American Electric Power Company Inc (AEP) — Q3 2021 Transcript

Thank you, Allen. Good morning, everyone, and welcome to the Third Quarter 2021 earnings call for American Electric Power. We appreciate you taking the time to join us today. Our earnings release, presentation slides, and related financial information are available on our website at www.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 Nick Akins, our Chairman, President, and Chief Executive Officer, and Julie Sloat, our Chief Financial Officer. We will take your questions following their remarks. I will now turn the call over to Nick.

Okay. Thanks, Darcy. Welcome again, everyone to American Electric Power's third quarter 2021 earnings call. Today we're pleased to report a strong third quarter operating earnings of $1.43 per share for the third quarter. This brings our year-to-date operating earnings to $3.76 per share versus $3.56 per share last year, which gives us confidence in raising the midpoint of our guidance range for 2021. AEP service territory continues to provide us with resiliency and stability with continued economic recovery experienced in the third quarter. In fact, AEP posted the strongest sales quarter in over a decade, and the gross regional product for the AEP footprint of the third quarter was the highest on record, as well as job growth being the strongest since 1984. The strength and diversity of our portfolio, the robustness of our organic growth opportunities, and our consistent ability to execute against our plan places AEP among what we believe should be one of the country's premium regulated utilities. Our strong performance this quarter, coupled with the level of economic recovery experienced within our footprint, provides us, once again, the confidence needed to raise our midpoint to $4.70 per share and narrow the 2021 guidance range to $4.65 to $4.75 while reaffirming our 5% to 7% long-term earnings growth rate. And as I've stated previously, I would still be disappointed if we were not in that upper half of our long-term growth rate. The driver of our strong performance is the talent and commitment of our employees. Our front line of central service work teams has continued to adapt to ensure the needs of our customers and communities are met day in and day out throughout the pandemic. Like many industries, the face of work for AEP will never be the same. As employees return to the office, we have taken actions to ensure the safe return to the workplace environment. I remain appreciative of the dedication of our employees and have the utmost confidence in their continuing ability to successfully check and adjust as we adapt to the future. We believe that this new work environment will continue to enable more efficiency, flexibility, and creativity that will contribute to the culture to excel in meeting our strategic objectives. This new future of work, along with digitization and automation, will continue to provide benefits for our Achieving Excellence program. Our growth opportunities over the next decade are significant, driven by our future forward renewables plan, that includes over 16 gigawatts of new renewable resources by 2030, and the transmission distribution investments needed to support the needs of a clean energy economy for our customers and communities. Additionally, the completion of a strategic review of our Kentucky Companies and our decision to move forward with the sale of our utilities enables us to focus our attention on executing that transaction and delivering on our growth strategy. So, let's cover the announced sale of Kentucky Power. Earlier this week, on Tuesday at market close, we announced the sale of Kentucky Power and Kentucky Transco to Liberty Utilities, the regulated utility operation of Algonquin Power. The sale was a result of the strategic review that we launched back in April. The sale is subject to regulatory approvals, including approvals from the Federal Energy Regulatory Commission within 180 days, and the Kentucky Public Service Commission within 120 days. The transaction is also subject to federal clearance pursuant to Hart-Scott-Rodino, which typically is within 30 to 60 days, and clearance from the Committee on Foreign Investment in the U.S. within 90 and 120 days for that approval. We anticipate making these regulatory filings in late November and early December. Separately, we will file with both the Kentucky and West Virginia commissions with necessary changes to the metro plant operating agreement to accommodate the ELG investments recently approved by the West Virginia Commission. The following will include a plan to resolve the question of Mitchell ownership post-2028. Both state commissions are expecting these filings as both issued recent orders directing us to do so. These filings will be made in the mid to late November timeframe. We're also very pleased with the outcome of the strategic review and know that the future owner of our Kentucky assets will be a great steward for all stakeholders in Kentucky, our valued employees, customers, and certainly the communities. Lastly, I want to thank all the Kentucky employees and the corporate support employees for their patience during this review and for their continued focus on safety and operational excellence during this period and as the transaction is completed. Now, moving to several of the regulatory activities. In Ohio, we expect an order in the fourth quarter on the settlement reached and filed with the Commission earlier this year. As a reminder, the settlement has broad support from the settling parties, including the commission staff, Ohio consumers’ counsel, industrial companies, commercial companies, and other entities like the Ohio Hospital Association. Additionally, AEP Ohio's grid smart Phase III settlement was filed yesterday and paves the way to continue our deployment of advanced smart grid technologies, including completion of our AMR meter rollout, the remaining 475,000 rollout customers. The unopposed settlement with support from commission staff allows consumer's counsel and several of our largest customers demonstrates that AEP Ohio continues to maintain a great working relationship with our regulator and interested parties. Public Service Company of Oklahoma reached a settlement in the rate case with the Oklahoma staff and other parties. The settlement was presented to the commission on October 5th. The black-box settlement includes a $50.7 million net increase in rates while adding another $102.7 million in base rates. In addition to continuing the practice of allowing some interim recovery of CapEx riders, the rider collecting for Maverick and Sundance North-Central wind assets was also included, with orders expected by year-end with rates reflected in November bills. In Indiana, the unfollowed base rate case on July 1st is based on a future test year model seeking a $97 million net revenue increase with a 10% ROE. Major items included recognition of over $500 million in capital investment per year in Indiana continuation of the transmission tracker, a federal tax rider in the event of a change in federal tax rates, and the advancement of AMI to provide customers greater control insights into their usage. The hearing was set before the Indiana Utility Regulatory Commission on December 2nd, with an order expected by April of '22. In Southwestern Electric Power Company's jurisdictions, cases are pending in Louisiana, Texas, and Arkansas. The SWEPCO Texas Commission deliberations are set for November 18th. Parties filed exceptions to the preliminary draft order issued by the hearing and replies. So those exceptions were filed yesterday. SWEPCO is seeking a $73 million net revenue increase with a 10.35% ROE. Our file includes investments made from February 2018, accelerated depreciation for plant, strong reserves, and increased vegetation management. We expect an order in the fourth quarter with rates being retroactive back to March of '21. In SWEPCO Louisiana, testimony has been filed, and a hearing is scheduled for January of '22. The case involves a $6 million to $73 million net revenue increase with a 10.35% ROE, with an order expected between the second and third quarter of '22. In Arkansas, we are seeking a $56 million net revenue increase with a 10.35 ROE. The following contains a formula rate plan for subsequent years and considers the pending retirement of previously announced coal net assets. This fall, we used time to align with the North-Central in-service dates and provided a mechanism for both recovery of costs associated with the investment and flow-through of the PTC for SWEPCO customers. The hearing is set for March