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 a $1.18 per share versus a $1.08 for the same period of 2020. Our second quarter results reflect significant progress in terms of economic recovery throughout AEP 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 important across AEP service territory is now 2% of its pre-pandemic levels after adding over a 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 again 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 in 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 $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, lower tax -- and lower taxes, which was 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, other -- higher other taxes and a prior period fuel adjustment. The impact of weather was favorable due to the warmer than normal temps 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. So, 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. So the magnitude of growth percentages is being influenced by the comparison basis. And 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 is having 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 the 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 -- up 2.8%. Similar to commercial class -- 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 a 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 a firm footing. So, let’s go to slide 10. There are two more charts here that help put the second quarter normalized sales performance into perspective. The bar chart shows the last five years of weather normalized retail sales in the second quarters for the AEP System. Retail load performance in the second quarter of 2021 has not only recovered from the recession, but this is also the highest second quarter since 2018. The line chart on the bottom of this page shows the seasonally adjusted retail sales by quarter which provides an illustration of the trend of the recovery, and again, confirms that our current level of sales is the highest since the second quarter of 2018. So, before we leave the load story, let me remind you of an important factor to consider when evaluating the impact of load growth. The mix matters. So, while we are seeing strong growth now in commercial and industrial sales, those are priced at much lower realizations than the decline we are seeing in residential sales. To further illustrate this point, the impact of the pandemic was most pronounced in our biggest metropolitan area, that’s Columbus Ohio. Since Columbus -- since AEP Ohio is in the T&D Utility segment where we only collect an unbundled rate, the strong recovery that we are seeing this year is coming in at much lower realizations in the system average. Finally, let me remind you that there are rate design mechanisms in place to limit the exposure when entering a downturn that can also limit the impact when you are coming out of 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 rise in COVID variant. 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 increase 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 is laid out on page 39 does not assume any asset rotation proceeds. Given the regulatory recovery activity that currently 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 there are 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. Julien Dumoulin-Smith: Hey. Good…

Hi, Julien. Julien Dumoulin-Smith: 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. Julien Dumoulin-Smith: 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 third quarter matters critically, obviously kept intact the total load growth here? Any comments to just resolve that against the full year numbers, 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 are just pent-up frustration then it starts to moderate. What’s promising is though that we are seeing -- 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, so 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. Julien Dumoulin-Smith: 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 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 it -- for that matter the distribution system as well. So I think they are making the right steps and I think there’s more steps to be made so 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 its 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. Julien Dumoulin-Smith: 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 a credible interest and it is a competitive process. Julien Dumoulin-Smith: Excellent. Thank you all. Take care.

Okay.

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

Good morning, Steve.

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.

Yeah.

And then just -- this might be a little bit hard to answer, but just in terms of thinking about the $1.4 billion for next year that’s in the plan. Obviously, if you were to sell Kentucky, some of that could maybe offset some of that. So just -- could you just give us latest thoughts on how to think about the Kentucky outcome relative to that $1.4 billion for next year?

Yeah. And then, I will -- Nick can add a finer point from a strategic perspective. But purely from a financing perspective, you are right on the money, Steve. So we got $1.4 billion embedded in our plan. And for those of you who following along at home, we are on page 39 of the cash flow if you want to take a look at 2022. About $100 million of that again is associated with the drip, about $800 million is associated with north central wind financing and then we have another $500 million just associated with general funding of growth CapEx. And so to your point, Steve, to the extent that we would find ourselves in a situation where we were able to transact and bring dollars in the door, we would absolutely be able to work off some of that, otherwise equity issuance and sidestep that. So I don’t -- I can’t give you a number. We don’t have a transaction. But that is absolutely the thinking and how we are modeling different scenarios inside the house. And I don’t know, Nick, if you have any comment, it would be great.

