American Electric Power Company, Inc.

Ladies and gentlemen, thank you for standing by. Welcome to the American Electric Power third quarter 2021 earnings conference call. At this time, your telephone lines are in a listen-only mode. Later, there will be an opportunity for questions and answers. If you would like to ask a question during the call, please press 1, then 0 on your touchtone phone. You will hear an indication you've been placed into queue, and you may remove yourself from the queue by repeating the 1, then 0 command. If you're on a speakerphone, we ask that you please pick up your handset and to please make certain your phone is unmuted before you press any buttons. And as a reminder, your conference call today is being recorded. I'll now turn the conference call over to your host, Vice President of Investor Relations, Darcy Reese. Go ahead, please.

Thank you, Alan. 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 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 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 are 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's service territory continues to prove its resiliency and stability with continued economic recovery experienced in the third quarter. In fact, AEP posted its strongest sales quarter in over a decade, and the gross regional product for the AEP footprint in 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 AAP 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 experience 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 frontline and central service work teams have 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 AAP 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 that excels 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 of over 16 gigawatts of new renewables resources by 2030, and the transmission and distribution investments needed to support the needs of a clean energy economy for our customers and communities. Additionally, the completion of the strategic review of our Kentucky company's and our decision to move forward with a sale to Liberty 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 is a result of a strategic review that we launched back in April. The sale is subject to regulatory approvals, including approvals from the Federal Energy Regulatory Commission, which is 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 the clearance from the Committee on Foreign Investment in the United States 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, West Virginia, and FERC commissions the necessary changes to the Mitchell-Platt Operating Agreement to accommodate the ELG investments recently approved by the West Virginia Commission. The filing 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, the Ohio's Consumers Council, industrial companies, commercial companies, and other entities like the Ohio Hospital Association. Additionally, AEP Ohio's Grid Smart Phase 3 settlement was filed yesterday and it paves the way to continue our deployment of advanced smart grid technologies, including completion of our AMI meter rollout to the remaining 475,000 rural customers. The unopposed settlement, with support from Commission staff, Ohio's Consumers Council, and several of our largest customers, demonstrates that AP Ohio continues to maintain a great working relationship with our regulator and interested parties. Public Service Company of Oklahoma reached a settlement in a rate case with the Oklahoma staff and other parties. The settlement was presented to the commission on October 5th. The black box settlement includes $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. and the order is expected by year-end with rates reflected in November bills. In Indiana, NEM filed its base rate case on July 1st based on a future test year model seeking $97 million in 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 and insight into their usage. The hearing is set before the Indiana Utility Regulatory Commission on December 2nd with an order expected by April of 2022. In our Southwestern Electric Power Company jurisdictions, cases are pending in Louisiana, Texas, and Arkansas. The SWEPCO Texas Commission deliberation is set for November 18th. Parties filed exceptions to the preliminary draft order issued by the hearing examiner, and replies to those exceptions were filed yesterday. SWEPCO is seeking a net revenue increase of $73 million with an ROE of 10.35%. Our filing includes investments made from February 2018, accelerated depreciation for the Dole Hills plant, a storm reserve, 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 hearing is scheduled for January of 22. Our case seeks a $73 million net revenue increase and a 10.35% ROE. An order is expected between the second and third quarter of 22. In Swepco, Arkansas, we are seeking a $56 million net revenue increase with a 1035 ROE. The filing contains a formula rate plan for subsequent years and considers the pending retirement of previously announced coal lignite assets. This filing is timed to align with the North Central and service dates and the provided mechanism both for recovery of costs associated with the investment and flow through the PTC to Swepco customers. A hearing is set for March of 2022. Both SWEPCO and PSO continue to make progress to recognize the storm URI expenditures. As a reminder, we filed for recovery of a WAC returned over five