide in the appendix that shows a bit more detail on first quarter sales by class. Those growth rates are among the best in the industry, and we have confidence that these loads are going to materialize. We have a significant amount of demonstrated and diverse demand across our system, but I think it's also important to highlight what that demand looks like and how we're incorporating it into our projections. You will see on Slide 10 a piece of that demand through some illustrative examples of the types of projects we're adding to our system. First and foremost, let's start with a number of overall requests to connect to the system. Across our 11-state operating footprint, we currently have more than 500 existing and potential customers actively requesting to connect almost 180 gigawatts of load to our transmission system. For context, our system-wide summer peak was just under 37 gigawatts last year, so we have nearly five times that amount active in the queue. Now, we know that not all of the requests will come online, which is why we take great care in using a probability-based approach to determine the likelihood of these loads as part of our annual load forecast. So far, we've committed to adding just over 20 gigawatts to the system over the next five years, which in the context of our queue is relatively conservative. Given the dynamic nature of AI driving the surge of data centers and large industrials coming online, we think it's vital to rely on demonstrated customer demand to build out our planning forecast. We believe the best mechanisms to demonstrate the demand are executed contracts backed by financial commitments, including electric service agreements and letters of agreement that show how firm these loads really are. Every megawatt in the forecast you see here is supported by these agreements. In addition to these agreements and in PJM, 80% of the load growth in this region is also backed by ESAs, which are take-or-pay contracts requiring customers to pay for power as of a certain start date, irrespective of their off-take. This not only helps confirm that customers' projects are real, but also incentivizes customers to stick to the schedule, reducing the risk to our existing customers and investors from a project not coming online. This is also why we've been very active in working with our regulators to strengthen and lengthen the tariff provisions in those contracts. Our contract terms, coupled with a queue that is nearly ten times the size of our current increased load forecast, gives us great confidence that this demand will materialize, which in turn makes us confident in our $54 billion capital plan with incremental upside. Should any of these projects be canceled or postponed, in addition to the protective financial provisions in the contracts, our queue means that we have other active customers to slot right into place and take up that capacity. In addition to the demonstrated demand that we're seeing across the system, it is also important to note the diversity in that demand. While data centers are driving a majority of the load growth in the coming years, we are also contracted to add roughly 6 gigawatts of industrial load across a number of diverse industries, including steel, autos, and energy. This diversity reassures us that the demand behind our capital plan is solid and can hold up across several different economic environments, including those with tariff impacts that we may find ourselves in over the next several years. Let's move on to Slide 11 to discuss AEP's liquidity and commitment to credit quality. Recall that AEP's funding plan supporting our capital spend through 2029 originally included $5.35 billion sourced from equity. In January, we secured a minority equity interest investment in the Ohio and I&M Transcos with KKR and PSP Investments for $2.82 billion. This deal is value accretive at 2.3 times rate base and 30.3 times price-to-earnings. We expect to close in the coming months, and the only remaining item outstanding is FERC approval, which we filed for on February 3rd. In March, we saw a compelling opportunity to further de-risk our funding needs through a $2.3 billion forward equity transaction, including the greenshoe that allowed us to capitalize on known market conditions and manage the timing of proceeds. In combination with the expected proceeds from the minority transaction, I am pleased that we now have completed our anticipated equity needs through 2029 associated with our $54 billion capital plan. Those two transactions are equivalent to issuing common stock at approximately $140 per share, a 25% premium to our current share price. Moving on to federal tax legislation and specific to transferability impacting FFO, we believe a complete retroactive IRA repeal is unlikely based on our many conversations with policymakers. If there is a repeal, we would expect any potential legislation to provide business certainty by protecting the qualifying tax incentives for existing projects as well as safe harbor projects currently under construction. This would give us the ability to monetize tax credits in a timely manner and meet our financial commitments. You can see the FFO-to-debt metric stands at 13.2% for the 12-month ended March 31, which is a 0.2% decrease from the prior quarter. However, the minority interest transaction is expected to improve near-term FFO to debt by 40 to 60 basis points, which sets us up to be well above our credit threshold and puts us on a path to be in the targeted 14% to 15% FFO to debt range. Finally, let's move on to Slide 12 before we take your questions. I wanted to summarize what you heard from us today. First, you heard that we have taken significant actions to de-risk our financial plan through the highly attractive and accretive minority interest transmission transaction which is expected to close in the coming months. Coupled with the $2.3 billion equity offering completed in late March prior to the current market turbulence, these transactions combined complete our anticipated equity needs through 2029 to support our current $54 billion capital plan. Second, you heard that we delivered strong financial results in the first quarter, growing earnings substantially compared to last year. Positive regulatory developments have set a strong foundation and are paving the way for a successful 2025. Third, you heard about our remarkable load growth story underpinned by major economic development activities across our footprint, providing significant investment opportunities in our utilities and creating an attractive growth profile for our investors. We highlighted the regulatory progress on retail tariffs that we've made to enable these load additions to result in a fair allocation of costs and protections for our existing customers. Fourth, you heard about our continued focus on the execution of our unprecedented $54 billion capital plan with the potential for incremental investments of up to $10 billion. In summary, our confidence in achieving our 2025 commitments remains strong, and we are reaffirming our operating earnings guidance range of $5.75 to $5.95 per share, our long-term growth rate of 6% to 8%, and targeted FFO to debt of 14% to 15%. With that, I'm going to ask the operator to open the call, so we can take your questions.

