Ladies and gentlemen, thank you for standing by. And welcome to the American Electric Power Second Quarter 2021 Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. As a reminder, this conference is being recorded. I would now like to turn the conference to our host, Vice President of Investor Relations, Ms. Darcy Reese. Please go ahead.

Thank you, Toni. Good morning, everyone. And welcome to the second quarter 2021 earnings call for American Electric Power. We appreciate you taking the time to join us today. Our earnings release, presentation slides and related financial information are available on our website at aep.com.

Okay. Thanks, Darcy. And welcome again everyone to American Electric Power’s second quarter 2021 earnings call. Today we reported a strong second quarter operating earnings of $1.18 per share versus $1.08 for the same period of 2020. Our second quarter results reflect significant progress in terms of economic recovery throughout AEP's service territory, with a continued focus on OEM as we navigate through what is hopefully an emergence from the COVID-19 pandemic. Gross regional product has already exceeded its pre-pandemic levels and importantly across AEP's service territory, it is now 2% of its pre-pandemic levels after adding over 163,000 jobs in the first six months of this year. Increased vaccinations combined with the additional fiscal stimulus from the American Rescue Plan are contributing to the strong demand for goods and services throughout the economy. AEP’s normalized retail sales in the second quarter of 2021 were the highest we have seen since the second quarter of 2018. Clearly, we are pleased with the improvements we have seen thus far and we will continue to monitor the recovery’s progress over the second half of the year. Accordingly, we are reaffirming our 2021 guidance range of $4.55 per share to $4.75 per share and a 5% to 7% long-term growth rate and would be disappointed not to be in the upper half of our stated guidance range as we have previously stated. Julie will be discussing these issues in more detail in her report. Rate case activity across our jurisdictions continues to be active and substantial. In Ohio, we are awaiting an order by the commission on the settlement reach involved with the commission earlier this year. As a reminder, the settlement has broad support among the settling parties including the commission staff, the Ohio Consumers Council, industrial companies, commercial companies and other entities like the Ohio Hospital Association. We expect a decision in the third quarter of this year. Public Service Company of Oklahoma filed a rate case at the end of April. PSO is seeking a $115.4 million net revenue increase and a 10% ROE. The following transitions North Central costs from the right established in the approval into base rates.

