American Electric Power Company Inc (AEP) — Q1 2021 Transcript

Thank you, Tony. Good morning, everyone, and welcome to the First Quarter 2021 Earnings Call for American Electric Power. We appreciate you taking time today to join us. Our earnings release, presentation slides and related financial information are available on our website at aep.com.

Thanks, Darcy, and welcome again everyone to American Electric Power's first quarter 2021 earnings call and happy Earth Day. Before I get started with our results for the quarter, I just have to say, I was struck with the public relations - public reactions to the Chauvin verdict. It has been a long wait, but justice and faith in our legal system prevail. I bring this up because I had chosen a song, which I do every quarter, for a different reason, but now it serves two purposes. One, the most mesmerizing singer I have ever heard was the late Marvin Gaye. I thought of his song when thinking about our quarter and the multitude of activities that AEP continues to accomplish and was thinking of what's going on in Marvin Gaye's hit from 1971 written during another tumultuous time in America. This song was a plea for peace, justice, and understanding perspectives to move forward in a positive way together. As I said, this song was released in 1971, 50 years ago, but it could not be more appropriate today. We need our leaders, our communities, and indeed, our companies to continue to come together and stop the divisiveness, which the news cycle tends to feed off of and recognize we have a lot more in common than our differences. That would be a great start to advancing this nation in a positive way. That being said, getting to my original purpose, AEP's first quarter of 2021 came in with operating earnings of $1.15 per share versus $1.02 for the first quarter of 2020, which met our expectations particularly given the impact in Texas, Arkansas, Louisiana, and Oklahoma, which we reported on in last quarter's earnings call. AEP continues to reaffirm our 2021 guidance range of $4.55 to $4.75 per share and our 5% to 7% long-term growth rate, and we would still be disappointed not to be in the upper half of the guidance range.

Thanks, Nick, and thanks, Darcy. It's good to be with everyone this morning. I'm going to walk us through the financial results for the quarter, share some thoughts on our service territory load and economy, and then finish with a review of our credit metrics and liquidity. So let's go to Slide 7, which shows the comparison of GAAP to operating earnings for the quarter. GAAP earnings were $1.16 per share compared to $1 per share in 2020. There is a reconciliation of GAAP to operating earnings on Page 15 of the presentation today. Let's walk through our quarterly operating earnings performance by segment, this is laid out on Slide 8. Operating earnings for the first quarter totaled $1.15 per share or $571 million compared to $1.02 per share or $504 million in 2020. Looking at the drivers by segment, operating earnings for the Vertically Integrated Utilities were $0.54 per share, up $0.04, driven by the favorable impact of weather due to warmer than normal winter temperatures in 2020. Other favorable items in this segment included off-system sales, higher transmission revenue, and the impact of rate changes across multiple jurisdictions. Partially offsetting these favorable items were higher depreciation, lower normalized retail load, higher O&M, a prior period fuel adjustment, and higher other taxes. The Transmission and Distribution Utilities segment earned $0.23 per share, down $0.01 from last year. Earnings in this segment declined primarily due to lower normalized retail load attributable in part to storm Uri. Other smaller decreases included higher depreciation, tax, and O&M expenses. Favorable drivers in this segment included transmission revenue, rate changes, and weather. The AEP Transmission Holdco segment continued to grow, contributing $0.35 per share, an improvement of $0.07 per share from last year. Net plant increased by $1.3 billion or 13% since March of last year. Generation and Marketing produced $0.06 per share, down $0.01 from last year. The favorable impact of the retirement of OCA Union and land sales on the generation business offset the unfavorable ERCOT market prices on the wholesale business during storm Uri in February. The decrease in the renewables business was driven by lower energy margins and higher expenses. Finally, Corporate and Other was up $0.04 per share, driven by an investment gain and lower interest expense, partially offsetting these items was the higher impact of higher taxes. Overall, we experienced a solid quarter and we're confident in reaffirming our annual operating earnings guidance. So let's take a look at our normalized load for the quarter on Page 9. Starting in the lower right corner, our first quarter normalized load came in 1.9% below the first quarter of 2020. There are two important factors to consider when evaluating the year-over-year comparison for the quarter. The first factor is that last year included an extra leap year day. Assuming everything else equal, you would expect about a 1% decline in sales due to one lesser day in the quarter, and the second factor is that the pandemic started during the last two weeks of the first quarter of 2020. In other words, the first quarter analysis is comparing a pre-pandemic view of our service territory load to a post-COVID view. Importantly, we still expect a stronger recovery in the second half of this year as vaccinations increase, positioning more communities to relax restrictions on businesses without jeopardizing public health. As a benefit of the American Rescue Plan stimulus, it was signed in late March, it works its way through the economy. I'll talk a little bit more about the latest economic projections when we get to Slide 11. So let's take a look at the upper left quadrant, our normalized residential sales increased by 1.5% in the first quarter compared to last year. The growth in the residential sales was spread across most operating companies. As the pandemic recovery progresses, growth in residential sales has begun to moderate. While we expect residential sales to decline by 1.1% in 2021, we're assuming a moderate sustained load benefit from this customer class, given the stickiness of work-from-home arrangements for many office workers across our service territory for the foreseeable future. So if you go over to the right, normalized commercial sales decreased by 1.6% in the first quarter. Even though commercial sales were down across every operating company except Ohio, we are seeing steady sequential improvement since the pandemic began. In fact, AEP Ohio was the first operating company to post positive commercial sales growth. This correlates well with the fact that the AEP Ohio territory added the most jobs in the first quarter. We also continue to see significant improvement in the same sectors that were hardest hit by the shutdowns in the second quarter of 2020. These sectors include schools, churches, restaurants, and hotels. So finally, if you look in the lower left chart, you'll see that industrial sales decreased by 6.1% in the quarter compared to 2020. Industrial sales were down across every operating company and most industrial sectors. Not surprisingly, the biggest declines were located in the western territory where storm Uri in February caused significant yet temporary disruptions to many manufacturing facilities located in ERCOT and SPP. In addition to the numerous electric generators unable to run due to frozen natural gas supply lines, there were several other manufacturing processes that rely on natural gas supply to produce their products. Many of those businesses were unable to produce for up to a week while the pipelines were being shut down and in some cases, industrial loads were stalled as long as 42 days in Texas. So the key takeaway here is that the dip in industrial sales in the first quarter was largely due to the one-time winter storm, which does not impact our fundamental outlook. So here's an interesting data point that illustrates this: our industrial sales in the eastern part of our service territory were down 2.6% compared to the significant 12.8% drop in the western part of our service territory, which was impacted by Uri. So obviously, that's a pretty dramatic difference. That being said, we're still very bullish about the second half of the year as the US acquires a significantly greater concentration of immunity from vaccinations and as the full impact of the additional fiscal stimulus is felt throughout the service territory economy.

