American Electric Power Company, Inc. (NASDAQ:AEP) Q2 2023 Earnings Call Transcript

American Electric Power Company, Inc. (NASDAQ:AEP) Q2 2023 Earnings Call Transcript July 27, 2023

American Electric Power Company, Inc. beats earnings expectations. Reported EPS is $1.2, expectations were $1.12.

Operator: Ladies and gentlemen, thank you for standing by and welcome to the American Electric Power Second Quarter 2023 Conference Call. At this time, all parties are in a listen-only mode. Later, we will conduct a question-and-answer session. [Operator Instructions] This call is being recorded. I’d now like to turn the conference over to our host, Vice President of Investor Relations, Ms. Darcy Reese. Please go ahead.

Darcy Reese: Thank you, Brad. Good morning everyone, and welcome to the second quarter 2023 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. Today, we will be making forward-looking statements during the call. There are many factors that may cause future results to differ materially from these statements. Please refer to our SEC filings for a discussion of these factors. Joining me this morning for opening remarks are Julie Sloat, our President and Chief Executive Officer; and Ann Kelly, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Julie.

Julie Sloat: Thanks Darcy. Welcome everyone to American Electric Power’s second quarter 2023 earnings call. Good to be with everyone this morning. It’s a rapid time of change in our industry with new opportunities resulting from federal policy shifts and evolving state and customer priorities. We also continue to navigate a dynamic environment with rising interest rates and supply chain constraints. In short, it’s definitely an exciting time to be at AEP as we make significant progress on our important stakeholder commitments and strategic objectives, including delivering on our 2023 operating earnings guidance and 6% to 7% annual operating earnings growth, providing dividend growth in line with earnings, strengthening our balance sheet as we move through the next few quarters, actively managing our portfolio, achieving net-zero by 2045 and central to our purpose, keeping our customer rates affordable.

We recently made some organizational adjustments such as the restructuring of our Federal Affairs function, the realignment of our regulatory team, and the refreshment of some of our operating company presidents. These changes will help us to operate more effectively and facilitate our success in this ever-changing environment. As always, we keep the customer at the center of every decision we make. This is why we engage with our federal and state regulators so we know how to best support our operating companies while we balance investor preferences as we grow the business and invest $40 billion over the next five years in new generation resources and our energy delivery infrastructure. This morning, I’ll provide a brief overview of our second quarter financial performance before getting into our measured and disciplined approach to simplifying and de-risking our business profile through our portfolio management activities.

Related to this, I’ll share some updates regarding our unregulated contracted renewables portfolio, retail and distributed resources businesses, and the status of our strategic review of our non-core transmission joint ventures. While we still have a lot of work to do on the regulatory front, I’ll conclude by providing insight into the recent successes related to our renewables execution and developments on our regulatory and legislative initiatives as we keep our customers’ needs top of mind. A summary of our second quarter 2023 business highlights and a high level overview of our financial results can be found on Slide 6 of today’s presentation. AEP delivered second quarter 2023 operating earnings of $1.13 per share or $582 million compared to $1.20 per share or $618 million last year.

The year-over-year decline reflects the timing of higher interest rates in the reversal of last year’s second quarter 2022 favorable weather. Today we’re pleased to reaffirm our 2023 full year operating earnings guidance range of $5.19 to $5.39 with a $5.29 midpoint and long-term earnings growth rate is 6% to 7%. Given our line of sight at this point in the year, I believe we have the operational flexibility and leverage to pool to ensure that we will deliver on our commitment. Later on, Ann’s going to talk or walk through our second quarter of 2023 performance drivers and share some perspectives on our load outlook as we drive economic development within our service territory. She’ll also share some details supporting our targeted 14% to 15% FFO to debt range.

While our FFO to debt is 11.1% this quarter, our forecasts show material improvement in this metric as we approach year-end and we fully expect to be in our targeted range in early 2024. As we continue to execute on our strategic objectives, we remain focused on simplifying and de-risking our business profile. To that end, you’ll recall that in February of this year, we announced a signed agreement with IRG Acquisition Holdings for the sale of our 1,365 megawatt unregulated renewables portfolio. A summary of the renewable sale can be found on Slide 7. In the second quarter, we received FERC 203 approval and clearance from antitrust authorities. The only remaining approval is from the Committee on Foreign Investment in the U.S., which we expect to see receive in the near-term and subsequently close on the sale in August.

As we’ve said, the proceeds from this transaction will be directed to our core regulated businesses and strengthening of our balance sheet. Turning to Slide 8, let’s touch on some other asset sales that we have in progress. In May, 2023, we also announced the sale of our New Mexico Renewable Development Solar portfolio, also known as NMRD. We are currently on track with our 50/50 joint venture partner, PNM Resources to close on this transaction by the end of 2023. The sales of our retail and distributed resources businesses are also on schedule to close in the first half of 2024 as previously announced. Please keep in mind that other than the unregulated renewables portfolio proceeds of $1.2 billion, no other sales proceeds are reflected in our five year cash flow outlook.

We’ll first obtain the signed sales agreements for NMRD and our retail and distributed resources businesses, and then incorporate the related proceeds into our cash flow outlook. As part of our commitment to portfolio management, I’m pleased to share some additional news with you today. We’re announcing that we’ve completed the strategic review of two of our three non-core transmission joint ventures and have determined that the sale of AEP’s interest in Prairie Wind Transmission and Pioneer Transmission as our preferred path forward. We expect to launch the sales processes soon and we’ll keep you updated on our progress. In the meantime, we continue our strategic review of Transource Energy and expect to complete that review by year end.

Now let’s switch gears to AEP’s regulated renewables execution and recent successes. Through our five year $8.6 billion regulated renewables capital plan, we now have a total of $5.2 billion approved and an additional $1.7 billion currently before our commissions for approval. You can find more detail on activities to acquire additional generation resources in the appendix on Slides 31 through 33. In May 2023, the Oklahoma Commission approved PSO’s 995.5 megawatt renewables portfolio for $2.5 billion, which includes three wind and three solar projects. These projects are projected to be in service toward the end of 2025. For SWEPCO’s 999 megawatt renewables portfolio totaling $2.2 billion of investments, I’m happy to report that last month, both the Arkansas and Louisiana Commissions approved the full portfolio containing two wind projects and one solar project.

