Ladies and gentlemen, thank you for standing by, and welcome to the American Electric Power Second Quarter 2021 Earnings Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. I would now like to turn the conference to our host, Vice President of Investor Relations, Miss Darcy Reese. Please go ahead. Thank you, Tony. Good morning, everyone, and welcome to the second 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 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, and welcome again, everyone, to American Electric Power's second quarter 2021 earnings call. Today, we report a strong second quarter operating earnings of $1.18 per share versus $1.08 for the same period of 2020. Our second quarter results reflect significant progress in terms of economic recovery throughout AEP's service territory, with a continued focus on O&M as we navigate through what is hopefully an emergence from the COVID-19 pandemic. Gross regional product has already exceeded its pre-pandemic levels, and employment across AEP's service territory is now within 2% of its pre-pandemic levels after adding over 163,000 jobs in the first six months this year. Increased vaccinations combined with the additional fiscal stimulus from the American Rescue Plan are contributing to the strong demand for goods and services throughout the economy. AEP's normalized retail sales in the second quarter of 2021 were the highest we've seen since the second quarter of 2018. Clearly, we are pleased with the improvements we've seen thus far and will continue to monitor the recovery's progress over the second half of the year. Accordingly, we are reaffirming our 2021 guidance range of $4.55-$4.75 per share, and a 5%-7% long-term growth rate and would be, again, disappointed not to be in the upper half of our stated guidance range as we have previously stated. Julie will be discussing these issues in more detail in her report. Rate case activity across our jurisdictions continues to be active and substantial. In Ohio, we are awaiting an order by the commission 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 Consumers' Counsel, industrial companies, commercial companies, and other entities like the Ohio Hospital Association. We expect a decision in the third quarter of this year. Public Service Company of Oklahoma filed a rate case at the end of April. PSO is seeking $115.4 million net revenue increase and a 10% ROE. The following transitions North Central costs from the rider established in the approval into base rates. The case also seeks to continue a distribution rider, recover RTO expenses, and update depreciation rates. Testimony of the parties is due in August with a hearing scheduled for September and an order expected in the fourth quarter of 2021. In Indiana, I&M filed a base rate case on July 1st. The filing is based on the future test year model and seeks a $97 million net revenue increase with a 10% ROE. The major items in the case include the recognition of over $500 million in capital investments per year in Indiana, continuation of the transmission tracker, a federal tax rider should those changes occur, and deployment of AMI meters to provide customers more control and insight into their usage. In our SWEPCO jurisdictions, we have rate cases pending in Louisiana and Texas and are preparing a filing in Arkansas for tomorrow, July 23rd. In Texas, a hearing was held in May, and SWEPCO filed its reply brief and proposed findings of fact and law on July 1st. SWEPCO is seeking a net revenue increase of $73 million and an ROE of 10.35%. The filing includes investment made from February 2018, accelerated depreciation for three coal plants, an increase in storm reserve, and vegetation management. We expect an order in the fourth quarter with rates relating back to the effective date of March 2021. In Louisiana, a procedural schedule was set with testimony due in the third quarter of 2021 and a hearing in January of 2022. The case seeks a $93 million net revenue increase and a 10.35% ROE. An order is expected between the second and third quarter of 2022. In Arkansas, the case will contain a formula rate plan for subsequent years and consider the retirement of previously announced coal lignite assets. This filing is timed to align with North Central in-service dates and to provide a mechanism both for recovery of costs associated with the investment and flow-through of the PTC to SWEPCO customers. We have certificate filings in Virginia, West Virginia, and Kentucky related to investments needed to comply with the CCR and ELG rules on coal plants in the region. We received an order in Kentucky and an ALJ decision in Virginia denying ELG investments. Final decisions from the Virginia Commission and the West Virginia Commission will be received in the third quarter of 2021. We understand that these are difficult decisions for states to make regarding the future of their generation resources. We'll be working with our commissions to navigate the implications of how each state's decision will affect the ongoing operations of these plants. SWEPCO and PSO continue to make good progress with their commissions to recognize the Storm Uri expenditures. Julie will cover this in more detail in her comments. As a reminder, we filed for recovery of a WACC return over five years in Louisiana, Arkansas, and Oklahoma, and will do so in the near future in Texas. PSO has filed for financing authority to explore the securitization option. It was established by the legislature. The company's plan to transition its generation fleet and reduce carbon emissions by 80% by 2030 and net zero by 2050 is well underway. In April, we announced new resource plans that include the addition of up to 16,600 MW of regulated renewable resources over the next decade. This plan provides a meaningful opportunity to invest in clean energy resources while benefiting our customers and strengthening our communities. Our $2 billion investment in the North Central wind facilities is a first and a very significant step forward in this transition, and it provides a solid foundation for our clean energy transformation. The Sundance facility was placed in service in the second quarter, and the Maverick and Traverse facilities remain on time and on budget for completion during the fourth quarter 2021 and first quarter 2022, respectively. Solicitations also are underway for additional large-scale renewable acquisitions at APCO and SWEPCO, and we expect to issue the RFP to begin to fill the resource needs for PSO in October 2021. Our transmission investments continue to be strong, helping our communities prepare for a clean, more efficient, and resilient energy future. Our Transmission Holdco contributed $0.34 per share in the second quarter, up $0.15 from the same period last year. We remain engaged in the various processes at RTOs and FERC as we advocate the need for transmission and more robust comprehensive planning methodologies to ensure that our path to a clean energy economy is as smooth as possible. We