of '22. Both SWEPCO and PSO continue to make progress to recognize the Storm Uri expenditures. As a reminder, we filed for recovery of a lack returned over 5 years in Louisiana, Arkansas, Oklahoma, and Texas. PSO is moving forward with the state on the securitization of costs as per Oklahoma law. We are continuing our efforts to secure approvals and clarity regarding investments necessary to meet the EPA, CCR, and ELG requirements. We received approval to construct the CCR compliance plans in Virginia, West Virginia, and Kentucky. While West Virginia approved ELG investments, Virginia, and Kentucky did not. West Virginia has since determined it was in the public interest to move forward with ELG investments for all three plants and has issued an order regarding West Virginia investing to preserve the option for these plants to run past 2028, approving both the investment and cost recovery from West Virginia customers. We'll be working with our commissions to implement the West Virginia decision and making the necessary adjustments to respect each state's decision. The Virginia Commission asked us to come back with more information, so we'll do that. We plan to lay out all the options before them on how to satisfy their capacity needs. The Virginia PSC approved the first-year revenue requirement of $4.8 million for broadband, which means we now have recovery for our broadband efforts in both Virginia and West Virginia. We continue to engage legislators and commissions in other states and stand ready to invest in synergistic mid-model broadband to support advanced grid technologies and rural broadband for our communities. We also understand, it's all about execution. On September 10th, AEP began commercial operation of the 287-megawatt Maverick Wind Energy Center in North Central Oklahoma. Maverick was one of three wind projects that composed the North Central energy facilities, which will provide 1,485 megawatts of clean energy to customers of our PSO and SWEPCO subsidiaries. The Traverse project, the largest single-site wind farm in North America, is well under construction and will come online in the January to April 2022 timeframe. Transforming the way energy is generated, delivered, and consumed is necessary to support the needs of a clean energy economy, and AEP continues to drive that transformation for the benefit of our customers and communities. With the success of our wind projects setting the foundation for our future regulated renewables platform, we are diligently working on securing additional renewable opportunities for our customers. RFP filings are ongoing and planned in multiple states. So more to come on this as we file for approval after resources; as a result of the RFP that were out in the market for which some of you probably have heard, we will be able to provide greater detail on the progress being made. Further, if federal efforts through various tax proposals to extend and expand PTCs and ITCs for Clean Energy Resources succeed, even more benefits will be enjoyed by our customers. So now, we move quickly to the equalizer chart at this point, and I'll go quickly through this. So far, the average with the overall regulated operations is currently at 9%. We generally target in the 9.5% to 10% range. So obviously, we continue to work on that. AEP Ohio came in at 9.3% for the third quarter, as below authorized primarily due to the timely recovery of capital investments, partially offset by higher O&M expenses. We expect that ROE to trend around authorized levels as we maintain concurrent capital recovery of distribution and transmission investments. We also, as I mentioned earlier, expect the commission order here in the fourth quarter of '21. AEP came in at 7.3%, as below authorized due to higher amortization, primarily related to what's hard coal-fired generating assets, and higher depreciation from increased Virginia depreciation rates and capital investment. And as you know, we are still at the Appeals Court appealing the Virginia Supreme Court, which is currently outstanding. We filed an appeal with that Virginia Supreme Court, so we're still waiting on that. As far as Kentucky is concerned, it came in at 6.9%, below authorized due to loss of load from weak economic conditions and loss of major customers. Transmission revenues were also lower due to the delay in some capital projects. I&M came in at 10.3%, exceeding authorized ROE primarily due to an increase in sales, partially offset by increased O&M and depreciation expenses associated with items in continued capital investment programs. As far as PSO is concerned, it came in at 7.6%, below its authorized level primarily due to increased capital investment currently not in base rates and higher than anticipated equity due to the extreme February winter weather event. And of course, we expect the commission order here on the rate case in the fourth quarter of '21. SWEPCO came in at 8.2%, as below authorized due to increased capital investment currently not in base rates and the continued impact of the Arkansas share of the Turk plant that is not in retail rates. The Turk plant again accounts for about 110 basis points that we're not recovering in Arkansas. Again, as I mentioned earlier, we expect various commission orders, particularly in Texas, in the fourth quarter of 2021, retroactive back to March. AEP Texas came in at 8.2%, as below authorized primarily due to the significant level of investment in Texas. And of course, we have favorable regulatory treatment there with that annual DCOS and bi-annual TCOS filings to recover rates. Significant levels of investment in Texas will continue to impact the ROE. But the expectation is for the ROE to trend towards an authorized 9.4% in the longer term. AEP Transmission Holdco came in at 11.2%. It was above authorized primarily driven by differences between actual and forecasted expenses. The transfer will benefit from a forward-looking formula rate mechanism, which helps minimize regulatory lag. The forecasted dollar rate is around 11% in 2021. So overall, we continue to make progress. Cases, obviously, we're waiting to hear the results of several cases that should provide some additional benefits, but that work continues. So, in closing, we are executing all and continue to drive the results expected of a premium regulated utility. The AEP portfolio is one that has enabled our investments in the wires side of the business supporting our transmission investments, including the $0.33 per share this quarter, through our AEP Transmission Holdco investments. Our plan to transition our generation fleet and reduce carbon emissions by 80% by 2030 and net zero by 2050 is well underway, with 2 of our 3 wind facilities of our $2 billion investment in North-Central land under our belt, providing a solid foundation for the next decade of growth. Throughout this transition, we remain engaged as a trusted voice on energy transformation efforts, helping to ensure a responsible transition to a clean energy economy. And we will continue to support federal efforts in that regard and state efforts as well. Finally, our strong quarter performance gives us the confidence again to set our midpoint at $4.70, or the range of $4.65 to $4.75. We continue to have all 17,000 employees dedicated to our customers and communities to enable the strong performance. Our discipline and controlling costs, our progress to manage the portfolio, and the significance of our future organic growth opportunities provide us with the confidence needed to raise the midpoint and near the guidance range. Two weeks ago, I was really struck by the halftime performance of the Ohio State Buckeyes marching band. They set their goals, in my opinion, really high. Never did I expect to see a marching band dedicate their halftime show to the music of Rush, to hear Tom Sawyer, Limelight, and others was truly amazing, considering it was difficult to even play. Even though they were also marching while designing guitar players, drones, and other choreography on the field, the creativity and the execution came through to deliver a truly remarkable show. It made me think of our team at AEP. On November 11th, I've been AEP CEO for 10 years, and I'm fortunate to lead a great company with great people who have an outstanding track record of delivering on the promises made to investors and customers consistently year in and year out. And we fully expect to continue our drive to take this company to the next level toward the clean energy economy and a solid infrastructure foundation, setting aggressive goals and delivering with creativity and solid execution. With that, I will turn it over to Julie.