years in Louisiana, Arkansas, Oklahoma, and Texas. PSO is moving forward with the state on the securitization of costs as permitted under Oklahoma law. We have continued our efforts to secure approvals and clarity regarding investments necessary to comply with the EPA, CCR, and ELG requirements. We received certificates 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 its support of 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 will approve the first-year revenue requirement of $4.8 million for broadband, which means we now have recovery for our rural broadband efforts in both rural Virginia and West Virginia. We continue to engage legislators and commissions in other states and stand ready to invest in synergistic mid-mile 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 is one of three wind projects that compose the north-central energy facilities, which will provide 1485 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 AAP continues to drive that transformation for the benefit of our customers and communities. With the success of North Central setting the foundation of our future forward 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 of resources as a result of the RFPs that we're out in the market for, which some of you probably have heard of, we will be able to provide greater detail on the progress being made. Further, if federal efforts through the various tax proposals that extend and expand PTCs and ITCs for clean energy resources succeed, even more benefits will be enjoyed by our customers. So I'll move quickly to the equalizer chart at this point. and I'll go quickly through this. So far, the average for the overall regulated operations is currently 9%. We generally target in the 9.5% to 10% range, so obviously we continue to work on that. AP Ohio came in at 9.3% for the third quarter. It was below authorized primarily due to 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 a commission order here in the fourth quarter of 21. APCO came in at 7.3%. It's below authorized due to higher amortization primarily related to its higher coal-fired generating assets and higher depreciation from increased Virginia depreciation rates and capital investments. 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, 6.9% below authorized due to loss of load from weak economic conditions and loss of major customers. Transmission revenues were also lowered due to a delay in some capital projects. I&M came in at 10.3%. It's above its authorized ROE, primarily due to increase in sales partially offset by increased O&M and depreciation expenses associated with I&M's continued capital investment programs. As far as PSO is concerned, it came in at 7.6%. It's 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 a commission order here on the rate case in the fourth quarter of 21. SWEPCO came in at 8.2%. It's 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. Turk issue, 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 that's retroactive back to March. AP Texas came in at 8.2%. It's below authorized primarily due to the significant level of investment in Texas. Of course, we have favorable regulatory treatment there with annual DCRF and biannual TCOS filings to recover rates. So 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. AP transmission holdco came in at 11.2%. It was above authorized, primarily driven by differences between actual and forecasted expenses. The transco's benefit from a forward-looking formula rate mechanism, which helps minimize regulatory lag, and that forecasted ROE is around 11% in 2021. So overall, 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're executing on all cylinders and continue to drive the results expected of a premium regulated utility. The AP portfolio is one that has enabled our investments in the large side of the business, supporting our transmission investments, including the $0.33 per share this quarter through our AP 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 two of our three wind facilities of our $2 billion investment in north central wind under our belt, providing a solid foundation for the next decade of growth. Throughout this transition, we remain engaged in a trusted voice on energy transformation efforts, helping to ensure a responsible transition to a clean energy economy, and we'll 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 470 with a range of 465 to 475, and we continue to have all 17,000 employees dedicated to our customers and communities to enable this strong performance. Our discipline in controlling costs, our progress to manage the portfolio, and the significance of our future organic growth opportunities provides us with the confidence needed in raising the midpoint and nearing 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, really high. Never did I expect to see a marching band dedicate their halftime show to the music of Rush. To hear Tom Sawyer, YYZ, Limelight, and others was truly amazing. When they were difficult to even play, even though they were also marching while designing guitar players, drums, 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's CEO for 10 years and 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 a clean energy economy and a solid infrastructure foundation by setting aggressive goals and delivering with creativity and solid execution. With that, I'll turn it over to Julie.