We expect the projects will be going into service by the 2025 timeframe. Since the Texas Commission denied SWEPCO’s application related to these projects, Arkansas will move forward with the 20% of the portfolio total and Louisiana will flex up with 70% giving wholesale customers the remaining 10%. We’re excited to deliver the benefits of lowest reasonable cost and reliable energy to these communities we serve in Arkansas and Louisiana. We’re also currently awaiting for commission decisions expected as early as in the third quarter of 2023 for 151 megawatts of owned wind and energy storage at APCo, 469 megawatts of owned solar at I&M and 154 megawatts of owned wind at PSO. Importantly, our regulated renewables goals are aligned and supported by our integrated resources plans.

Accordingly, we’ve issued requests for proposals for generation resources at APCo and I&M with more to come from operating companies soon. I’ll turn now to updates on several of our ongoing regulatory and legislative initiatives. More detail on our regulatory activities can be found in the appendix on Slides 34 through 36. We’re unquestionably focused on closing the gap between our authorized versus earned ROEs. While our second quarter ROE came in at 8.6%, this measure was depressed by 40 basis points due to mild weather. Closing this gap is going to take a little longer than we had anticipated in our 2023 guidance, which you may recall included a 9.4% ROE. But I’m confident that we’ll reduce this gap by year end and still meet our earnings guidance.

As we make needed progress in this regard, we are continuing to prioritize federal, state and customer preferences to meet the needs of our communities that we serve. We look forward to building on our constructive relationships with all of our stakeholders and clearing the path for our operating companies to be effective and successful in their respective service territories. In fact, while being mindful of any ex-parte restrictions, I’m personally meeting with many commissioners across AEP’s footprint to engage in discussions about our company and what is top of mind for them in the way of priorities and expectations as we work together to do our best to provide this product that is the fundamental enabler for society. In June 2023, we filed a new base case in Kentucky to address the financial health of the company and established a path for future investment.

The application incorporated a comprehensive rate review and a proposed 9.9% ROE with a request to allow for the securitization of $471 million of regulatory assets. This will help to ensure that Kentucky Power is best positioned to provide safe and reliable service, while managing costs to provide affordable service to our customers. We expect that the new rates will be in effect in early 2024. In May 2023, we settled PSO’s base case with the commission staff, attorney general and other parties in Oklahoma providing a path for approval for more efficient cost recovery mechanisms with continuation of the transmission tracker and reestablishment of a distribution tracker. While we await commission – a commission decision expected in the third quarter of 2023, we implemented interim rates starting in early June.

For APCo Virginia’s 2022 – 2020 to 2022 triennial filed in March of 2023. We’re working through regulatory – the regulatory calendar and expect an order later this year. And Texas legislation was passed last month, which permits utilities to file the Distribution Cost Recovery Factor or DCRF twice per year instead of once per year. The bill also allows DCRF to be used by a utility even if it has a pending base case review proceeding. This important legislation will help improve AEP’s regulatory lag in Texas, as we make needed distribution investments to bolster the grid in this region. AEPs management of fuel cost recovery remains a top priority with deferred fuel balance at $1.4 billion as of the second quarter 2023. We’ve adapted fuel cost recovery mechanisms across most of our jurisdictions with a focus on balancing customer impact.

Notably, we are awaiting a decision on our fuel case in West Virginia. Through this spring we were active at the state legislature and collaborated on a new securitization bill to provide an effective path forward on fuel recovery and other legacy costs while mitigating customer bill impact. In April, 2023, – in our April, 2023 fuel recovery application, we filed two options for consideration, one which amortizes the fuel balance over three years, and alternatively, in an effort to even further minimize cost impacts to customers, we requested West Virginia Commission approval to use securitization to manage our $553 million deferred fuel balance. We also proposed an opportunity within that second option to apply the securitization mechanism to $88 million of deferred storm costs and $1.2 billion of legacy coal plant balances with the intention of offering a solution that would essentially have a neutral impact on customer rate.

Keep in mind; securitization is the mechanism we can use to address affordability in West Virginia. While it’s important that we addressed fuel and storm cost recovery in the state, let me be clear that the possible securitization of $1.2 billion for our Amos and Mountaineer coal plant balances is not required to hit our credit metrics, nor does it suggest that there’s a change in our current plant – our current plant retirement schedule of 2040 for these units. Rather, this is entirely driven by the desire to consider all options to mitigate impact to customer bills. The West Virginia Commission subsequently issued a procedural schedule in the fuel case, including the April, 2023 prudence [ph] report, which will be addressed in an evidentiary hearing beginning on September 5.

This schedule provides an opportunity to ensure focus on cost concerns and a constructive future in West Virginia balancing customer and financial impacts. Pending the commission’s decision later this year, we could issue bonds to securitize a possible combination of the deferred fuel balance, deferred storm cost, and legacy coal plant balances in the first half of 2024. I’m pleased with the progress we’ve made so far. We still have a lot of work to do as we execute on our plans to meet our commitments, overcome challenges, reach our strategic objectives, engage with stakeholders, and keep customers a top priority. Together we deliver safe, clean, reliable, and affordable energy to our communities while creating value for our investors.

With that, Ann will now walk you through our second quarter, 2023 performance drivers and details supporting our financial target. Ann?

Ann Kelly: Thank you, Julie and Darcy. It’s good to be with you all this morning. Thanks for dialing in. I’m going to walk us through our second quarter and year-to-date results, share some updates on our service territory load and finish with commentary on credit metrics and liquidity, as well as some thoughts on our guidance, financial targets and portfolio management activities underway. Let’s go to Slide 9, which shows the comparison of GAAP to operating earnings. GAAP earnings for the second quarter were a $1.01 per share compared to a $1.02 per share in 2022. Year-to-date GAAP earnings through June, were a $1.78 per share compared to $2.43 per share in 2022. In our year-to-date comparison of GAAP to operating earnings, we’ve reflected the expected loss on the sale of the contracted renewables business as a non-operating cost, as well as an adjustment true of cost related to the terminated Kentucky transaction in addition to our typical mark-to-market adjustment.