Thanks so much, Nick. Thanks, Darcy. And Nick, I love your Buckeye reference. Go Bucks. Thank you very much. Big game this weekend. Anyway, it's good to be with everybody this morning. I'm going to walk us through the third quarter and year-to-date financial results. I'll share some updates on our service territory load, and finish with some commentary on financing plans, credit metrics, and liquidity. Let's go to slide six, which shows the comparison of GAAP top rating earnings for the quarter and year-to-date periods. GAAP earnings for the third quarter were $1.59 per share, compared to $1.51 per share in 2020. GAAP earnings through September were $3.90 per share compared to $3.56 per share in 2020. There's a reconciliation of GAAP to operating earnings on Pages 14 and 15 of the presentation today. Let's go to Slide 7 where we can talk about our quarterly operating earnings performance by segment. Operating earnings for the third quarter totaled $1.43 per share or $717 million, compared to $1.47 per share or $728 million in 2020. Operating earnings from the vertically integrated utilities were $0.87 per share, up $0.02. Favorable drivers included rate changes across multiple jurisdictions, weather primarily in the West, transmission revenue, and lower income tax. These items were offset somewhat by higher O&M expenses, partly due to lower prior year O&M, which included actions we took to adjust to the pandemic, and higher depreciation expense, as well as lower normalized margins and lower AFUDC. The Transmission and Distribution Utilities segment earned $0.31 per share, flat to last year. Favorable drivers in this segment included rate changes, transmission revenue, and income taxes. Offsetting these favorable items were O&M expenses again, a function of lower prior year O&M associated with pandemic-related efforts, depreciation, and property taxes. The AEP Transmission Holdco segment continued to grow, contributing $0.33 per share, an improvement of $0.05, driven by the return-on-investment growth. Generation and Marketing produced $0.04 per share, down $0.09 from last year, impacted by the prior-year land sales, lower retail volumes and margins, generation, and income taxes. Finally, Corporate and other was down $0.02 per share driven by lower investment gains and unfavorable net interest expense, which was partially offset by lower income taxes. The lower investment gains are related to a pullback of some of the ChargePoint related gains we've talked about in prior quarters. Let's have a look at our year-to-date results on slide number 8. Operating earnings through September totaled $3.76 per share or $1.9 billion compared to $3.56 per share or $1.8 billion in 2020. Looking at the drivers by segment, operating earnings for vertically integrated utilities were $1.87 per share, down $0.03 due to higher O&M and depreciation expenses. Other smaller decreases included lower normalized sales and wholesale load, higher other taxes, and a prior period fuel adjustment. Offsetting these unfavorable variances were rate changes across various operating companies and the impact of weather due to warmer than normal temperatures in the winter of 2020 and summer of 2021, which created a favorable year-over-year comparison for us. Other favorable items in this segment included higher off-system sales, transmission revenue, reduced interest expense, and income taxes. The transmission and distribution utilities segment earned $0.85 per share, up a penny from last year. Earnings in this segment were up due to higher transmission revenue, rate changes, weather, normalized load, and income taxes. Partially offsetting these favorable items were increased depreciation, O&M, other taxes, and interest expenses. The AEP Transmission Holdco segment contributed $1.02 per share, up $0.27 from last year related to investment growth and favorable year-over-year true-up. Generation and Marketing produced $0.20 per share, down $0.11 from last year due to favorable one-time items in the prior year relating to an Oklaunion ARO adjustment, the sale of Conesville, and reduced land sales in 2021. Higher energy margins and lower expenses in the generation business offset the unfavorable marketplaces on the wholesale business during storm yearly in February. We also saw an unfavorable result in retail due to lower power and gas margins. Income taxes were also unfavorable. Finally, Corporate matters were up $0.06 per share driven by investment gains and lower taxes, partially offset by higher O&M. Let me take a quick minute here to talk about the investment gain, which is predominantly a function of our direct and indirect investment in ChargePoint. As you'll see on the waterfall, it produced a $0.06 benefit year-to-date in 2021, as compared to the corresponding 2020 period. You may recall that in the fourth quarter at full-year 2020, this investment produced a $0.05 contribution, and we would expect the year-over-year bids to be more pronounced at this point in 2021, as we have no benefit during the same period in 2020. Turning to Page 9, I'll update you on our normalized load performance for the quarter. Everything you see on the slide is showing year-over-year growth. That means these numbers can be influenced by what was going on last year or what is happening now in 2021. Given all that occurred in the economy last year, it's obvious that these growth rates are at least partially being influenced by the comparison basis. This leads to the natural follow-up question like, how does today's load compare to pre-pandemic levels? And I'll get to that question on the next slide. But before I do, let's take a look at what our normalized load growth was for the quarter. Starting in the upper left corner, normalized residential sales were down 