AEP - NASDAQ

Ladies and gentlemen, thank you for standing by. Welcome to American Electric Power First Quarter 2023 Earnings Conference Call. At this time, your telephone lines are in a listen-only mode. Later, there will be an opportunity for questions and answers. [Operator Instructions] As a reminder, your call today is being recorded. I'll now turn the conference call over to your host, Vice President of Investor Relations, Darcy Reese. Please go ahead.

Thank you, Alan. Good morning, everyone, and welcome to the first 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.

Thanks, Darcy. Welcome everyone to AEP's first quarter 2023 earnings call. It's good to be with everyone this morning. Our direction and strategy remain on track with an emphasis on our generation fleet transformation and continued investment in our energy delivery infrastructure, which is all embedded and our five-year $40 billion capital plan. I'll start with an overview of our financial performance for the first quarter before discussing our Kentucky operations following the termination of our transaction with Liberty. I'll then provide some updates on our unregulated contracted renewable sale, retail business review and other strategic plans before closing with some insight into our progress on the regulatory and legislative front as we work to implement important new initiatives to ensure our customers and communities' needs are met and continue to come first, which you know enables us to deliver on our financial stakeholder commitments as well. A summary of our first quarter 2023 business highlights can be found on Slide 6 of today's presentation. We have a long-standing history of consistently delivering on our strategic objectives, and we're pleased to share that this quarter is no different. Turning to a high-level overview of our financial results. I can tell you that AEP delivered first quarter 2023 operating earnings of $1.11 per share, or $572 million. Weather this quarter ranked as one of the mildest in the past 30 years resulting in an unfavorable impact of first quarter results. Despite this, our thoughtful and disciplined approach to managing the business enables us to reaffirm our 2023 full year operating guidance range of $5.19 per share to $5.39 per share, and with a $5.29 per share mid -- $5.29 per share midpoint and long-term earnings growth rate of -- growth rate range of 6% to 7%. We're confident in the built-in flexibility we have in our business to ensure that we successfully deliver on our financial commitments and continue AEP's strong track-record of financial performance. We're also pleased to report that AEP has experienced minimal financial and operational supply chain impacts to-date, primarily due to our successful efforts to diversify our mix of suppliers and increase our order quantities to minimize the impact on our robust capital investment plan. Ann I'll walk through our first quarter performance drivers and share some perspective on our positive load outlook, as we continue to drive our economic development and service territory expansion. She'll also review the drivers to support our targeted 14% to 15% FFO to debt range. While our FFO to debt is at 11.4% this quarter, I am confident this metric will improve materially by year-end. As I mentioned to you on last quarter's call, simplifying and derisking our business profile is one of our top strategic priorities. By actively managing our portfolio and demonstrating a clear commitment to a disciplined execution of initiatives and transactions, we continue to deliver significant benefits to our stakeholders. Actively managing our portfolio also means staying flexible and being ready to change our focus and adapt our strategy when it becomes clear that certain transactions or initiatives may no longer be viable. A few weeks ago, our team was faced with this very challenge. On April 17, we announced the termination of the sale of our Kentucky operations to Liberty. Ensuring the best outcome for stakeholders remains our top priority and we took a disciplined approach to evaluating the continued pursuit of a sale and what that would mean in terms of economics, regulatory expectations, timing uncertainty. We ultimately determined that the better outcome was to terminate the pending sale transaction and to continue our work to develop a clear strategy for our Kentucky operations. I'm thankful for the team's ability to react and adapt to shifting circumstances for the long-term benefit of our customers, employees and investors. After the termination of the sale, AEP met with the Kentucky commissioners and key stakeholders. We discussed Kentucky Power's future and the collaboration needed so that we may continue to serve our customers in a reliable manner while ensuring the financial health and discipline of Kentucky Power moving forward. In the near term, we're renewing our focus on the region and support -- and our support of the communities we serve. You'll see in the earnings call materials today that Kentucky Power's earned ROE for the 12-month period ending the first quarter of 2023 is 2.9%. This does not reflect a financially healthy utility, which needs to be resolved in consideration of the interest of all stakeholders. The underperformance is due in part to a number of unique issues that are and will be addressed for improvement over the course of the next year. As we think about the opportunities ahead for our Kentucky operations, the actions we will be engaged and include a refocus on economic development, enhanced local system reliability, and controlling customer cost. We plan to file a base case in Kentucky in June with an expected six-month commission approval process, with new rates taking effect in January 2024. Other factors that will be beneficial in improving the financial profile and performance include using securitization to recover deferred storm costs and legacy generating plant balances and rightsizing the rate base. While we pivot in Kentucky, we're focused on the successful execution of other key transactions. In February 2023, we announced an agreement with IRG Acquisition Holdings for the sale of our 1,360-megawatt unregulated renewables portfolio. A summary of the renewable sale can be found on Slide 7. All regulatory filings were made in March, and at this time, we're waiting on approval from FERC under section 203 and clearance from the Committee on Foreign Investment in the United States and Euro Antitrust. We already have cleared Hart-Scott-Rodino approval and China Antitrust. Consistent with our prior messaging, we expect the sale to close near the end of our second quarter 2023 depending on the timing of regulatory approvals. The proceeds from the transaction will be directed to our regulated businesses as we transform our generation fleet and enhance the electric delivery infrastructure. Furthering our commitment to simplify and derisk the company, and summarized on Slide 8, we've agreed with our joint venture partner PNM Resources to sell our portfolio of operating and developing solar projects in New Mexico. This 50/50 partnership is known as New Mexico Renewable Development, or NMRD. And we hold this within our unregulated operations portfolio, AEP. NMRD owns eight operating solar projects totaling 135 megawatts, 150 megawatt project currently under construction and six development projects totaling 440 megawatts. Last week, an adviser was selected to move forward with the sale process. We anticipate making a sale announcement early in the fourth quarter of this year and will target closing by the end of 2023, subject to timing of regulatory approvals. We also have some news to share with you today. As you know, in October 2022, we announced the strategic review of our AEP Energy retail business, which primarily operates in the PJM markets. We've completed that strategic review and decided that we will start a sales process for that business and will also fold into the process AEP OnSite Partners, which is our unregulated distributed resources business. We've hired an advisor to move forward, and we'll keep you updated on the progress. We expect to launch the sale process sometime this summer, and we'll update you with the details along the way, but currently expect the completion of this transaction in the first half of 2024. We're focused on our core regulated