Title

Presentation

American Electric Power Company, Inc. beats earnings expectations. Reported EPS is $1.54, expectations were $1.4.

Operator: Hello and thank you for standing by. My name is Regina, and I will be your conference operator today. At this time, I would like to welcome everyone to the American Electric Power First Quarter 2025 Earnings Call. [Operator Instructions] I would now like to turn the conference over to Darcy Reese, Vice President of Investor Relations. Please go ahead.

Darcy Reese: 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.

Bill Fehrman: 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 where we delivered strong results and have 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 invasion to meet the needs of 5.6 million customers across 11 states. We are actively managing 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%.

We have 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, and we were recently 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 center on execution and accountability and we 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. As we move forward, we will remain disciplined in sourcing efficient forms of capital to manage our needs in support of incremental investment opportunities. We remain excited about the significant growth opportunities ahead, including the load growth in many parts of our service territory. This growth is not a show me 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 said, 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 state’s 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 load 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 exceedingly well in attracting hyperscalers to our system who need consistent large load bulk power. We also 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 deploy 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 customer’s 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 and we recently 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. Building on our 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 recent 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 and 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 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 will follow 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 SWEPCOs annual Foreign Reload Rate Plan in Louisiana For I&M, the team recently filed to acquire an 870 megawatt natural gas plant in 2026 which is 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 a number of 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 multiyear 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. And 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.

Trevor Mihalik: 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. This was driven by the cold weather that most of our service areas experienced in the first quarter of this year, which was 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 of 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. That represents the largest acceleration of load at AEP since the late 1960s, a truly once in a generation opportunity. In fact, 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 lows, 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 one of the best in the industry and we have confidence that these lows are going to show up. 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 obviously 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 onto 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, or EFAs, and letters of agreement, or LOAs, showing how firm these loads really are. Every megawatt in the forecast you see here is supported by LOAs. In addition to LOAs and 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 offtake.

This not only helps confirm that customer’s 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 10 times the size of our current increased load forecast, gives us great confidence that this demand will show up, 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 Q [ph] 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 derisk 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 window. 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 derisk 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 low 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.

Operator: [Operator Instructions] Our first question will come from the Shar Pourreza with Guggenheim. Please go ahead.

Shar Pourreza: Hey guys, good morning.

Bill Fehrman: Good morning, Shar. How are you?

Shar Pourreza: Good morning. Oh, well, 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 prior 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.

Bill Fehrman: Yes, really appreciate the question. We’ve been having first of all, at a high level really good luck with a lot of our regulatory outcomes across the system. And I’m really pleased with the work that the team has been doing to focus closer in on our local communities and our states and pushing us to do what our states want. And in the case of West Virginia, I’m excited with where we’re at. The hearing is scheduled for June with the commission decision later on 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%.

So I think there’s really some interesting opportunities here because that would essentially decrease the increase we’re looking for to around 3.8%. But 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 and we’ll participate in discussions as they come up. But right now overall though, I’m very, very excited with how the organization is responding in our states. And I think as you hopefully listen to all of the positive regulatory outcomes we’ve had over the past few months, you’ll see that we’re really moving in the right direction and I’m really excited about where we’re at.

Shar Pourreza: 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.

Bill Fehrman: Sure. Well, of course, overall on our system, demand remains really robust. And as Trevor noted, we’ve got over 500 existing and potential customers that are looking to connect 180 gigawatts of load on the transmission system. And so despite the fact that Microsoft made a decision to delay their projects, we’ve got an incredible backlog that want to come onto our system and we’re very excited about working with those customers and getting them connected. I don’t really see a reduction in our other load coming from data centers or hyperscalers or the industrials for that matter, because we’ve contracted that about 6 gigawatts of industrial load as well across the system and really given us a diversity that will strengthen the company overall for us going forward.

And so I think we’re in a very strong position. This diversity provides confidence that the demand supporting our capital plan is really resilient and capable of enduring these 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.

Shar Pourreza: Got it. Perfect. Fantastic, guys. Congrats. See you soon.

Operator: Our next question comes from the line of Jeremy Tonet with JPMorgan. Please go ahead.

Aidan Kelly: 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, like the sales trends we’ve seen this quarter against your 2025 forecast, would this imply a strong pickup later in the year? And are there any sensitivities we should think about here in general?