Thanks so much, Nick. Thanks, Darcy. And, Nick, I love your Buckeye reference. Go Bucs. I love that. 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, 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 a comparison of GAAP to operating 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. Gap earnings through September were $3.90 per share compared to $3.56 per share in 2020. There's a reconciliation of gap 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 for 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 due in part 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-driven efforts, depreciation, and property taxes. The AP transmission holdco segment continued to grow, contributing $0.33 per share. That was an improvement of $0.05 driven by the return on investment growth. Generation in marketing produced $0.04 per share, down $0.09 from last year, influenced by the prior year land sales, lower retail volumes and margins, generation in income taxes. Finally, corporate and other was down $0.02 per share, driven by lower investment gains and unfavorable net interest expense. This was partially offset by lower income taxes. The lower investment gains are related to a pullback of some of the charge point related gains we've talked about in prior quarters. Let's have a look at our year-to-date results on slide number eight. 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 driver's buy segment, operating earnings for vertically integrated utilities were $1.87 per share, down 3 cents 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 temps in the winter of 2020 and the summer of 2021, which created a favorable year-over-year comp for us. Other favorable items in this segment included higher off-system sales, transmission revenue, net 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 AP transmission whole cost segment contributed $1.02 per share, up 27 cents from last year, related to investment growth and favorable year-over-year true-up. Generation in 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 Oakley Union ARO adjustment in the sale of Conesville and reduced land sales in 2021. Higher energy margins and lower expenses in the generation business offset the unfavorable ERCOT market prices on the wholesale business during Storm Uri in February. We also saw an unfavorable result in retail due to lower power and gas margins. Income taxes were also unfavorable. Finally, corporate and other was up 6 cents per share driven by investment gains and lower taxes and 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 charge point. As you'll see on the waterfall, this produced a 6-cent benefit year-to-date in 2021 as compared to the corresponding 2020 period. You may recall that in the fourth quarter and full year 2020, this investment produced a 5-cent contribution. and we would expect the year-over-year variance to be more pronounced at this point in 2021, as we had no benefit during the same period in 2020. Turning to page 9, I'll update you on our normalized load performance for the quarter. Before we get into the specifics, let me start by reminding everyone that 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 level? 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 nine-tenths of a percent. You'll notice 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 are down only 1.6%, which suggests there's 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 the residential chart is that you'll notice that 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 shows an improvement as we now expect residential to end the year down 9 tenths of a percent. Moving right, weather normalized commercial sales increased by 5%, bringing the year-to-date growth up to 4.3%. Last year, third quarter commercial sales were down 4.6%. So, again, we're seeing a net positive story as the commercial sales class is bouncing back faster than expected. And 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 ninth largest commercial sector across the AP system. Today it's the sixth largest and will likely move further up in the rankings as more data center loads are expected to come in 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 half percent decline assumed in the original guidance forecast. The economy has recovered much faster than originally assumed, which is one of the reasons why we've updated the forecast and showing you 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'll 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. you'll notice that 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 right corner, you'll see that normalized retail sales increased by 3% for the quarter and were up 2.3% for the first nine months. By all indications, the recovery from the pandemic and recession is happening faster than expected and our service territory is positioned to benefit from future economic growth. You'll recall that the original guidance forecast assumed normalized low growth of two-tenths 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 low 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 here show how the year-to-date sales in 2021 compared to 2019, which was 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 our reported