Also due to new legislation in Texas allowing the recovery of incentive compensation, favorable entry was booked in the second quarter to capitalize previously incurred costs, which was almost entirely reflected as non-operating earnings. There is a detailed reconciliation of GAAP to operating earnings on Pages 16 and 17 of the presentation today. Let’s walk through our quarterly operating earnings performance by segment on Slide 10. Operating earnings for the second quarter totaled $1.13 per share or $582 million compared to a $1.20 per share, or $618 million in 2022. The lower performance compared to last year was primarily driven by weather, interest and O&M, partially offset by rate increases in our utility and transmission revenue growth in both our Utilities and the Transmission Holding Company segment.

The unfavorable weather was largely due to positive weather we saw in the second quarter of 2022, while weather was mild begin in the second quarter of 2023; the unfavorable impact was less significant in comparison to the first quarter of this year. Interest continues to be unfavorable versus the prior year, and that is primarily driven by higher debt balances as well as the higher interest rates. The higher debt balance also has resulted in an increase in interest expense as compared to our guidance, but we continue to adjust in other areas to offset this impact. Again, we were expecting this variance to be more pronounced in the first half of 2023 as interest rates somewhat stabilized. We also expect the announced sale of our contracted renewables business to close this quarter and the conversion of the $850 million equity units in August to lessen the burden in the second half of the year.

Finally, I’d like to note as well that we still expect to see favorable O&M in the second half of the year compared to the prior year, reflecting the timing of O&M spending and near term actions that we are taking to help offset the unfavorable weather, such as holding positions open, reducing travel, and adjusting the timing and of discretionary spending. These actions are in addition to our ongoing efficiency efforts that we target to offset the impact of inflation each year. Operating earnings for our vertically integrated utilities were $0.51 per share, down $0.08. Favorable drivers included rate changes across multiple jurisdictions, depreciation and off-system sales. These items were more than offset by the unfavorable weather interest expense, O&M and lower retail and wholesale load.

I will touch on our retail load trends in a couple minutes. Consistent with our first quarter results, depreciation is favorable at the vertically integrated utility segment, primarily due to the expiration of the Rockport Unit 2 lease in December of 2022. I&M should continue to see about $0.055 net favorable depreciation in each of the first three quarters of 2023, plus an additional $0.035 in Q4. Including the impact of the Rockport lease, depreciation was $0.04 favorable in Q2. However, if we exclude the impact of the lease, depreciation would’ve been about $0.02 unfavorable, which is consistent with the incremental investment in this segment. I also want to mention that the favorable off system sales showing up again in the second quarter is due to the fact that Rockport Unit 2 margins are no longer shared with our retail customers.

The Transmission and Distribution Utilities segment earned $0.30 per share, down $0.02 compared to last year. Favorable drivers in this segment including transmission revenue and rate changes largely due to the distribution investment rider in Ohio and the distribution cost recovery factor rider in Texas. Offsetting these favorable items were unfavorable weather, lower retail load, depreciation, O&M and interest. The AEP Transmission Holdco segment contributed $0.38 per share up $0.11 compared to last year. The main drivers here included favorable investment growth and a favorable year-over-year change in the true-up. You’ll recall that we had a negative true-up in 2022. Generation & Marketing produced $0.13 per share down $0.05 from last year.

The negative variance is primarily due to the development asset sale and other one-time favorable items in 2022 as well as higher interest expense in 2023. These unfavorable items were partially offset by higher retail power margins in 2023. Finally, corporate and other was down $0.03 per share, driven primarily by higher interest expense and O&M. These unfavorable items are partially offset by a favorable change in investment gain and income taxes. The favorable change in investment gain is primarily due to investment loss incurred in the second quarter of 2022. Before we move on to the next slide, to give an update on load, I want to briefly mention that the details of our year-to-date operating earnings performance will be shown in the appendix of supplemental information going forward.

You can find these details on Slide 15 of the presentation today. Turning to Slide 11. I’ll provide an update on our normalized load performance for the quarter. Overall load continues to come in ahead of budget, but we’re closely monitoring key components of our retail sales in the context of the slowing economy, and we are seeing different trends between our retail customer classes. As we discussed last quarter, our projections already assume that economic conditions will slow in the second half of the year. Recent positive economic data on inflation supports that any slowdown will be in line with our previous expectations. Beginning in the upper left hand quadrant of the slide, we see a slowing in our residential load compared to a year ago.

Our residential customer counts continue to grow, but we are seeing usage decline as many of our customers return to the office and even more squeezed by the relationship between inflation and income growth. That relationship is a key driver of residential usage and we expect to see it stabilize in the second half of the year. This month’s CPI data point was an encouraging sign that inflationary pressures on our residential customers are continuing to lessen into the fall. Moving to the lower left hand quadrant of the slide, we can see a noticeable slowing in the industrial class. So still ahead of year end budget projections, industrial load is beginning to reflect the expected slowdown in the outlook for manufacturing across the country. This slowing has been broad based across industries and operating companies, but would’ve been even worse without an our ongoing commitment to economic development.

We estimate that total industrial load through the quarter would’ve actually declined by 1.2% if not for growth tied to our economic development efforts. Even with these efforts, however, we do expect industrial load growth to remain subdued due to the tighter financial conditions and slowing levels of demand for finished goods through the end of the year. Offsetting this slowing is a significant boost to our normalized commercial sales that you can see in the upper right corner driven by new large customer volumes from our ongoing economic development efforts. Year-to-date commercial load has grown almost 8% year-over-year in each of the last two quarters. We expect our commercial load to continue to outperform through the end of the year.

Thanks to ongoing technology development across our operating footprint. Gains in AEP Texas and AEP Ohio should continue to be especially robust with several new projects scheduled to come online through the end of the year. With the June CPI data, we’ve now seen a material deceleration in key components of inflation that the economy has been waiting to see. We think this progress on inflation coupled with continued resilience in the labor market dramatically reduces the probability of a severe economic contraction in 2023. Our near and long-term load projections are bolstered by our discipline commitment to economic development across the service area. We know that working with local stakeholders to attract more economic activity is a key strategy to providing value to our customers.