also continue to be a strong advocate, like many, supportive of achieving net zero targets for the continuation of the 50 basis point RTO incentive. This important incentive, codified in the Federal Power Act, is critical to ensuring that needed transmission investment is made as we transition to a clean energy economy. If this nation is to move quickly to a clean energy environment, there must be a resolution and clarity around the important issues of investment return expectations, as well as longstanding issues of transmission siting processes and cost allocation mechanisms. FERC certainly seems to be on the right track as they look at transmission-related planning issues to spur additional development, of course, investment-related incentives are important in that equation as well. Regarding the strategic process that is ongoing regarding our Kentucky assets. We're on track with the timeline we shared previously to have an announcement of a complete process, one way or another, by year-end. As we have stated previously, keep in mind that we must obtain FERC and Kentucky Public Service Commission approvals before a deal could close, that could push into 2022. As we focus on reaching a suitable transaction deal, we would announce in 2021 and move forward expeditiously on these two filings in parallel and reach closing as soon as possible. These regulatory approval processes are 180 days for the FERC Section 203 filing and 120 days for the Kentucky Public Service Commission transfer of control review. While this is an ongoing confidential process, progress is being made. It reminds me of the Carly Simon song, "Anticipation," and if I paraphrase some of the lyrics, we can never know about the days to come, but we think about them anyway, and hopefully you're chasing after some finer day. More to come during the rest of 2021 on what that finer day looks like for AEP. Last but not least, our Achieving Excellence Program is a year-over-year effort to maintain our cost discipline. Our efforts year to date have largely centered on the returning to the workplace. The vast majority of those that will be in the office are returning in August. Like many employers, we will accommodate remote, hybrid, and on-site work going forward. What was once 100% on-site for our office staff prior to the pandemic will become approximately 24% remote, 43% hybrid, and 33% on-site when we fully return, and that excludes field-level employees, of course. We plan to reap the benefits of reduced travel, less occupied office space, savings on real estate, a broader talent pool, and improved worker efficiency through digitization and automation initiatives that accelerated during the COVID-19 pandemic. As you know, one of the highest priorities involves ensuring AEP is active in supporting our communities and serving as a positive voice and force for social justice and advancing racial equality. We have engaged both in community dialogues as well as conversations within the company to promote a deeper understanding and commitment to meaningful change. Our efforts include a renewed focus in our charitable giving to support organizations that are focused on these efforts. Our AEP Foundation has announced significant additional focus on social injustice-related initiatives. These activities not only support the culture we expect within AEP, but also sets an example for our communities and the nation on what could be in this country. Now I'll move to the equalizer chart, and I think you have that with the bubbles of each company. For that, I will remind everybody, we generally target the ROE for the regulated segments to be in the 9.5%-10% range. The ROEs, we have to keep in mind, though, that we are and have been in the process of thickening the equity layers over the last several years, so we have to take that into account. For AEP Ohio, the ROE for AEP Ohio comes in at 9.7%. Its ROE is near authorized primarily due to timely recovery of capital investments. We expect the ROE to continue to trend around those authorized levels. Of course, I mentioned earlier, we're waiting on a Commission order as well. At APCO, the ROE is coming in at 8.1%. Its ROE was below authorized due to higher amortization primarily related to the retired coal-fired generating assets and higher depreciation from increased Virginia depreciation rates and capital investments. Of course, I've already talked previously about the Virginia case and where it stands with the Virginia Supreme Court. In Kentucky, the ROE is 5.9%. Kentucky's ROE is below authorized due to loss of load from weak economic conditions and loss of major customers, along with higher expenses. In June 2020, Kentucky Power filed a base rate case seeking a $65 million revenue increase and an ROE of 10%. Kentucky Power received a final order in its base case rates that went into effect in January of 2021, authorizing an ROE of 9.3% and a revenue increase of $52 million. I&M came in at 9.8%. Their ROE is consistent with authorized ROEs, which are 9.6% in Michigan and 9.7% in Indiana. Earlier in July 2021, as I mentioned earlier, they filed a new rate case in Indiana, we'll continue on with that. PSO came in at 7.9%, it's below its authorized level, primarily due to increased capital investment currently made in base rates and higher than anticipated equity due to the extreme February winter weather event, which Julie will be talking about a little bit later. Of course, in April 2021, as I mentioned earlier, we filed a new base rate case there as well. For SWEPCO, the ROE at SWEPCO is 7.9%. It's below authorized, primarily 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. Of course, I've mentioned earlier, it affects about 110 basis points. We have the three cases. In October 2020, SWEPCO filed a Texas case, which we're still awaiting an outcome. SWEPCO also is following the Arkansas case, and then I mentioned earlier the Louisiana case as well. AEP Texas is at 7.9%. Their ROE is below authorized, primarily again due to significant level of investment in Texas and the timing of the annual cost recovery filings associated with that investment. As you recall, we have DCRF and TCOS filings to recover on a pretty regular basis. The expectation is for the ROE to continue to hover around that 8% because of all the investment that's going in that state. Should trend toward 9.4% in the longer term. AEP Transmission Holdco, the ROE for the holdco is at 11%. The ROE is above authorized, primarily driven by higher revenues due to differences between actual and forecasted revenues. The Transcos benefit from a forward-looking form of rate mechanism, which helps minimize regulatory lag. Transmission is forecasting to continue to be around that 11% in 2021. The overall is about 9%, but again, remind you that the equity layers have increased actually pretty substantially over the last few years. That's one of the trade-offs that are being made there. Okay. In closing, we had a strong quarter in the first half of the year. I'm proud