utility operations and continue to evaluate all value additive potential activities to enhance their performance and look for opportunities to recycle capital. As a consequence of this effort, we've decided to pursue a strategic review of three of our non-core transmission joint venture businesses, including AEP's interest in Prairie Wind Transmission, Pioneer Transmission, Transource Energy. These businesses total approximately $551 million in net plant investment for AEP and consists of 370 line miles and four substations of in-service assets, as well as various projects under development in PJM and SPP. We'll definitely keep you posted on our -- or updated on our progress, but we expect to complete our review by the end of 2023 with a conclusion that consists of remaining in or divesting some or all of the businesses. So, let's switch gears and talk about AEP's regulated renewables execution. I'm pleased to share that we continue to make significant progress on our transition to a clean energy economy that provides more stable and predictable cost to our customers. Through our five-year, $8.6 billion regulated renewables capital plan, we have a total of $6.7 billion approved or before our commissions. Most recently, in March to be specific, we made regulatory filings for $1 billion of investment at INM, representing 469 megawatts of solar energy and another 151 megawatts of owned, wind, storage at owned and -- owned, wind and storage at APCo for $466 million. Public Service of Oklahoma Company along with other parties filed a settlement in early April of 2023 in the fuel-free power plan case, which relates to PSO's 995.5-megawatt solar and wind portfolio for $2.5 billion. Like, in any other negotiation, this settlement we focused on the assurance of customer benefits without undue risk to the company. In this case, the settlement provided crucial capacity without fuel expense that'll help address PSO's large capacity need. The case took a positive step forward last week when the judge issued a preliminary opinion approving the settlement on April 27, and the commission has a case on its agenda for today, May 4. For SWEPCO's 999-megawatt renewables project, which represents a $2.2 billion investment, parties recently filed an Arkansas settlement in January for these owned, wind and solar resources. In another positive development in Texas, the administrative law judge that oversaw the evidentiary hearing issued the preliminary order which recommended project approval. And in Louisiana, we reached the settlement, however, we were disappointed that the Louisiana Commission did not approve the settlement on April 26, but we remain optimistic that the matter will be reconsidered at the next meeting this month. We look forward to the continued consideration in Louisiana and orders coming in Arkansas and Texas in the second quarter. It's important to note that our regulated renewables goals are aligned and supported by our integrated resource plans, focused on reliability and customer affordability. In accordance with these plans, we have requests for proposals issued or preparing to be issued for additional resources at each of our vertically integrated utilities. We plan to make related regulatory filings over the next year while taking into consideration commission preferences from previous RFP processes. Now, let me provide an update on several of our ongoing regular and legislative initiatives. We're focused on reducing our authorized versus ROE gap. Have some work to do on that as our ROE was at 8.8% this quarter, driven in part by the unfavorable weather conditions that I mentioned earlier. On the effort to close the gap, I am happy to report that we reached the settlement and gained commission approval in January 23 -- 2023 that closed out our SWEPCO Louisiana base case. A key to this case was the ability to reset rates and recover costs under a formula rate plan. And we have already put this into action as we filed under this provision last month. Similarly, in April, AEP filed a formula rate review in Arkansas, which was authorized by that commission in the last base case. As we advanced through 2023, the team is actively pursuing rider recovery of the 88 megawatts of the Turk plant not currently in Arkansas rates. And the current base case in Oklahoma is set for hearing on May 9. So, we're making progress on the regulatory front. We also worked closely with our stakeholders on the legislative front in Virginia to improve the former triennial rate case process. The new biennial rate process became law in April after active -- after an active legislative session, APCo filed its last triennial in March of 2023 for the 2020 through 2022 period. The new law will require APCo to file its first biennial in 2024 with the biennial continuing in subsequent two-year period. So, it's going to work like this. The pending triennial will put rates in place for 2024 while we litigate the biennial in 2024 for rates effective in 2025, and we can help you with your modeling needs once we get a little further down the line here. Pivoting to our fuel cost recovery efforts for a minute. Our management of fuel cost recovery is a top priority for us with our total deferred fuel balance at $1.6 billion as of our first quarter. We adapted our fuel cost recovery across all of our jurisdictions with a focus on balancing customer impacts. In Texas, the commission approved the $83 million special fuel surcharge filed in October of 2022 and was being recovered subject to review since February 2023. So, making progress there. We are aware of the staff prudence filing last Friday, April 28 in West Virginia that recommended a disallowance of certain fuel costs. The recommendation was rooted in the commission's prior reference to a 69% capacity factor at our coal facilities. Prudence review is a report produced by an outside consulting firm hired by the staff. The report relies on factors beyond AEP's control and takes issue with some of the practices taken to ensure that our power plants would have fuel available to provide electricity during the peak winter period. Those in the area are very familiar with how the historic swing of fuel cost over the past two years placed extreme pressure on the system and fuel recovery mechanisms. We advocated for the securitization legislation that recently passed in West Virginia knowing it provided an effective path to deal with those issues. In line with this strategy, APCo made a filing on April 28 seeking West Virginia Commission approval to utilize the new securitization tool to pay off the $553 million deferred fuel balance as February 28, 2023. The filing also proposes to apply the mechanism to certain storm costs and legacy coal costs in a manner that minimizes cost impacts to customers while still addressing these historical costs. Related to the consultant's prudence recommendation, the new APCo filing also lays out the environment APCo was operating in over this volatile fuel time or time in fuel cost and the actions taken to ensure coal would be available on the most extreme days on the system. Our plan is to collaborate with the commission to address customer and deferred fuel concerns together for constructive path forward in West Virginia. After receiving the commission approval, the plan would be to issue bonds to securitize a combination of deferred fuel balance, deferred storm costs, and legacy coal plan balances in the amount of $1.84 billion in the first half 2024. So, wrapping it up, I'm pleased with the progress we're making, capitalizing on our momentum from 2022. We continue to deliver on our commitments and execute against our strategic objectives. We're taking a thoughtful and disciplined approach to simplify and derisk our business and investments we make to support our positive earnings growth and outlook. I proudly lead a team whose experience and expertise have made it possible for AEP to lay new groundwork for future success while also responding and adapting to the rapid changes we're seeing in our industry. Together, we're delivering safe, clean, affordable, and reliable energy to our customers and communities, all while creating values for our investors. With that, Ann -- I will ask her to now walk through the first quarter performance drivers and provide us with some details on our financing targets. So to you, Ann.