So let's go over to Slide 10 where I can provide a little color on the industrial sales performance in the first quarter. The blue bars show the change in sales to our oil and gas customers. In aggregate, the sales to oil and gas sectors were down 9.6% in the first quarter, led by the 21% reduction in oil and gas extraction. Most of the decline in this sector is in response to the challenging market signals from last year when the drop in global demand, along with a temporary price war, caused oil prices to fall below many producers' breakeven point. However, we do not expect the weakness in oil and gas to persist. In fact, natural gas prices in March were up about 60% from last year, and domestic oil prices last month have more than doubled since March of 2020. We fully expect the higher prices today will provide the necessary signal that producers are looking for to increase their production within the service territory. And once we see the production increase in the upstream sectors, it's only a matter of time before we see the corresponding increase in the midstream and downstream operations. The orange bars in the chart show the change in industrial sales, excluding oil and gas. While it was still down 3.3% for the quarter, we expect to see stronger improvement in the second half of the year as the global economy recovers from the pandemic. Some of the weakness in manufacturing right now is related to supply chain disruptions. As efforts continue to strengthen the resiliency of the domestic supply chain for manufacturing, the AEP service territory is positioned to benefit from any movement in that direction.

So let's go over to Slide number 11 where I can provide an update that I mentioned a few moments ago on the latest economic conditions within the AEP footprint. Starting in the lower left chart or on the left chart, you'll see that AEP service territory experienced a 1.6% increase in gross regional product compared to the first quarter of 2020. This was much better than the US, which had a relatively flat first quarter in terms of year-over-year GDP growth. The AEP service territory was less impacted by the virus and had fewer restrictions on businesses than other parts of the country, which has allowed the regional economy to fare better than the US throughout the pandemic. Looking forward, the AEP service territory is expected to grow by 5.2% in 2021, lagging the economic recovery in the US as you might expect. Moving to employment on the right, you can see that the job market for the AEP service territory has also outperformed the US throughout the pandemic. For the quarter, employment growth was only down 1.6%, which was 4 points or 4% better than the US during the first quarter. This is largely the result of the mix of jobs in our local economy, which has a heavier relative concentration of manufacturing and government jobs and a smaller share of leisure and hospitality jobs. Going forward, we expect job growth of 1.7% in 2021. So let's go to Page 12 checking on the Company's capitalization and liquidity position. On a GAAP basis, our debt to capital ratio is 62.5%. When adjusted for the Storm Uri event, the ratio remains consistent with our year-end 2020 ratio at 61.8%. Let's talk about our FFO to debt metric because, as you would expect and as we've been signaling, the impact of Storm Uri has and will have a temporary and noticeable impact in 2021 on this metric. Taking a look at the upper right quadrant on this page, you see 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 decreased by 3.9% during the quarter to 9.1% on a Moody's basis. While this is a pretty dramatic impact, the rating agencies are very much aware of this and have taken the metric data point as well as the anticipated recovery into consideration as it relates to our credit rating. On an adjusted basis, the Moody's FFO to debt metric is 12.9%. To be very clear, this 12.9% 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 in the SPP region directly impacting PSO and SWEPCO in particular. The metric is also adjusted to remove the effect of the associated debt we used to fund the unplanned payments. This should give you a sense of where we would be from a business-as-usual perspective of 12.9%. As you know, we're in frequent contact with the rating agencies to keep them apprised of all aspects of our business, and importantly, there is no change in our equity financing plan. On the topic of anticipated recovery, there is no debate that Storm Uri was an extreme event, and consequently, the various states would like to resolve recovery docket as expeditiously as practical. Assuming