of the accomplishments our employees have made in 2021 and the commitment that our team makes day in and day out to the communities we serve, especially during the pandemic and as we come out of this trying time. Our employees continue to focus on maintaining a high level of discipline in controlling costs. With a broad economy on the mend, certainly gives us confidence in the rest of the year in delivering on the mission of consistent earnings and dividend growth expectations that we have produced year after year. If I look at the key areas for AEP to address for the remainder of 2021 and into 2022, they are to conclude the strategic review of Kentucky, conclude North Central with the appropriate financing, ownership, and recovery, advance our clean energy transition with a 16,600 MW of renewable resources, and continue the improvement of our credit metrics in line with our 2022 expectations, which Julie will talk about again. Of course, all of this is grounded fundamentally about safety, cultural, and operational excellence expectations with a focus on execution. If we have any Foo Fighters fans on the call, the Rock Hall is inducting them into this year's class of inductees. They did a song called "This Will Be Our Year," which was originally recorded by the Zombies, but it says, "Now we're there and we've only just begun. This will be our year. Took a long time to come." This is true for AEP regarding our clean energy transition and our execution towards portfolio optimization. With that, I'll turn it over to Julie. All right. Thanks, Nick. Thanks, Darcy. It's good to be with everyone this morning. I'm going to walk us through the second quarter and year-to-date financial results, share some thoughts on our service territory load, and finish with a review of our credit metrics and liquidity. Let's go to slide six, which shows the comparison of GAAP to operating earnings for the quarter and year-to-date periods. GAAP earnings for the second quarter were $1.16 per share compared to $1.05 per share in 2020. GAAP earnings through June were $2.31 per share compared to $2.05 per share in 2020. There's a reconciliation of GAAP to operating earnings on pages 14 and 15 of the presentation today. Let's walk through our quarterly operating earnings performance by segment. That's laid out on slide seven. Operating earnings for the second quarter totaled $1.18 per share, or $590 million, compared to $1.08 per share or $534 million in 2020. Operating earnings for the vertically integrated utilities were $0.45 per share, down $0.10, driven by a year-over-year increase in O&M due to lower prior year O&M, which included actions we took to adjust to the pandemic. Other pressures included lower wholesale load and higher depreciation and other taxes. These items were partially offset by the impact of rate changes across multiple jurisdictions, higher normalized retail load, transmission revenue, and off-system sales. The transmission and distribution utility segment earned $0.31 per share, up $0.02 from last year. Favorable drivers in this segment included higher normalized retail load, transmission revenue, and rate changes. Partially offsetting these favorable items were higher tax, depreciation, and O&M expenses, as well as unfavorable weather and lower AFUDC. The AEP Transmission Holdco segment continued to grow, contributing $0.34 per share, an improvement of $0.15, which got a boost because of the unfavorable annual true-up last year, consistent with the 2021 earnings guidance assumptions we had provided to you. Our fundamental return on investment growth continued as net plant increased by $1.4 billion or 13% since June of last year. Generation and marketing produced $0.09 per share, down $0.02 from last year, influenced by the prior year land sales and one-time items relating to an Oklaunion ARO adjustment and the sale of Conesville. These were mostly offset in the generation business by higher energy margins and lower expenses from the retirement of Oklaunion. Finally, corporate and other was up $0.05 per share, driven by investment gains and lower taxes, which was partially offset by higher O&M and net interest expense. Bear with me a moment. I'm going to talk a little bit more about that investment gain as we walk through the year-to-date view. If you flip to slide eight, we can look at year-to-date results. Operating earnings through June totaled $2.33 per share or $1.2 billion, compared to $2.10 per share or $1 billion in 2020. Looking at the drivers by segment, operating earnings for vertically integrated utilities were $1 per share, down $0.05 due to higher O&M and depreciation expenses. Other smaller increases included lower normalized retail and wholesale load, higher other taxes, and a prior period fuel adjustment. The impact of weather was favorable due to the warmer-than-normal temps in the winter of 2020. Other favorable items in this segment included the impact of rate changes across multiple jurisdictions, higher off-system sales, and transmission revenue. The transmission and distribution utility segment earned $0.54 per share, up $0.01 from last year. Earnings in this segment were up due to higher transmission revenue, rate changes, weather, and normalized retail load. Partially offsetting these favorable items were higher tax, depreciation, O&M, and interest expenses, as well as lower AFUDC. The AEP Transmission Holdco segment contributed $0.68 per share, up $0.21 from last year for the same reasons identified in the quarterly comparison. Generation and marketing produced $0.16 per share, down $0.02 from last year due to favorable one-time items in the prior year relating to an Oklaunion ARO adjustment and the sale of Conesville. 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. The decrease in renewables business was driven by lower energy margins and higher expenses. Corporate and other was up $0.08 per share, driven by investment gains and lower taxes, and partially offset by higher O&M. Let me take a quick moment to comment about the investment gain, which is predominantly a function of our direct and indirect investment in ChargePoint. As you'll see on the waterfall, this produced a $0.09 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 $0.05 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 nine, I'll update you on our normalized load performance for the quarter. Before I talk about class-level trends, I'd like to start with a couple of observations at a macro level. First of all, since all of these charts are showing a year-over-year growth, it is important to recall that the second quarter of 2020 was at the trough of the recession when restrictions on businesses to manage the public health crisis were at their greatest. The second observation is that there has been a steady path to recovery since bottoming out in the second quarter of last year. The momentum we're seeing is a positive sign for the economic recovery throughout the service territory. If you start in the upper left corner, you'll