All right. Thanks, Nick. Thanks, Darcy. It’s good to be with everyone this morning. I am going to walk us through the second quarter and year-to-date financial results, share some thoughts on our service territory load and finish with a review of our credit metrics and liquidity. So let’s go to slide number six which shows the comparison of GAAP to operating earnings for the quarter and year-to-date periods. GAAP earnings for the second quarter were $1.16 per share, compared to $1.05 per share in 2020. GAAP earnings through June were $2.31 per share, compared to $2.05 per share in 2020. There’s a reconciliation of GAAP to operating earnings on pages 14 and 15 of the presentation today. So let’s walk through our quarterly operating earnings performance by segment that’s laid out on slide number seven. Operating earnings for the second quarter totaled $1.18 per share or $590 million, compared to $1.98 per share or $534 million in 2020. Operating earnings for the Vertically Integrated Utilities were $0.45 per share, down $0.10 driven by a year-over-year increase in the O&M due to lower prior year O&M, which included actions we took to adjust to the pandemic. Other pressures included lower wholesale load and higher depreciation and other taxes. These items were partially offset by the impact of rate changes across multiple jurisdictions, higher normalized retail load, transmission revenue and off system sales. The Transmission and Distribution Utilities segment earned $0.31 per share, up $0.02 from last year. Favorable drivers in this segment included higher normalized retail load, transmission revenue and rate changes, partially offsetting these favorable items were higher tax, depreciation and O&M expenses, as well as unfavorable weather and lower AFUDC. The AEP Transmission Holdco segment continued to grow contributing $0.34 per share, an improvement of $0.15, which got a boost because of the unfavorable annual true-up last year consistent with the 2021 earnings guidance assumptions we had provided to you. Our fundamental return on investment growth continued as net plant increased by $1.4 billion or 13% since June of last year. Generation and Marketing produced $0.09 per share, down $0.02 from last year, influenced by the prior year land sales and one-time items relating to an Oklaunion ARO adjustment in the sale of Conesville. We were mostly offset in the generation business by higher energy margins and lower expenses from the retirement of Oklaunion. Finally, Corporate and Other was up $0.05 per share, driven by investment gains and lower taxes, which were partially offset by higher O&M and net interest expense. So bear with me a moment, I am going to talk a little bit more about that investment gain as we walk through the year-to-date view. So, if you flip to slide eight, we can look at year-to-date results. Operating earnings through June totaled $2.33 per share or $1.2 billion, compared to $2.10 per share or $1 billion in 2020. Looking at the drivers by segment, operating earnings for Vertically Integrated Utilities were $1 per share, down $0.05 due to higher O&M and depreciation expenses. Other smaller increases included lower normalized retail and wholesale load, higher other taxes and a prior period fuel adjustment. The impact of weather was favorable due to the warmer than normal temperatures in the winter of 2020. Other favorable items in this segment included the impact of rate changes across multiple jurisdictions, higher off-system sales and transmission revenue. The Transmission and Distribution Utilities segment earned $0.54 per share, up $0.01 from last year. Earnings in this segment were up due to higher transmission revenue, rate changes, weather and normalized retail load, partially offsetting these favorable items were higher tax, depreciation, O&M and interest expenses, as well as lower AFUDC. The AEP Transmission Holdco segment contributed $0.68 per share, up $0.21 from last year, for the same reasons identified in the quarterly comparison. Generation and Marketing produced $0.16 per share, down $0.02 from last year, due to favorable one-time items in the prior year relating to an Oklaunion ARO adjustment in the sale of Conesville; higher energy margins and lower expenses in the generation business offset the unfavorable ERCOT market prices on the wholesale business during Storm Uri in February. The decrease in renewables business was driven by lower energy margins and higher expenses. Finally, Corporate and Other was up $0.08 per share, driven by investment gains and lower taxes and partially offset by higher O&M. So, let me take a quick moment to comment about the investment gain which is predominantly a function of our direct and indirect investment in charge point. As you will see on the waterfall, this produced a $0.09 benefit year-to-date in 2021 as compared to the corresponding 2020 period. You may recall that in the fourth quarter and full year 2020, this investment produced a $0.05 contribution and we would expect the year-over-year variance to be more pronounced at this point in 2021 as we had no benefit during the same period in 2020. So, turning to page nine, I will update you on our normalized load performance for the quarter. Before I talk about class level trends, I’d like to start with a couple of observations at a macro level. First of all, since all of these charts are showing a year-over-year growth, it is important to recall that the second quarter of 2020 was at the trough of the recession when restrictions on businesses to manage the public health crisis were at their greatest. Therefore, the magnitude of growth percentages is being influenced by the comparison basis. The second observation is that there has been a steady path to recovery since bottoming out in the second quarter of last year. The momentum we are seeing is a positive sign for the economic recovery throughout the serviced territory.

So, if you start in the upper left corner, you will see that normalized residential sales were down 3.1% compared to last year bringing year-to-date decline down to 0.5%. As mentioned earlier, the comparison basis is the key here. You will notice that residential sales were up 6.2% when the COVID restrictions were at their greatest. In fact, one year later, they are only down 3.1%, which suggests some of the increase in residential has some staying power as more businesses have embraced a remote workforce for jobs that can be easily performed at home. In fact, the second quarter normalized sales in 2021 were the second highest second quarter on record exceeding every second quarter before the pandemic began. So moving to the right, weather normalized commercial sales increased by 10% bringing the year-to-date growth up to 3.9%. If you compare this with the residential class, you will notice the commercial sales growth in the second quarter is more symmetrical with last year when sales were down just over 10%. The growth in commercial sales for the quarter is spread across all operating companies and most sectors. The only sector that was down slightly compared to last year was grocery stores, which were very busy at the onset of the pandemic trying to keep shelves stocked when panic purchasing was at its highest. So moving to the lower left corner, you will see that industrial sales also bounced back in the second quarter. Industrial sales for the quarter increased by 12.8% bringing the year-to-date growth up to 2.8%. Similar to the commercial class, you will see a symmetrical recovery compared to the second quarter of 2020 when sales were down 12.4%. Also industrial sales were up at every operating company and nearly every sector. The only industrial sector in our top 10 that reported less sales this year compared to the second quarter of 2020 is the paper manufacturing sector, which ironically was also higher last year, partially due to panic purchasing of toilet paper. This is a phenomenon that none of us is likely to forget especially if you were one of the folks who didn’t get a jump on it. Finally, in the lower right corner, you can see that in total normalized retail sales increased by 6.3% for the quarter and were up 1.9% through the first half of the year. By all indications, recovery from the pandemic and recession are on firm footing.