recovery begins this year, our cash flow metrics will quickly return to the low to mid-teens target range next year as expected. So this should be a one-year phenomenon for us. As many of you know, we have initiated regulatory cases in our respective states to evaluate the costs and determine the recovery plan. Let me provide a quick update where we are in this process. On February 24th, PSO filed with the Commission for recovery of fuel costs through a regulatory asset and weighted average cost of capital carrying charge and subsequently filed a motion seeking recovery of a $615 million regulatory asset with a five-year amortization. At this point, PSO has received approval to defer the storm-related costs, with recovery of the established regulatory asset over five years at an interim rate of PSO's short-term financing cost of about 75 basis points. This is intended to be an interim order, and the actual carrying charge will be determined in a future review, and the regulatory asset amount is subject to finalization. Importantly, Oklahoma has also taken up a securitization bill to address the extraordinary fuel and purchase power costs felt by all utilities; PSO will evaluate if the securitization is appropriate for the recovery. And if so, we would expect it to occur as early as next year. In March, the Arkansas Public Service Commission issued an order authorizing recovery of the approximate $113 million Arkansas jurisdictional share of the retail customer fuel cost over five years, with the carrying charges to be determined at a later date, and the actual amount to be recovered being subject to finalization. We requested a WACC rate, which was supported by the staff in accordance with the order, SWEPCO began recovery in this jurisdiction in April, that was at a customer deposit rate of something like 80 basis points. The recovery period and associated carrying charge will be further reviewed in a hearing that's already been set for July 8th of this year, so 2021. In March, the Louisiana Public Service Commission approved a special order granting a temporary modification to the fuel adjustment clause to allow utilities to spread recovery over a longer period of time. In April, SWEPCO began recovery of the Louisiana jurisdictional share of these fuel costs, which is about $150 million based on a five-year recovery period in a fuel over-under recovery mechanism. SWEPCO will be working with the Louisiana Commission to finalize the actual recovery period and determine the appropriate carrying charge. And in Texas, SWEPCO intends to file for recovery under fuel surcharge, most likely in the second quarter. Our current plan is to request recovery over five years with a WACC carrying charge. Obviously, we have a lot in process on the regulatory recovery front on this matter and we'll keep you apprised as we make progress, because, as we all know, this is extremely important.

Let's take a quick moment to visit our liquidity summary on the lower right of Slide 12. On March 31st, AEP renewed its $4 billion bank revolver for five years and also entered into a two-year $1 billion revolving credit facility to fortify our liquidity position as we go forward, just placing our net liquidity position as of March 31st at a strong $3.4 billion. Switching gears, our qualified pension funding increased 1.7% during the quarter to 103.5%, and our OPEB funding increased 9.6% to 170.5%. Rising interest rates that decreased plan liabilities along with positive equity returns were the primary drivers for the funded status increases in both plans during the first quarter. So let's go to Slide 13, so we can wrap this thing up and get your questions, but I just want to call out a couple of quick things before we do that. So on the top of mind for many folks I know this, we want to mention to you that we completed the planned $125 million equity funding portion of the North Central Wind Sundance project. We used our at-the-market mechanism, so that we could time the equity need with our purchase of the Sundance project, which occurred last week. As you know, we will continue to move forward with additional opportunities in the renewable space supporting our ESG focus as we transition toward a clean energy future. Our performance in the first quarter and the stability of our regulated business model gives us the 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, 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. And with that, I'm going to turn the call over to the operator for your questions.

Good morning, Shar.

Good morning, guys. Good morning, Nick. Good morning, everyone.

Good morning.