see that normalized residential sales were down 3.1% compared to last year, bringing the year-to-date decline down to 0.5%. As mentioned earlier, the comparison basis is the key here. You'll notice that residential sales were up 6.2% when the COVID restrictions were at their greatest. In fact, one year later, they're only down 3.1%, which suggests some of the increase in residential is having some staying power as more businesses have embraced a remote workforce for jobs that can be easily performed at home. In fact, the second quarter normalized sales in 2021 were the second highest second quarter on record, exceeding every second quarter before the pandemic began. Moving to the right, weather-normalized commercial sales increased by 10%, bringing the year-to-date growth up to 3.9%. If you compare this with the residential class, you'll notice the commercial sales growth in the second quarter is more symmetrical with last year when sales were down just over 10%. The growth in commercial sales for the quarter is spread across all operating companies and most sectors. The only sector that was down slightly compared to last year was grocery stores, which were very busy at the onset of the pandemic, trying to keep shelves stocked when panic purchasing was at its highest. Moving to the lower-left corner, you'll see that the industrial sales also bounced back in the second quarter. Industrial sales for the quarter increased by 12.8%, bringing the year-to-date growth up 2.8%. Similar to the commercial class, you'll see a symmetrical recovery compared to the second quarter of 2020, when sales were down 12.4%. Industrial sales were up at every operating company and nearly every sector. The only industrial sector in our top 10 that reported less sales this year compared to the second quarter of 2020 is the paper manufacturing sector, which ironically was also higher last year, partially due to panic purchasing of toilet paper. This is a phenomenon that none of us are likely to forget, especially if you were one of the folks who didn't get a jump on it. Finally, in the lower-right corner, you can see that in total, normalized retail sales increased by 6.3% for the quarter, and we're up 1.9% through the first half of the year. By all indications, recovery from the pandemic and recession are on a firm footing. Let's go to slide 10. There are two more charts here that help put the second quarter normalized sales performance into perspective. The bar chart shows the last five years of weather-normalized retail sales in the second quarters for the AEP system. Our retail load performance in the second quarter of 2021 has not only recovered from the recession, but it is also the highest second quarter since 2018. The line chart on the bottom of this page shows the seasonally adjusted retail sales by quarter, which provides an illustration of the trend of the recovery, and again, confirms that our current level of sales is the highest since the second quarter of 2018. Before we leave the load story, let me remind you of an important factor to consider when evaluating the impact of load growth. The mix matters. While we're seeing strong growth now in commercial and industrial sales, those are priced at much lower realizations than the decline we're seeing in residential sales. To further illustrate this point, the impact of the pandemic was most pronounced in our biggest metropolitan area. That's Columbus, Ohio. Since AEP Ohio is in the T&D utility segment, where we only collect an unbundled rate, the strong recovery that we're seeing this year is coming in at much lower realizations than the system average. Let me remind you that there are rate design mechanisms in place to limit the exposure when entering a downturn that can also limit the impact when you're coming out of recession. While the industrial sales are up significantly this year versus last year, it does not mean the revenues will increase by the same percentage. What does all this mean when we think about the remainder of 2020? Well, it means that our confidence in our earnings guidance range is fortified by what we're seeing. It suggests that the load trends we anticipated are coming to fruition as the chart on page nine illustrates. Our continued investment at Transco is fueling strong performance in this segment beyond the favorable true-up impact that we had anticipated. While O&M is up, it's enabling us to take care of our business and customer needs given the load growth we're seeing. Obviously, we have the second half of the year to navigate, but we are pleased with the direction and are keeping a watchful eye on the economic activity in our service territory while scanning for any impact associated with the rise in COVID variants. Let's check in on the company's capitalization and liquidity position on page 11. On a GAAP basis, our debt-to-capital ratio increased 0.1% from the prior year quarter to 62.6%. When adjusted for the Storm Uri event, the ratio remains consistent with year-end 2020 at 61.8%. Let's talk about our FFO-to-debt metric. As it did in the first quarter, the effect of Storm Uri continues to have a temporary and noticeable impact in 2021 on this metric. Taking a look at the upper-right quadrant on this page, you'll see that our FFO-to-debt metric based on the traditional Moody's and GAAP-calculated basis, as well as on an adjusted Moody's and GAAP-calculated basis. On a traditional unadjusted basis, our FFO-to-debt ratio increased by 0.2% during the quarter to 9.3% on a Moody's basis. On an adjusted basis, the Moody's FFO-to-debt metric is 12.8%. To be very clear, this 12.8% 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 costs in the SPP region, directly impacting PSO and SWEPCO in particular. This metric is also adjusted to remove the effect of the associated debt we used to fund the unplanned payments. It should give you a sense of where we would be from a business as usual perspective. As you know, we are in frequent contact with the rating agencies to keep them apprised of all aspects of our business. The rating agencies continue to take the anticipated regulatory recovery into consideration as it relates to our credit rating. Importantly, there continues to be no change in our equity financing plan, and our multi-year cash flow forecast that's laid out on page 39 does not assume any asset rotation proceeds. Given the regulatory recovery activity that's currently in flight, we do expect our FFO-to-debt cash flow metric to return to the low-to-mid-teens target range next year. Here's a quick refresh on where all this regulatory activity stands today for PSO and SWEPCO. In Oklahoma, we're working through the regulatory process and anticipate issuing securitization bonds in the first half of 2022. In both Arkansas and Louisiana, recovery is underway while final details get worked out in the regulatory process, and we'll be filing for recovery in Texas in the third quarter of 2021. Let's take a quick moment to visit our liquidity summary on slide 