Thank you, Julie and Darcy. It's good to be with you all this morning, and thanks for dialing in. I'm going to walk us through our first quarter 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. Let's go to Slide 9, which shows the comparison of GAAP to operating earnings for the quarter. GAAP earnings for the first quarter were $0.77 per share compared to $1.41 per share in 2022. For the quarter, I'll mention that we reflected the loss on the expected sale of the contracted renewables business as a non-operating cost, as well as an adjustment to true-up expected cost related to the Kentucky transaction in addition to our typical mark-to-market adjustment. There's a detailed reconciliation of GAAP to operating earnings on Page 15 of the presentation deck. Let's walk through our quarterly operating earnings performance by segment on Slide 10. Operating earnings for the quarter totaled $1.11 per share or $572 million compared to $1.22 per share or $616 million in 2022. The lower performance was primarily driven by the unfavorable weather, as Julie mentioned. When looking at historical weather in the first quarter of the past 30 years, we've only seen one quarter with more mild weather than the first quarter of 2023. Operating earnings for our Vertically Integrated Utilities were $0.52 per share, down $0.07. Favorable drivers included rate changes across multiple jurisdictions, normalized retail load, off-system sales primarily associated with Rockport Unit 2, transmission revenue and depreciation. I have more to share and load and performance, and we'll get to that in a minute. These items were more than offset by unfavorable weather, higher O&M and income taxes largely related to timing differences between the years and interests. We expect the year-over-year interest variance to be more pronounced in the first half of the year, as interest rates have somewhat stabilized. We also expect to see favorable O&M in the second half of the year compared to 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 of discretionary spending. These actions are in addition to our ongoing efficiency efforts that allow us to offset the impact of inflation each year. I would like to take a second to talk about the off-system sales and depreciation. Due to the purchase of Rockport Unit 2 in December, we are seeing $0.05 of favorable off-system sales year-over-year since the margins are no longer shared with our retail customers. Also, due to the expiration of Rockport Unit 2 lease, I&M will see approximately $0.055 net favorable depreciation each of the first three quarters of 2023, plus an additional $0.035 in Q4. Including the impact of the Rockport lease, depreciation was $0.02 favorable versus the first quarter of last year. However, if you exclude the impact of the lease, depreciation would have been about $0.04 unfavorable, which is consistent with the incremental investment and a higher depreciable base in our Vertically Integrated Utilities segment. The Transmission and Distribution Utilities segment earned $0.24 per share, down $0.06 compared to last year. Favorable drivers in this segment included rate changes from the distribution cost recovery factor rider in Texas and the distribution investment rider in Ohio, as well as transmission revenue. Offsetting these favorable items were unfavorable weather, unfavorable O&M largely due to higher distribution spending in the quarter, higher interest and lower normalized retail sales due to customer mix. The AEP Transmission Holdco segment contributed $0.35 per share, up $0.01 compared to last year, primarily driven by $0.02 of favorable investment growth. Generation & Marketing produced $0.09 per share, up $0.06 from last year. Favorable drivers here include a higher retail and wholesale power margins, favorable development site sales, depreciation, and taxes. And finally, Corporate and Other was down $0.05 per share, largely driven by unfavorable interest. I'll note that this is due to both an increase in interest rates as well as higher debt balances. I'd like to remind everyone that we reflected the higher interest rates in our guidance that we provided on our year-end 2022 earnings call. While the quarter was unfavorable to the prior year, we are taking actions to offset the unfavorable weather, including the O&M refinements that I just mentioned, that give us confidence to reaffirm our full year guidance range. Turning to Slide 11, I'll provide an update on our normalized load performance for the quarter. We've continued to see load growth outperform when it's proving to be a weak economy across our service areas. This is most evident when comparing load performance across retail classes. So, we are seeing some weakness in residential loads. Our commercial and industrial classes are benefiting from new large customer volumes from our ongoing economic development efforts. This provides some potential upside to the full year outlook. Beginning in the upper left hand corner of the slide, normalized residential load was down as customers continue to be 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 over the rest of the year. While we are seeing a decline in residential uses for customer, total residential customer counts were up by 0.5%, demonstrating growth in our service territory. Looking through the rest of the slide, you'll see that this was substantially offset by gains in our commercial and industrial loads attributable to new