Well, I think, you covered it well. As far as -- it’s great to have a financing plan assuming Kentucky a sale at Kentucky doesn’t happen. But also it’s great to have options available to further optimize what that financing plan looks like. So and it is -- and I will say again, the timing particularly with Traverse being the last one, it’s the largest one in first quarter 2022, that sums up pretty well with this process. So we will get this resolved and there will be finance one way or another, but at the end of the day, the timing of it and the process is continuing on plan.

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. And are you -- do you have a bias within that range at all or just the kind of that’s the range?

That’s -- probably 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 well on AG strong comments prior to the decision. Nick is this sort of a signal that the state and the PSC in general they 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?

Yeah. That’s right. It’s sort of interesting. I mean, it’s multi-jurisdictional, as you know, and Mitchell is wheeling in Kentucky Power. And I think we have to get resolved Kentucky, Virginia and West Virginia. West Virginia has yet to speak on this issue, but -- and it’s only the ALJ in Virginia. So we will hear more on from Virginia on that. But I think it’s really important for us to really hold on our cards for now, because we got to get through a state process. It’s good to have clarity. And I think Kentucky, obviously, is the first shoe to drop in this regard. But we have also made it clear that these are multi-jurisdiction unit. So we have to make sure that there’s some compatibility of the jurisdictions that are involved. We will go through the process. We will get the initial views of the commissions and then if they are on different tracks, we will have to further analyze and resolve that with the commissions and there’s a lot of resolutions that could occur. Some are shorter, some are longer. But we have to understand where all three commissions are before really doing anything. I think it’s good to get clarity though and I think it’s pretty important that whether it’s the ELG or the CCR, if they approve CCR investments, but don’t improve -- approve ELG investments, then that effectively brings the generation retirement dates back from 2014 to 2028. So that’s something we have to consider along with those commissions. But we will know more about this in the August time frame. But I’d be hesitant to say what Kentucky, it’s pretty interesting that they would be looking at the ELG part of it. And I think there is becoming more of an awareness of -- that there has to be a plan. Now what that plan is, we have got a fully resolved with all those commissions. So, more to come on that.

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?

Yeah. Yeah. So -- and just like, we have gone through probably a couple of years now of discussions about how North Central is going to get financed and we are finally getting to a point where ultimately we will know how it’s being financed. The 16.6 gigawatts and -- is, certainly, we made a pretty credible case that we ought to own a significant part of that. I’d like to own all of it. But certainly, if -- but operationally, and from a contracting standpoint, and certainly, the ability for us to respond to a system related activities, it’s important for us to own and control those assets. And I think that, as we go forward, you are right, it will be the integrated resource planning filings that were made, there will start that dialogue, now we are in the process of doing RFPs to get more information obviously from the -- for the market in terms of what’s out there from a developmental perspective and that process is ongoing. So, that will certainly fortify any CCN filings we have to make or anything like that after the resource planning filings. But the resource planning filings will be your first real dialogue around how quickly this transformation will occur and in each one of the jurisdictions. And so, we are feeling pretty good about it, because it’s getting to a point where we have to decide from a capacity standpoint, how we support these utilities and it’s pretty clear to me that the movement is to that clean energy economy to move it is to toward as long as you have some element of baseload 24x7 capacity, that renewables will be the big part of that. So, a lot of that’s just becoming, I think, it’s becoming much more transparent and our jurisdictions, I think, their conditions both federally and from a state perspective, they are just a better realization of what the options are and the timing of those options. And that’s what will drive of course to that 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. Like I said before, we are on the outside looking in. We have no knowledge of any of that activity. And so if the report is true, I am glad to see that there is some element of putting all these in a rearview mirror, because naturally, and I said before, AEP has been hung up in the wake of that. And I am certainly hopeful that there’s some closure brought about from that. So, but, yeah, I have -- it was a surprise to me and we knew nothing about it, and certainly, there’s really nothing else that we have -- that AEP can say other than what we have put on our website and naturally there’s just nothing to report from our perspective.

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.

How are you?

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 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.