1.6% compared to last year, bringing the year-to-date decline down to 9/10 of a percent. That means that last year, residential sales were up 3.8% in the third quarter when the economy was just starting to reopen. One year later, they're down only 1.6%, which suggests there has been a shift up in residential sales, as more businesses have embraced a remote workforce for jobs that can be performed at home. The last item to point out on residential charges is that you'll notice we added a new bar to the right, showing our latest projection for 2021 based on the load forecast update. The original guidance assumed residential sales would decrease by 1.1% in 2021. The latest update showed an improvement as we now expect residential to end the year down 9/10 of a percent. Moving right, weather-normalized commercial sales increased by 5%, bringing the year-to-date growth up to 4.3%. Last year's third quarter commercial sales were down 4.6%. So again, we're seeing a net positive story for commercial sales classes bouncing back faster than expected. While we're seeing a strong bounce-back in the sectors most impacted by the pandemic such as schools, churches, and hotels, we're actually seeing the strongest growth in commercial sales this year from growth in data centers, especially in Central Ohio. To give you some perspective, last year, the sector was the 9th largest commercial sector across the AEP system. Today, it's the 6th largest and will likely move further up in the rankings as more data center loads are expected to come online over the next several years. You'll also notice that our latest load forecast update now suggests that commercial sales will end the year up 3.7% as opposed to the 0.5% decline assumed in the original guidance forecast. The economy has recovered much faster than we originally assumed, which is one of the reasons why we've updated the forecast and ensured an improvement in that regard. In the lower left corner, you'll see that industrial sales also had a very strong quarter. Industrial sales for the quarter increased by 7%, bringing the year-to-date up to 4.2%. Industrial sales were up at every operating company in nearly every sector. I point out, however, that the 7% growth in the third quarter this year did not quite offset the 7.8% decline experienced last year, which means we still have a little more room to grow before the industrial class fully recovers from the pandemic recession. The good news is we have a lot of momentum to work with. The latest load update now projects industrial sales will end the year up 4.3%, which is 2.4% higher than assumed in the original guidance forecast. Finally, when you put it all together in the lower left corner, you'll see that normalized retail sales increased by 3% for the quarter and were up 2.3% for the first nine months. But all indications suggest that recovery from the pandemic and recession is happening faster than expected, and our service territory is well positioned to benefit from future economic growth. You'll recall that the original guidance forecast assumed normalized load growth of 2/10 of a percent in 2021. Based on our latest update, we're now expecting to end the year up 2.2%, which is a supporting factor in narrowing our earnings guidance range and raising the midpoint for 2021. Turning to Slide 10, I want to answer the question from earlier, that asked how our current load performance compares to pre-pandemic levels. This bar chart is designed to answer that question. The blue bars are the same year-to-date bars that we shared on the prior page. As a reminder, these represent growth versus 2020, which was influenced by the restrictions implemented to manage the public health crisis. The orange bars show how the year-to-date sales in 2021 compared to 2019, the most recent pre-pandemic year for comparison. These bars tell us how close we are to a full recovery from the pandemic. Starting at the left, you'll notice that reported residential sales are down 9/10 of a percent compared to last year, but they're actually up 1.6% compared to our pre-pandemic levels. This is a gauge for how our customers' behaviors have changed since the pandemic, with more people working from home. The next bar shows that while commercial sales are up 4.3% compared to last year, they are still down 8/10 of a percent from the pre-pandemic levels. Given the recent growth we're seeing, especially in the data center nodes, we would expect commercial sales to fully recover nearly soon. Moving further right, you can notice that while industrial sales were up 4.2% compared to last year, they are still 3% lower than pre-pandemic levels. Given some of the headwinds for manufacturing today with supply chain disruptions, labor shortages, et cetera, it may take a little longer before the industrial class fully recovers from the pandemic recession. But we do expect to eclipse the pre-pandemic levels in 2022. In total, our normalized load is up 2.3% compared to last year and is now within 7/10 of a percent of being fully recovered from the pandemic, so it's safe to say that we're pleased with the strength and balance of this recovery in the AEP system. Let's check on the Company's capitalization and liquidity on Page 11. On a GAAP basis, our debt-to-capital ratio decreased by 0.4% from the prior quarter to 62.2%. When adjusted for the storm-related event, the ratio is slightly lower than it was at year-end 2020, and now stands at 61.5%. Let's talk about our FFO to debt metric, as in the first and second quarter. Effective storm yearly continues to have a temporary and noticeable impact on this 2021 metric. Taking a look at the upper right quadrant on this page, you'll see our FFO-to-debt metrics based on traditional Moody's and GAAP calculated basis, as well as an