large customer additions. Normalized commercial sales accelerated an exceptional 7.8% compared to the first quarter of 2022. Though the growth in commercial sales was spread across many of our operating companies, gains were especially robust in AEP Texas and AEP Ohio, attributable to the new data center projects coming online in the new year. Outside of data centers, commercial gains were driven primarily by real estate, general merchandise stores, and food and drink establishments as individuals continue to move more freely in the wake of the pandemic. If we look to the lower left hand corner, we see the industrial sales resume their healthy pace of growth, increasing 5.1% from a year ago. As with commercial sales, gains were most robust in AEP Texas, while SWEPCO also experienced double-digit growth in its industrial sales. Looking at individual sectors, gains are most pronounced among oil and gas extraction and primary metal. You'll note that despite our strong commercial and industrial results for the first quarter, our expectations for 2023 load growth are still muted. Probability of a national downturn is extraordinarily high, and it's clear that activity is already slowed to a point that it's having a material impact on our customers' finances. While we expect the pace of economic growth to slow further, we don't anticipate a severe economic contraction across our service area in 2023. Though weaker than they were a year ago, household finances are still healthy by historical standards. Furthermore, the labor market continues to be resilient in the face of Fed rate hikes, which will serve to limit the severity of a potential downturn. These assumptions have been baked into our full year guidance for some time allowing us confidence that our projected load growth for 2023 is very much achievable. Adding to that confidence is our believe that there is more upside to our load projections than downside, stemming from a disciplined commitment to economic development across our 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 the customer experience while mitigating the rate impacts on our customer base. So, let's move to Slide 12 to discuss the company's capitalization and liquidity position. Taking a look at the upper left quadrant on this page, you can see our FFO to debt metric stands at 11.4%, which is a decrease of 1.8% from year-end and below our long-term target. The primary reason for this decrease is a $1.9 billion increase in balance sheet debt during the quarter, partially due to the return of the mark-to-market collateral positions associated with the decline in natural gas and power prices. Return of collateral also reduces our funds from operations, so it hits us on both sides of the equation. Without the fluctuations in our mark-to-market collateral positions, our FFP to debt metric will be closer to 13%. 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 units conversion, and our funds from operation improve over prior year, predominantly in the fourth quarter. We remain committed to our targeted FFO to debt range of 14% to 15% and plan to trend back into this range early in 2024 as we continue to work through the regulatory recovery processes of our deferred fuel balances. 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 facilities that was just extended to March 2025 support our liquidity position, which remains strong at $3.4 billion. The $800 million increase in liquidity from last quarter is mainly due to a decrease in commercial paper outstanding from long-term debt issuances. On a GAAP basis, our debt to capital ratio increased from the prior quarter by 1.2% to 64.1%. We plan to trend back closer to 60% this year as we close our announced sale transaction and complete our previously planned equity units conversion. On the qualified pension front, our funding status decreased 1.1% during the quarter to 101.3%. Rates fell during the quarter, which caused the pension discount rate to decrease, driving an increase in the liability that was greater than the gain on assets. Now turning to Slide 13. The first quarter has brought a significant challenge our way in the form of unfavorable weather. As we progress through the remainder of the year, we will continue to take action to manage our business and mitigate this impact. Our core business remains in a strong position and we are reaffirming our operating earnings guidance range of $5.19 to $5.39. We also continue to be committed to our long-term growth rate of 6% to 7%. As Julie previously addressed regarding the terminated Kentucky sale transaction, we are establishing a new -- a renewed focus in long-term strategy in order to maximize the full potential of our Kentucky operations going forward. We are on track to close the divestiture of our unregulated contracted renewables portfolio in the second quarter of this year, have announced the sale of our retail and distributed resources businesses, and are embarking on a review of some transmission joint ventures. These initiatives will help us to simplify and derisk our business while we continue to focus on the fundamentals, executing the $40 billion transmission, distribution and regulated renewables capital plan, disciplined O&M management and positive regulatory outcome. We really appreciate your time and attention today. And with that, I'm going to ask Alan to open the call so we can hear what's on your mind and answer any questions that you have.