Let's look at slide 10. This slide includes two charts that provide context for the normalized sales performance in the second quarter. The bar chart illustrates the weather normalized retail sales for the AEP System over the past five years in the second quarters. The retail load performance in the second quarter of 2021 has not only bounced back from the recession, but it also marks the highest second quarter since 2018. The line chart below shows seasonally adjusted retail sales by quarter, highlighting the trend of recovery and confirming that our current sales levels are the highest since the second quarter of 2018. Before we conclude the discussion on load, I want to point out an important factor to consider regarding load growth: the mix is significant. While we are currently experiencing strong growth in commercial and industrial sales, these sectors are priced at much lower rates compared to the decline we are witnessing in residential sales. To emphasize this, the pandemic's impact was most evident in our largest metropolitan area, Columbus, Ohio. Since AEP Ohio operates in the T&D Utility segment with unbundled rates, the strong recovery we are observing this year is reflected at much lower realizations compared to the system average. Lastly, it's important to remember that there are rate design mechanisms in place to mitigate exposure during downturns, which can also help cushion the impact during the recovery from a recession.

So while the industrial sales are up significantly this year versus last year, it does not mean that revenues will increase by the same percentage. So what does all this mean when we think about the remainder of 2020? Well, it means that our confidence in our earnings guidance range is fortified by what we are seeing. It suggests that the low trends we anticipated are coming to fruition as the chart on page nine illustrates. Our continued investment at Transco is fueling strong performance in this segment beyond the favorable true-up impact that we had anticipated. And while O&M is up, it’s enabling us to take care of our business and customer needs given the low growth we are seeing. Obviously, we have the second half of the year to navigate, but we are pleased with the direction and are keeping a watchful eye on economic activity in our service territory, while scanning for any impact associated with the rise in COVID variants.

So, let’s check in on the company’s capitalization and liquidity position on page 11. On a GAAP basis, our debt to capital ratio increased 0.1% from the prior year quarter to 62.6%. When adjusted for the Storm Uri event, the ratio remains consistent with year-end 2020 at 61.8%. Let’s talk about our FFO to debt metric. As it did in the first quarter, the effect of Storm Uri continues to have a temporary and noticeable impact in 2021 on this metric. Taking a look at the upper right quadrant on this page, you will see that our FFO to debt metric based on the traditional Moody’s and GAAP calculated basis, as well as on an adjusted Moody’s and GAAP calculated basis. On a traditional unadjusted basis, our FFO to debt ratio increased by 0.2% during the quarter to 9.3% on a Moody’s basis. On an adjusted basis, the Moody’s FFO to debt metric is 12.8%. To be very clear, this 12.8% figure removes or adjusts the calculation to eliminate the impact of approximately $1.2 billion of cash outflows associated with covering the unplanned Uri-driven fuel and purchase power costs in the SPP region directly impacting PSO and SWEPCO in particular. This metric is also adjusted to remove the effect of the associated debt we used to fund the unplanned payments. It should give you a sense of where we would be from a business as usual perspective. As you know, we are in frequent contact with the rating agencies to keep them apprised of all aspects of our business. The rating agencies continue to take the anticipated regulatory recovery into consideration as it relates to our credit rating. And importantly, there continues to be no change in our equity financing plan and our multiyear cash flow forecast laid out on page 39 does not assume any asset rotation proceeds. Given the regulatory recovery activity that currently is in flight, we do expect our FFO to debt cash flow metric to return to the low to mid-teens target range next year. So here’s a quick refresh on where all this regulatory activity stands today for PSO and SWEPCO. In Oklahoma, we are working through the regulatory process and anticipate issuing securitization bonds in the first half of 2022. In both Arkansas and Louisiana, recovery is underway, while final details get worked out in the regulatory process and we will be filing for recovery in Texas in the third quarter of 2021. So let’s take a quick moment to visit our liquidity summary on slide 11. You will see here that our liquidity position remains strong at $3.3 billion, supported by our five-year $4 billion bank revolver and two-year $1 billion revolving credit facility that we entered into on March 31st of this year. If you look at the lower left side of the page, you will see that our qualified pension continues to be well funded and our OpEd is funded at 174.2%. So let’s go to slide 12, we will do a quick wrap up and we can get your questions. Our performance in the first half of the year gives us confidence to reaffirm our operating earnings guidance range of $4.55 per share to $4.75 per share. Because of our ability to continue to invest in our own system organically including both our energy delivery system and the transformation of our generation fleet, we are confident in our ability to grow the company at our stated long-term growth rate of 5% to 7%. So we surely do appreciate your time and attention today. So, with that, I am going to turn the call over to the Operator for your questions.