11. You'll see here that our liquidity position remains strong at $3.3 billion, supported by our five-year, $4 billion bank revolver and two-year, $1 billion revolving credit facility that we entered into on March 31st of this year. If you look at the lower left side of the page, you'll see that our qualified pension continues to be well-funded, and our OPEB is funded at 174.2%. Let's go to slide 12. We'll do a quick wrap-up, and we can get to your questions. Our performance in the first half of the year gives us confidence to reaffirm our operating earnings guidance range of $4.55 per share to $4.75 per share. Because of our ability to continue to invest in our own system organically, including both our energy delivery system and the transformation of our generation fleet, we're confident in our ability to grow the company at our stated long-term growth rate of 5%-7%. We surely do appreciate your time and attention today. With that, I'm going to turn the call over to the operator for your questions. Thank you. Ladies and gentlemen, if you wish to ask a question, please press one then 0 on your telephone keypad. You may remove yourself from any time by repeating the 1-0 command. If you're using a speakerphone, we ask that you pick up the handset before pressing the numbers. Once again, if you have a question, please press one then 0 at this time. There'll be one moment for our first question. That'll come from the line of Julien Dumoulin-Smith with Bank of America. Please go ahead. Morning, Julien. Hey. Thank you for all the remarks. I'd say at the pace that you guys were just talking, I would've mistaken you guys for sitting in New York or something like this. Yeah, I know. I'm going to try to catch up on everything that was just said. Maybe in summary on the load growth, I hear you. I think the critical comment you made was mix. Where are you trending against your guidance range here as you think about, obviously, third quarter matters critically. Obviously, you kept intact the total load growth here. Any comment to just resolve that against the full-year numbers? I know we're still early-ish in the year. Well, you sort of answered the question. We're still early-ish in the year because third quarter is particularly meaningful. We typically look after third quarter to see where we actually stand. Again, as Julie mentioned, O&M goes up commensurate with all the customer expansion as well, and we have pretty sizable customer expansion. Look at the industrial and commercial numbers. They're up considerably. I think it obviously is outstripping our estimate going into the year of what overall load growth would be. It remains to be seen because I think we're sort of in a very cyclical period of trying to figure out what the future holds in terms of whether this other variant of COVID-19 is going to have an impact or what happens actually. Is there just pent-up frustration, then it starts to moderate? What's promising is, though, that we're still seeing residential load, although it's negative to 2020. It's still positive overall. Our original thesis of more residential load going forward, and if we could tie that together with improved industrial and commercial load as well, it could be very positive. We certainly have to feel our way through that and really understand that. It'll be past third quarter before we really have a good feel of that. Julie? Yeah. Just to maybe add a little finer point, too. If you're thinking sequentially for the remainder of the year, our load growth rates are expected to moderate in the second half of the year based on prior year comps. When you think about it, restrictions were most severe in the second quarter of last year. By the third quarter of last year, the service territory had begun essentially a phased reopening. As a result, the 6.3% growth for the second quarter is probably not only the highest growth in the quarter, actually, it is the highest growth in AEP's history, but it'll also be the highest load growth stat during the recovery. If you think about the second half of the year, I would expect it year-over-year to moderate a little bit. We're just keeping a watchful eye on how the trend continues to click along. I know I saw in the Wall Street Journal this morning CFOs commenting on where they think the economy's going to go. Doesn't look like anybody's changing their estimates based on COVID trends. We're keeping an eye on that. Got it. Excellent. Thank you. Yeah. If I can pivot to ERCOT, obviously you all have a pretty meaningful footprint there. We've seen various legislative efforts underway. I'm curious, as best you can tell thus far, I know it's early, any kind of context you can put, especially on the transmission side of potential projects here? We're hearing from various peers about potentially meaningful shifts. Certainly, obviously, it remains to be seen. As far as transmission investment, and really we think of T&D and what part of the business is associated with T&D. We have made some inroads in terms of backup generation, those kinds of things. In terms of transmission, I really think there's probably continued opportunity for development of storage capability, of other transmission-related investments on the grid to ensure that we're able to adjust. For us, we're doing a lot in terms of line-of-sight into the transmission grid itself. Continuing to expand our SCADA abilities, continuing to focus on our ability to have even more transmission in place. Because if you're looking for additional generation to be placed in various areas, transmission's a big part of that solution as well. I think Texas is a sort of microcosm of the country when you start reevaluating the system based upon the needs from not only a natural gas perspective, but also from a renewable perspective. That brings in the whole planning effort and communication in real time associated with the operations of the transmission, and for that matter, the distribution system as well. I think they're making the right steps. I think there's more steps to be made, and it's going to be a multi-year type of effort. Of course, we're a big part of the transmission in Texas, so we'll be certainly very focused on how the T&D business can be expanded to improve the resiliency of the T&D efforts. That means Texas is really going to have to start thinking about resources and a broader view of resources like we're having to do for the rest of the system. Transmission technologies, and for that matter, distribution technologies, are going to have to be recognized in its ability to provide a more resilient grid. You can't have these strict lines drawn between generation and transmission and distribution, because that's not the world we're in anymore. We'll continue that focus. Every legislative session, every regulatory session will be centered on that effort. Excellent. Just last, Kentucky, I imagine you can't say much, but what's the level of interest, if you can give any kind of parameters? Yeah. Obviously, I don't