Thank you. [Operator Instructions] Our first question will come from the line of David Arcaro with J.P. Morgan. Go ahead.

Hi, thanks so much for my question. Dave Arcaro at Morgan Stanley. Let's see, maybe starting on the transmission business, I was wondering if you could elaborate a little bit on your strategic thinking there. What makes those assets non-core? Why that size of assets? And wondering what you're thinking -- if it does come to a divestiture decision, what you would plan to do with the proceeds? Could that reduce equity needs in the plan from here?

Yeah, thanks so much. Appreciate the question. As we continue to talk about simplifying the business, I wouldn't necessarily put the transmission strategic review of the JVs as a derisking, because we are very comfortable with the risk profile of transmission, JV or otherwise. So that being said, this is more about simplification and really focusing on our ability to deal with customers in our footprint. So, nothing wrong with these assets. We love the assets. But we'd really like to take those dollars and channel them toward the traditional core utility business and transco utility business we have at American Electric Power. So -- and why Transource and Pioneer and Prairie Wind? Again, those are outside of our traditional footprint that we have today. ETT is a little different, and it is not necessarily under currently -- or not under current review at this point, as we focus on these pieces that are outside of our footprint. So, we'll see how this goes as far as utilizing any proceeds that we would have from a sale transaction should that occur. Again, this is a strategic review. We haven't made any decisions yet. What you should expect us to do is the same thing we've been talking about, dollars get channeled to traditional investment in the regulated utility operations. Clearly, have a lot to do on the transmission side. But when you bring dollars in the door, our expectation is to maintain a very healthy balance sheet. We've got a little bit of work to do. Ann talked about that in her opening comments. The metric should heal by the end of the year. So, we feel confident in that regard. But going out further in the timeline, we would always look to make sure the metrics are good. And then if we can, responsibly reduce equity issuances in future periods. But again, strategic review underway. We'll keep you apprised. And I would expect this would be more of a story as we get through the end of 2023 with the strategic review. And if anything were to occur, being 2024 story for us. So, thank you for the question.

We'll go next to line of Jeremy Tonet with J.P. Morgan. Go ahead.

Hi. This is actually Aidan Kelly on for Jeremy. Good morning. So just shifting to the New Mexico and retail distributed resources sales, could you talk more about the prospective of buyer market you're seeing right now? Any insight on the type of buyer you would be interested here? Also, just any language on OnSite Partners as well with the G&M segment would be great. Thanks.

Yeah, you bet. So let me take a couple of different tacts at this. So number one, as you know, we've had a strategic review underway for the retail business. So that shouldn't be a surprise. Scooping in the OnSite Partners businesses is the new addition today. Those comprise about -- Energy Partners is about, I'd say, $0.04 of -- I'm sorry, I should say, retail business is about $0.04 of the component that we're talking about in terms 2023 guidance. OnSite Partners is about $0.02. So let me give you those parameters, so you know exactly what we're talking about. NMRD is about $0.01 of the 2023 guidance. You got a few pennies there that we're playing with. As far as who are the likely buyers, let me answer it this way. We're already dealing with a multitude of buyers from our unregulated contracted renewables business. So, we're very familiar with that space because we have that contract underway with that piece of the business. NMRD, I would think would fit more closely with that type of activity in terms of the parties that might be interested in that particular asset base. But then let's move to the retail business. I think you got a little bit more of a narrower or more unique buyer set for that particular piece of the business. And then -- and I won't go into any names, but just given the nature of the business, the field narrows just a touch. And then on the distributed part of the business, meaning OnSite Partners, it got hundreds of parties that could be potentially interested in that. The other thing that we're thinking about is when we start working with our financial advisor to move forward with the transaction, there could be a situation where you have a combined platform where both the retail and the distributed pieces of the business are put together and sold that way. But we're completely open to separating the [two tube] (ph) just because you've got different buyer bases. Can't really opine on it yet just because we're just getting started with it, but we will absolutely keep you apprised of what our progress is and what we're experiencing as we move through time here. So early stages, but well underway in terms of getting the financial advisor kicked off and then the process started.

We have a follow-up question from the line of David Arcara with Morgan Stanley. One moment, please. Apparently, that line is not in queue. We'll go next to the line of Shar Pourreza with Guggenheim Securities. Go ahead, please.

Hi. This is James Ward on for Shar. Thank you for taking our questions. First, as you look towards your June rate case filing in Kentucky, how are you thinking about the key asks in this case? And as a follow-up, could you expand on how you see capital allocation to this jurisdiction developing in the context of your overall investment plans over the forecast period?