adjusted Moody's and GAAP calculated basis. On a traditional unadjusted basis, our FFO-to-debt ratio increased by 0.9% during the quarter to 10.2% on a Moody's basis. And just reiterate, rating agencies continue to take the anticipated recovery into consideration as it relates to our credit ratings. So that's very important to note. On an adjusted basis, the Moody's FFO-to-debt metric is 13.6%. This figure removes or adjusts the calculation to eliminate the impact of approximately $1.2 billion of cash outflows associated with covering the unplanned winter-driven fuel and purchase power in the SPP region, directly impacting PSO and SWEPCO in particular. The metric is also adjusted to remove the effect of the associated debt we used to fund the unplanned payments. This should give you a sense of where we would be from a business-as-usual perspective with that 13.6%. Importantly, as Nick mentioned, the recovery of the fuel and purchase power expense in the PSO and SWEPCO jurisdictions is well underway and we're making progress. As a result, inconsistent with what we have previously communicated, we still anticipate our cash flow metrics to return to below the mid-teens target range next year. Obviously, we are trying to push towards the mid-teens range, but that will take us a little while longer, but we're definitely on our way there. And as you know, we'll keep you posted on our progress. Before we leave the balance sheet topic, I do want to make note of the intended change to our 2022 financing plan in light of our announced sale of Kentucky Power and Kentucky Transco. You may recall that we had planned to issue $1.4 billion of equity in 2022, inclusive of a $100 million dividend reinvestment plan to fund our growth CapEx program, where we will provide our typical 3-year forward annual review of our cash flows and financial metrics at the upcoming EEI Conference. What we can expect to see is that the 2022 forecast will be adjusted to eliminate the previously planned $1.4 billion of equity financing that I just mentioned, with any residual proceeds being used to reduce a small portion of the 2022 debt financing that we had planned. These actions will have no impact on our previously stated credit metric targets or messaging in that regard. On the slide deck today, on page 39, you'll see our current cash flow forecast, which you are already familiar with. We've included a note on the side to reflect the fact that the numbers have not been updated for the announced Kentucky transaction, along with the red circle around the 2022 financing-equity financing amount that will be changed and updated when we roll out the new view in a couple of weeks in conjunction with the EEI conference. So, while we're talking about the Kentucky transaction, I can also share that we expect the sale will be $0.01 to $0.02 accretive in 2022, and we will reflect this in our 2022 earnings guidance that we provide to you at the EEI Conference. Okay. So back to our regularly-scheduled earnings call programming and commentary. Let's take a quick moment to visit our liquidity summary on the lower right side of Slide 11. Our 5-year $4 billion bank revolver and 2-year $1 billion revolving credit facility, along with proceeds from the quarter-end debt issuance, support our liquidity position, which means we were strong at $5.1 billion. If you look at the lower left side of the page, you will see that our qualified pension continues to be well funded at 104%. Additionally, our OPEB is funded at 173.9%. Let's go to Slide 12 and I'll do a quick wrap-up and we can get to your questions. Our performance through the first three quarters of this year gives us confidence to narrow our operating guidance to the upper half of our current range, resulting in the new range of $4.65 per share to $4.75 per share with a midpoint of $4.70 per share. As we stated, we are committed to our long-term growth rate target of 5% to 7%. Today's 2021 earnings guidance revision is yet another demonstration of our drive to deliver performance in the upper half of our guidance range. From a strategic perspective, we're making significant progress in addressing items that are top of mind for our current and prospective investors. We're mounting a contract to sell Kentucky Power and Kentucky Transco, which we expect to complete in the second quarter of 2022. This transaction enables us to avoid the $1.4 billion equity issuance that was part of our original forecast, which we will share with you for 2022. Therefore, it alleviates the equity overhang. Additionally, this allows us to deliver a transaction that we estimate will be $0.01 to $0.02 accretive in 2022. We will be more able to do this while concurrently preserving our ability to get our FFO to debt metrics comfortably into that mid to low teens range by 2022, which aligns with maintaining a Baa2 rating stabilization as we continue to target that. The intention is to remain in this credit metric range. Again, with a preference to try to get closer to that midpoint as we move along in time. All of this positions us to continue our generation transformation, which is underpinned by the renewable investment opportunity we have shared with you and complemented by our ongoing energy delivery investment. So here you can expect to see from us at the upcoming EEI Conference in early November. In addition to the updated 3-year forward cash flow and financing plan, we'll be introducing and sharing the details behind our 2022 Earnings Guidance and our longer-term capital plan, which we typically roll out for 5 years, all of which will incorporate the effects of the announced Kentucky sales. So, with that, we do appreciate your time and attention and I'm going to turn it over to the operator so we can get to your questions.