So a couple of quick questions here. First on the incremental 8.6 gigawatts of renewable opportunities, which just added to plan. It's very sizable - maybe touch a little bit on how we should think about these new opportunities in light of the 5% to 7% growth that you gave, what sort of financing avenues were you kind of looking at the approval tariffs, and what are you assuming in terms of owned versus PPA?

Yeah, I think we have - the last part - last part of your question first. I think we have a pretty compelling argument now for owners of these facilities given even past the winter storm activity that we learned operationally; certainly what we learned from the provisions of the agreements that we put in place relative to the approvals really stands better in terms of our ability to manage the project, manage congestion, and manage other factors that really provide benefits to our customers. So we're going to make a strong position that we should own those assets and actually when you think about the strength of the utilities, it's going to be important for the states to really focus on how do we keep our utilities strong, and PPAs don't do it from a capital structure perspective. We need to make sure that ownership and their flexibility of operations is key in that regard. And regarding the other, 8600 megawatts, yeah, it is a sizable number, but obviously when you look at the evaluation of the retirements, when you look at the needs of the operating companies and also North Central certainly showed you can deploy capital and reduce the overall bills to consumers. So when you think about the retirements of coal-fired generation, the imposition of additional transmission, having the benefits of the fuel cost aspects of it are tremendously important. So when you look at the analysis having some level of carbon pricing in there certainly increases the focus on the ability for renewables to come into play, and that's certainly what we've been focusing on. So as you look at the finance ability of it, the finance ability pretty much worked like we did for North Central, although it's a large number. So we'll have to be very aware of what our balance sheet strength looks like during the process, the timing of when the different tranches of these renewables come into play, the cash position that supports these projects coming online, and being able to improve as Julia mentioned. This FFO to debt thing where it is today is really a 2021 issue. In 2022, FFO to debt comes back up, and certainly with the ability to put these projects in place, it will help in terms of our ability to continue to fund these projects. So it will probably - we certainly would like for it all to be incremental, but in reality when you go through this process, it will probably be around capital allocation and prioritization associated with that within the existing plan, but also incremental. So it'd be a combination of both. Yet to be seen, obviously if load continues to grow, if the position relative to the regulatory framework getting concurrent recovery, making sure that we get off the tax ADIT issues, that's all going to be helpful in terms of our ability to finance. So it's still a work in progress.

Got it. And then maybe just transitioning to corporate strategy and asset optimization, obviously, the strategic review for Kentucky has started, so Brian has been obviously very busy this year. Can we maybe just elaborate on the phase we are in with that process? Have bidders emerged or data rooms opened, and assuming this would backfill most of your Wind Catcher equity need. So we should obviously consider leakage share and any NOLs as well that could be applicable in this case?

Yes, Shar, you are always ahead in terms of questions. Yeah, and I really can't answer any of those at this point because we are in a process and certainly, as soon as we have information on it, I think the real issue here is we have made a deliberate decision to really start our portfolio management approach and evaluating jurisdictions because we are fully regulated. We can look at these areas and determine what the best fit is in terms of future capital needs and what our focus is in terms of moving to a clean energy economy. So, and for us to come out and say that we are in a strategic process relative to Kentucky is an important statement in that regard. That's probably as far as we can go right now.

Let me ask you something a little bit more of a theoretical question. Would you consider asset rotations above your current equity needs, let's say, from North Central to fund the incremental CapEx or renewables or T&D? I mean, you're within your credit metric guidance, but does it make sense for you to further improve your balance sheet and simplify your store even further? I mean, do you kind of like looking at the stock valuation, and does it maybe more sense to - do you think there's incremental value from a multiple standpoint to even have a stronger balance sheet and operate in even fewer states here, and I'm thinking maybe Texas?

Well, certainly, like I said, this is at the beginning of this process, but multiple expansion is clearly on our minds and making sure that you can - you're investing in the right things at the right places at the right time is going to be incredibly important. And you saw that with North Central, the timing of the recovery with the actual investments with the turnkey approach that we took and it's all about the timing of it, it's all about the decisions made to ensure that we are doing proper capital allocation and rotation to manage this process forward. So, like I said earlier, that's going to be a continuing part of our business.

Terrific. Thank you, guys. I'll jump in the queue. I appreciate it.

Good morning, Julien.

Hey, good morning, team. Congratulations on all these updates.

Yeah.

A lot to digest here today, I did. If I can, let's start with a higher level question here, right? So you're proposing a lot specifically in PSO, how do you think about the events that have transpired in Texas and Uri impacting that and specifically around some intermittent resources like solar in Oklahoma, right? We just haven't seen a lot of that historically and so this is a little bit of new territory for that geography more than the economics all around. Can you talk to that and have you kind of vetted some of the proposals here and the approval process?