Thank you. And that will come from the line of Julien Dumoulin-Smith with Bank of America. Please go ahead.

Hey. Good…

Hi, Julien.

Thank you for all the remarks. I’d say at the pace that you guys were just talking I would have mistaken you guys sitting in New York or something like this?

Yeah. No.

So, I am going to try to catch up on everything that was just said. But maybe in summary on the logos, I hear you. I think the critical comment you made was mixed. Where are you trending against your guidance range here as you think, but obviously the third quarter matters critically. I mean, I know we are still early-ish in the year?

Yeah. I think, well, you just sort of answered the question. We are still early in the year because the third quarter is particularly meaningful and we typically look after third quarter to see where we actually stand. But again, as Julie mentioned, OEM goes up commensurate with all the customer expansion as well and we have pretty sizable customer expansion. Look at the industrial and commercial numbers. They are up considerably. So and I think obviously without outstripping our estimate going into the year of what overall load growth would be. But it remains to be seen. Because I think we are sort of in a very cyclical period of trying to figure out what the future holds in terms of whether this other variant of COVID is going to have an impact or what happens actually; is there just pent-up frustration then it starts to moderate? What’s promising is though that we are still seeing residential load, although it’s negative to 2020; it’s still a positive overall. So our original thesis of more residential load going forward. And if we can tie that together with improved industrial and commercial load as well, it could be very positive. But we certainly have to feel our way through that and really understand that. So we pass the third quarter before we really have a good feeling of that. Julie?

Yeah. Just maybe add a little finer point too. If you are thinking sequentially for the remainder of the year, our load growth rates are expected to moderate in the second half of the year based on prior year comps. So when you think about it, restrictions were most severe in the second quarter and by the third quarter of last year, the service territory had begun essentially a phased reopening. And so as a result, the 6.3% growth for the second quarter, probably not only the highest growth in the quarter, and actually it is the highest growth in AEP’s history. But it will also be the highest load growth stat during the recovery. So if you think about the second half of the year, I would expect it year-over-year to moderate a little bit and so we are just keeping a watchful eye on how the trend continues to click along. I know I saw in the Wall Street Journal this morning CFOs commenting on where they think the economy is going to go, doesn’t look like anybody is changing their estimates based on COVID trends. But we are keeping an eye on that.

Got it. Excellent. Thank you. And then, if I can pivot the text, obviously, you all have a pretty meaningful footprint there. We have seen various legislative efforts underway. I am curious, as best you can tell thus far, I know it’s early. Any kind of context you can put especially on the transmission side, the potential project here? We are hearing from some of your peers about potentially meaningful shifts?

Well, certainly, obviously, it remains to be seen as far as transmission investment and really we think of T&D and what part of the business is associated with T&D. We have made some inroads in terms of backup generation, those kinds of things in terms of transmission. I really think there’s probably continued opportunity for development of storage capability, of other transmission related investments on the grid to ensure that we are able to adjust that. For us, we are doing a lot in terms of line of sight into the transmission grid itself. We are continuing to expand our scale abilities, continuing to focus on our ability to have even more transmission in place, because if you are looking for additional generation to be placed in various areas, well, transmission is a big part of that solution as well. So is that, I think, Texas is sort of a microcosm of the country when you start reevaluating the system based upon the needs from not only a natural gas perspective, but also from a renewable perspective, that brings in the whole planning effort and communication in real time associated with the operations of the transmission and distribution system as well. So I think they are making the right steps and I think there’s more steps to be made, and it’s going to be a sort of a multiyear top of effort, and of course, we are a big part of the transmission in Texas. So we will be certainly very focused on how the T&D business can be expanded to improve the resiliency of the T&D efforts. But that means Texas is really going to have to start thinking about resources and a broader view of resources like we are having to do for the rest of the system and transmission technologies, and for that matter, distribution technologies are going to have to be recognized in their ability to provide a more resilient grid. You can’t have these strict lines drawn between generation and transmission and distribution because that’s not the world we are in anymore. So, we will continue that focus. Every legislative session, every regulatory session will be centered on that effort.