Trevor Mihalik: Yes, Aidan, thanks for the question. This is Trevor. So I would start by saying the anticipated load growth, particularly the rapid 8% to 9% increase that we’re seeing over the next several years does open up substantial capital investment opportunities. And we expect that to drive consistent and robust earnings growth, especially in the second half of the decade. So to your specific question, while near term earnings impacts are somewhat muted due to the general lower profit margins of the C&I customers compared to the residential customers, I would say the rapid addition of C&I load really does create additional headroom and further enhances customer affordability. Just kind of as a rule of thumb or an example, the margins from the vertically integrated residential customers are roughly five times larger than those of our data center customers.

And for our T&D customers, that ratio is almost 8:1. So, you’ll see a little bit of a decline in margins as we see some efficiencies on the residential side but overall this is really just a very positive growth story around C&I and what we’re able to do to deploy capital over the long term. So we feel very good about it.

Aidan Kelly: Got it. That’s helpful. Thanks, Trevor. And then just maybe switching gears to kind of the opening remarks on Ohio. Could you just walk through the puts and takes, from 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?

Bill Fehrman: Sure. Well, HB15 was a 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 then we anticipate that the bill will become law thinking 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 really actually provides benefits to our customers. For us, the main provisions that impact our business, first and foremost is the new legislation that ends ESP and it introduces a multi-year forward looking test year with a true UP [ph] mechanism. So that is a significant advantage for us.

It promotes timely recovery of our investments and then unlike other Ohio utilities, our transition from ESP5 to the new construct will proceed seamlessly with no gaps in our timing. And so really looking forward to moving through that transition, it’s going to be an incredible advantage for us going forward. And then the second piece was the behind the meter components of the legislation. So this legislation, again we’re happy with the outcome here. It basically grandfathers the two projects that we had in flight with our Bloom Energy solution for the data centers that we previously have discussed. This will preserve those existing agreements and then we have basically the flexibility to deploy future fuel cell purchases to other affiliates.

And so we’re going to continue to offer that as an alternative in our other areas and then make sure that we deliver on our commitments to the two customers that we have in Ohio. And then the third piece of this is, is the OVEC issue and I’ll turn that over to Trevor to describe, but I think overall it’s something that we’ll be able to manage through. So Trevor.

Trevor Mihalik: Yes, terrific. Thanks, Bill. Yes, so with regards to the OVEC situation, historically we’ve indicated that ending the cost recovery would result in roughly a $40 million impact, and that’s what it’s done 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 really significantly muted to the tune of about potentially $0.02 or we said roughly $10 million of earnings. And that’s something that I think is very manageable and we can incorporate prospectively. As Bill also just mentioned here, this will probably most likely become law and take effect in mid-August. And so we will get recovery up through that date. And so I think this is one of those things that is really not a huge earnings driver for us and we can deal with this going forward.

Aidan Kelly: Appreciate the color. I’ll leave it there. Thanks.

Trevor Mihalik: Absolutely. Thanks, Aidan.

Aidan Kelly: Yes, thanks.

Operator: Our next question comes from the line of David Paz with Wolfe Research. Please go ahead.

David Paz: Hey, good morning.

Bill Fehrman: Morning.

David Paz: 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, see that they’re tracking at least year-over-year, 12%, but your target a little higher for the full year. Just are you seeing any delays? Is there a specific shaping that you may have talked about previously that’s playing out in terms of just back end loaded for the year for 2025 on commercial sales?

Bill Fehrman: Yes, David. So I think the good thing, and we mentioned this in the prepared remarks, is with the commercial load growth, what we’re seeing is a lot of these counterparties are signing the LOAs and entering into firm contracts with us. And so, these are again, really take or pay contracts that are enabling us, irrespective of what their load looks like, to ensure that they are starting to pay under those contract terms. And so while the step up of 12% is really positive, we continue to see people signing these take or pay type contracts and I think you’ll continue to see additional load coming on over the next several years and so this is all very positive in that regard. But I wouldn’t say it’s shaped towards the back end or anything to that regard. I think it’s really more just a steady increase in commercial load coming on that we have seen over the last several months here.

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

Bill Fehrman: That’s right.

David Paz: Year end 25 versus year end 24, okay.

Bill Fehrman: Yes.

David Paz: And then just you just touched on this, the previous question on the Bloom partnership. But will, will there be a — how should we think about the deployment versus what you have before the Ohio law understanding it’s not, the Ohio Market, AP Ohio Market is not there. But will this change any type of schedule of deployment for the remaining one gig?

Bill Fehrman: Well, we’re in the market to sell those to customers who are interested in this technology. It will not affect at all the two projects that we have in flight. Those will go forward as planned and those are well underway. So for the remaining 900 megawatts that we have available to us, we do have a number of customers that we’re in conversations with and feel optimistic that there may be deals coming down the road. So we’ll see where this all heads and can certainly report on this more as future calls come this year.