This allows us to continue to prioritize investments that will improve customer experience while mitigating the rate impact on our customer base. Great examples of our recent successes are NL and Tulsa and GM and Samsung in Indiana. Both of these economic development wins will not only add load to our industrial segment, but each is also expected to bring more than a 1,000 full-time jobs that will ultimately benefit our residential segment and boost the local economy. Let’s move on to Slide 12 to discuss the company’s capitalization and liquidity position. Taking a look at the upper left quadrant in the page, you can see our FFO to debt metric stands at 11.1%, which is a decrease of 30 basis points from last quarter and continues to be below our target.

The primary reason for this decrease is a $1.3 billion increase in debt during the quarter, partially due to long-term debt issuances at the operating company level to support our capital investments and the return of mark-to-market collateral positions associated with decline in natural gas and power prices. Return of collateral reduces our funds from operations, so hits us on both sides of the equation without the fluctuations in our mark-to-market collateral positions over the past 12 months and some remaining impact of deferred fuel, our FFO to debt metric will be closer to 13.7%. We expect that this metric will improve by year end as we reduce debt after the close of the announced renewable sale and our 2020 equity unit conversion and we see the improvement in funds from operations over prior year in the fourth quarter.

We remain committed to our targeted FFO to debt range of 14% to 15% and we expect material improvement by the end of 2023 and to achieve our target in early 2024. You can see our liquidity summary in the lower left quadrant of the slide. Our five-year $4 billion bank revolver and two-year $1 billion revolving credit facility support our liquidity position, which remains strong at $3.1 billion. On a GAAP basis, our debt-to-capital ratio increased from the prior quarter by 50 basis points to 64.6%. We plan to reduce this percentage in the third quarter as we eliminate debt when we close our announced contracted renewable sale transaction and complete our previously planned equity unit conversion. On the qualified pension front, our funding status increased during the quarter to 102.2%.

The funded status improved due to rising rates during the quarter that decrease the liability while solid equity returns positively impacted plan access. Let’s go to Slide 13 for a quick recap of today’s message. The unfavorable change in weather primarily due to positive effects in the second quarter of 2022 is a significant driver in our quarter-over-quarter earnings comparison. If we removed this effect, we would’ve been $0.05 favorable compared to the prior year and our results were roughly in line with our expectations for the company as a whole. I will note from a year-to-date perspective 2023 weather has been the most mild on record for the AEP system in the past 30 years, resulting in $0.29 EPS impacts year-over-year and about $0.20 versus normal weather.

So as we progress through the remainder of the year, we will continue to focus on taking action to mitigate this and other headwinds. Overall, our business remains in a strong position and we are reaffirming our operating earnings guidance of $5.19 to $5.39 per share. We also continue to be committed to our long-term growth rate of 6% to 7%. As Julie previously addressed, we are on track to close the sale of our unregulated contracted renewables portfolio in the third quarter this year, and our retail and distributed resources business in the first half of 2024. We’ve concluded that the sale of our interest in two of our transmission joint ventures, Prairie Wind Transmission and Pioneer Transmission is our preferred path, and we continue a strategic review of our Transource Energy joint venture.

These initiatives will help simplify and de-risk our business going forward. We really appreciate your time and attention today and with that and going to ask Brad to open the call, that we can hear what’s on your mind and answer any questions that you have.

Operator: Thank you. [Operator Instructions] Give us just a moment here. And I can go to Shar Pourreza with Guggenheim Partners. Please go ahead.

Q&A Session

Shar Pourreza: Hey, good morning guys.

Julie Sloat: Good morning.

Shar Pourreza: Good morning. Just on the credit metrics, obviously, a little bit more slippage this quarter, which you highlighted. I guess can you talk about the pathway to get to that 14% to 15%, a little bit more detail? I think 300 basis points seems like a lot of improvement that’s needed in a short timeframe, being that it’s your early 2024 target. I mean, could we see incremental equity in plan? Is the asset sales enough to get you there? And how important is collecting the unrecovered fuel balance in terms of being able to hit that target, which I guess it still stands around $1.4 billion. Thanks.

Ann Kelly: Yes. Shar, I’ll take that. As we mentioned, the main impact to our FFO to debt is the timing of the collateral payment. So that’s about a 240 basis point impact to our FFO to debt, and so that should resolve itself by year end and result in a noticeable improvement. We also have about a 100 basis points of favorable impact from the proceeds of the contracted renewable sale and the equity unit conversion. So we are, confident that we are going to have measure improvement by the end of the year and be into the range by next year. In our forecast we don’t have any of the securitization in our cash flows. We do have recovery of deferred fuel, but that is not necessary to be able to get into our current range.

Shar Pourreza: Got it. Okay, perfect. And then maybe just a more of a strategic question for Julie. I mean, obviously, AEP is never CapEx constrained, right? I guess how do we sort of think about overall financing, especially given the current interest rate environment and kind of where the stock currently trades? Do you have ongoing; you do have ongoing needs, right? So as we’re thinking about parent leverage and equity are more non-core asset sales out there, or could we actually start to see some more core assets sales to kind of fund the plan and maybe further simplify the story? Thanks

Julie Sloat: Yes, no, Shar. I so appreciate the question. And you’re right, we have a lot of opportunity to put capital to work as it relates to taking care of the customer and delivering reliable, affordable service. But as you point out, we need to make sure that we’re hitting all the metrics too. So not only do you need to be real mindful of where customer rates are going, when we put money to work, I need to make sure that all my earnings growth targets are going to be hit. Because I think you guys would be upset with me if that didn’t happen, so we’ll make sure that happens. But I also need to make sure that my balance sheet’s really strong too. So let me get to your question around asset sales. We’ve really been focused on, as you know, the non-core related activities that when people buy AEP shares or invest in our bonds, they’re not necessarily looking to buy something that is not a traditional regulated utility type business.

So to that end, that’s why you see us kind of going through the paces today where we’ve talked about the unregulated components of our business and, while we love transmission even looking at some of these transmission investments of the joint ventures that are off our footprint, because if we can channel all of our efforts and dollars to taking care of our customers that are regulated in our footprint, that’s where we want to play. So, I wouldn’t anticipate, a significant additional activity coming from us for a couple of reasons. I think we’re pretty cleaned up once we get some of this non-core stuff taken care of. I think we’re in a good place. I think that, there may be some opportunities, on the edges, but for the most part we’re – we should be in a really good space to be continuing to look at the regulated pieces of our business.