residential sales are down nine-tenths of a percent compared to last year, but they're actually up 1.6 percent 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 percent compared to last year, they are still eight-tenths of a percent below the pre-pandemic levels. Given the recent growth we're seeing, especially in the data center loads, we would expect the commercial sales class to fully recover very soon. Moving further right, you'll notice that while the industrial sales are up 4.2% compared to last year, they are still 3% lower than pre-pandemic levels. Given some of the headwinds from manufacturing today with supply chain disruptions, later 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 seven-tenths 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 gap basis, our debt-to-capital ratio decreased 0.4% from the prior quarter to 62.2%. When adjusted for the Storm Uri 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, the effect of Storm Uri 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 metric based on the traditional Moody's and gap calculated basis, as well as on an adjusted Moody's and gap 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 to, again, reiterate, rating agencies continue to take the anticipated recovery into consideration as it relates to our credit rating, so very important to note that. 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 URI-driven fuel and purchase power in the SPP region, directly impacting PSO and SWEPCO in particular. The metric is also adjusted to remove the effect of the associated debt we use 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 URI-driven fuel and purchase power expense in the PSO and SWEPCO jurisdictions is well underway and we're making progress. As a result, and consistent with what we have previously communicated, we still anticipate our cash flow metrics to return to the low to mid-teens target range next year. Obviously, we're trying to push toward 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. That's inclusive of our $100 million dividend reinvestment plan to fund our growth CapEx program. Well, we will provide our typical three-year forward annual review of our cash flows and financial metrics at the upcoming EEI conference. What you 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. In the slide deck today on page 39, you'll see our current cash flow forecast, with which you're already familiar. we've included a note on the slide to reflect the fact that the numbers have not been updated for the announced Kentucky transaction, along with the red circle around the 2022 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 that the sale will be one to two cents accretive in 2022, and we'll 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 five-year, $4 billion bank revolver and two-year, $1 billion revolving credit facility, along with proceeds from a quarter-end debt issuance, support our liquidity position, which reigns really strong at $5.1 billion. If you look at the lower left side of the page, you'll see that our qualified pension continues to be well-funded at 104%. Additionally, our ERPED 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 give us confidence to narrow our operating guidance to the upper half of our current range, resulting in a new range of $4.65 per share to $4.75 per share overall. with a midpoint of $4.70 per share. As we've 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 are making significant progress in addressing items that are top of mind for our current and prospective investors. We are now in 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 we had shared with you for 2022 and therefore alleviates the overhang, the equity overhang, and also allows us to deliver a transaction that we estimate to be one to two cents accretive in 2022. Furthermore, we're 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 is commensurate with a Moody's BAA2 stable rating. As you know, we continue to target that. The intention is to then remain in this credit metric range, again, with the preference to try to get closer to that midpoint as we move along in time. All of this positions us today. to continue our generation transformation, which is underpinned by the renewable investment opportunity we've shared with you and complemented by our ongoing energy delivery investment. So here's what you can expect to see from us at the upcoming EEI conference in early November. In addition to the updated three-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. You know, we typically go out five years. all of which will incorporate the effects of the announced Kentucky sale. So with that, surely 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. And as a reminder, if you would like to ask a question, press 1, then 0 on your touchtone phone. You'll hear an indication you've been placed into queue, and you may remove yourself from the queue by repeating the 1, then 0 command. Also, please pick up your handset before pressing any buttons. We will go first to the line of Julian Dumont-Smith. Your line is open. Go ahead, please. I'm sorry. I'm having some technical difficulty. One moment while we open your line. Your line is open. Go ahead, please.

