American Electric Power Company Inc (AEP) — Q1 2023 Transcript

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.

Thank you, Darcy. Welcome everyone to AEP's first quarter 2023 earnings call. It's great to be here with you all this morning. Our direction and strategy are on track, focusing on transforming our generation fleet and continuously investing in our energy delivery infrastructure, all outlined in our five-year $40 billion capital plan. I will begin with a summary of our financial performance for the first quarter before addressing our Kentucky operations after our transaction with Liberty was terminated. Following that, I'll share updates on our unregulated contracted renewable sales, a review of our retail business, and other strategic initiatives. I will conclude with insights into our progress on regulatory and legislative matters to ensure we meet the needs of our customers and communities, which in turn supports our financial commitments. A summary of our first quarter 2023 highlights can be found on Slide 6 of today's presentation. We have a strong history of meeting our strategic objectives, and I’m pleased to report that this quarter follows that tradition. Looking at our financial results, AEP recorded first-quarter 2023 operating earnings of $1.11 per share, totaling $572 million. The weather this quarter was one of the mildest in the past 30 years, negatively impacting our results. Nonetheless, our disciplined management approach allows us to maintain our full-year operating guidance range for 2023 of $5.19 to $5.39 per share, with a midpoint of $5.29 and a long-term earnings growth rate of 6% to 7%. We are confident in our business's built-in flexibility to uphold our financial commitments and maintain AEP's strong financial performance. We are also pleased to announce that AEP has faced minimal financial and operational supply chain disruptions so far, thanks to our successful supplier diversification and increased order quantities, which protect our capital investment plan. Ann will outline our first quarter performance drivers and provide insights into our positive load outlook as we continue to grow our economic development and service territory. She will also discuss the elements supporting our targeted 14% to 15% FFO to debt range. Although our FFO to debt this quarter is at 11.4%, I am confident this metric will improve significantly by year-end. As I mentioned last quarter, simplifying and managing risks in our business profile is a top strategic priority. By actively managing our portfolio and maintaining a disciplined approach to executing initiatives and transactions, we continue to create significant benefits for our stakeholders. Managing our portfolio also requires adaptability; we must be prepared to shift our focus and adjust our strategy when certain transactions or initiatives no longer seem viable. Recently, we faced such a challenge. On April 17, we announced the termination of the sale of our Kentucky operations to Liberty. Our foremost priority is ensuring the best outcome for stakeholders, so we carefully evaluated the ongoing sale and its implications on economics, regulatory expectations, and timing uncertainty. We ultimately concluded that terminating the transaction was in our best interest, allowing us to focus on developing a clear strategy for our Kentucky operations. I appreciate the team’s ability to respond and adjust for the long-term benefit of our customers, employees, and investors. After terminating the sale, AEP engaged with the Kentucky commissioners and key stakeholders to discuss the future of Kentucky Power and the collaboration needed to serve our customers reliably while ensuring the financial health of Kentucky Power. In the short term, we are recommitting to the region and supporting the communities we serve. As noted in our earnings call materials, Kentucky Power had an earned ROE of 2.9% for the 12-month period ending the first quarter of 2023. This figure indicates the need for financial improvement, which we will address in the interest of all stakeholders. The underperformance can be attributed to various unique issues that we are addressing for improvement over the next year. Looking ahead for our Kentucky operations, we plan to focus on economic development, enhancing local system reliability, and controlling customer costs. We intend to file a base case in Kentucky in June, with an expected six-month commission approval process, aiming for new rates to take effect in January 2024. Other contributing factors that will help improve our financial standing include leveraging securitization to recover deferred storm costs and legacy generating plant balances and optimizing 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, a 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 will 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 result of this effort, we've chosen to conduct a strategic review of three of our non-core transmission joint venture businesses, which include AEP's stake in Prairie Wind Transmission, Pioneer Transmission, and Transource Energy. These businesses represent roughly $551 million in net plant investment for AEP, encompassing 370 line miles and four substations of operational assets, along with various projects under development in PJM and SPP. We will keep you informed of our progress, but we anticipate concluding our review by the end of 2023, with a decision to either remain in or divest some or all of these businesses. Now, let's shift focus to AEP's regulated renewables execution. I'm happy to report that we are making substantial progress in our transition to a clean energy economy that offers more stable and predictable costs to our customers. Through our five-year, $8.6 billion regulated renewables capital plan, we have secured a total of $6.7 billion approved or pending before our commissions. Most recently, in March, we submitted regulatory filings for $1 billion of investment at INM, which includes 469 megawatts of solar energy and an additional 151 megawatts of owned wind, along with storage at APCo for $466 million. In early April 2023, Public Service of Oklahoma Company and other parties filed a settlement in the fuel-free power plan case, which pertains to PSO's 995.5-megawatt solar and wind portfolio, valued at $2.5 billion. Like in any other negotiation, this settlement focused on assuring 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 needs. 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 regulatory and legislative initiatives. We're focused on reducing our authorized versus ROE gap. We 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 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 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 periods. 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, which has been recovered subject to review since February 2023. So, we're 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 costs over the past two years placed extreme pressure on the system and fuel recovery mechanisms. We supported the securitization legislation that recently passed in West Virginia because it offers an effective way to address significant issues. Following this strategy, APCo filed on April 28 for approval from the West Virginia Commission to use the new securitization tool to settle the $553 million deferred fuel balance as of February 28, 2023. The filing also suggests using this mechanism for certain storm costs and legacy coal costs in a way that minimizes the impact on customers while still addressing these historical expenses. Regarding the consultant's prudence recommendation, the new APCo filing details the environment in which APCo was operating during the fluctuating fuel prices and the measures taken to ensure coal availability during the most critical days. Our plan is to work with the commission to jointly tackle customer and deferred fuel issues to create a constructive way forward in West Virginia. Upon receiving commission approval, we aim to issue bonds to securitize a combined total of $1.84 billion for deferred fuel balance, deferred storm costs, and legacy coal plant balances in the first half of 2024. In summary, I am pleased with our progress, building on the momentum from 2022. We remain committed to delivering on our promises and pursuing our strategic goals. We are adopting a careful and disciplined method to simplify and reduce risks in our business and our investments to support positive earnings growth and outlook. I am proud to lead a team whose knowledge and experience have enabled AEP to establish new foundations for future success while responding to and adjusting to rapid changes in our industry. Together, we are providing safe, clean, affordable, and reliable energy to our customers and communities while creating value for our investors. Now, I will turn it over to Ann to discuss first quarter performance drivers and share details on our financing targets. Ann, it's yours.