Yeah, so obviously, we're right out of the gate in terms of the announcement of what's included in each jurisdiction. So we'll have discussions with the commissions, and that's part of the integrated resource planning processes. And keep in mind, too, when we do this evaluation during the RFP - I mean, during the process, as always, solving for whatever the least cost is in terms of what those resources are. So it shows up as a win. And then solar, typically it's showing up as more wind early on, and solar starts to pick up, but that's pretty fungible as you go forward. I mean, these plans will change as we go forward based upon where technologies go, certainly where the opportunities exist. Oklahoma may want more wind and less solar, but that won't matter; it'd be a part of the total renewables piece that's included there. The other part of it, too, is we will be very mindful of how much renewables are placed into service in relation to 24/7 supply, and there is some natural gas that's built into this plan as well that enables more renewables to be put in place, but the real focus going forward during this transitional period will be for units that provide 24/7 to be more of a reliability component, certainly more of an insurance backstop for weather events or other events that may occur that impact the grid security, and we'll have to be very, very mindful of how those studies actually go. And I'll tell you, in our climate report, we saw for 2050 with a $15 carbon price, and then a more aggressive $30 carbon price, the 2035 case didn't solve because of the timing of getting resources in place and system-related issues. So you have to really think about how that's done, and we've looked at these plans and we certainly believe that was the level of 24/7 supply we still have out there and the additional opportunity associated with just the diversity of some of these projects. It's going to be of particular value to our customers going forward. And I guess, I'll just remind you that North Central would have been operational during this time of the Texas and Oklahoma outages with the Uri; it would have saved customers $227 million. So you think about the savings associated with that, and the other thing too, the previous question, someone was - Shar was asking, when the utilities do it, they focus on the long term, and North Central already had the weather package already in place where you don't find that in a large part of the market. So we think the long-term when we go about these investments, and that's why ownership is clearly important.

Excellent. And just to clarify this a little bit further, I know that the equity numbers aren't moving around too much. We're at all, frankly, relative to CapEx, but how much capital could be shifted given the latest updates here in the three-year versus the five-year outlook here? Just want to understand, out of the total 10-year view that you guys are providing today, how much could be in that three-year and five-year window as you think about just the specific timing of each of these dockets that will come up for renewable resources?

Well, yeah, as I mentioned, 10,000 of the megawatts of the 16,000 - over 16,000 is in the '21 to '25 timeframe, so it's going to be near-term. So when you think about these projects, they take a couple of years to put in place. You'll be looking more at that '23 to '25 for most of it, but some of it is already in play. There are already RFPs going out for suppliers of some of these renewables as we speak. Julia, do you want to add anything to that?

No, you've got that perfect, thank you.

Thank you.

Good morning, Stephen.

Hi, thanks guys for taking my question.

Good morning.

Congrats on a great update and a big movement in renewables, so happy to see that. I wanted - if you could just talk a little bit more about as you grow out renewables, whether there might be some additional transmission distribution requirements or stores there just other things that would sort of be additive as well, it's obviously just huge amount of megawatts, just curious about the other impacts?

Yeah, there will be, and many of these projects, obviously, we'll have to look at the placement of these projects as in the level of congestion, but also the level of transmission investment that's required. But keep in mind too, with the Biden administration's doing relative to the movement to clean energy, which obviously is a big part of his plan, large-scale transmission will also be incredibly important. So, I see with what's going on today and in excess of all these things coming together, our transmission, which you've always said is, as far as I can see for a decade, well, it's probably even higher. We don't know what that number is at this point, and I think we've got to get through the process and fully understand that, but when you do the net benefits associated with fuel and the capital cost of the renewables projects and transmission, it's still a benefit to consumers. So, we'll go through that process, but you're right to be bullish about transmission in relation to these investments, but also everyone else's investments because we are the largest transmission provider in the country, and most of this has to come through us.

That's really helpful. And then I wanted to drill into Texas for just a moment. There are some bills, as you know, floating around that would permit securitization of costs and those look to be quite helpful from a financing point of view. Just curious how you're thinking about that impact. How might that impact your thoughts on financing? I appreciate the point you raised earlier that essentially the credit metrics are sort of artificially low at the moment because of the storm, but with some of these bills being especially helpful to you?

Well, certainly, the ERCOT portion of Texas, we are essentially a large company there at T&D. So, we have, based on our cost provisions in place for recovery of that, we - the only real exposure we've got from a standpoint is any, I guess some of the reps, they could potentially go bankrupt, but that's where it's going to be important to understand where that goes, and also as far as securitization is concerned, we view securitization in the past in Texas, and you're seeing it develop for what's classified as storm caused, but it really is Uri-related investments we'd be fine with that. Julia, anything?