Excellent. Just last, Kentucky, I know you can’t say much, but what’s the level of interest if you can give any kind of parameters?

Yeah. So, yeah, obviously, I don’t want to get into too much detail there. I think, again, you answered it sort of right at the beginning. It is a confidential process. But I can say that we do have credible interest and it is a competitive process.

Excellent. Thank you all. Take care.

Okay.

Thank you. Our next question comes from Steve Fleishman with Wolfe Research. Please go ahead.

Hey. Good morning. Can you hear me, Nick?

Good morning. Oh! Yeah. I can hear you fine.

Okay. Great. Thanks. I might have missed this, but just where are you on this $600 million of equity plan for this year? How much have you issued so far?

Yeah. Thanks for the question, Steve. We have actually used the ATM to issue just under $200 million. I think there’s around $195 million that was associated with the financing of the Sundance North Central wind facility and we will be continuing on with the rest of that program. As you know, about $100 million of that $600 million is also associated with the drip. So that continues to play in the background. Does that help?

Okay. This might be a little bit challenging to address, but regarding the $1.4 billion planned for next year, if you were to sell Kentucky, that could potentially help offset some of that amount. Could you share your latest thoughts on how the outcome in Kentucky relates to the $1.4 billion projection for next year?

Sure. I’ll let Nick add more from a strategic angle, but from a financing standpoint, you're correct, Steve. We have $1.4 billion included in our plan, and for those following along, that’s on page 39 of the cash flow section for 2022. Approximately $100 million of that is linked to the drip, around $800 million is related to north central wind financing, and the remaining $500 million is dedicated to general growth CapEx funding. As you mentioned, if we find ourselves in a position to bring in funds, we would certainly work off some of that instead of relying on equity issuance. I can’t provide a specific number as we currently don’t have a transaction, but that’s definitely part of our thinking and scenario modeling. Nick, if you have anything to add, please feel free.

I believe you covered it well. It's great to have a financing plan in place in case a sale in Kentucky doesn’t occur. Additionally, having options to optimize that financing plan is beneficial. The timing, especially with Traverse being the largest deal in the first quarter of 2022, aligns well with this process. We will resolve this, and there will be financing one way or another. Ultimately, the timing and process are proceeding as planned.

And just if I could…

Okay.

…to follow up…

Yeah.

…Steve. Again just to reiterate. The plan as it stands today, as you know, assumes no asset rotation. And again, I want to reinforce that, the 5% to 7% is well intact even if we don’t have a transaction.

Okay. Do you have a preference within that range or is that just the range?

That’s probably something we can’t answer at this point, Steve.

Okay. So you are being very unbiased?

We are.

Smart move. Okay. Thanks so much.

Yeah. Sure. Thanks.

Thank you. Our next question comes from the line of Shahriar Pourreza with Guggenheim Partners. Please go ahead.

Good morning, Shahriar.

Hey. Good morning, guys. I wanted to start with a recent event and get your sense on the Mitchell order and Kentucky, sort of rejecting the rate increase you saw, and obviously, it’s not a surprise with AG strong comments prior to the decision. Nick, is this sort of a signal that the state and the PSC in general are starting to commit to maybe a little bit more of a rational thinking around an economic approach to coal like the least cost approach is just starting to bend further towards renewable? So how do we think about the viability of the plant in the state and could we see some acceleration of that 1.4-gig of solar and when you bought into plan for the state on a prior call as a direct grid? And then, how do we sort of think about West Virginia’s rate request coming off the Kentucky order?