I still appreciate that. And I get it, you guys have a really busy morning. So, I know we have different names who don't typically cover us. So, I just -- I'm still appreciative of your time and attention today. Lots of companies reporting. So that being said, on the Kentucky front, stay tuned, because what you'll -- you should expect us to do is be in conversations with the different stakeholders, with the commission, and staff in particular in Kentucky to make sure we're scratching all the inches. We want to be successful in the arena. And we are going to absolutely have a very thoughtful approach in sensitivity to reliability. We need to make sure that we're keeping the lights on and keeping them affordable for the state of Kentucky and the area that we serve in particular. So, I have a lot of granularity to share with you today other than to assure you that we will be working collaboratively with the partners in that jurisdiction. So, extremely important to us particularly when you look at where the current ROE is. We need to get that up. We need that utility company to be in a healthy situation so we can continue to have low cost capital allocated to that particular piece of the business. And then, I'll ask Ann to talk a little bit about our capital allocation and how we're going to digest that from Kentucky.

Right. So, our capital plan, the $40 billion capital plan going forward is not going to change. We would just be reallocating from other areas within the same segment. So, you would expect to see the transmission, distribution, generation, all those planned numbers for the five-year timeframe will stay the same. We will just allocate within jurisdictions to Kentucky to make sure that they are focused on reliability, as Julie mentioned.

Our next question will come from the line of Durgesh Chopra with Evercore. Go ahead.

Hey. Good morning, team. Thanks for giving me time. Hey, just I know you gave us property plant and equipment number on the transmission assets, which are up for strategic review. Is there a rate base number that you have handy that you can share with us? If not, I'll just follow-up with Darcy.

You know what, Durgesh, thank you so much for your question. I don't have a rate base number in front of me. We can absolutely get that to you though. So, we'll circle back with you. But the $551 million, as you point out, is the net plant position that is attributable to AEP in particular.

We'll go next to the line of Andrew Weisel with Scotiabank. Go ahead.

Hi, good morning. Thank you. First question on the balance sheet. Just to clarify, if none of these transactions move forward besides contracted renewables, what's your degree of confidence in the targeted credit metrics and FFO guidance, and over what time period?

Yeah. So what I talked about earlier was based on that scenario. We have not modeled in any additional asset sales transactions besides the contracted applicable. So, we would expect an improvement by year-end and getting it within our targeted metrics early next year.

We'll now go to the line of Anthony -- pardon me, Anthony Crowdell with Mizuho. Please go ahead.

Great. I guess two quick questions. One is on Slide 27 that shows the underearning gap. I guess when I look at the like five OPCos that are under earning anywhere between 90 to greater basis points. What's a reasonable assumption of underearning we could assume when you closed that gap and during what timeframe? And then the follow-up is -- and I may have not heard correctly. I think -- I don't know if it's a Turk plant or the Rockport plant, you've bought back or it's maybe not part of lease or maybe I didn't hear that correctly. Does that now move to the G&M segment in reporting? Thank you.

Yes. Thanks so much for the question. I'm going to take your first one on the ROEs. I'm going to back up the truck a little bit. You may recall when we provided 2023 earnings guidance, the average ROE across the system for our regulated businesses was going to be around 9.4%. Today, as you know, we're at 8.8%. So here's my expectation. I expect we're going to close that gap as we get toward the end of the year. And as you know, I mentioned several different regulatory filings and successes that we've had in 2023 that are going to help us close that gap. So we feel confident that gap will close, but I do expect that we'll be a little under that 9.4%. Importantly, we have not changed our earnings guidance, so we still plan to get within the goalpost on the earnings guidance and growth rates. So I'm not worried about that either, but it's going to take us a little longer to close the gap versus the 9.4% that we had in that 2023 guidance. So, I'll leave you with that. And as you know, we're not dependent on any single one utility company to get in a direct earning level relative to authorized, that's the benefit of having a portfolio of utilities. But boy, I surely would love to close that gap and be within 10s of basis points versus the authorized in each of our jurisdictions. That's an objective. It's just going to take us a little while to get there because, as you know, these things have a little bit of a lead time on them. So stand by and know the guidance is sound. And then on the Rockport unit, that actually it becomes a merchant unit. And I believe that's captured in, what, our Vertically Integrated Utilities segment, right? And that would be captured as off-system sales, okay? So, hopefully, that will help you with your modeling needs there, too.

And that's due to the ownership structure. So, we didn't want to move it because it's still owned by the Vertically Integrated Utilities.

We have a follow-up question from the line of Shar Pourreza with Guggenheim. Go ahead.

Hi. James Ward here again. Thank you for this follow-up. Unrelated to the prior question, just wanted to ask, assuming the successful eventual sales of both your retail business, distributed resources and the three non-core transmission JVs you highlighted today, how should we think about the source of funds for future financing needs? And specifically, will asset sales and capital recycling always factor into your financing approach? Or is there a point at which you would no longer look to recycle assets? Thank you.