Trevor Mihalik: And 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. And so if we can find capacity and customers to take them, that makes sense. We will do that. But again, we’re not obligated to.

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

Bill Fehrman: Yes.

David Paz: Great. Thank you. Yep.

Operator: Our next question comes from the line of Julien Dumoulin-Smith with Jefferies. Please go ahead.

Julien Dumoulin-Smith: Hey, good morning team. Thank you guys very much. Appreciate it. Nicely done here. Just wanted to follow up on the 10 billion upside number here. I just wanted to say a little bit of what’s already approved here. What do you have line of sight even within that $10 billion bucket? It seems like there could be some 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 comment several different times about this being tied to the load growth and the relative degree of confidence you have on the load growth. So effectively, what are we waiting for? What are the sub pieces there that would enable you the confidence to more formally integrate that into the plan?

Trevor Mihalik: Yes, Julien, it’s Trevor. Appreciate the question. I would say what we’re really doing is we’re setting the cadence where we want to come out with a formal growth plan on an annual basis. And we’ll generally do that around call the third quarter call right before we go into EEI, unless there’s something material that would increase that $10 billion plan or $10 billion potential upside to the $54 billion plan. That being said, I think, it’s important to note that the recently awarded 765 transmission lines, for example, in Texas, that’s roughly $1 billion to $2 billion. That’s not in the current plan. And so as things firm up, we will continue to look at how we manage the overall portfolio spend relative to what our customer’s needs and what the states want and that’ll impact a large part of what that 10 billion looks like.

I think roughly, if you wanted to kind of take a look at that 10 billion, we’ve said publicly that roughly about half of that 10 billion relates to transmission and the remaining is a majority of that is generation projects in the various service territories as we file and look at the various capacity and needs in the states. But again, we have great opportunities not only in ERCOT, we also have opportunities in PJM and we continue to flesh those out and we’ll come with more definitive answers when we roll out our revised five year capital plan in the third quarter.

Julien Dumoulin-Smith: Got it. Okay, fair enough. And maybe just to elaborate a little bit further, 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 that you have? Is this just about line of sight on RFPs coming out of anticipated load growth or is there something further within that here?

Trevor Mihalik: No, it’s largely what you just said there. It’s the RFPs. It’s also looking at potential wind projects or other renewable projects in various states. It’s also related to potentially some combined cycles as we look at what the overall capacity needs are and the generation needs are in our service territory, so these are items that we have a line of sight to but we have not firmly committed to yet.

Julien Dumoulin-Smith: Oh, actually just to clarify, you’ve got two acquisitions out there, one potentially in Oklahoma and one in Indiana or Ohio specifically. Those are included in the plan and you intend to move forward with those?

Trevor Mihalik: That’s right, that’s correct. Those were items that were included and we do have, the needs in those states for that generation. And so those, those are in there.

Julien Dumoulin-Smith: Awesome. All right, I’ll leave it there. I’ll pass it on. Thank you guys very much. Done again, thanks.

Trevor Mihalik: Thanks.

Operator: Our next question comes from the line of Durgesh Chopra with Evercore. Please go ahead.

Durgesh Chopra: Hey team, good morning. Thanks for giving me time. I just wanted to start-off 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 third quarter being the largest. Maybe just comment on how first quarter turned out, what’s your expectations? Are you going into the balance of the year higher than where you expect it to be, just any color there would be helpful. Thank you.

Bill Fehrman: Yes, thanks Durgesh. So as you did highlight, weather was a significant driver as was some of the rate impacts as we rolled out the revised rates in certain jurisdictions. But weather was a significant opportunity for us in the quarter. I will say, that’s roughly in line with where we anticipated we would be and we feel very good about laying out our full year guidance range and staying within that guidance range. And as you indicated it’s still fairly early with just the first quarter but we’re going to be very disciplined in our capital allocation. We are looking for ways to ensure we are doing things efficiently at the operating companies as well as at the corporate center to drive efficiencies and to drive affordability for our customers.

But I feel good about the 560 or the 575 to 595 guidance range that we put out in the 6% to 8% long-term growth rate and certainly would anticipate that we would again talk to that in the second quarter as we continue to see some of the successful regulatory outcomes rollout that we’ve seen over the last few months here.

Durgesh Chopra: Got it. Sounds like things are on track. Okay. Then switching gears to just the per colocation process here. A couple weeks ago the IPP came out and sort of suggested settlement talks any color you can share there on what might be happening behind the curtains and timeline for a potential settlement if it’s reached.