Thank you. Can you hear me now?

Hey, you doing and how you?

Hey, quite well. Thank you. Congratulations on the transaction there. Nicely done.

Yeah, I’m thanks.

Absolutely. So perhaps just to dive into that one a little bit more, can you talk about what happens with the Mitchell plant here, just as a function of the sale? Will it get transferred to Wheeling? How are you thinking about that vis-a-vis Liberty and any kind of pricing there, and in terms of transfer, what have you?

Yes, the operating agreement is being adhered to. Wheeling will take on the role of operator, with the transfer occurring in 2028. Until then, Kentucky will remain a half-owner of the Mitchell plant. Once Wheeling assumes operations, the employees will also transition to Wheeling. We will continue to work with the West Virginia and Kentucky commissions to address the operating agreement and related matters. At the end of 2028, it will be transferred at fair market value. This plan will be implemented in the November and December timeframe, and we will navigate through it. Both commissions have a vested interest in resolving this matter due to differing perspectives on the ELG aspect. Regardless of this transaction, we must adhere to the operating agreement modifications because of the divergent paths taken by the commissions. We will resolve this as part of the overall approval process.

Excellent, well said. Fair market value it is. In terms of ongoing transactions and portfolio evaluation in the near term, how do you approach the continued evaluation of the portfolio? It's not necessarily an immediate concern, but I want to give you the chance to elaborate on that a bit more.

Yes, I have mentioned repeatedly, for quite some time now, that we need to focus on portfolio management to better understand our capital needs and manage our balance sheet, as Julie highlighted. We are aiming for mid-teens returns and are on track to achieve that while also funding our growth strategy. We've divested from several assets, including unregulated generation and some hydro facilities, totaling about $6 billion, which have significantly contributed to our growth—around $7 billion a year in capital investments. It’s crucial for us to assess what our portfolio should look like in the future, and we will consistently work on this. Chuck, Julie, and the team will keep analyzing our portfolio to ensure it's managed effectively. For example, concerning Kentucky Power, we have shifted our investment strategy away from solely focusing on coal units. This change marks a pivotal moment for AEP as we evolve into a fully regulated entity and begin to explore the best strategies for investing $20 billion in potential renewables. It's important to reflect on our history, noting that the last time we sold a regulated utility was the Scranton system back in the 1940s and 50s, illustrating the significant shift we are undergoing. Kentucky Power itself was part of the original acquisition by American Gas and Electric in 1922, marking almost a century since then. This transformation in our portfolio management underscores our commitment to handling our assets responsibly. I realize this is a more detailed response than you might have expected, but I felt it was important to share.

Very much appreciate it. I'll leave it there. Speak with you guys soon.

Okay.

Good morning, Shahriar.

Good morning, guys, and congrats on Kentucky.

Yes.

Just a follow-up on Julien's question a little bit more. As we think about trigger points for another asset sale, what's kind of a catalyst? Because the 10 gigawatts of solar and wind that you're looking to build through '25, I mean, even if you assume a 50-50 PPA structure, could yield an incremental $3 billion rate of spending opportunities. And you obviously have a slope of IRP. So, do you need to see affirmations with the various filings or actual approvals in GRC? So how should we think about how these could be funded, especially in light of where the stock trades?

When you think about the way we're approaching the renewables fees, the process has been that we term the need for equity associated with those particular investments when they actually come online and we get regulated recovery. So, we get the cash flow to support those investments at the time they come online. That means, obviously our FFO to debt doesn't suffer as a result of that. So, if we continue that approach, and keep in mind too, I've always said that for us to take a look at a regulated entity or other parts of our portfolio doesn't match the future needs in terms of where we are and where we're going as a company. If we have a chronically under-performing part of the portfolio, then it's important for us to take a look at it. That may be temporary; it could be long-term, but certainly we have to make sure that we're evaluating each one of these assets in a way that considers their locational and financial perspectives, as long as we're getting the return expectation and also that the forward view of the utility is positive compared to others. So, we have to compare in various parts of our service territories, and that's where we make those decisions.

Perfect. And then just Nick, appreciate we're going to head into EEI. We'll get an update here. But do you see the current renewable additions, at least through '25, the 10 gigawatts, right, between solar and wind swinging materially with some of these counteractive items like federal policy benefits versus the input cost pressures we're seeing in the space impacting some project timings? So, do you see any of this swinging at all?

Yes, I do. When we conduct the analysis, we've looked into all jurisdictions. However, conditions have changed, including load changes and the potential impact of PTCs and ITCs, which can alter the business cases. For some projects that were previously on the margins, especially in the east, they may now offer benefits to customers. I believe these numbers will continue to fluctuate. From what I've observed so far, some will increase and some will decrease. Generally, they should align with what we've discussed. We expect to provide more detailed information during the first quarter of 2022 when the integrated resource plans are filed. At that time, you'll have a clearer understanding of what these projects entail, including the outcomes of RFPs and the status of projects seeking regulatory approval. While there will be more clarity, I can confidently say that they will mostly fall within the categories we've mentioned.