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 costs 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 on 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 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 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 the 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 margin, 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 usage for customers, 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 has 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 belief 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. The 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 FFO 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 the 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 were 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 presented a significant challenge due to unfavorable weather. As we move through the rest of the year, we will continue to take steps to manage our business and reduce this impact. Our core business remains strong, and we are reaffirming our operating earnings guidance range of $5.19 to $5.39. We are also committed to a long-term growth rate of 6% to 7%. Regarding the terminated Kentucky sale transaction, we are establishing a renewed focus on long-term strategy to maximize the full potential of our Kentucky operations moving forward. We are on track to finalize the sale 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 reviewing some transmission joint ventures. These initiatives will help us simplify and de-risk our business while we focus on the fundamentals, executing the $40 billion transmission, distribution, and regulated renewables capital plan, disciplined O&M management, and positive regulatory outcomes. We appreciate your time and attention today. With that, I'm going to ask Alan to open the call so we can hear your thoughts and answer any questions you may have.

Hi, thank you for taking my question. I would like to ask about the transmission business and your strategic thinking regarding it. What factors make those assets non-core? What is the significance of their size? Additionally, if a divestiture decision is made, what are your plans for the proceeds? Will this help reduce equity needs moving forward?

Thank you for the question. As we continue to simplify the business, I want to clarify that the strategic review of the transmission joint ventures is not about de-risking, as we are comfortable with their risk profile. This review is more about simplification and focusing on our customer relationships within our core area. We value these assets but prefer to allocate those resources to our traditional utility operations at American Electric Power. Transource, Pioneer, and Prairie Wind are outside our current core focus. ETT is a bit different and isn't under review right now as we concentrate on these external assets. We'll evaluate any proceeds from a sale transaction if it occurs. This review is strategic, and no decisions have been made so far. We plan to direct funds into traditional regulated utility operations. Although we have a lot to address in the transmission sector, our aim with incoming funds is to keep a robust balance sheet. We've identified some areas for improvement, and we believe the metrics will recover by the year's end. Looking ahead, we will ensure the metrics remain solid and, if possible, responsibly reduce future equity issuances. The strategic review is ongoing, and we will keep you updated. Expect more developments on this as we move towards the end of 2023, with any significant updates likely to emerge in 2024. Thank you for your inquiry.

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.