Bill Fehrman: This is Bill. Sure. So this is Bill on the co-location issues. We’ve said many times on this is that we’re not against colocation. What we are wanting to make sure is that anyone doing that sort of arrangement pay their appropriate fees on the transmission system and so we’re continuing to follow the process at FERC and that’s moving forward and will continue to be engaged fully. But at the end of the day on this it’s really more about ensuring that if you use the transmission system you pay your fair share. And so we’ll continue to monitor this and see where it goes.

Durgesh Chopra: Got it. Thanks Bill. Thanks Trevor and congrats on start to the year.

Bill Fehrman: Yes, thank you.

Trevor Mihalik: Thanks Durgesh.

Operator: Our next question comes from the line of Nick Campanella at Barclays. Please go ahead.

Nick Campanella: Hey, thanks for all the updates.

Bill Fehrman: Good morning.

Nick Campanella: Hey. 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 kind of wrap it into the plan into next year, like 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? I guess just do you have any levers to kind of mitigate what’s been more of a more traditional, I don’t know, 40% to 50% of funding across the industry.

Bill Fehrman: Yes. So Nick, one of the things we did, and we said on the year end call in February that we had the 5.35 billion of overall equity that we needed over the five year plan and 2.8 billion of that was taken care of already with the sale of the Transcos. And then given where Bill and I were in March, we anticipated we’d rather take the market we know and so we went out with the remaining $2.3 billion, which really effectively takes all the equity, the marketed equity, off the table over the five year plan. So when you look at the incremental $10 billion, even if we needed to fund that with some level of growth equity, that would be on the back end of the plan because we’ve already pre funded a lot of that equity on the 2.8 billion on the sale and then the 2.3 billion is done under the forward through December 2026.

And so when you look at that, we’ve really taken care of all the equity needs even with the forward in really the first two years of the five year plan, and so if we were to come back and firm up the 10 billion, I think we would really be in a situation where we would not need to issue incremental equity in the near term and then we will come back at a later time as to how we would fund that. To some of the points you raised specifically, again you mentioned the securitization. And while we believe that securitization is highly beneficial for our customers in modulating the rates, it also allows us to take approximately $2.4 billion of cash and deploy that cash elsewhere, and so there’s a lot of levers like that. And then lastly, I would say we also would look at potential hybrids that we have out there, whether it’s junior subordinated debt and I know others in the market have been utilizing those structures as well, and so we do have a lot of other levers to pull.

That being said, I think we do like our assets and from our perspective, I don’t think you’re going to see us sell down any more transmission or anything to that effect, but rather we would look at ways to finance the growth in a very, very shareholder friendly way.

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

Bill Fehrman: Yes. So I would say again, on the whole IRA walking it back and I think this kind of gets back to some of the comments we made in our prepared remarks. But we really do believe that a complete retroactive repeal of IRA is pretty unlikely and that if a repeal does occur, we would expect the tax incentives for the existing projects and Safe harbor projects that are under construction will be protected. I think really when you look at this, all of AEP’s existing tax credits, along with really all the anticipated tax credits through 2027 are safe harbored and would not be impacted by this proposal. And so then people have kind of questioned us with regards to the specific dollar amounts. And I would say transferability in our plan is manageable.

It’s roughly $200 million currently and then over the next several years it averages about $300 million. But all of that really pertains to Safe harbor and pre IRA projects that are expected to continue to qualify under the transferability. So again, very limited exposure in that regard from the IRA repeal language that’s being talked about right now.

Nick Campanella: Appreciate all those details. Thank you again.

Bill Fehrman: Thanks, Nick.

Operator: Our next question comes from the line of Carly Davenport with Goldman Sachs. Please go ahead.

Carly Davenport: Hey, good morning. Thanks for taking the questions. Maybe to start. Just to follow up, Trevor, on some f your comments earlier on the margin contribution from RESI versus C&I ocustomers. Can you just talk a little bit about the RESI dynamics driving that to track negative over the last several quarters here? Is that something you’re watching and do you anticipate something shifting there to get you back towards that full year forecast for 25?

Trevor Mihalik: Yes. Carly, thanks for the question. And we certainly are focused on residential customers. And I think what you’re seeing is we do have slight increases in residential and actual meter count. But what we’re seeing is that’s being more than offset by the decline in throughput on the residential side, mostly from efficiency and people really focusing on the costs to go through a cold winter like we just had, so from our perspective, I think we do watch it. We do see that C&I is adding a lot of growth that is helping to offset that. But again, as I mentioned, the C&I really margins are a lot less than residential and so we continue to monitor that. But what we need to do is continue to find ways to deliver very high quality service to our residential customers at an affordable price and then that will continue to be something that will offset some of the efficiencies that they’re doing or the use that they’re declining in.