But we also and very candid Shar, we don’t need to engage in asset sales to make the balance sheet work. What we need to do is make sure we’re being as efficient as possible, and that’s another reason why I want to make sure that every dollar we do put to work is one that a, makes sense for our customers, but also is something that makes sense for our service territories. And specifically why I am calling that out is another reason why I’m out talking with folks in our community. So whether its commissioners, customers, et cetera, need to make sure that we’re aligned or at least absolutely aware of one another’s priorities and then we can make refinements based on those conversations. So, I would never say that we’re not at all capital constraints because I think we naturally are because we put our own constraints on because we got to take care of customer rates and make sure that we’re going to have a really strong balance sheet.

We’re working on that. As Ann just mentioned, we expect that FFO to debt to look a lot better once we get to year end and going into 2024. I think in the interim here, it’s going to be just a little bumpy as we work through a couple of the next few months. So I wouldn’t be too concerned about that. I feel comfortable with the numbers I’m seeing, but we’ll continue to be very disciplined around, which dollars we put to work where that it’s consistent with what our stakeholders need and want taking care of our customer and then just being as efficient as we can. So my focus is going to be more at this point on let’s close that gap on the ROE. That’s the piece that I can try to do my best to control.

Shar Pourreza: Got it, terrific. And then no, it does. And then we do appreciate some of the salient points you brought up in your prepared remarks as far as the outreach to the regulatory folks and various stakeholders. So thank you for that points.

Julie Sloat: Yep. Thank you for the coverage.

Operator: And next we go to Jeremy Tonet with JPMorgan. Please go ahead.

Jeremy Tonet: Hi, good morning.

Julie Sloat: Good morning.

Jeremy Tonet: I wanted to kind of follow up on some of the points that you were just touching on here because, some of the dockets and local media attention have highlighted some regulatory pushback in certain areas of ablate, and you mentioned, reaching out to local commissioners to build relations there. Just wondering over what timeframe, you expect to kind of meet all of them? Is this a change in regulatory strategy where they hear from headquarters more regularly here? Just wondering how you think about this type of outreach going forward?

Julie Sloat: Oh, Jeremy, I love that question. So I’m going to tell you from my perspective, this is coming from a former operating company president. So I keep that hat kind of in my back pocket that I got to throw on from time to time. And so let me start with this. What my hope to do, well I, what I hope to do or achieve is, pay [ph] the way or clear the path for our operating companies so that they can do the best they can do boots on the ground. And so my objective is to get out, to make sure that I’m talking with different commissioners. And by the way, that’s already underway. So, I’ve already been out talking with several folks and I’ve got my calendar lined up over the next few months to continue to that effort.

So I’m not going to get into necessarily exactly who I’m talking to when, but that, that’s well underway. So rest assured that’s happening. But I just, I want to make sure that they’re hearing from me and that they understand that AEP, the parent or the service core is here to provide clearance and service and support for the individual operating companies. Really, that’s the only reason the service core exists, is to support the operating companies. And I need them to hear that from me. And more importantly I just want to be a really good listener so that I can be really good at my job so I can take care of our customers, take care of my team, and then ultimately take care of my investors and the other stakeholders that are party to everything that we’re doing here.

So I don’t want people to think that I’m stepping in the way or thinking that something’s not right because that’s not the case at all. I just want to make sure that we’re doing everything we can to support the teams so that they can be as successful as they possibly can be. Because here’s the other point, right. You call out the fact that there are pressure points as it relates to regulatory activities. I think that’s going to be what we’re dealing with for the next several years. We got a lot of headwinds now. The game’s changed, the industry’s going through a material transition. Each of our states is in a different place as it relates to their economies. And so I think everybody is doing their jobs and that means we got to do ours too. We have been doing it, but we have to be really good listeners and learners and adjusters.

And I think that goes for all the different stakeholders. So the more dialogue we can have, I think the smarter we’re going to be and if nothing else that will – we only be able to take care of the customer and make sure we’re keeping the lights on and delivering this product that make life possible. But I think we’re going to be doing it in a much more effective way, and we’re going to have to pick up the pace too. So we got to do it in a faster way than we’ve ever done it in our history. So I think it’s exciting. I love getting out and talking with people. You guys know from The Street, I love getting out and talking with you too, so that’s not going to stop. So I just got to work my calendar and I’ll be out front and I’m happy to talk about any of the conversations that I’ve had.

Jeremy Tonet: Got it. That’s very helpful. And just one more along these lines, dialing in a little bit more. In Kentucky, our local stakeholder conversations highlight a focus on increased distribution investment as a priority as opposed to the more recent, I guess, transmission investment which could help local stakeholder relations there with a focus on distribution. Just wondering how you see a Kentucky strategy evolving over time here?

Julie Sloat: Yes, I’ll tell you, let me start with this. Again, having been a former CFO as well. At 1.6% ROE, yes, we got to work on that. And that to me, when I see that number that’s not a financially healthy, sustainably healthy entity so that’s why we’re going through the case activities. So we’re going to work on that and that’s exactly why we went out and socialized the case well in advance with dozens of meetings with a variety of different stakeholders. So again, listening and learning so we understand where everybody’s kind of shaken out, but also understanding what it is that we need to do so that we’re successful, not only in taking care of our customers, but making sure we’re doing everything we can to make sure that the stakeholders understand what our objectives are and are comfortable with it.

So yes, the objective is to, A, get a plan in place that will allow us to improve the financial positioning of the company, which then enables us to make future investments to take care of the customers, they need the power too. It doesn’t matter which state you’re sitting in, but the idea is to engage in these activities, hopefully have a really good case. And I don’t expect it to be easy. It’s not supposed to be easy. If it was easy, everybody would be doing it. So we’ll engage in those activities and hopefully get us on a path forward that enables us to continue to invest in a really smart way in the state that everybody can feel good about.

Jeremy Tonet: Got it. So there’s room to pivot towards more distribution over transmission. Sounds like you’re working with stakeholders there?