want to get into too much detail. I think, again, you answered this right at the beginning. It is a confidential process, but I can say that we do have credible interest, and it is a competitive process. Excellent. Thank you all. Take care. Thanks. Thank you. Our next question comes from Steve Fleishman with Wolfe Research. Please go ahead. Morning, Steve. Hey, good morning. Can you hear me, Nick? Good morning. Oh, yeah. I can hear you fine. Okay, great. Thanks. Just where are you on the $600 million of equity plan for this year? How much have you issued so far? Yep. Thanks for the question, Steve. We've actually used the ATM to issue just under $200 million. I think it was around $195 million that was associated with the financing of the Sundance Wind Energy Center. We'll be continuing on with the rest of that program. As you know, about 100 of that 600 is also associated with the DRIP. That continues to play in the background, if that helps. Okay. Yep. Just, this might be a little bit hard to answer, but just in terms of thinking about the $1.4 billion for next year that's in the plan, obviously, if you were to sell Kentucky, some of that could maybe offset some of that. Could you just give us latest thoughts on how to think about the Kentucky outcome relative to that $1.4 billion for next year? Nick can add a finer point from a strategic perspective. Purely from a financing perspective, you're right on the money, Steve. We got $1.4 billion embedded in our plan. For those of you who are following along at home, we're on page 39 of the cash flow, if you want to take a look at 2022. About $100 million of that, again, is associated with the DRIP. About $800 million is associated with North Central Wind financing. Then we have another $500 million just associated with general funding of growth CapEx. To your point, Steve, to the extent that we would find ourselves in a situation where we were able to transact and bring dollars in the door, we'd absolutely be able to work off some of that otherwise equity issuance, and sidestep that. I can't give you a number. We don't have a transaction. That is absolutely the thinking in how we're modeling different scenarios inside the house. I don't know, Nick, if you have any comment on that strategy. No, I think you covered it well. It's great to have a financing plan, assuming a sale of Kentucky doesn't happen. Also, it's great to have options available to further optimize what that financing plan looks like. I'll say again, the timing, particularly with Traverse being the last one, it's the largest one, in first quarter 2022. That times out pretty well with this process. We'll get this resolved, and it'll be financed one way or another. At the end of the day, the timing of it and the process is continuing on plan. And just if I could- Okay just to follow up, Steve. Yeah. Just to reiterate, the plan as it stands today, you know, assumes no asset rotation. Again, I want to reinforce that the 5%-7% is well intact, even if we don't have a transaction. Okay. Do you have a bias within that range at all, or just kind of that's the range? That's the part probably we can't answer at this point, Steve. Okay. You're being very unbiased. I'm being very Smart move. Okay. Thanks so much. Yep. Sure thing. Thank you. Our next question comes from the line of Shar Pourreza with Guggenheim Partners. Please go ahead. Morning, Shar. Hey. Good morning, guys. Wanted to start with a recent event and get your sense on the Mitchell Order in Kentucky, sort of rejecting the rate increase you sought. Obviously, it's not a surprise following the AG's strong comments prior to the decision. Nick, is this sort of a signal that the state and the PSC in general, they're starting to commit to maybe a little bit more of a rational thinking around an economic approach to coal? The least cost approach, is this starting to bend further towards renewables? How do we think about the viability of the plant in the state, and could we see some acceleration of that 1.4 GW of solar and wind you brought into plan for the state on the prior call as a direct read? How do we think about West Virginia's rate request coming off the Kentucky Order? Sure. It's sort of interesting. It's multi-jurisdictional, as you know, and Mitchell is Wheeling and Kentucky Power, and I think we have to get resolved Kentucky, Virginia, and West Virginia. West Virginia is yet to speak on this issue, and it's only the ALJ in Virginia, so we'll hear more from Virginia on that. I think it's really important for us to really hold onto our cards for now because we've got to get through a state process. It's good to have clarity, and I think Kentucky obviously is the first shoe to drop in this regard. We've also made it clear that these are multi-jurisdictionally units. We have to make sure that there's some compatibility of the jurisdictions that are involved. We'll go through the process. We'll get the initial views of the commissions, and then if they are on different tracks, we'll have to further analyze and resolve that with the commissions. There's a lot of resolutions that could occur. Some are shorter, some are longer. We have to understand where all three commissions are before really doing anything here. I think it's good to get clarity, though. I think it's pretty important that whether it's the ELG or the CCR, if they approve CCR investments but don't approve ELG investments, then that effectively brings the generation retirement dates back from 2040 to 2028. That's something we have to consider along with those commissions. We'll know more about this in the August time frame. I'd be hesitant to say what Kentucky. It's pretty interesting that they would be looking at the ELG part of it, and I think there is becoming more of an awareness that there has to be a plan. What that plan is, we've got to fully resolve with all those commissions. More to come on that. Got it. Thanks for the visibility around sort of the Kentucky process. I know, Nick, you obviously mentioned that further optimization is always a possibility. Remind us if the trigger point is the shaping of that, for instance, that 16.6 GW of renewables you discussed in the prior call. Obviously, Kentucky will more than likely backfill some of your North Central equity needs. As we're thinking about further optimization, should we be watching the outcomes of the IRPs, the PSC approval of how much you plan to own versus PPAs, which I guess would stipulate your incremental equity needs and the resulting size of potentially further optimization measures? Just like we've gone through probably a couple years now of discussions about how North Central is going to get financed, we're finally getting to a point where ultimately we'll know how it's being financed. The 16.6 GW is certainly. We've made a pretty credible case that we ought to own a significant part of that. I'd like to own all of it, certainly, operationally and from a contracting standpoint and certainly the ability for us to respond to