Hey, good morning, Steve. Can you hear me now? Hey, Julian. How are you? Hey, quite well. Thank you. Congratulations on the transaction here. Nicely done. Yeah, thanks. Absolutely. So perhaps just to dive into that one a little bit more, can you talk about what happens with the Mitchell plan here just as a function of the sale? Will it be transferred to Wheeling, or how are you thinking about that vis-a-vis Liberty and any kind of pricing they're in in terms of transfer or what have you?

Yeah, so that's why the operating agreement is being followed. Wheeling would become the operator, and it does get transferred to Wheeling. in 2028. We'll continue with Kentucky being half owner of Mitchell until that period of time. Wheeling will take over the operations of the plant. The employees will move over to Wheeling as well. And then we'll continue working with the West Virginia and Kentucky Commission to get resolved the operating agreement-related issues. And then, of course, at 2028. it transfers over at a fair market value type of approach. So that's the plan. And that will get filed here in November and December timeframe, and we'll go through that. And actually, both commissions have... have the incentive to get this resolved because we do have various views of the ELG piece of it. So regardless of whether we had this transaction or not, we would be needing to file for the operating agreement change out just because of the different directions that the commissions have gone. So we'll get that resolved as part and parcel to the overall approvals.

Excellent. Nicely done. Fair market value it is. And then just vis-a-vis ongoing transactions and portfolio valuation, clearly alleviating the equity needs here in the very near term. How do you think about just continued evaluation of your portfolio here? Clearly it's not necessarily a near-term dynamic, but I want to give you the opportunity to speak to that a little bit further. Yes, sure.

I've said over and over for a couple of years now, but even beyond that. We do have to get to portfolio management to enable us to look at the sources and uses of the capital needs that we have and to manage the balance sheet, as Julie has mentioned. We target the mid-teens, and we want to get there. Obviously, we're well on our way of getting there, so we want to do that, but at the same time be able to fund the capital growth. When you think about it, We've sold the unregulated generation. We've sold River Ops. We've sold some hydro-related facilities. And with Kentucky, you're talking about $6 billion of assets that have been sold, but they've fueled... substantial growth, I mean, to the tune of $7 billion a year in capital. So it's part of the process to determine what the portfolio needs to be in the future, and we'll continue to do that. Certainly we have Chuck and Julie and others will continue to review that portfolio, and we'll manage it in the proper way. I think, you know, And I'll say this, Kentucky Power, you think about the threshold. At one point we talked about we always invested in coal units no matter what, and obviously we've changed that focus to make sure it's more deliberative in terms of the decision points that are made. It's quite a move for AEP to get to a point where we're managing our portfolio in a way that, first of all, we became fully regulated. And then we start to look at that portfolio to determine, okay, what's the best approach to fuel $20 billion in potential renewables investments. So when you think about that, we have to consider it. And I can tell you, I mean, the last time we sold a regulated utility was – I guess the Scranton, Pennsylvania system and the Pennsylvania and the New Jersey system back in the 1940s and 50s. So it's a pretty substantial change. And when you think about Kentucky Power itself, It was one of the first acquisitions of American Gas and Electric in 1922. So by the time we get through this, it's been 100 years. So when you think about the threshold level of portfolio management that has occurred in this company, It really should shine a lot on terms of our seriousness of making sure that we're managing that portfolio in a proper way. That's probably a longer answer than what you asked for, but I wanted to at least get all that out there.

Absolutely. Very much appreciate it. I'll leave it there.

See you guys soon. Okay. We'll next go to the line of Shara Peretza with Guggenheim Partners. Go ahead, please.

Morning, Shara. Good morning, guys, and congrats on Kentucky. Yeah. Just to follow up on Julian's question a little bit more, as we sort of 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 2025, I mean, even if you assume a 50-50 owned PPA structure could yield an incremental $3 billion rate of spending opportunities. You obviously have a slew of IRPs, so do you need to see affirmations with the various filings or actual approvals and GRCs? So how should we sort of think about how these could be funded, especially in light of where the stock trades? Yeah, and so...

Yeah, and when you think about the way we're approaching the renewables piece of it, the process has been that we time 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, and that means obviously our FFO debt doesn't suffer anymore, 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, does it match the future needs in terms of where we are and where we're going as a company? If we have a chronically underperforming part of the portfolio, then it's important for us to take a look at. Now, that may be temporary. It could be long-term, but certainly we have to make sure that we're evaluating things each one of these assets in a way that says, okay, it doesn't matter where it's located as long as we're getting certainly the return expectation and also the forward view of the utility is positive, and that's comparative with 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, you know, Nick, I 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 to 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 this space impacting some project timings? So do you see any of this swinging at all? Yeah, I do.

And when we actually go do the analysis, and we've done analysis for all the jurisdictions, but conditions change. Load changes, certainly PTCs, ITCs can change as a result, which change the business cases where some may have been on the margins, particularly in the east, now become benefits to customers. So I think those numbers will continue to change, and I can tell you from what I've seen so far, those numbers will change. And, you know, some will go up, some will go down, but overall, nominally it should be on path to what we've talked about. We'll have more to report on that. probably during first quarter 22, because we'll have the integrated resource plans. And when those integrated resource plans are filed, that's what I mentioned today, is you'll have a more definitive view of what those projects look like because they'll be the results of RFPs and they'll be the results of actual projects that are put in for regulated approval. So more definition, but I would... So I would certainly say that anomaly will be in that category we previously discussed.