Yes, I -- this is Julie. I'll hand it to Ann here in a minute. Here's how I look at it. Simplification and derisking the business should be part of our fabric. So, we are going to continually look at where the best use and highest value is for each of the dollars that we put to work. So I think that's our job is to make sure that the portfolio of assets we have is the best we can have in the highest earnings. You go back to the question I just answered around earning your authorized ROE, we have to do better at that, and we'll continue to do better at that as we go down the path here. So, I do think you should keep that in back of the mind. We will continue to keep you updated on and signal to you if we think there's a business that might fit that profile that we would consider recycling it. But the ones that you see us talking about today are the ones that are absolutely those in terms of strategic review on the JV side of the house, transmission that -- we love transmission, but we may be able to put that to better use inside the traditional footprint. And then, clearly, on the unregulated side of the house, we want to derisk and simplify. It makes complete sense to move forward with those actions that we outlined today. So Ann, I don't know if you want to talk any more about or add any additional color to that?

Yeah, I mean you're absolutely right, Julie. And when we look at the cash flows, which are on Slide 24 that we've only modeled in the contracted renewables sale here. So any additional sales proceeds will also be able to strengthen the balance sheet. And as we mentioned, we could potentially selectively reduce the equity issuances going forward, while maintaining the same capital plan.

Our next question will come from the line of Sophie Karp with KeyBanc. Go ahead.

Hi. Good morning, and thank you for taking my question. I wanted to ask you about the Texas utilities and the ROE gap there. I guess in Texas, the regulatory recovery mechanisms are very constructive, right? So, you have your DCRF and TCOS and whatnot. So what needs to be, I guess, addressed there to close that gap specifically? Could you speak to that?

Yeah, I still appreciate that question. So thanks for being on the call today. We're working on it. So let me start with the backdrop on the story. As you know, we continue to channel a great deal of capital to AEP Texas. We do think the recovery mechanisms there are very good. We always think there's opportunity for improvement. So I'll talk about that here in a moment. But one of the things that we've gotten comfortable with, with the touch of underearning relative to authorized in Texas, is the amount of growth that we have in Texas. So on average, we can grow earnings there at 10%, but I got to take a little bit of a haircut because no regulatory recovery is perfect. But we're trying to work on that. And so for example, if you read on Page Number 27, there's some commentary under the little earnings bubble there that we talk about bi-annual TCOS filings to recover significant capital investment. Those good things. We love that. We do have some legislation that is in process and working through that relates specifically to the DCRF and the ability to shorten that timeframe. So maybe we can do that twice a year versus annually. So that will help to kind of close that gap a little bit. And then there's also some legislation around cap structures, too, that might be helpful to us. So, we're trying to work all the different angles. Not to mention the other thing that we're thinking about and continue to talk about is, a way to continue to use those excellent cost recovery mechanisms that are much more progressive in Texas throughout the period, even when you're in for a base case. So, we're trying to use the legislative aspects as well as just trying to be as efficient as possible to close that gap. But we've been comfortable in the near term, taking the little bit of a hit relative to authorized on the ROE because we can grow earnings there and the demand is there. So that was the rationale. But we love the business. We're just trying to make it better in terms of recovery.

We'll go now to the line of Julien Dumoulin-Smith with Bank of America. Go ahead.

Hey, good morning, team. Thank you guys very much. Appreciate the time. Just following up on a couple of the remarks earlier. Just can you elaborate a little bit more on next steps here as you think about Louisiana? Obviously, a little bit of a setback here, but you alluded to potentially putting this back on the -- or maybe not you all, but perhaps the commission electing to reconsider the matter next month. Can you elaborate on the procedural element there, but also some of the other avenues, there's a flex consideration here that can be pursued to the extent to which there may be different outcomes?

Yes. Julien, thank you for being on the call today. And that is absolutely top of mind for us. As you know, and I mentioned in my opening comments, we're able to get to a settlement agreement and the Louisiana staff filed constructive testimony with conditional approval, all that good stuff. So, we want to continue to work that angle. And actually, one of the commissioners suggested that the decision could be recalled at the next meeting for reconsideration once some additional information is shared. So, we have that top of mind for us. So here's what you should expect from SWEPCO. You should expect to see us seeking rehearing in which we continue to be optimistic that we can pool this across the goal line. So, stay tuned on that. I don't want to get too much in the weeds on it just yet because we're literally in game with that right now. And then specifically, we would hope that this is going to move forward, and we'll have all three jurisdictions stepping in line and be able to absorb with positivity, the applications that we have in front of them. But do we have flexibility in terms of flexing up in the other jurisdictions? On a discrete basis, we think that there is that opportunity with the different projects that we have that are included in that filing. So again, nothing specific to share today. But rest assured, we're looking at all the different tools and angles in the tool bag there that we're able to use should we need a different route if Louisiana can't get there. But we're optimistic and we're having conversations, so stay tuned.

We'll go next to the line of Paul Fremont with Ladenburg. Go ahead.

Thank you. I guess my first question is on FFO to debt. In order to hit the sort of the 14% to 15% targeted range, should we assume that you need to basically collect on the $1.6 billion in fuel deferrals? And can you give us a sense of the timing that you would expect to recover those amounts?