Julie Sloat: We, absolutely and so those are the conversations that we’re having. We do know that transmission has been very important to the commission. And so that is top of mind for us as well. And we’ve worked that into the structures that we’ve essentially set forth in our case. But at the end of the day, it’s the distribution that also matters because we got to keep the lights on.

Jeremy Tonet: Got it. I’ll leave it there. Thank you very much.

Julie Sloat: You bet. Thank you.

Operator: And next, we’ll move to Anthony Crowdell with Mizuho. Please go ahead.

Anthony Crowdell: Hey, good morning. Thanks for taking my question.

Julie Sloat: You bet.

Anthony Crowdell: Just – first off, Slide 12, maybe I’ve been following it too long, but I think over the last 10 years, the total debt to total capitalization has gone from 53%. Now it sits at 65%. I’m just wondering, does that stabilize or where do you see the sweet spot for total debt to total capitalization?

Ann Kelly: Yes, absolutely. Thanks for the question. So it has inched up, as you can see on the graph. I mean, 60% is our sweet spot and that’s what we’re targeting going forward. As you can see, we’re above that right now. We do expect that to decrease with the contracted renewable sale proceeds and also the equity unit conversion. So that’s a couple hundred basis points, that’ll reduce that closer to the 60%, but we still have some work to do.

Anthony Crowdell: Great. And then if I stayed on the balance sheet here, I think you’ve talked about, you’ve planned to be in a target, and I hope this correct in 2024. If I could get real granular, when do you think you’re going to get into the midpoint of your 14% to 15% range? Is that something you’d talk about?

Julie Sloat: Yes, I mean, I would say we’re going to be, we say we’re going to be in the target in 2024 and I think approaching the midpoint probably by the end of 2024. There are the fluctuations as I mentioned in FFO that we’re experiencing. And that’s just really due to timing of quarter-over-quarter fund flows. And so, you will see especially in 2023 that it will be press till the fourth quarter when we really see that switch in the collateral collections and improving our FFO there, so that’s what’s going to take some time. But we do expect it to increase, like I said, materially by the fourth quarter and then into next year. And Anthony, just to put a little finer point on it too, remember, our threshold that we’re sensitive to is 13% as it relates to our Baa2 rating from Moody’s.

And so that’s why we toggle to the 14% to 15% because what we want to have is cushion. So 14% definitely gives us some cushion, so keep that in mind as well. And the other thing I mentioned in my comments too is as we proceed through the rest of this year, you can expect maybe a little more pressure as we go through the next couple of months with some improvement as we get to the fourth quarter. Just want to manage those expectations.

Ann Kelly: Yes. The other thing just to highlight is that, we’re talking a lot about the timing of collateral payments, but 80% of that volatility that we’re seeing relates to our retail business, which as you know, is for sale. So once we sell that business, we would expect that reduction in volatility going forward.

Anthony Crowdell: And then just lastly, Julie, I appreciate all the commentary you’ve given on the regulatory strategy and especially Kentucky. And I know Kentucky’s a very small piece, but when you look at the equalizer chart, I mean the ROE is pretty low. What’s a reasonable assumption for us to use? Where that ROE could go in 20 – by 2024? I mean, does that go to an allowed of 9.9%? I’m just curious, how long does it take to recover the regulated returns of the utility?

Julie Sloat: Yes, Anthony, it’s going to take a while. Do not expect a flash cut. And so remember in our case, we requested a 9.9% ROE, our current authorized is 9.3%. I’m looking at Page number 34 in the slide deck right now. It will be a walk. So that’s something we’re trying to manage our own expectations around as well as for you all, as you work to model. So stay tuned and let this case proceed and see how things move along and then we can continue to kind of dial that in and give you more direct guidance.

Anthony Crowdell: Great. Thanks so much for taking my questions. I really appreciate it.

Julie Sloat: You bet. Thanks for being on the call.

Operator: And we can go to Julien Dumoulin-Smith with Bank of America. Please go ahead.

Julien Dumoulin-Smith: Thank you Julie and team. Good morning. Appreciate it. Maybe to follow-up on some of the last few questions here, if I can. Just as you think about some of these headwinds here with respect to securitization heading into 2024, obviously you down fairly confident, not just in offsetting the weather year today, but in the 2024 items here. Can you talk about some of those tailwinds here or some of the forthcoming offsets? What else gives you the confidence in having that linear trajectory on the 6% to 7% here? If you can speak to that a little bit more. And maybe related to that, can you talk about maybe the timing of some of these items to the extent, which some of those headwinds on securitization bleed into 2025 as well? I don’t want to be too myopic on the next year.

Ann Kelly: Yes. I mean, what I’ll do is I’ll start with kind of addressing the 2023 earnings guidance question. As you look, we’re $0.18 below prior year and we guided to year-over-year for the full year it’s about $0.20 improvement. So that’s $0.38 that we need to outperform last year for the second half of the year. When I look at this, I think it’s helpful to break it down into components. So weather was $0.29 over 2022, about $0.20 of that impact is versus normal. And that’s where we’ve taken some action to offset those headwinds. Interest also is about $0.29 unfavorable year-to-date. It’s running a bit above expectations. We had guided to $0.20, but that also didn’t include interest on Kentucky, because we had expected to sell the business.

So that’s about $0.10 per year and that’s covered in revenue. So we had anticipated much of our year-over-year increase to be in the first half of the year because of the timing of the Fed actions. So while we are a little bit short coming into the back half of the year, we also have the proceeds from the contracted renewable sale and equity unit conversion that’ll help reduce our debt somewhat. And we’ve taken other actions to offset the increase in rates because it has been – the Fed has been tightening a little bit longer. When you look at O&M, unfavorable to last year in the first half, but we expect this to reverse due to timing of our O&M spending. Our original guidance planned for reduction of O&M during the second half of the year because last year’s spending was a little bit robust on the O&M side in the back half.

And so we had already anticipated a reduction and then we’ve taken additional actions like those that I’ve mentioned to be able to make up for the reduction in weather volumes. And then lastly, there’s a couple other things that we’re pointing to. One is the favorable trends in commercial load that we expect to continue. And then we’ve also seen favorable results in our generation and marketing business that’ll benefit us this year. So, putting that all together that what give us the confidence and our ability to meet our earnings guidance for this year. In terms of maintaining the 6% to 7% EPS growth going forward, it’s really a story on our capital deployment and we have a very robust capital pipeline that allows us to do just that.