And, Charlie, what you should anticipate is when we go to EEI, you'll see a refreshed five-year forward CapEx plan, so 22 through 26, and you'll start to begin to see a little bit more of this renewable opportunity dropped in. So stay tuned for that. and we'll be able to talk more granularly with you here in a couple 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 financial plans. And then just like with North Central, we make decisions on whether it goes up or down based upon our ownership. Got it. Terrific, guys. Congrats on the results. See you soon.

Thank you. We will next go to the line of Steve Fleischman with Wilkes Research. Go ahead, please. Yeah, hey, good morning.

Can you hear me, Nick? Yeah, oh yeah, I can hear you. Good morning. Okay, great, thanks. Hey, one question that might be a bit premature, but there's obviously a lot going on in D.C. with the reconciliation bill and the like, and one of the provisions that's gotten more focus the last few days is the minimum tax provision. I'd just be curious how you're thinking for larger companies like yourself, how you're thinking if that has any impact for a largely regulated utility like you? or does it not really have much of an impact?

Well, I would say, and we've been vocal about this and the industry has been vocal about it, if you put a minimum 15% tax, and a lot of us are, as you know, heavy on capital, and it's growth capital and it's also infrastructure-related capital, so an increase with a minimum tax would certainly have a cooling effect on our ability to continue with not only development of infrastructure and have an effect on that, not to mention customers' bills ultimately because the taxes are a pass-through to our customers, but also the administration has a focus on clean energy and it will have an effect on... the renewables transformation that's existing as well. So I think it put a pale over all the utilities' ability to continue investing capital in the way that we are. Now, if we do do that, then obviously there's customer impacts associated with it, and again, it's sort of a hidden tax on our customers. We're not for it. We're not for that provision. I think actually we've been very forthright about this and trying to be an honest broker when we were talking about CEPP and all the other things. It was important for us to be able to make this transformation from a clean energy standpoint Certainly, the PTCs, ITCs with expansion of long-term storage, nuclear, but certainly in terms of wind and solar are very important to continue this process to move to a clean energy economy. We can get a long way there. This industry is very focused on doing that. And any kind of tax headwind that goes the other direction is not helpful. And I think you'll probably hear that across the board.

Okay. Okay. And more direct AP 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...?

It's in the public interest, obviously, because they have to look at the suitor and determine is that the right approach and is it done in the proper way. Actually, there have been some discussions in Kentucky previously. I think it's probably gone past some of that now. We wanted to make sure we were operating Kentucky the way we should. We've been operating it the way we always have. We've been investing. We've been doing the things that we need to do, whether we owned it or not. I think certainly the buyer has recognized that. During the transition... we will continue to support a smooth transition to ensure that the services provided and the things that need to be done to make Kentucky Power successful, we'll be there to do it. And, of course, we'll support Liberty Utilities and Algonquin in doing that. Great.

And then one just quick question maybe for Julie. Just the... The proceeds from the Kentucky sale look like they're matching up pretty much one-for-one with reducing the equity need, but obviously when you sell an asset, you lose some cash flow, albeit Kentucky maybe wasn't having the best cash flow. Are there offsets in other businesses that are making up for the lost cash flow from the asset sale?

Yeah, thanks for the question, Steve. You're right. I mean, we do lose the funds from operation as it relates to Kentucky and Kentucky Transco, although we've got to keep in mind that we also eliminate about $1.3 billion of debt associated with those assets, too, because that goes away. And then the other thing 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 I'm able to sidestep that as well. and that comes with maybe also having some additional dollars to reduce debt at the parent. As I mentioned in my opening comments, anything above and beyond that $1.4 billion will channel toward debt reduction that was otherwise planned for 2022. And then also keep in mind that Kentucky Power had very strained FFO to debt to begin with, so to eliminate that piece of, I guess, drag, to the overall average FFO to debt for the organization is also a net positive for us. So we're able to be able to put these numbers together. And quite frankly, from an FFO to debt perspective, it is very 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're able to take literally that $1.4 billion of planned equity out of the plan, and again, you'll see that at EDI when we refresh the forecast.