Yeah. That’s helpful. And then maybe just thinking through the upcoming RFPs, you mentioned the APCo and SWEPCO RFPs, could you just talk a little more detail in terms of color around the timetable there? And I am sorry if I missed that if you all did go through it. I don’t -- didn’t quite follow there, I am just thinking about sort of what that might mean for timing of incremental spending and sort of how we should think about those processes?

Yeah. So, we have certainly gone through the basic requirements for the RFPs for all of these areas. But as we go through that process, there is -- at APCo, we issued an RFP there for 300 megawatts of solar and wind resources really for a completion date of 2023 or 2024. And then in May of 2021, APCo issued an RFP to obtain, I guess, it was 100 megawatts of solar and wind energy via PPA and RFP for the renewable energy certificates only, which is consistent with the Virginia and what their requirements are. And then, SWEPCO issued an RFP for own resources up to 3,000 megawatts of wind and up to 300 megawatts of solar resources with optional battery storage by the way that can achieve a completion by 2024 to 2025. And they are also seeking 200 megawatts of capacity into 2023 to 2024 range and another 250 into 2025 to 2027 range, so those bids are due in mid-August. And then at PSO, we -- in June, we notified the regulators that it intends -- we intend to issue an RFP seeking up to 2,600 megawatts of wind and up to 1,350 megawatts of solar, again with options for battery storage consideration and that’s meeting capacity needs by 2025. So and then PSO plans to issue the RFP in October of this year. So those are the ones that are on the Board right now, and have really some near-term related requirements and most are capacity related requirements. So, and again, they are being done pretty much the same way as the others with North Central that we will certainly do more of it of a turnkey type of thing where we take ownership at the time it is approved in rate. So, and then, of course, we will go through the process of approvals by the various commissions along the way. So, but that’s the plan right now. And then, we will continue to -- as a matter of fact, we are spending a lot of time with our Board focused on the strategies related to these types of filings and the plan long-term and it’s important for everyone to understand this is going to be a continual process. And you are just seeing the first part of these really driven by capacity requirements and not just sort of an energy convenience. So, I think, they are really good to go out with right now and that’s what we have at this point.

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?

Yeah. So, for the first question, we started out this process saying that that we expected to get strategics and financials, and we have strategics and financials, so both are involved. And then as far as your second question is concerned, as I said earlier with the Foo Fighters dialogue, this is going to be a continual process for us. And if we are practically fully regulated so we have the opportunities to look at if we are building 16.6 gigawatts of renewables resources during the transition, then we got to think -- we have to have everything on the table in terms of sources and uses. So we are going to go through that process, and of course, Kentucky is sort of a first stop, but we will continue to evaluate our assets as sources. And if it makes sense, based upon what the other opportunities are, then that’s the kind of framework that we want to move this company toward.

Got it. That’s helpful. Thanks for that. And then there’s news coming out of FERC with regards to kind of the transmission planning process. I am just wondering if you might be able to provide some thoughts on -- your thoughts on what’s been said recently and what you see is kind of best practices here?

Yeah. So, obviously, we would like to see a much better transmission related planning across regions and AEP does a pretty good job itself in terms of transmission planning, because we do have a large system to consider. But at the same, RTO to RTO type planning process to try to make them more consistent so you can have this large transmission being built across regions and across states. If you are going to get that going, particularly as you are trying to get renewable resources to load centers, we are going to have to resolve these issues around multi-jurisdictional, multi-RTO type of analyses and making sure that we are consistent. The other part too is we have got to have consistency in terms of rate making and this notion of reevaluating incentives, structures and those types of things is not good for making decisions relative to transmission or -- and this is not good relative to the RTO model itself. So, I think, FERC really needs to sort of step back and take a look at it. And I think it’s a real positive approach to be focusing on the planning aspects and addressing RTO to RTO boundaries, addressing areas where, what’s competitive, what’s not competitive, all those types of things, that’s fine. But we have to have a clear planning process. And first of all, you can’t have coming back later after a project, multi-millions have been spent on a project to, say, we are going to stop the project. That has to change. And the other part of it is, we have got to be able to make these investments with some sense of certainty and be able to move quickly to make that happen. So, I just -- I think, there’s only so much value -- there’s a lot of value of being in an RTO for customers. But there also has to be value for the companies involved from -- to make the investments that benefit customers in orders of magnitude greater than what the costs are related to, any incentives related to transmission. And if you want to send a bad message for anybody to join an RTO or anybody to stay in an RTO, it’s just not good to start messing around with what the assumptions are relative to the future recovery of transmission investment. And now, when you start questioning incentives, you are really questioning anybody that’s trying to put a multiyear model together to show the benefits of transmission has to take that into account that something may change. So, like trying to make an investment in a coal unit, with clean energy activities going on in Washington. So you really do have to really think this process through and think about what you are trying to achieve. Sorry, I went on that one though.