Julie Sloat: And Julien, on that note, just to kind of put an end cap on this. I think the core is solid. And so when you look out in the next few years, as Ann mentioned, we got $40 billion we’re put into work in terms of capital investment over the next five years. We’ll continue to work with our regulators to make sure that we’re deploying the dollars where we all agree that they need to go. And then at that point it’s really around making sure that we also execute on not only the regulatory plans that we lay out there, but as you know, we’ve got some strategic asset sales that are underway. So we’ll deal with the fact that some of those businesses are falling away, rechanneling those dollars to the regulated pieces of the business that will help us from the math perspective and making sure that we’re hitting all of those other balance sheet metrics that we need to make sure that we hit, so people aren’t worried or concerned.

And we got a little more flexibility. So when we have a weather event or something of that nature, we can easily sustain that. But the core is solid and at this point it’s around being efficient, putting the dollars to work where it makes sense and closing the gap on the ROEs.

Julien Dumoulin-Smith: Got it. All right. Excellent. And then if I could follow-up briefly on a couple details. Just with respect to PSO, obviously dynamic situation with the ALJ and settlement, can you talk a little bit about your expectations here and maybe about what you had been planning in interim rates? Just ultimately what happens, how you’ve been planning, what’s reflected in rates? If you don’t mind a little bit of an update there.

Julie Sloat: Yes. So we implemented interim rates in early June I think it was, as it relates to the settlement that we had put in place. And at this point, as you mentioned, the ALJ had its report that it is submitted and then file – exceptions were filed, I think it was yesterday to the ALJ report. So if you haven’t taken a look at that I would encourage you to take a look at that. But effectively the parties to the settlement agreement were absolutely supportive of the settlement agreement, which we would’ve expected anyway. So we felt good about that. And we’re going to let this thing play out over the next couple of weeks really, because we’re getting pretty close here. Parties have four days to response the exceptions that were filed.

And that is effectively August 1st. And then we will have an oral argument of the exceptions that’s scheduled for mid-August and we would expect to get an order in September. So stay tuned. The process is working and like I mentioned, we’ve got inter rate – interim rates in effect. And we will keep you apprised, but do go take a look at the exceptions. I thought that was interesting.

Julien Dumoulin-Smith: Duly noted. Thank you. All right, I’ll leave it there. Good luck guys. Speak to you soon.

Julie Sloat: Excellent. Thanks, Julien.

Operator: Next we’ll go to David Arcaro with Morgan Stanley. Please go ahead.

David Arcaro: Hey, good morning. Thanks for the questions.

Julie Sloat: Good morning.

David Arcaro: Wanted to, let’s see – could you give some color on what your plans are going forward for Texas in terms of the generation outlook you’ve had some challenges there just with the repeat renewables proposal. I’m wondering how you’re thinking about that going forward in terms of strategy and generation pollution?

Julie Sloat: Yes, absolutely. Yes. So we did file for rehearing, because we need to make sure that we’re doing all we need to do from a traditional regulatory and administrative perspective. And then what you can anticipate AEP doing is essentially running another RFP and running another process so that we can make sure that we’re doing what we need to accommodate the capacity situation in Texas. I do believe that Texas understands there is an adequacy issue that we would otherwise have to deal with. So that’s something that we will be proceeding forward with. So standby and you’ll see what we come to the street with here in the not too distant future.

David Arcaro: Got it. And could there be a cell phone [ph] option in there? And to the extent there was, would that be, I guess, incremental to what’s currently in the renewable generation outlook for CapEx plan?

Julie Sloat: Yes, that’s a possibility. That’s a possibility. But what we would do is, accommodate any type of investment in the current CapEx forecast.

David Arcaro: Okay. Got it. Understood. And then you do have a couple other renewable projects out there for approval this quarter in several states. I was just wondering if you could give a sense of your confidence level in those before the proposals that you’ve put forth and what alternatives you might have if there end up being challenges in any of those?

Julie Sloat: Yes, and actually I’m trying to flip the page so we can kind of draw everyone’s attention to them. Right now, I’m looking at Page 32. So for example, we’ve got an application open in Virginia and we made the same filing in West Virginia. For Appalachian Power Company, we’re talking about 151 megawatts, about a $500 million investment for wind and storage capacity there. At this point the process is proceeding along as we would expect. So, I have nothing new to report. So, standby there. And trying to think of where else we have open cases in Indiana, Michigan. Looks like staff has been supportive on the Michigan side, through those applications. And Indiana order is expected in 3Q, so the third quarter of this year.

So stay tuned there as well. But so far constructive and productive and we’re moving forward. Then of course we also have, I guess I should call out the wind out – the Wind investment Rock Falls that’s included in the base case at PSO. But that’s part of the base case settlement. So as you know, I just mentioned that we’re well underway in that proceeding.

David Arcaro: Got it. Okay. That’s helpful. Thanks so much.

Julie Sloat: Thank you.

Operator: And we can go to Sophie Karp with KeyBanc. Please go ahead.

Sophie Karp: Hi. Good morning and thank you for taking my questions. I have a couple of questions here. First is on the renewables, right? So clearly Texas maybe has lesser appetite for renewables at this point. And I’m just curious if you how much of the incremental appetite for this do you think is left in Louisiana and like other states that picked up slack in this particular instance? Is there risk in the near term, I guess in your mind, that those states would also turn down potential future proposals because of their perception that they have? They’re pretty much like full as far as renewable generation goes.

Julie Sloat: Sophie, I appreciate that question very much, because as you know, that’s been top of mind for us as we worked through that proceeding. So, we obviously got the approval for the 999 megawatts and Louisiana flexed up, so we’re moving along in that regard. You may recall that we also had another process that was underway for SWEPCO in particular, I want to say it was 2,400 megawatts that we were seeking interest in as it relates to how we would put that portfolio together. And so what we’ve done is, we’ve actually tabled that and we’ll be coming back to everyone to say, look, we want to look at this from an all source perspective, including PPAs. So stay tuned on that because there is absolutely a capacity need.