Carly Davenport: Got it. Great. That’s helpful. Thank you. And then could you maybe talk a little bit about the 765kV Permian opportunity set? Just any color on how we could think about sizing what that CapEx could look like or the timing to deploy it? And is that something that is in the $10 billion of identified upside to the plan?

Bill Fehrman: Yes, good morning. So first of all, we’re very, very excited about that outcome in Texas when we think about the opportunities there going to 765 was a very strong message by the government and regulators in Texas that they foresee a very strong future for the business climate there and the need for energy, and the fact that they moved to 765 is an incredibly strong statement about what they view as their potential in Texas. And so for us, of course, we were the original innovator of 765 back in 1960 and have been building it and perfecting it for many years, and in fact, really the only company in the country that has the capabilities to do this. And so we’re incredibly well positioned in Texas for this. We’re excited about this first project and firmly believe that it will open up additional ones going forward for this one.

We think it’s in the $1 billion to $2 billion range and the work on this project will begin in the very near future and of course it will take some time to deploy. But overall, the fact that we are the leader in this country for 765 and the fact that Texas is looking at a significant increase in that type of transmission bodes well for AEP.

Carly Davenport: Thank you so much for the color.

Bill Fehrman: Thank you.

Trevor Mihalik: Thanks, Carly.

Operator: Our next question comes from the line of Andrew Wiesel with Scotiabank. Please go ahead.

Andrew Wiesel: 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 TTM basis through March, that’s down from 14% last year. Can you just talk a little bit about the moving pieces. Then, of course, 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.

Trevor Mihalik: Yes, thanks, Andrew. So we ended last year at 14% FFO to debt, but that was also prior to the change in methodology with regards to the deferred fuel. And that took about 40 to 50 basis points off of that 14% FFO to debt. Now, I will say that the deferred fuel, as we’re collecting the deferred fuel balances, we’re really not putting that or the new methodology does not put that into the numerator. That rolls off and will be largely done by the end of 2026. So that’s where we really were with regards to the deferred fuel and the end of the year. So the 14% was under the old methodology and call it 13.5, 13.6 under the new methodology. And then we’re at 13.2, you’re right, with the trailing 12 months, but what we’re anticipating is the minority interest transaction will raise that by 40 to 60bps.

So that’ll take us to 13.6% to 13.8% once we close that transaction and then just continued focus on execution around efficient operations and increasing the numerator will be a big part of how we’re going to ultimately get into that 14% to 15% targeted range that Bill and I really feel we want to be in so that, you know, we can have a level of cushion well above our 13% downgrade threshold. So hopefully that gives you a little bit of color.

Andrew Wiesel: Yes, that’s very helpful. Okay, great, Great. And then one, just to clarify, of the recent regulatory wins, were they all included in the CapEx plan already? Specifically, I’m talking about the 1.1 billion of transmission from Transource Energy and the 600 million through AEP Transcos as well as the Texas Resilience plans.

Trevor Mihalik: Yes, look, I would say from our perspective, within the plan, we laid out what we thought was a very good plan at the beginning of the year. I came in as the new CFO, certainly pressed on what the planning assumptions were, and we’re still very committed to our 575 to 595 and there’s going to always be some puts and takes, but at the end of the day. We feel very good about where we are on the 575 to 595 and the overall 6% to 8% long-term growth rate.

Andrew Wiesel: Okay, I guess my question was, were those projects included in the $54 billion five year plan?

Trevor Mihalik: Yes. And again, I would say yes, there are some projects that are included, there are some projects that fall away. So there’s always puts and takes, but generally, yes.

Andrew Wiesel: Okay, got it. But you’re saying there’s flexibility for projects over time. Understood. Okay, thank you so much.

Trevor Mihalik: Absolutely. Yes.

Andrew Wiesel: Thanks.

Operator: And that will conclude our question and answer session. I will now hand the call back over to Bill Fuhrman for closing remarks.

Bill Fehrman: 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 when I think 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 incredible support we’ve had from our board to keep pushing forward with our plan to really strengthen the balance sheet, improve our regulatory outcomes and execute around what our states want. And I couldn’t be more excited to be with this team and see where we’re taking the company. So if there’s any follow up items, please reach out to our IR team with your questions. This now concludes our call. Thank you.

Operator: Today’s conference will be available for replay beginning approximately two hours after the conclusion of this call and will run through 11:59 Eastern Time on Tuesday, May 13, 2025. The number to dial to access the replay is 800-770-2030 or 647-362-9199 for international callers. The conference ID number for the replay is 786-4240. This concludes today’s conference call. Thank you all for joining. You may now disconnect.