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

Thank you.

Thank you. Our next 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?

Yeah. So, obviously, we have the, I guess, that’s $1.2 trillion, the infrastructure bill that -- it’s interesting we are talking in trillions as opposed to billions now. But in terms of the hard infrastructure side of things, yeah, it appears there’s some kind of convergence in Washington on that particular issue, although, more has to be done on the actual language and things like that. But as far as pursuing the advancement of, and certainly, transmission investment, but direct pay and those kinds of issues are clearly important along the way. We also have to, as far as, renewables and clean energy, PTCs, ITCs extensions of those, I think that makes sense, particularly RSI did the delays because of COVID and that kind of thing. So I think there’s opportunities for that and then as far as electric vehicles, certainly we would like to see electric vehicle infrastructure continue to be developed. So, I think all of those areas are positive. The issue is how you leverage into the private. The private companies like ours or that instead of the government funding and for transmission, for example, we think that mechanisms already exist for the development of transmission as long as you can keep all the incentives and all that kind of stuff. But -- so the federal and -- federal government funding of that now is, I think, you have to sort of think about what level of encouragement and what area. So, if they can make siding much better, if they can make, certainly, the focus on planning. Those issues enable transmission to get investments. We have no problem financing transmission investments. So I think the government probably ought to pick and choose between what they truly want to focus on that not already leveraged into the utilities, for example. They can certainly encourage development of electric vehicles with the focus on charging station infrastructure and those types of things that would be a benefit. And then, as far as the renewables transformation or the clean energy transformation, any kind of hard infrastructure around being able to move more quickly from a renewable standpoint, whether tax incentives and also uh other technologies like storage. And then also, we would like to see benefits related to either tax incentives for coal-fired generation to reduce the underappreciated plant balances, for example. If you want to have a national plan around moving to a clean energy economy, then the more quickly we can reduce underappreciated plant balances, the better we are able to make decisions and conditions, and states can make decisions about what future resource replacements would be. So I think there’s several ways to really focus on this. But we are all moving toward a clean energy economy. We just need to make sure that the government doesn’t try to do too much across the Board as opposed to very selected areas that enable investment to continue in the private sector. That would be my view.

Appreciate that color, Nick. Really quick just -- good to see First Energy with all the DOJ investigation or at least have an agreement this morning they highlighted. Just any update on the SEC subpoena you got? Any more color that you can share with us?

No. Nothing new there. We are -- we have been communicating with the SEC and we are responsive to any requests they have from a documentation standpoint. And we are going to continue to work with them and be supportive and constructive in the process and but nothing new to report there.

Understood. Thank you for taking my questions.

Yeah.

Thank you. And our final 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 low it 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.

Ladies and gentlemen, this conference will be available for a replay after 11:30 a.m. Eastern today through July 29, 2021. You may access the AT&T replay system at any time by dialing 1-866-207-1041 and entering access code 4754105. International participants may dial 402-970-0847. Those numbers again are 1-866-207-1041 and 402-970-0847 with access code 4754105. That does conclude our conference for today. We thank you for your participation and for using AT&T conferencing service. You may now disconnect.