Hey guys, good morning.

Good morning, Shar. How are you?

Good morning. Oh, very well, Bill. Just I know West Virginia is one of the first rate cases you kind of rolled up your sleeves for after that previous bad outcome which obviously predated you, I guess. How are conversations going there, especially around securitization? Can you settle this before the mid-June hearings? Thanks.

Yes, I really appreciate the question. We've been, first of all, at a high level, having really good luck with a lot of our regulatory outcomes across the system. I'm very pleased with the work that the team has been doing to focus closer on our local communities and our states, pushing us to do what our states want. In the case of West Virginia, I'm excited about where we're at. The hearing is scheduled for June with the commission decision later this year. We've incorporated securitization as an option to enhance customer affordability. We've worked with the teams there, and we believe that this offers a really significant benefit to our customers by potentially reducing the impact on their bills by almost 75%. This would essentially decrease the increase we're looking for to around 3.8%. Ultimately, the decision rests with the commission, and we look forward to working with all of the stakeholders to achieve a favorable outcome for everyone. Overall, I'm very excited with how the organization is responding in our states. If you listen to all of the positive regulatory outcomes we've had over the past few months, you'll see that we're moving in the right direction and I'm excited about where we're at.

Perfect. Fantastic. And then just lastly, the 20 gigawatts of load you have out there. We've seen some pullback with at least one hyperscaler in Ohio. Microsoft, I think, is the notable, I think, in your service territory, I guess. How are conversations going with the hyperscalers? More specifically, are you seeing any kind of sense of pullbacks? Just trying to get a sense with that customer class specifically. There seems to be some conflicting data points out there with the caveat you guys have a diversified load environment. Right, but specific on hyperscalers. Thanks.

Sure. Overall, on our system, demand remains really robust. As Trevor noted, we've got over 500 existing and potential customers looking to connect 180 gigawatts of load on the transmission system. Despite the fact that Microsoft made a decision to delay their projects, we have an incredible backlog that wants to come onto our system, and we're very excited to work with these customers and get them connected. I don't see a reduction in our other loads coming from data centers, hyperscalers, or the industrials, because we've contracted about 6 gigawatts of industrial load across the system, giving us diversity that will strengthen the company overall going forward. I think we're in a very strong position. This diversity provides confidence that the demand supporting our capital plan is really resilient, capable of enduring various economic outcomes. So whether Microsoft is with us or not, we see really significant demand coming forward, and we've got plenty of folks who want to jump in if they want to jump out.

Hey, good morning. This is actually Aidan Kelly on for Jeremy. Just focusing on the load growth again. It looks like total retail sales were up around 3.2% versus the 8.8% 2025 target. And then also with the commercial up 12% versus 24% target. How do you reconcile the sales trends we've seen this quarter against your 2025 forecast? Would this imply a strong pickup later in the year? Are there any sensitivities we should think about here in general?