Great. Thanks so much. Thanks, Dave. We'll next go to the line of Durgas Chopra with Evercore ISI. Go ahead, please.

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

Yep, gotcha. You'll see 2024 when we roll out our EEI guidance, so three years forward. But as we continue to say, we're talking about mid to low teens. And the reason I say that is, you know, as I mentioned today, if you look at our FFO to debt on an adjusted basis, so backing out the yearly consequence, we're 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 expectation is to start to push more toward what I would characterize as mid. It would 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 EI and unveil that forecast. But I wouldn't change that. how you're thinking about it. So, you know, think about mid to low teens as it relates to Moody's, BAA2, with a preference toward, you know, 14-ish plus percent.

Got it. Okay, so it sounds like more mid to low teens through 2024 here. Just a big picture question, just we've talked a ton about natural gas prices, so maybe just talk about your gas generation portfolio here. fuel costs, any hedges and impact on customer bills?

I'll take this from a customer rate perspective, if I could, because that's how we think about it, because ultimately this impacts our customers. When you think about, for example, do some sensitivity analyses around, let's say, a 10% hike in natural gas prices, as we all know they've gone up substantially, the impact to customer rates varies significantly from one operating company to the next. depending on the fuel mix. So, for example, if I looked at Appalachian Power Company, the average residential impact price in terms of a 10% hike in gas prices would equate to about a 0.9% increase in the customer's rate. Let's compare and contrast that to, say, PSO or Swepco, where there's much more gas concentration. So PSO, we'd be talking about 1.6%. Increase in customer rates, swap code 1.5%. So this is something we are very sensitive to because, as you know, overall we're extremely sensitive to customer rate increases in the aggregate as we continue to execute on our general CapEx program. And I don't know if, Nick, you had any additional questions.

Yeah, I'd say certainly your question actually shows the reinforcement of our renewables transformation because it's a perfect edge. to natural gas if North Central were in place during the time of Storm Uri, it would have saved customers $225 million. So when you think about the process we're going through, it's great to have natural gas, but at the times where you can layer in renewables to do that, it turns out to be a significant benefit to consumers. So it reinforces that, and I think probably this winter we'll show it

Understood. Thanks, guys. I appreciate the time.

Thank you.

We'll next go to the line of Andrew Wiesel with Deutsche Bank. Go ahead, please. 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 subs might file new rate cases over the next 12 months or so?

Yeah, I'm trying to think of what else we would be following because in just about every jurisdiction we have a case that we expect approval of and certainly a lot of cases that are still ongoing in just about all the jurisdictions. So I'd say we're always reviewing that on a regular basis at this point. But, you know, we have plenty of active cases that we've got to get across the finish line and then determine where we're at. The other part, too, is, okay, what happens to the denominator? You know, because, as Julie mentioned, road is changing significantly, and it continues to do that as we emerge from, hopefully, a post-COVID world. And if that's the case, then... that will be a determinant in terms of when we would file for any case. And I think, of course, if we do have tax changes that occur, then that will force a whole new view going forward to many of these cases, just like it did when we got tax reform last time around, except this one may be on the upside.

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?

Yeah, probably quiet in terms of followings, but probably noisy in terms of results.

All right. Thank you very much. As a reminder, if you do have questions, press 1 then 0 on your touchtone phone at this time. We'll go next to the line of Michael Lapidus with Goldman Sachs. Go ahead, please.