system-related activities, it's important for us to own and control those assets. I think that as we go forward, you're right. It'll be the integrated resource planning filings that are made that'll start that dialogue. Now we're in the process of doing RFPs to get more information, obviously, from the market in terms of what's out there from a developmental perspective. That process is ongoing. That'll certainly fortify any CCN filings we have to make or anything like that after the resource planning filings. The resource planning filings will be your first real dialogue around how quickly this transformation will occur in each one of the jurisdictions. We're feeling pretty good about it because it's getting to a point where we have to decide from a capacity standpoint how we support these utilities. It's pretty clear to me that the movement into that clean energy economy, the movement is toward as long as you have some element of base load 24/7 capacity, that renewables will be the big part of that. A lot of that's just becoming, I think it's becoming much more transparent. Our jurisdictions, I think the conditions, both federally and from a state perspective, they're just a better realization of what the options are and the timing of those options. That's what we'll draw forward through that resource planning process. Got it. Lastly, [audio distortiion], I apologize if I'm putting you on the spot because the news just broke this morning. Is there any kind of relation to the FirstEnergy deferred prosecution agreement that was announced this morning to the SEC investigation at AEP? No. Like I said before, we're on the outside looking in. We have no knowledge of any of that activity. If the report is true, I'm glad to see that there's some element of putting all this in the rear-view mirror because naturally, and I've said before, AEP has been hung up. In the wake of that, and I'm certainly hopeful that there's some closure brought about from that. Yeah, it was a surprise to me, and we knew nothing about it. Certainly, there's really nothing else that AEP can say other than what we've put on our website. Okay. Naturally, there's just nothing to report from our perspective. Terrific. Thank you, Nick and Julie. Congrats on today's results. Yep. Okay. Thank you. Our next question comes from the line of Stephen Byrd with Morgan Stanley. Please go ahead. Morning, Stephen. Hey, good morning. How are you? Congrats on a constructive update and on weaving in a mention of both Carly Simon and [audio distortion]. That may be a first. Yeah. Yeah, right. Lots of good keywords. I just wanted to discuss on Kentucky, if there are approaches that can help minimize tax leakage. How are you all thinking about sort of ability to bring proceeds back and sort of the impact of taxes? Thanks for the question, Stephen. As you know, we're a little tax inefficient right now. Given the tax basis in Kentucky and the different hurdles that we're considering, I wouldn't see that one being a showstopper. Quite frankly, that might give us an opportunity to enhance or improve our tax efficiency without getting into a bunch of numbers. I wouldn't let that trip you up in terms of what things could stop us moving forward. That's helpful. Maybe just thinking through the upcoming RFPs. You mentioned the APCO and SWEPCO RFPs. Could you just talk in a little more detail in terms of color around the timetable there? I'm sorry if I missed that, if you all did go through it. I didn't quite follow there. I'm just thinking about sort of what that might mean for timing of incremental spending and sort of how we should think about those processes. We've certainly gone through the basic requirements for the RFPs for all of these areas. As we go through that process, at APCO, we issued an RFP there for 300 MW of solar and wind resources, really for a completion date of 2023 or 2024. In May of 2021, APCO issued an RFP to obtain, I guess it was 100 MW of solar and wind energy via PPA and RFP for the renewable energy certificates only, which is consistent with Virginia and what their requirements are. SWEPCO issued an RFP for own resources up to 3,000 MW of wind and up to 300 MW of solar resources with optional battery storage, by the way, that can achieve completion by 2024-2025. They're also seeking 200 MW capacity in the 2023-2024 range, and another 250 MW in the 2025-2027 range. Those bids are due in mid-August. At PSO, in June, we notified the regulators the intent that we intend to issue an RFP seeking up to 2,600 MW of wind and up to 1,350 MW of solar, again, with options for battery storage consideration. That's meeting capacity needs by 2025. PSO plans to issue the RFP in October of this year. Those are the ones that are on the board right now and have really some near-term related requirements and most are capacity-related requirements. Again, they're being done pretty much the same way as the others with North Central that will certainly do more of a turnkey type of thing where we take ownership at the time that it's approved in rates. Of course, we'll go through the process of approvals by the various commissions along the way. That's the plan right now. Matter of fact, we're spending a lot of time with our board focused on the strategies related to these types of filings and the plan long term. It's important for everyone to understand this is going to be a continual process. You're just seeing the first part of these really driven by capacity requirements and not just sort of an energy convenience. I think they're really good to go out with right now. That's what we have at this point. That's really helpful. That's all I have. Thank you. Thank you. Our next question comes from the line of Jeremy Tonet with JP Morgan. Please go ahead. Hi, good morning. Good morning. How are you doing? Good. Just wanted to pick up on Kentucky a little bit more, if that's possible, and just wanted to know if you might be able to comment, in any degree, to whether the strategic review process has received more interest from strategic or financial players. Then as well, kind of given strong prices achieved in recent industry transactions and the strong interest you know here in Kentucky, has this process made you thought about more asset rotation beyond Kentucky to increase balance sheet headroom overall? For the first question, we started out this process saying that we expected to get strategics and financials, we have strategics and financials. Both are involved. As far as your second question is concerned, as I said earlier with the [audio distortion] dialogue, this is going to be a continual process for us. We're practically fully regulated, we have the opportunities to look at, if we're building 16.6 GW of renewables resources during a transition, we have to have everything on the table in terms of sources and uses. We're going to go through that process. Of course, Kentucky is sort of a first stop. We'll continue to evaluate our assets as sources. If it makes sense, based upon