Yes, Aidan, thanks for the question. This is Trevor. I would start by saying the anticipated load growth, particularly the rapid 8% to 9% increase we foresee over the next several years, does open up substantial capital investment opportunities. We expect that to drive consistent and robust earnings growth, especially in the second half of the decade. For your specific question, while near-term earnings impacts are somewhat muted due to the general lower profit margins of C&I customers compared to residential customers, the rapid addition of C&I load really does create additional headroom and further enhances customer affordability. As a rule of thumb, the margins from vertically integrated residential customers are roughly five times larger than those of our data center customers. For our T&D customers, the ratio is almost 8:1. You'll see a little decline in margins as we experience some efficiencies on the residential side, but overall, this is a very positive growth story surrounding C&I and how we can deploy capital over the long term. So we feel very good about it.

Got it. That's helpful. Thanks, Trevor. And then switching gears to the opening remarks on Ohio. Could you just walk through the puts and takes of shifting away from ESPs into NYPs and to what extent does this impact your regulatory strategy in the state and future rate case timing in general?

Sure. HB15 was legislation that ultimately received approval from both chambers; it has not been sent to the Governor yet. We expect that to happen really any day now. Once that happens, the governor has 10 days to sign the bill, and we anticipate that the bill will become law in early August, which is 90 days after his approval. My view of this legislation is that it's highly constructive. It supports capital investment growth in Ohio and benefits our customers. For us, the main provisions that impact our business are, first and foremost, the new legislation that ends ESP and introduces a multi-year forward-looking test year with a true-up mechanism. This is a significant advantage for us, promoting timely recovery of our investments. Unlike other Ohio utilities, our transition from ESP5 to the new construct will proceed seamlessly with no gaps in our timing. I’m looking forward to moving through that transition, as it’s going to be an incredible advantage for us going forward. The behind-the-meter components of the legislation preserve existing agreements and offers flexibility for future fuel cell purchases to other affiliates. We will continue to deliver on our commitments to the two customers we have in Ohio. Regarding the OVEC issue, I'll turn that over to Trevor to describe, but I think overall we can manage through this.

Yes, terrific. Thanks, Bill. With regards to the OVEC situation, historically, we indicated that ending the cost recovery would result in about a $40 million impact, which is what we've seen in years past. Again, as we said in our prepared remarks, given the upcoming capacity prices in PJM, we expect the earnings impact to be significantly muted to about $0.02, or roughly $10 million of earnings. This is very manageable, and we can incorporate it prospectively. As Bill also mentioned, this will likely become law and take effect in mid-August, when we will get recovery up through that date. Overall, the earnings impact from this change is not significant.

Appreciate the color. I'll leave it there. Thanks.

Absolutely. Thanks, Aidan.

Hey, good morning.

Morning.

I know you addressed this, I think, on the previous question to a certain degree, but maybe on the commercial sales in particular for 2025, I see that they're tracking at least year-over-year, 12%, but your target is a little higher for the full year. Just are you seeing any delays? Is there specific shaping you may have talked about previously that's playing out in terms of just back-end loading for the year for 2025 on commercial sales?

Yes, David. The good thing, as mentioned in the prepared remarks, is with the commercial load growth, many counterparties are signing the LOAs and entering into firm contracts with us. These are really take-or-pay contracts enabling us to ensure continuous payment irrespective of their load looks like. The step-up of 12% is positive, and we continue to see people signing these take-or-pay types of contracts. I think you'll continue to see additional load coming over the next several years, and this is all very positive. I wouldn't say it’s shaped towards the back end or anything of that regard. It's more just a steady increase in commercial load that we've seen over the last several months.

Okay, so for 2025, you still anticipate about 23%.

That's right.

You previously mentioned the Bloom partnership. How should we consider the deployment in relation to what you have planned before the Ohio law, given that the Ohio market isn’t currently available? Will this impact the deployment schedule for the remaining one gig?

We're in the market to sell these to customers who are interested in this technology. It will not affect at all the two projects we have in flight—they will go forward as planned and are well underway. For the remaining 900 megawatts, we have a number of customers we're engaging with and feel optimistic about potential deals down the road. So we will see where this all heads and can certainly report on this more in future calls this year.

Let me add just one thing, Bill, if I could on that. The remaining 900 megawatts is really an option for us—we are not obligated to take those fuel cells. If we find interest in customers for those, we will proceed, but we are not obligated to.

Yes, the original 100 megawatts that we did contract are taken care of.

Yes.

Hey, good morning team. Thank you guys very much. Just wanted to follow up on the $10 billion upside number here. I want to say a little bit about what's already approved. What do you have in the line of sight even within that $10 billion bucket? It seems like there could be various pieces there. And then also what are you waiting for in terms of line of sight to formally introduce that? As you say, it’s within the five-year program. You've commented several different times about this being tied to the load growth and the degree of confidence you have on the load growth. Effectively, what are we waiting for? What are the sub pieces that would enable the confidence to more formally integrate that into the plan?