Sure, I can address that. First off, as you know, we have been conducting a strategic review of our retail business, which is not unexpected. The inclusion of the OnSite Partners businesses is a new development. Energy Partners accounts for about four cents of our 2023 guidance, while OnSite Partners contributes roughly two cents. To clarify, NMRD represents approximately one cent of that guidance. So, we have a few cents to consider. Regarding potential buyers, we are currently engaging with various buyers from our unregulated contracted renewables sector, which we are well-acquainted with due to existing contracts. NMRD seems to align more closely with that area in terms of interested parties. On the other hand, the retail business likely has a more limited set of unique buyers, although I won't mention any names specifically. For OnSite Partners, we have a very broad range of possible interested parties. Furthermore, as we collaborate with our financial advisor to move forward with this transaction, it's possible that we might explore the option of combining both the retail and distributed segments for a joint sale. However, we are also open to selling them separately due to their differing buyer profiles. It's too early to provide detailed insights, but we will certainly keep you updated on our progress as we move forward. We are in the initial stages of engaging with our financial advisor and beginning the process.

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 appreciate your understanding. I know it's a busy morning, and there are different analysts covering us today. Thank you for your time and attention. As for the situation in Kentucky, we'll be in discussions with various stakeholders, including the commission and staff, to ensure we cover all aspects. Our aim is to succeed in this area while being sensitive to reliability. We want to ensure that we maintain affordable, reliable power for Kentucky and the regions we serve. I have detailed information to share, but I can assure you that we will work closely with our partners in that jurisdiction. This is particularly crucial given the current Return on Equity (ROE) status, which we need to improve. It's important for the utility company to be in a healthy position to secure low-cost capital for this part of the business. Now, I'll turn it over to Ann to discuss our capital allocation and how we plan to approach it regarding 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.

Hey, good morning team. Thanks for giving me time. Hey, just I know you gave us a 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.

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.

I have two quick questions. First, regarding Slide 27, which shows the underearning gap, I noticed that the five operating companies are under earning by anywhere from 90 to more than 100 basis points. What would be a reasonable assumption for closing that gap, and what timeframe should we expect? Secondly, I might have misunderstood, but could you clarify if it's the Turk plant or the Rockport plant that you've bought back, or if it is not part of the lease? Does that plant now get reported under the G&M segment? 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 10 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 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.

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 and 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, this is Julie. I'll pass it to Ann shortly. I view simplification and reducing risk as essential to our business strategy. We will consistently evaluate the most effective and valuable use of every dollar we invest. Our goal is to ensure that our portfolio of assets generates maximum earnings. Regarding our authorized return on equity, we need to improve, and we are committed to making progress in that area. Keep this in mind as we move forward; we will keep you informed about any businesses we might consider selling. The assets we are discussing today are currently under strategic review, particularly in our joint ventures and transmission operations. We appreciate transmission but believe we can optimize its use within our main areas. Additionally, on the unregulated side, our goal is to simplify and reduce risk. It makes sense to proceed with the actions we've outlined today. Ann, would you like to add anything or provide further details?

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.

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 the 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 under earning 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.

Good morning, team. Thank you for your time. I wanted to follow up on some earlier comments. Could you provide more details on the next steps concerning Louisiana? There’s been a slight setback, but you mentioned the possibility of the commission reconsidering the issue next month. Can you explain the procedural aspects involved, as well as other options we might explore, including any flexibility that could lead to 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 pull 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 toolbox 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.

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 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.

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?

I don't have specific numbers to share with you today because at the time of our conversation, we hadn't announced earnings yet. That information is new and public today, which sets the stage for our future discussions. The goal is to collaborate, and I'm confident that both the commission and commissioners are interested in maintaining a financially sound utility company. We will be working towards that common objective. Regarding our strategy, we will focus on economic development to influence our top-line revenue, which may take longer due to its lead time, but we have had success in this area in the past. So, please stay tuned. We are also very mindful of costs. Another priority for us will be utilizing new tools like securitization. We have deferred storm costs and potential financial obligations related to legacy coal plants, estimated at around $290 million linked to Big Sandy, which we could securitize. This will help us figure out the financials and address the need to rightsize the rate base. We will collaborate with the commission and various stakeholders in Kentucky to ensure we achieve our objectives. However, from my perspective, a 2.9% return on equity is not healthy, and we need to improve this situation while keeping energy affordable. We don't have much additional information to share today as we are still in the process of evaluating this new data point of 2.9%. Thank you, Sophie, for your follow-up.

Hi, good morning. Most of my questions have been asked and answered. But I have a question about the timing of the approval for the contracted renewable sale. You submitted the filing on March 22. What gives you confidence that you'll receive approval in Q2? Additionally, what must you demonstrate in those filings to obtain approval from both FERC and 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 a 60-day approval process at FERC. 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 laws. 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.

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?