It’s just going to take a little different shape than what we were initially expecting as we were running that RFP process. And remember when you probably heard me saying earlier here today on the call; we need to make sure that we’re listening to our regulators. And so this is exactly what we’re doing as it relates to the conversation and the experience that we just had in Louisiana, Arkansas, and Texas. And so we are adjusting and moving forward. So there will be more RFPs stay tuned for that. And they will be more all source oriented, no different than what we would be doing in Texas as you call out. Yeah, it looks like not a lot of interest in renewables there right now. So we need to think about what the other alternatives are, but we will work together with our regulators so that we can make sure that we’re doing what the state needs.

Because at the end of the day, this is all about making sure that our customers have reliable, affordable electricity period.

Ann Kelly: Yes. And just to reiterate on our capital plan, so far $5.2 billion of projects have already been approved and we have another $1.7 billion that, that Julie just talked about in the regulatory process that’s out of our $8.6 billion. So we are well on our way and we also have flexibility with our transmission and distribution investments to fill in to the extent that anything else gets delayed a little bit in the process with these RFPs.

Sophie Karp: Great, great. Thank you. My other question was in the ROEs, maybe I’m referencing Slide 34 here, my reading this right, that the 40 bps – depressed by 40 bps per mild weather is sort of average across the board. So if it wasn’t for weather, all of these bubbles would be like roughly 40 bps higher or how should we think about this? There’s like a lot of numbers here.

Ann Kelly: Yes. That 40 bps is on average. Okay. So let me answer it this way though, because when I’m thinking about what does this mean for the rest of the year, and as I mentioned in my opening comments, we had initially anticipated or expected on a weighted average basis. We’d be about a 9.4% ROE across our operating companies in our 2023 guidance. And so now what we’re suggesting is now that we have a little bit of a hole that is associated with weather on that ROE can’t make all that up, I don’t think, unless we had some ridiculous weather circumstance in the back half of this year. So we’re not going to bet on that because we’re going to bet on normal. And so what I would expect is we expect to improve from 8.6%, it will not get to that 9.4%.

So even if you get closer to 9%, I think that’s reasonable. And our point that we want to make today is despite the fact that we’ve had pressure as a result of weather, we’re adjusting the sales and we fully well expect to be within our guidance range. And so that’s the important key to take away today as it relates to our messaging. Then with also the understanding behind the scenes we just need to fundamentally do our very best to make sure we’re earning as close as possible to those authorized ROEs beyond the weather situation.

Sophie Karp: Got it. So just to be clear, the 8.6% is the average with the Transmission Holdco?

Julie Sloat: Yes.

Sophie Karp: Of all distribution…

Julie Sloat: Weighted average. Yes.

Sophie Karp: Okay. Got it.

Julie Sloat: Thank you. You bet.

Ann Kelly: Thank you.

Operator: And next we go to Paul Patterson with Glenrock Associates. Please go ahead.

Julie Sloat: Hey, Paul.

Paul Patterson: [Indiscernible] I’m managing. So just – most of my questions have been answered. Only I have a question for you that’s a little bit different and that is the Chevron’s defense. It looks like that know that the Supreme Court might act on it. And I’m kind of scratching my head and I was thinking what you guys might be thinking about what might happen if in fact, the Chevron doctrine or whatever you want to call it is substantially changed or were repealed or what have you. Do – have you guys thought about this or I’m sure you’ve thought about it, but any ideas about what you think that might mean for you guys on the ground?

Julie Sloat: Paul, I don’t have a lot of detail to share with you today. I do know that our legal team is looking into this and our strategy team. But for my day to day right now at the moment, not been top of mind I’m just taking comfort knowing that the rest of the team’s working on it. But hey, if you have a conversation, I’m happy to circle back.

Paul Patterson: Okay, sure.

Julie Sloat: Yes.

Paul Patterson: It was my first question, but the rest were answered, so thanks so much and I’ll follow up with you guys later.

Julie Sloat: That’d be great. Thank you.

Paul Patterson: Okay, great. Thank you

Operator: We’ll go to Paul Fremont with Ladenburg. Please go ahead.

Paul Fremont: Thank you very much. I guess my first question is if you were to get the securitization proceeds, does that change the equity issuance plans that you lay out on Slide 28?

Julie Sloat: No. No, it really doesn’t. So if we get the securitization proceeds, what we would do is reinvest that into the other areas within the AEP footprint. So not in APCo but in the other areas so that we’re in making sure that we continue to earn on the investment while getting the benefits to the Appalachian Power customers.

Paul Fremont: And then my second question sort of related is if you were to get incremental CapEx, what percent should we assume would be equity funded versus let’s say debt funded?

Julie Sloat: Yes, I mean I would assume just kind of the average of what we have in the current plant. Yes, Paul, we typically get, if we have an opportunity to invest more we’re going to try to manage directly back to those target ratios that we throw out there and obviously be mindful of debt to cap as well. So at this point, we’re focused entirely on executing on the plant that we already have out in front of you. The issue could be from time to time is how much slides from one year to the next. So you’re kind of playing with the toothpaste tube, right? So you’re just on passing the CapEx back and forth, because we got $40 billion that we’re put into work. And again, at this point, while we always have more opportunities we need to make sure that this is affordable for our customers as well.

So that’s going to be another stopping point for us too because we’re essentially trying to thread the needle, make sure the balance sheet stays strong, make sure those metrics are absolutely in place, but make sure that, our customers are able to afford what we’re essentially providing. Our regulators definitely help us with that, but that’s also precisely why we have to be really disciplined and not just continuing to spend CapEx that would be fun and nice to spend and actually absolutely make our system stronger and absolutely reliable. But is that what is necessary to keep the lights on and what customers can afford. So it is a constant balancing act for us.

Paul Fremont: Great. Thank you very much.

Julie Sloat: You bet. Thank you.

Operator: [Operator Instructions]

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

Operator: Certainly. Thank you. Replay will be available after 11:30 today and running through August 4 at midnight. You can access the AT&T replay system at any time by dialing 1-866-207-1041, and entering the access code 1289635. International parties may dial 402-970-0847. Those numbers again, 1-866-207-1041 and 402-970-0847 with the access code 1289635. That does conclude our call for the day. Thanks for your participation and for using at AT&T teleconference. You may now disconnect.