Yes, Julien, it's Trevor. I appreciate the question. We're setting a cadence to formally come out with a growth plan on an annual basis. We generally do this around the third-quarter call, right before we go into EEI, unless something material would increase that $10 billion potential upside to the $54 billion plan. Notably, the recently awarded 765 transmission lines, for example, in Texas are roughly $1 billion to $2 billion and aren’t currently in the plan. We will continue to review how we manage the overall portfolio spend relative to our customers' needs and state requirements. About half of the $10 billion relates to transmission, while the remaining is primarily generation projects across different service territories, as we file and look for overall capacity and needs in the states. We have great opportunities in ERCOT, and we continue to flesh these out to provide more definitive answers when we roll out our revised five-year capital plan in the third quarter.

Got it. Okay, fair enough. Can you elaborate on what is in that $5 billion generation bucket? Can you speak a little bit to how you think about that versus the load growth numbers you have? Is this just about line of sight on RFPs coming out of anticipated load growth or something further?

No, it's largely what you just said. It's the RFPs, alongside looking at potential wind projects or other renewable projects in various states. It's also evaluating combined cycles as we assess overall capacity and generation needs in our service territory. These are items that we have a line of sight to but have not firmly committed to yet.

Oh, actually, just to clarify, you've got two acquisitions out there, one potentially in Oklahoma and the other in Indiana or Ohio specifically. Are those included in the plan, and do you intend to move forward with those?

That's right, that's correct. Those are included and we do have needs in those states for that generation. So, yes, those are in there.

Awesome. All right, I'll leave it there. I'll pass it on. Thank you guys very much. Done again, thanks.

Thanks.

Hey team, good morning. Thanks for giving me time. I just wanted to start with the Q1 earnings performance. So the report numbers are higher than where we thought you would end up in the quarter. You mentioned the weather benefit, but you also reaffirmed guidance for the year. I appreciate there are three more quarters to go, with Q3 being the largest. Can you comment on how the first quarter turned out? What’s your expectations? Are you going into the balance of the year higher than where you expect to be? Any color there would be helpful. Thank you.

Yes, thanks Durgesh. As you highlighted, weather was a significant driver, as were some of the rate impacts from revised rates in specific jurisdictions. I would say that was roughly in line with our expectations, and we feel very good about laying out our full-year guidance range and staying within it. Following just the first quarter, we're going to be very disciplined in our capital allocation. We're exploring ways to ensure efficiency at the operating companies and the corporate center to drive efficiencies and affordability for our customers. I feel confident about our $5.75 to $5.95 guidance range and the 6% to 8% long-term growth rate. We will surely communicate further in Q2 as more successful regulatory outcomes roll out in the following months.

Got it. Sounds like things are on track. Switching gears to the per colocation process. A couple of weeks ago, the IPP came out and suggested settlement talks. Any color you can share on what might be happening behind the curtains and timeline for a potential settlement if it's reached?

This is Bill. We've mentioned this several times that we are not against colocation. What we want to ensure is that anyone pursuing that type of arrangement pays their appropriate fees on the transmission system, and we will continue to engage the process at FERC as it continues forward.

Got it. Thanks Bill. Thanks Trevor, and congrats on the start of the year.

Yes, thank you.

Thanks, Durgesh.

Hey, thanks for all the updates.

Good morning.

Just wanted to follow up on the CapEx upside. I'm just curious if you could talk about how you would plan on financing the $10 billion if you were to wrap it into the plan next year. Do you have additional levers to pull on the asset sales side or could the securitization that's pending in West Virginia impact the company's overall equity needs in any way? Do you have any levers to mitigate what’s been more of a more traditional, I don’t know, 40% to 50% of funding across the industry?

Yes. One of the things we did is mention on the year-end call in February that we have 5.35 billion in overall equity needs over the five-year plan, and 2.8 billion of that was secured with the sale of the Transcos. Given where our execs were in March, we decided to proceed with the remaining $2.3 billion, which effectively takes all the marketed equity off the table for the five-year plan. Regarding that incremental $10 billion, even if we needed to fund it with a level of growth equity, that would be on the back end of the plan. The equity needs have already been largely met with those two transactions. There are some levers like potential hybrids that we could consider, whether it's junior subordinated debt, but we do not plan to sell down any more transmission assets. I think we are in a good position for financing growth in a shareholder-friendly manner.