It’s interesting because it involves multiple jurisdictions. Mitchell is working with Kentucky Power, and we need to address matters in Kentucky, Virginia, and West Virginia. West Virginia hasn't commented yet, and we're still waiting for the administrative law judge in Virginia to weigh in. It's crucial for us to be cautious for now as we navigate the state processes. Gaining clarity is important, and Kentucky will be the first to provide that insight. We've indicated that these units span multiple jurisdictions, so we need to ensure compatibility among them. We will follow the processes in place and gather the initial perspectives of the commissions. If their views diverge, we will need to analyze and resolve those differences, knowing that some resolutions may take longer than others. Understanding the positions of all three commissions is essential before making any decisions. Clarity is beneficial, especially since there's a distinction between ELG and CCR investments. If CCR investments are approved but ELG investments are not, it would push back the generation retirement dates from 2014 to 2028, which is a significant factor to consider with these commissions. We expect to have more information around August. It’s intriguing that Kentucky is examining the ELG aspect, and there’s a growing awareness of the need for a comprehensive plan. However, we need consensus from all the commissions before finalizing what that plan will look like. More updates will follow.

Got it. And thanks for the visibility around sort of the Kentucky process. I know, Nick, you obviously mentioned that further optimization is always a possibility. Remind us just like that sugar point is the shaping of that for instance that 16.6 gigawatts of renewables you discussed in the prior call. Obviously, Kentucky will more than likely backfill some of your North Central equity needs. So as you are thinking about further optimization, should we be watching the outcomes at the IRPs, the PSC approval, how much you plan to own versus PPA, which I guess would stipulate your incremental equity needs and the resulting size of potentially further optimization measures?

We have been discussing how North Central will be financed for a couple of years now, and we're finally nearing a point where we will have clarity on the financing. With the 16.6 gigawatts, we have made a strong case for owning a significant portion of it, ideally all of it. It's crucial for us to own and control these assets from an operational and contracting perspective, particularly as we manage system-related activities. Moving forward, the integrated resource planning filings will initiate a more meaningful dialogue, and we are currently in the process of conducting RFPs to gather more information from the market regarding development options, which is ongoing. This process will strengthen any CCN filings we need to make following the resource planning filings. These filings will provide our first real discussion on the speed of this transformation across different jurisdictions. We feel positive about this progress as we determine the capacity needed to support utilities, and it's clear that we are shifting towards a clean energy economy. As long as there is some level of baseload capacity available 24/7, renewables will play a significant role. The options and their timelines are becoming clearer in our jurisdictions, influenced by both federal and state conditions, and this will drive the resource planning process.

Got it. And lastly for me and I apologize if I am putting you on the spot, Nick. The news just broke out this morning. But is there any kind of refer to the First Energy deferred prosecution agreement that was announced this morning to the SEC investigation at AEP?

No, we are on the outside looking in and have no information regarding that activity. If the report is accurate, I am relieved to see some progress in moving past it, as AEP has been impacted by this situation. I am hopeful for some closure. It was a surprise to me, and we were unaware of it. There really isn’t anything more to add from AEP beyond what we have already shared on our website, and there is no further information to provide from our side.

Terrific. Thank you, Nick and Julie. Congrats on today’s results.

Yeah. Okay.

Thank you. Our next question comes from the line of Stephen Byrd with Morgan Stanley. Please go ahead.

Good morning, Stephen.

Hey. Good morning.

Okay.

Congrats on a constructive update and on weeping in, you mentioned of both, Carly Simon and a maybe a first.

Yeah. Right.

Okay. So a lot has been covered. Just wanted to discuss on Kentucky, if there are approaches that can help minimize tax leakage, how are you all thinking about sort of the ability to bring proceeds back and sort of the impact of taxes?

Yeah. Thanks for the question, Stephen. As you know, we are a little tax efficient right now. So, given the tax basis in Kentucky and the different hurdles that we are considering, I wouldn’t see that one being a show stopper. And quite frankly, that might give us an opportunity to enhance or improve our tax efficiency without getting into a bunch of numbers. I wouldn’t let that trip you up in terms of what things could stop us moving forward.

That's helpful. Could you provide more detail on the timetable for the upcoming RFPs, specifically the APCo and SWEPCO RFPs? I apologize if I missed it earlier, but I'm trying to understand what this means for the timing of additional spending and how we should approach these processes.