Hey, guys. Hey, Nick. How are you doing? I'm fine. Rough year for your Bayou Bengals this year. A lot of change. Hey, got a couple of questions for you. With the Kentucky sale and your slide number five, I think it is, has over the years has done a good job of detailing how hard it's been on authorized in Kentucky. Now that Kentucky will be kind of off your plate, when you look at the other jurisdictions What are the ones where you say, hey, we still struggle to earn authorized here? And what are the structural changes, whether it's legislation, and we've seen lots of utilities in places like North Carolina, Kansas, Missouri, go in and make structural changes via legislation. What are the structural changes you're going to seek outside of just normal rate case filings that could help improve authorized versus earned returns in those jurisdictions?

Yeah, you know, you're seeing... You're seeing a pretty fundamental shift in all the remaining operating companies. We've made a lot of progress on riders, and we have a lot of focus on getting concurrent recovery and cash in the door. And what you're seeing really in terms of a lot of these lags is the amount of investment that we're placing in these companies. But as well, as you make the transition certainly from wires-related activities with riders and then the renewables conversion that occurs, the way we're doing the renewables is is commensurate with the recovery so we should see the authorized um our returns be closer to the authorized as time goes forward we don't see any fundamental issues in any of the jurisdictions that are left that says that we have significant headwinds. I mean, the only thing you could probably point to is the Turk issue at SWEPCO. But other than that, and actually when you think about Arkansas, we keep saying we're not recovering the Arkansas portion of Turk. That's not because of the commission. That is because of the Supreme Court of Arkansas. So we've got very good relations with the commissions and all the jurisdictions, and we feel like the fundamentals are there for continued improvement relative to that regulatory lag that exists. And because we're spending on more areas and our generation is really renewables, and that's helping out every time we put an investment in, and the timing of the investment improves FFO to debt, improves the returns of the individual companies, and I think we'll continue to make progress in that regard. So I'm pretty optimistic that we'll continue to make progress in all of these jurisdictions. Got it.

And just a quick follow-up, and this may be a jewelry one. Just curious, when we think about your multi-year kind of your guidance, growth rate, and kind of the language around wanting to be at the high end, outside of the transmission segment, the standalone segment, what does that embed as a earned ROE at the rest of the kind of regulated businesses?

Yeah, and so, Michael, as Nick mentioned, we strive to be in the upper half of the guidance range. not necessarily the upper end, although that would be very nice. So just a point of clarification there. And as it relates to returns, as you can see, we've kind of been hovering around the 9% ROE return level. I think that's a safe place for you to assume that we'll kind of hang out there for a while until we get a little more traction. Another thing, if I could, circling back to your original question, when we look at the equalizer chart, oftentimes we get questions around AEP Texas. and why the lower ROE relative to authorized there. And so, you know, back to your question around, you know, growth and how do you manage the business. AAP Texas, we continue to invest a significant amount of capital on an annualized basis. And while we have very progressive weight recovery mechanisms in place that we really enjoy, I can tell you this. While the ROE may look a touch depressed relative to authorized, that company continues to produce earnings growth in, say, the 8% to 10% range. So that fortifies our ability to, back to your original point, get in that upper half of the range. So, you know, again, ROE, our system-wide average, assume roughly around 9%-ish and trending upward over time. And then around AEP Texas, keep in mind the capital is intentional there as we continue to try to take care of the customer and grow that business. And it's paying dividends in the sense that we're getting 8% to 10% TPS growth out of it.

Yeah, and the other thing you have to look at, too, and we have it on that page, is actually the increase in equity layers as well. So you see improvement in the equity layers, and then we're still investing and still meeting the 5% to 7% and being in the upper half and that kind of thing. And, of course, we continue to manage the FFO to debt towards the mid-teens. So all the pieces are starting to fit together, and there's a lot of optimization that will occur for us to execute on to ensure that we're continuing to meet the earnings objectives. But at the same time... investing in the right things that enable us to bridge that gap on the regulatory lag. Got it. Thank you, guys. Much appreciating. Congrats, Kentucky.

Yep, sure thing. Thanks. And speakers, we have no one else in queue at this time.

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

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