No, that would be great. Great question, Stephen. So, we're keeping an eye on what's going on in Oklahoma. There is an opportunity potentially to engage in some securitization activity there. We would love to get cash in the door. So if that's something that's workable, we will absolutely take the cash, and my understanding is, the way that is being at least discussed and potentially structured would be such in such a way that that does not sit on our balance sheet, which makes it even better. So, yes, we'll take that cash and with no doubt on the balance sheet, we like that very much. So, we are definitely poised and ready and waiting.

That's great. Maybe one last quick one, just as we think about this growth in renewables, are there any changes in terms of your thoughts on coal retirement dates?

Well, obviously the move we made on the second Rockport Unit solidified at least at 2028, and it could occur earlier depending on what the conditions are and what the evaluations are with the commission and the replacements of capacity. And so, we are - and actually, we're looking for provisions like that even in legislation that's occurring because you're seeing all kinds of incentives developed for the extension of PTCs, ITCs, direct pay we like. So direct pay not only for renewables projects, but also for transmission. If you have an ITC, but I think also we'd like to see incentives for the undepreciated plant balances of coal units to further accelerate the ability to retire and obviate the impact to our customers. But the current plan does assume any of these advancements so - and this happens all the time where we have plans that are out there that are public, but a lot of things get worked on, and we'll continue to work on these objectives, because our objective is to move as quickly as possible to derisk these investments, particularly with new environmental rules with CCR and other things. We're making decisions about these plants, and you've seen in the last two quarters, we've announced earlier retirements of coal and lignite plant operations. So I would fully expect to see that process continue.

Very good. Thank you very much.

Yeah.

Good morning, Steve. How are you doing?

I'm doing well. I have a couple of questions on the Kentucky Power announcement.

Yeah.

So just I think, Nick, you said that you're doing a strategic review with a target for year-end. So, is that the target to basically have a sale done and proceeds by year-end or have a kind of like a sale or other plan announced by year-end?

Steve, I didn't say year-end. I said we would get the evaluation done in 2021; that could be earlier in the year or it could be later in the year. Obviously, we need to get farther down the road in terms of this process. I can tell you that the process is established; it's ongoing, and we're going to move as quickly as possible. So, and we've always talked about the timing of the resolution of anything related to the weather was Kentucky or anything else in relation to the needs around North Central. So, and we still believe that timing fits.

Okay, that's helpful.

So, I wasn't saying that would be the end of the year before we know anything; I just said during '21.

Okay. And just, is there kind of - this may be, it seems silly, but just, is there a reason that this wasn't part of your slide deck or release or just - it was just stated on the call? Just - it's something just happened, the Board just decided something?

No, I think it was out of respect to our employees, because obviously, you can't say something like this from an SEC perspective without some thought around that, but also there is the human aspects of it too and employee aspects. Matter of fact, our employees just found out about it when I've said it; I have a webcast after this with all employees to talk about this to just alleviate their concerns through the process, but this is the way that occurs; there are multiple things you have to think about when you're making these kinds of announcements.

Understood. And then just in terms of - that's helpful. So in terms of thinking about your financing, this would still be potentially directed at replacing the equity needs that you have currently for North Central as a potential replacement for some of that it will be?

Yeah, I'll let Julia talk about that.

Steve, yeah, thank you for the question. Absolutely, to the extent that we get dollars in the door, that will be a wonderful place to put that to work in terms of being able to sidestep some of the equity need, and we'll see if we can make that happen, absolutely.

We have the access, but obviously, it would change the nature of that.

One challenge with Kentucky Power has a lot of coal plants and exposure I guess, so to speak, just, do you feel like there is still despite that decent interest to be able to monetize at a reasonable price?

Yeah, and obviously different parties look at it in different ways and that's what we're going to find out through the strategic process what evaluation Kentucky's ownership of Mitchell in terms of valuation and its impact on overall price would be. It still has value; it still has years to operate and certainly, if you look at the plan that we presented, you still have a potential renewables opportunity there, particularly with the potential retirement of Mitchell at some point. So, anyone who is looking at this, I would say, it's not - in terms of just the valuation of Mitchell, it's an evaluation of what you do with it during the transition. So there's a lot of things to look at from that perspective.

And my last question just on this topic and my last question is just, the overall portfolio optimization kind of that you've been doing, is this a conclusion of that or is this something where we could get more?

No, it's going to be an ongoing part of our process. So it's just the beginning. Yeah, okay.

Good morning, Durgesh.

Hey, good morning, Nick. Thank you for taking my question. Just I have - I think you've covered the rest, just on storm costs, Julia, you're currently deferring those, right, the $1.2 billion on the balance sheet? Can you just remind us...