We have completed the basic requirements for the RFPs in these areas. At APCo, we released an RFP for 300 megawatts of solar and wind resources set for completion in 2023 or 2024. Additionally, in May 2021, APCo issued an RFP to acquire 100 megawatts of solar and wind energy through a PPA and RFP specifically for renewable energy certificates, in line with Virginia's requirements. SWEPCO issued an RFP for up to 3,000 megawatts of wind and up to 300 megawatts of solar resources, incorporating optional battery storage, aiming for completion between 2024 and 2025. They are also seeking 200 megawatts of capacity for 2023 to 2024 and another 250 megawatts for 2025 to 2027, with bids due in mid-August. At PSO, we notified regulators in June of our intent to issue an RFP for up to 2,600 megawatts of wind and up to 1,350 megawatts of solar, again including options for battery storage, to meet capacity needs by 2025. This RFP is planned to be issued in October of this year. These projects are focused on near-term capacity requirements. They will follow a similar process to earlier projects and we plan to own them once they are approved by the appropriate regulatory authorities. We are actively engaging with our Board on strategies related to these filings and long-term plans, emphasizing that this will be an ongoing process driven by capacity needs rather than just energy convenience. We're excited about the current opportunities and that’s our update at this time.

That’s really helpful. That’s all I had. Thank you.

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

Hi. Good morning.

Good morning. How are you doing?

Good. Good.

Okay.

Just wanted to pick up on Kentucky a little bit more, if that’s possible and I just want to know if you might be able to comment in any degree to whether the strategic review process has received more interest from strategic or financial players? And then as well, kind of given strong prices achieved in recent industry transactions and the strong interest here in Kentucky, has this process made you thought about more asset rotation beyond Kentucky to increase balance sheet headroom overall?

We began this process anticipating involvement from both strategic and financial partners, and that has indeed been the case. Regarding your second question, as I mentioned earlier, this will be an ongoing process for us. Given that we are nearly fully regulated, we have the chance to consider how to build 16.6 gigawatts of renewable resources during this transition, which means we need to have all options on the table for sources and uses. We will continue this assessment, starting with Kentucky, but our evaluation of assets will expand. If it aligns with other opportunities, that will guide our direction for the company.

Got it. That’s helpful. Thanks for that. I'm curious about the recent developments from FERC regarding the transmission planning process. Could you share your insights on what's been discussed lately and what you consider to be best practices in this area?

We would like to see improved transmission planning across regions, and AEP does a solid job of that due to our large system. However, there needs to be more consistency in the planning processes between different RTOs to facilitate large transmission projects across various regions and states. This is especially critical for connecting renewable resources to load centers, which means we must tackle issues around multi-jurisdictional and multi-RTO analyses to ensure consistency. Additionally, we need uniformity in rate-making, and re-evaluating incentives can hinder decision-making regarding transmission and the RTO model itself. FERC should take a step back to review this matter. Focusing on planning and addressing RTO boundaries and competitiveness is essential, but we need a clear planning process. It's unacceptable to halt a project after millions have been spent. We also need to make investments with certainty and act quickly on them. While being part of an RTO offers considerable value for customers, there must also be value for the companies making those investments, which should significantly outweigh any costs tied to transmission incentives. It's detrimental to question future recovery of transmission investment plans, as this sends a negative message regarding participation in RTOs. Revisiting assumptions about incentives can make it challenging for anyone trying to develop a long-term model that highlights the benefits of transmission. This process requires careful consideration to achieve our goals.

No. That’s helpful. Thank you for that. I will stop there. Thank you.

Thank you.

Thank you. And our final question comes from the line of Durgesh Chopra with Evercore ISI. Please go ahead.

Hey, Durgesh. How are you?

Hey. Good morning, Nick. Thanks for taking my question.

Good morning.

Hey. You addressed sort of a lot of transmission questions in the Q&A. Maybe just like the MISO transmission opportunity that the MISO has flagged perhaps just sort of unveiled towards the end of the year. I know a small sort of a set of assets for you in that location. But could you compete for some of those projects? Could that be an upside for you there?

Oh! Yeah. We could. We could compete with our Transource entity, which we have been. But, yeah, we could. And actually a small impact for us as it stands. But certainly, we could certainly participate in any of that, yeah.

Understood. And then just anything you are hearing at your level and your peers and through the sort of the EI organization. I mean the infrastructure bill has a pretty sizable CapEx on the transmission side or investment on the transmission side. Just anything you are hearing from that on the federal front?