And sure, what you should anticipate is when we go to EEI, you'll see a refreshed 5-year forward CapEx plan, so '22 through '26, and you'll start to begin to see a little bit more of this renewable opportunity drop in. So, stay tuned for that, and we'll be able to talk more granularly with you here in a couple of weeks.

Yeah. And I would say that when you see that, it certainly will reflect, I don't know if you call it a risk-adjusted approach or whatever, but it's a nominal view for us to make financing plans, and then just like with North Central, we make decisions on whether it goes up or down based upon our ownership.

Got it. Cheers to you guys. Congrats on the results. See you soon.

Thank you.

Hey, good morning. Can you hear me, Nick?

Yes. Yes. I hear you.

Okay, great. Thanks. Okay. One question that might be a bit premature, but there's obviously a lot going on in DC with the reconciliation bill and the like, and one of the provisions that's gotten more focused on these few days is the minimum tax provision. And I just be curious how you're thinking if that has any impact for larger companies like yourself or does it not really have much of an impact?

I would say that we've been quite clear about this issue, as has the industry. Implementing a minimum 15% tax will significantly affect companies like ours that are heavily invested in capital, particularly growth and infrastructure capital. This tax increase would have a cascading impact on our ability to develop infrastructure and could ultimately raise costs for our customers, as these taxes would be transferred to them. Additionally, the administration's focus on green energy will impact the ongoing transformation towards renewables. This situation could restrict utilities like us from making necessary capital investments, which would also affect our customers. We're firmly against this provision, and we have actively advocated for change while emphasizing the importance of transitioning to clean energy. The availability of Production Tax Credits and Investment Tax Credits, along with advancements in long-term storage, nuclear, wind, and solar energy, is crucial to making this transition successful. The industry remains dedicated to this goal, and any tax barriers in the opposite direction are detrimental. I believe this sentiment is likely to be echoed throughout the industry.

Okay. More to direct AEP things. Just on the approval for the Kentucky sale, could you remind us what the standard for approval is in Kentucky? Is it just in the public interest or that benefits?

Yes, it's in the public interest. They need to evaluate the potential buyer and decide if that approach is appropriate. Because of previous discussions in Kentucky, it's clear that we need to make sure we are operating in Kentucky correctly. We've maintained our operations as usual and continued to invest in the region, regardless of ownership. The buyer has acknowledged this, and during the transition, we will ensure a smooth process to support Kentucky Power's success. We will also assist Liberty Utilities and Algonquin in this effort.

Great. And then one just quick question, maybe for Julie. The proceeds from the Kentucky sale look like they're matching up one for one with reducing the equity need. But obviously when you sell an asset, you lose some cash flow, albeit Kentucky may not have been having the best cash flow. So, are there offsets in other businesses that are making up for the lost cash flow from the asset sale?

Yes, thanks for the question, Steve. You're right. I mean, we do lose the funds from operations that relate to Kentucky and Kentucky Transco. Although, we got to keep in mind that we also eliminate about $1.3 billion of debt associated with those assets because that goes away. And the marathon that we think through, just to take it a step further, is if we avoid issuing equity, we avoid having to cover off additional dividends that were in our original plan. So, another to sidestep that as well. And that comes with maybe also having some additional dollars to reduce debt. As I mentioned in my opening comments, anything above and beyond that $1.4 billion which channel toward debt reduction that was otherwise planned for 2022. And then also, keep in mind that Kentucky Power had barely strained FFO-to-debt to begin with. So, to eliminate that piece of, I guess, drag to the overall average FFO-to-debt for their organization is also a net positive for us. So, we are able to put these numbers together. And quite frankly, from an FFO-to-debt perspective, it is mildly beneficial and obviously a little bit of a cost on the debt-to-cap because we're not issuing additional equity. But the numbers all do hang together, and coincidentally, we'll be able to take literally that $1.4 billion of planned equity out of the plan, and again, you'll see that at EEI when we'll refresh the forecast.

Great. Thanks so much.

Thanks, Steve.

Morning, Durgesh.

Hey, good morning, Nick. Maybe just along the FFO-to-debt lines, my first question is to Julie. In terms of 2024, I'm thinking about your equity needs in my model shift used to target for FFO to debt. Actually, is it mid-teens or is it low to your? Because, obviously, that's going to dictate how much equity you might need in 2024. So, any color you could share there?

Got you. You'll see 2024 when we rollout our EEI guidance, so 3 years forward. But, as we continue to say, we are talking about mid to low teens. And the reason I say that is, as I mentioned today, if you look at our FFO to debt on an adjusted basis, so backing out the yearly consequence, we have something like 13.6% on a Moody's basis. As you know, our target has been to be around that Baa2 stable rating. That's why we talk about mid to low teens or low to mid-teens. Obviously, our preference and our expectation are to start to push more towards what I would characterize as mid. It'd be nice to have at least a 14 handle on that FFO to debt, and that is absolutely the plan, but we'll be able to share more with you as we get to EEI and build that forecast. But I wouldn't change how you're thinking about it. So, thinking about mid to low teens as it relates to Moody's BAAT, with a preference toward 14 plus percent.