Yeah...

Thank you. Can you just remind us what is factored into your 2021 guidance? I'm just thinking about how the regulatory decisions here in the next few months impact your 2021 numbers?

Yeah, absolutely. You have it exactly right. We're deferring those storm costs, particularly as it relates to the fuel and purchase power costs because that's the biggest chunk of the dollars that we had exposure to as it relates to storm Uri in particular. And as it relates to what's embedded in our guidance, I would tell you, we actually updated our cash flow forecast. That's included in the slide deck that you have today to incorporate the impact of this particular circumstance as well as the fact that we did have some ice storms and more I'd characterize more kind of normal storm-related activities that occurred in the eastern portion of our jurisdictions here during the first quarter. So all of that is factored into those new cash flow forecast details, which you'll see impacting the cash flow from operations line in the slide included in the deck today. As you know, we did take on some additional debt to be able to accommodate the fuel and purchase power spike that was not anticipated, and so that is now being absorbed into our 2021 operations and therefore into our earnings. Interestingly, if you look at Page number 8 of the slide deck that we have out there today, on the Corporate and Other segment, you'll actually see that interest expense was a benefit to us this time despite the fact that we have taken on a little additional debt in that capacity, because we took a $500 million term loan on at the parent company; interest rates - in terms of interest cost, I should say, were much lower in this particular quarter versus last year. We do have - still have lower debt outstanding from a short-term perspective versus last year. So all of those factors, interestingly, helped to have this impact to be one of benefit to us in this particular period. So take steady as she goes, no change in forecast; still feeling really good about where we are. Hopefully that helps you a little bit.

It does, it does in a nutshell. It’s captured in your EPS guidance, interest costs and the cash flow metrics already reflect the sort of the treatment you might get in terms of recovery for these costs.

You've got it. We did that by design because we wanted to make sure we had a fair amount of integrity in that forecast, particularly when you look at the cash flow metrics, and give a shout out to our fixed income friends because I know that's extremely important.

Understood, thanks. Just one last one for me. Nick, you mentioned the disappointing first quarter, it's just what to look forward there in terms of next steps? Is there going to be a rule-making procedure and just next steps there? What should we be looking for?

Yeah, it is open for right now. So, and obviously our comments will be very direct and very focused, and I'm sure there will be others in the industry with that as well, but it just seems like a direct polar opposite to where the administration is trying to go with movement to a clean energy economy. Really, it is directly opposite to years of precedents of encouraging the development of transmission. So I'm certainly hopeful as we get through the dialog of what this all means and actually with RTO participation. When we originally joined the RTO years ago, we were making a lot of money off of through an outrates of transmission. We traded that in for generation benefits because we were selling a lot of generation. We're not selling generation to any real extent; certainly, when you look at the value proposition of an RTO, it is centered on the ability to optimize across a larger jurisdiction. But from an AEP perspective, you got the cost of the RTO, and certainly, our customers need to be able to benefit from that. So if you disrupt that net cost-benefit opportunity, you will have people making different decisions about RTO participation. So I think it's just sort of a policy move in the wrong direction, but certainly hopeful that the commission comes together on that.

Understood. Is there a timeline as to when the common period ends and when they might make a final determination yet?

I don't know that there is right now; they have to post the noper in the Federal Register first. So we're thinking probably a summer timeframe for the noper.

Understood. Thank you. Appreciate the color.

Yeah.

Good morning, Andrew.

Thanks. Good morning, everyone. I appreciate late in the call here. First, just to follow up on the transmission, are you able to provide an EPS sensitivity or potential impact if that RTO incentive adder would be eliminated?

Yeah, we had in our queue actually, the number for our evaluation that we lost the entire 50 basis points, it would amount to $55 million to $70 million pre-tax. So, and that's the evaluation now; who knows what they're going to do because you went in the meeting thinking they may actually go up on the RTO incentive, but remains to be seen what they decide to do, but that's the impact.

Well, that was the next thing I was going to ask, do you see any potential of an increase or do you think it's highly improbable at this point?

I think certainly with what transpired, we're just trying to make sure it stays the same, but if it increases, there are a lot of reasons for it to increase because RTO participation and the adders associated with transmission, like I said, the expenses of an RTO continue to go up and up. So I think there definitely needs to be an incentive there.

Okay, great. Then just one last follow-up question on the renewables. You talked a bit about the cost savings from coal plant retirements, and I know it's early and the cost would be continuously changing hopefully downward. But from what you see today, do you expect this update to the generation stack to lower customer bills in most cases, all else equal? And you mentioned something about potential carbon policy; does your analysis assume some sort of federal clean energy standard, and how would it look from an affordability perspective without that?