We are discussing a $1.2 trillion infrastructure bill, which marks a shift in how we talk about funding, moving from billions to trillions. There seems to be some alignment in Washington regarding hard infrastructure, but further refinement in the language is necessary. In terms of advancing transmission investments and direct pay, those aspects are crucial as we also focus on renewables and clean energy, including extensions of PTCs and ITCs, particularly in light of COVID-related delays. We see opportunities there, and for electric vehicles, we want to support the ongoing development of infrastructure. It’s important to leverage private companies like ours rather than solely relying on government funding for transmission development. If the government can simplify the siting process and enhance planning, it would facilitate investment in transmission. We are capable of financing transmission investments, but the government should selectively determine where they want to focus, ensuring they don't duplicate existing utility leverage. They can promote electric vehicle charging infrastructure, which would be beneficial. For renewable energy, we need to accelerate our transition through hard infrastructure, tax incentives, and new technologies like storage. We would also advocate for tax incentives for coal-fired generation to address underappreciated plant balances. To advance a clean energy economy, it's vital to quickly improve these balances, allowing states to make informed decisions about future resource replacements. There are multiple ways to approach this, but it’s essential that the government focuses on specific areas to enable continued private sector investment.

Appreciate that insight, Nick. It's great to see First Energy resolved the DOJ investigation, or at least reached an agreement this morning. Do you have any updates on the SEC subpoena? Is there any additional information you can share with us?

No, there's nothing new to report. We have been in communication with the SEC and are responding to any documentation requests they have. We will continue to collaborate with them in a supportive and constructive manner.

Understood. Thank you for taking my questions.

Yeah.

Thank you. And our last question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead.

Nice try on that one.

Michael who?

Yeah. Hey, actually, Michael, the guy who’s excited about the changes in the Southeastern Conference they had. Hey, guys, real quick question or two. First of all, one on O&M this year, obviously, O&M at the VIU segment is up a lot. How do you think about what the second half of the year O&M trajectory looks like versus the first half? And how should we think about both for VIU and T&D kind of segments, the long-term kind of the 2022 and beyond trajectory for O&M?

Yeah. I will just generally say, and Julie can certainly follow up on this, but as you have expansions in customer load, you are going to have higher O&M associated with that, but that’s a good expansion. The issue for us is, what we typically do is, we are evaluating the true impacts of our Achieving Excellence Program against what our forecast needs to be in terms of bending the O&M curve. So we continue to take account of the good O&M that supports the expansion from a customer load perspective, but also continue to not only optimize that, but also continue the overall optimization of the O&M budget itself. So, yeah, you may see it, and that’s why, obviously, we are watching what third quarter looks like and fourth quarter with the load that does. But we want to make absolutely sure that we are continuing to make progress consistent with that plan of consistent earnings and dividend improvements in that 5% to 7% growth trajectory. So that’s what we are doing. We are not just saying, oh yeah, load’s going up, let’s spend more O&M. It really is a measured approach from our perspective. Julie?

Yeah. No. That’s spot on, Nick. And thanks for the question, Michael. As I am sitting here thinking about this and as we were preparing for the earnings call, one of the things I am looking at is the mix point. You look at where load is coming in. And as mentioned in a previous answer to a question, we do expect that load on a relative basis. When you compare it to last year, for the second half, it would not be as pronounced, although we do expect it to continue to improve. So that’s a good thing. And that allows us to be a little more comfortable with O&M costs where they are, because that does help the customer in the long run. So we keep that top of mind and continue to be very diligent about managing costs. But if you are trying to model for the rest of the year, let me start by saying this, we are not changing our guidance. But as you know, once we start the year and we give you that plan, so you see that waterfall that we give to you, how we get to the end of the year, obviously changes, right, because it’s a dynamic business. So I wouldn’t be surprised if relative to that plan, if you saw our O&M be running a little richer. But I would hope that load would be hanging in there too. And then, as you know, we are doing well on the Transmission Holdco segment already kind of clipping along where we thought we would be for the full year. So there may be some benefit there too. So do keep that in mind when you go back and compare and contrast to that guidance walk that we gave to you. I think it was on February 25th during our earnings call and then we are happy to help you with any modeling that you have offline.

No. That sounds great. Thanks, guys. Much appreciated.

Sure. Thanks.

Thank you for joining us on today’s call. As always, the IR team will be available to answer any additional questions you may have. Toni, would you please give the replay information.

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