Got it. So, some of that moment to low teens through 2024, yeah. A big picture question, we've talked in depth about natural gas prices. So maybe just talk about your gas generation portfolio, fuel costs, any hedges impacting customer bills?

I will approach this from the perspective of customer rates, as that's how we view the situation. Ultimately, it affects our customers. For instance, if we conduct a sensitivity analysis around a 10% increase in natural gas prices, which have risen significantly, the effect on customer rates varies greatly between operating companies due to differences in fuel mix. For example, Appalachian Power Company's average residential impact from a 10% rise in gas prices would lead to approximately a 0.9% increase in customer rates. In contrast, for companies like PSO or SWEPCO, which have a higher concentration of gas, the increases would be 1.6% and 1.5% respectively. We are very aware of these figures because, overall, we are acutely sensitive to the impact of increased rates on our customers as we continue to pursue our general capital expenditure program. I'm not sure, Nick, if you have any further comments.

I believe your question highlights the importance of our shift towards renewables, as they serve as a strong alternative to natural gas. During Storm Yuri, this switch could have saved customers $225 million. While natural gas is important, incorporating renewables can provide substantial benefits to consumers. This winter will likely demonstrate that advantage.

Understood. Thanks, guys. I appreciate the time.

Thank you.

Good morning, Andrew.

Hey, good morning. Thanks for a lot of good updates here. One remaining question I had was after a few rate case settlements and expectations for several other outstanding cases to be resolved in the coming months. Can you share your expectations around which sub we might file new rate cases over the next 12 months or so?

We are considering various factors regarding ongoing cases and anticipate approvals for some of them. We're continuously reviewing our situation across different jurisdictions. We still have active cases that need to be finalized, after which we can assess our status. Another aspect to consider is how changes in demand will impact our decisions, especially as we transition towards a post-COVID environment. These changes could influence when we file new cases. Additionally, if there are any tax changes, they could significantly alter our approach to these cases, similar to how tax reform affected us previously, potentially in a more favorable manner this time.

Okay, great. So, would it be fair to say that '22, at least the second half of '22, might be a quieter year as far as the regulatory calendar than what we currently have?

Probably quieter in terms of filings but probably noisy in terms of results.

All right. Thank you very much.

My name. I'm fine. It was a tough year for you with your goals this year. There's been a lot of change. I have a couple of questions for you. Regarding the Kentucky sale and your slide number five, it mentions that over the years you've detailed the challenges in obtaining authorization in Kentucky. Now that Kentucky will be off your plate, when you evaluate other jurisdictions, which ones are still difficult for you to gain authorization? What are the structural changes you're aiming for, whether it concerns legislation? We've seen many utilities in states like North Carolina, Kansas, and Missouri make structural changes through legislation. What additional structural changes will you pursue beyond regular rate case filings to improve authorization in those jurisdictions?

You're witnessing a significant transformation across all remaining operating companies. We have made substantial progress with riders, and we are concentrating on achieving concurrent recovery to enhance cash flow. The delays you are noticing reflect the investments we are making in these companies. As we transition from wire-related activities with riders to renewable energy initiatives, our approach to renewables aligns with the recovery process. Therefore, we expect our returns to align more closely with what has been authorized in the future. We don’t anticipate any major challenges in the jurisdictions we are still involved in, aside from the Turk issue at SWEPCO. It is worth noting that regarding Arkansas, our inability to recover the Arkansas portion of the Turk is not due to the commission but rather a decision from the Supreme Court of Arkansas. We maintain strong relationships with the commissions in every jurisdiction and believe the fundamentals support ongoing improvement with respect to the regulatory lag. Furthermore, as we invest in various sectors and our generation shifts more towards renewables, each investment enhances the FFO-to-debt ratio and improves returns for the companies. I am quite optimistic that we will continue to make progress across all these jurisdictions.

Got it. Just a quick follow-up, I'm curious about your multi-year guidance growth rate and the emphasis on wanting to be at the high end. Outside of the transmission segment, what does that imply for the earned return on equity for the rest of the regulated businesses?

Michael, as Nick mentioned, we aim to be in the upper half of the guidance range, though reaching the upper end would be ideal. Just to clarify, we've been maintaining around a 9% ROE return level, which is a safe assumption for the near future until we gain more traction. Returning to your initial question, regarding the equalizer chart, we often receive inquiries about AEP taxes and their relation to authorized levels. In terms of growth and business management, AEP Texas continues to see significant annual capital investments. We have effective rate recovery mechanisms in place, and while the ROE may seem slightly lower compared to the authorized level, the company is still delivering earnings growth within the 8% to 10% range. This supports our goal of achieving the upper half of the guidance range. Overall, you can expect our system-wide average ROE to be around 9% and gradually improving over time. Additionally, AEP Texas remains focused on intentional capital investments to benefit customers and grow the business, resulting in dividends of 8% to 10% EPS growth.

We haven't addressed the increase in equity layers, which shows improvement, and we are still investing to stay within the 5% to 7% range, aiming for the upper half. We're managing the funds from operations to debt towards the mid-teens. All of these elements are coming together, and we are optimizing our execution to continue meeting our earnings goals while investing in the right areas to address the regulatory lag.

Got it. Thank you, guys. Much appreciated. Congrats to have Kentucky.

Yeah. Sure thing.

Thanks.

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