Hey, that was great color. I appreciate that. Thanks for that. And then just one clarification. I know you mentioned in your prepared remarks your comments on IRA. Is there quantifiable exposure if transferability did go away? Would that impact your plans whatsoever? Do you have any exposure there? Thanks.

Yes, again, on the IRA, we believe that a complete retroactive repeal is quite unlikely and, if a repeal does occur, we expect that the tax incentives for existing projects and safe harbor projects currently under construction will be protected. AEP's existing tax credits, along with anticipated tax credits through 2027, are safe harbored and wouldn't be affected by this proposal. There is very limited exposure from the IRA repeal language.

Appreciate all those details. Thank you again.

Thanks, Nick.

Hey, good morning. Thanks for taking the questions. Maybe to start. Just to follow up, Trevor, on some of your comments on margin contribution from residential versus C&I customers. Can you just talk a little bit about the residential dynamics driving that to track negative over the last several quarters? Is that something you're watching, and do you anticipate something shifting there to get you back towards that full-year forecast for 2025?

Yes. Carly, thanks for the question. We are focused on residential customers. I think what you’re seeing is slight increases in residential meter count, but that’s being overshadowed by the decline in throughput on the residential side, mostly due to efficiency and cost considerations during a cold winter. We are watching it, and while C&I is adding a lot of growth that is helping offset that, we need to continue delivering high-quality service to residential customers at an affordable price.

Got it. Great. That’s helpful. Thank you. Then could you maybe talk a little about the 765kV Permian opportunity set? Any color on how we could think about sizing what that CapEx could look like or the timing to deploy it? Is that something that is in the $10 billion identified upside to the plan?

Yes, good morning. We're very excited about the outcome in Texas; moving to the 765kV system shows a strong future business climate and need for energy. We've been the innovator of the 765kV system and are well-positioned in Texas. We expect the first project to be in the $1 billion to $2 billion range, with work commencing in the near future, recognizing that it will take time to deploy. The fact that Texas is looking at significant transmission increases bodes well for AEP.

Hey, good morning everyone. Appreciate all the detail on the call here. I've just got one follow-up on the FFO to debt. I might have misheard some of what you said in the commentary, but based on the slides, it looks like it was 13.2% on a trailing twelve-month basis through March, that’s down from 14% year-over-year. Can you talk about the moving pieces? As you mentioned, the minority interest sale will add 40 to 60 basis points later this year. That won’t quite get you to 14%. Can you talk about what will get you over the hurdle so you’ve got the 100 basis point cushion over the 13% downgrade threshold, please? Thank you.

Yes, thanks, Andrew. We ended last year at 14%, but that was prior to the change in methodology regarding deferred fuel, taking about 40 to 50 basis points off of that FFO to debt. While we expect the minority interest transaction to raise the FFO to debt by 40 to 60 basis points, it won’t get us to 14%. Continued focus on execution around efficient operations and increasing the numerator will be significant as we aim for that 14% to 15% targeted range.

Very helpful. Great. Thank you so much. Were all of the recent regulatory wins included in the CapEx plan already? I'm specifically talking about the 1.1 billion of transmission from Transource Energy and the 600 million through AEP Transcos as well as the Texas resiliency plans.

Yes, I would say there are some projects included, and some may fall away, but generally, yes. There are always puts and takes, but we feel overall good about the $54 billion plan.

Okay, got it. But there’s flexibility for projects over time. Understood. Thank you.

Yes, thank you. We appreciate everyone joining us on today's call. I'd like to close with just a few summary remarks. First, I'm very excited about the opportunities ahead at AEP as we advance the long-term strategy to drive growth, enhance the customer experience, and achieve positive regulatory outcomes. We are putting our robust capital plan to work, and continue to grow the business across our large footprint while delivering shareholder value. I’d also like to reinforce the tremendous support we've had from our board to keep pushing forward with our plan to strengthen our balance sheet, improve our regulatory outcomes, and execute around what our states want. I couldn’t be more excited to be with this team and see where we're taking the company. If there are any follow-up items, please reach out to our IR team with your questions. This now concludes our call. Thank you.