We've always had the carbon value in our analysis from a resource planning perspective, and I think it's $15 a ton is what we've used. In our reports, our Climate Report, we used two cases, a $15 case and a $30 case that was more aggressive, and certainly that brought more - that case more renewables in more quickly, but that's not reflected in the plan that we've shown here. So, yes, it's certainly something that we're going to continue to look at and evaluate with the commission.

If I could...

Yeah, go ahead.

Just to throw additional finer point on that as well, if carbon pricing is excluded from the equation, the renewable opportunity could get a haircut by about 2 gigawatts. So it's not that significant, but I wanted to throw that out there.

Yeah, we're looking at this thing as a $15 billion to $20 billion investment opportunity. So it would not be much of an impact if you took out the carbon pricing, but you can't plan for anything without putting in a carbon pricing these days.

Okay, great. And the affordability question, assuming the carbon is in the bulk part of what you're talking...

Yeah, and we've demonstrated that with North Central. I mean, you can put these projects in place and keep in mind, we're thinking about the resiliency and reliability of the grid too. So there's limitations and we have to go through that process, but the ones we have in this plan, we can do, and certainly, when you look at the benefits of North Central, for example, it was a $3 billion benefit to the customers. And so when you have those kinds of economics in play, if you're able to run your 24/7 generation as more of a reliability and as an insurance policy essentially and layer in as much renewables you can, put in transmission to make sure the system continues to operate the way it should, and then it could be a pretty powerful combination to benefit customers in the future.

That's great. Thank you very much for the details.

Yeah.

Good morning, Jeremy.

Good morning. Thanks for squeezing me in here at the end. Just wanted to touch base on Rockport, if I could, in kind of the decision tree that led to this and just wanted to see what other kinds of options you were evaluating, just a bit more color would be helpful there. Thanks.

Yeah, so obviously we were looking at future requirements instead of environmental requirements on the units, and if we kept them operating longer than 2028, that would be a challenge from an economic perspective. We didn't want to start making those kinds of investments not knowing how long the units would actually be operational, so that was a consideration. The other, as I mentioned, was litigation to clear all that out to make sure we took ownership and we took control. And then, of course, the value of the short-term bridge that exists that gives us the flexibility to make decisions with the Indiana Commission to focus on what is the right path for that transition. So it gives us a lot of optionality, a lot of flexibility and control, and by the way, I mean there's two units there. So one we own, one we leased, and it just made more sense for us to own both of them and make the decision of the plant as a whole and be able to adjust accordingly. So it worked out well overall from that perspective and like I say, it gives us a lot of optionality and flexibility and actually at a pretty - at a price that I think it was $115 million. So it's an opportunity for us to really pay for that degree of optionality that has considerable value.

Great, that's helpful. I'll stop there. Thanks.

Yeah, sort of thing.

This is Darcy. We have time for one more question.

Michael, you snuck in there.

I snuck in at the end, but better late than never. Thank you for taking my question, team. Hey, Nick, you mentioned Kentucky today; you also outlined the renewable growth platform and plan for the regulated businesses. And obviously, lots of renewable companies, pure plays trading at pretty good multiples even after the recent share price weakness. Just curious how do you think about the renewable portfolio at the G&M segment and whether that piece of the business is truly core to AEP or whether the real growth is obviously in the regulated subsidiaries, and maybe the non-reg contracted renewable business could potentially be a source of funds for the parent to fund regulated growth?

Yeah, so that's been a continual part of our business; it just gets allocated capital. The AEP Energy gets allocated capital, and he is perfectly willing to throw it back over the fence because we make evaluations based upon his threshold, which is commensurate with the regulated part. And also, just his business is important because it keeps us in a part of - like for example, we're doing a lot of projects here in Ohio directly with customers, and it enables us to speak with customers and corporations, and enables us to be in that business, but at the same time, we're able to manage the capital such that you can throw it back over the fence if we see a better opportunity on the regulated side. So we have that working very well where we can make those trade-offs on a continual basis. So yes, it could be a source of capital to do some of these things, and again that lends itself to the portfolio management approach to ensure that we're putting the money in the right place at the right time. So - and like I said, he is doing an incredible job with that organization, and the fact is they are still doing the renewable part of it, but they're also doing specific relationships with customers with microgrids and those types of applications. So, the value proposition of that business is so important to us seeing the leading edge of what we need to be doing and making cases in our regulated business to ensure that we can continue to grow from those perspectives as well. So, all in all, it's working fine. But, yeah, the answer is yes, we can utilize that as a source.

Got it. Thank you, Nick. Much appreciate it, guys.

Okay.

Hey Tony, I wanted to say thank you for joining us on today's call. As always, the IR team will be available to answer any questions you may have. If you could please give the replay information.