Yes, I'll take that, Julie. So, we would expect to collect over the extended timeframes that we have already agreed upon within our jurisdictions. And with respect to West Virginia, we have that model taking advantage of the securitization in the first quarter or the first half of next year.

We have a follow-up question from the line of Sophie Karp with KeyBanc. Go ahead.

Hi. Thank you for giving me more time. If I can ask a follow-up on Kentucky, right, like asked differently, when you spoke to regulators there, and clearly, you need to bring the ROE up, right? But what kind of a rate increase would that require for Kentucky rate payers? And like do you get the sense of kind of like the upper limit of the appetite that the regulators might have for rate increases in this environment?

Yeah. So, let me answer that this way. I don't have specific numbers to share with you today because when we actually had the conversation, we hadn't announced earnings yet, okay? So that's new information today, that's public today. And so this will be the go-back conversation that we'll have. And again, the plan is truly to collaborate, because I'm confident that the commission and the commissioners are interested in having a very sound -- financially sound utility company. And so we'll all be working in that same direction. Now as far as tools in the tool bag, obviously, we'll try to influence the top-line with economic development and things of that nature. That takes a little longer, as you know, because it's got a little longer lead time on it. But we know we're really successful with that, too. So stay tuned. And then, of course, we'll be very sensitive to cost as well. The other thing that will be top of mind for us is using the new tools in the tool bag is securitization, okay? So, we've got deferred storm costs that are sitting on the balance sheet. We have an opportunity to take care of net plant of legacy coal plants that's sitting on the balance sheet, too, to the tune of something like $290 million associated with Big Sandy. So those are things that we'll be able to securitize and then kind of back into what -- how we need to make that math work. And I mentioned that also talks about or at least strikes at the idea of kind of rightsizing the rate base. So, we work with the commission and all the various stakeholders in the state of Kentucky that we deal with to make sure that we're getting where we need to be. But honestly, from my seat and from a utility seat, just 2.9%, it's not healthy. We need to get it in a healthy situation. And that will be top of mind for us, because we've got to keep the lights on to and keep it affordable. So stay tuned. We don't have a lot of color to share today because we're literally in game. This is a new data point with 2.9%, okay? But Sophie, thank you for jumping back in line.

We have a follow-up question from Paul Fremont with Ladenburg. Go ahead.

Thanks. So, the assumption is that you will -- that you're assuming you'll get securitization in West Virginia as part of getting to the -- to that 14% to 15% FFO to debt?

Paul, this is Julie. Actually, securitization will be a great thing, and that helps us, give us a little more flexibility, more importantly, it's good for the customer. And so, when we filed for our new ENEC filing that we made on what was it like February -- I'm sorry, April 28, I think, was the date that we filed it. What you'll see is that we have two proposed options to recover the fuel balance in our filing. And one is to spread the recovery over three years, and the other is to use securitization for the under-recovered fuel balance. And as part of that, we also looked in as an option, again, with the idea and backdrop and motivation is to protect the customer rates because we can't have them trying to swallow a watermelon here is to essentially securitize plant balances from legacy coal plants, so Amos and Mountaineer in particular, and I think we have some storm costs in there as well. And so when I mentioned today, that $1.84 billion number that we would like to securitize, that's all in. And so, we're trying to give the commission options so that we can all work collectively to make sure that the citizens and customers of West Virginia are protected, but that we still have a healthy utility and we're able to hit the balance sheet metrics that we need. So, it's doable. It's absolutely doable, we'll just need to move through the process.

And one thing just to add on FFO to debt, when you think about just the quarterly dynamics, in Q4 of last year, due to market conditions, we did have a significant outflow of collateral as well as an increase in deferred fuel. So, as we get through that this year, and that quarter rolls off, that will significantly help our FFO to debt as well.

[Operator Instructions] We have a follow-up question from Paul Fremont with Ladenburg. Pardon me, that line did not open up. We have Bill Appicelli with UBS. Go ahead.

Hi, good morning. Most of my questions have been asked and answered. But just a question around the timing of the approval for the contracted renewable sale. You made the filing on March 22. I guess what gives you the comfort that you'll get approval in Q2? And I guess what's the -- what do you need to demonstrate in those filings to get approval both at FERC and on the Committee on Foreign Investment?

Yes. So as far as FERC and the other two approvals that we'll need to get, let me answer it this way. When we made the filing initially, we had requested at FERC a 60-day approval process. So, we would like to get an order within 60 days. May 22 would be 60 days. And given that this is normal kind of traditional business unregulated, not tied to significant customers and multiple stakeholders, we don't anticipate any material roadblock as it relates to getting not only FERC approval, but the clearance from the Committee on Foreign Investment in the United States and/or approval under any of the applicable competition loss. So we're comfortable with where we are and expect that we should have that in pretty short order, which gives us confidence to say we think that we'll get this done by the end of the second quarter at the latest. But we'll keep you apprised if anything were to come up. But at this point, we're past commentary periods, and everything seems to be going relatively smoothly. So, anyway, I'll leave it at that, and suggest that if anything shifts, we'll be right in front of you immediately.

We have no further lines in queue at this time.

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