what the other opportunities are, that's the kind of framework that we want to move this company toward. Got it. That's helpful. Thanks for that. There's news coming out of FERC with regards to the transmission planning process. I'm just wondering if you might be able to provide some thoughts on what's been said recently and what you see as kind of best practices here. Obviously, we'd like to see much better transmission-related planning across regions. AEP does a pretty good job itself in terms of transmission planning, because we do have a large system to consider. At the same time, RTO to RTO type of planning process to try to make them more consistent, so you can have this large transmission being built across regions and across states. If you're going to get that going, particularly as you try to get renewable resources to load centers, we're going to have to resolve these issues around multi-jurisdictional, multi-RTO type of analyses and making sure that we're consistent. The other part too is, we've got to have consistency in terms of rate making. This notion of reevaluating incentives, structures, and those types of things is not good for making decisions relative to transmission, or it's not good relative to the RTO model itself. I think FERC really needs to sort of step back and take a look at, and I think it's a real positive approach to be focusing on the planning aspects and addressing RTO to RTO boundaries, addressing areas where what's competitive, what's not competitive, all those types of things. That's fine. We have to have a clear planning process. First of all, you can't have coming back later after a project, multi-millions have been spent on a project to say, "We're going to stop the project." That has to change. The other part of it is, we've got to be able to make these investments with some sense of certainty, and be able to move quickly to make that happen. So I think there's a lot of value in being in an RTO for customers. There also has to be value for the companies involved to make the investments that benefit customers in orders of magnitude greater than what the costs are related to any incentives related to transmission. And if you want to send a bad message for anybody to join an RTO or anybody to stay in an RTO, it's just not good to start messing around with what the assumptions are relative to the future recovery of transmission investment. Now, when you start questioning incentives, you're really questioning anybody that's trying to put a multi-year model together to show the benefits of transmission have to take that into account. That something may change. It's sort of like trying to make an investment in a coal unit with clean energy activities going on in Washington. You really do have to really think this process through and think about what you're trying to achieve. Sorry I went on about that one, Ben. No, that's helpful. Thank you for that. I'll stop there. Thank you. Thank you. Thank you. Our next question comes from the line of Durgesh Chopra with Evercore ISI. Please go ahead. Hey, Durgesh, how are you? Hey, good morning, Nick. Thanks for taking my question. Good morning. Hey, you addressed sort of a lot of transmission questions in the Q&A. Maybe just like the MISO transmission opportunity that the MISO has flagged, perhaps to sort of unveil towards the end of the year. I know a small set of assets for you in that location, but could you compete for some of those projects? Could that be an upside for you there? Oh, yeah, we could. We could compete through with our Transource entity, which we have been. Yeah, we could. It's actually a small impact for us as it stands. Certainly we could certainly participate in any of that. Yep. Understood. Just anything you're hearing at your level and your peers and through the sort of the EEI organization. The infrastructure bill has a pretty sizable CapEx on the transmission side or investment on the transmission side. Just anything you're hearing from that on the federal front? Obviously, we have the, I guess it's 1.2 trillion, the infrastructure bill. It's interesting we talk in trillions as opposed to billions now. In terms of the hard infrastructure side of things, it appears there's some kind of convergence in Washington on that particular issue, although more has to be done on the actual language and things like that. As far as pursuing the advancement of certainly transmission investment, but direct pay and those kinds of issues are clearly important along the way. We also have to, as far as renewables and clean energy, PTCs, ITCs, extensions of those, I think that makes sense, particularly the IRS-related delays because of COVID and that kind of thing. I think there's opportunities for that. As far as electric vehicles, certainly we'd like to see electric vehicle infrastructure continue to be developed. I think all of those areas are positive. The issue is how you leverage into the private companies like ours, that instead of the government funding and for transmission, for example, we think that mechanisms already exist for the development of transmission, as long as you keep all the incentives and all that kind of stuff. Federal and federal government funding of that now, I think you have to sort of think about what level of encouragement and what area. If they can make siting much better, if they can make certainly the focus on planning, those issues that enable transmission to get investments, we have no problem financing transmission investments. I think the government probably all have to pick and choose between what they truly want to focus on that's not already leveraged into the utilities, for example. They could certainly encourage the development of electric vehicles with the focus on charging station infrastructure and those types of things that would be a benefit. Then as far as the renewables transformation or the clean energy transformation, any kind of hard infrastructure around being able to move more quickly from a renewables standpoint, whether tax incentives, and also other technologies like storage. Then also, we'd like to see benefits related to either tax incentives for coal fire generation to reduce the undepreciated plant balances, for example. If you want to have a national plan around moving to a clean energy economy, then the more quickly we can reduce undepreciated plant balances, the better we're able to make decisions and commissions and states can make decisions about what future resource replacements would be. I think there's several ways to really focus on this, but we're all moving toward a clean energy economy. We just need to make sure that the government doesn't try to do too much across the board as opposed to very selected areas that enable investment to continue in the private sector. That'd be my view. Yeah, appreciate that color, Nick. Real quick, just good to see FirstEnergy resolve the DOJ investigation, or at least have an agreement this morning to highlight it. Just any update on the SEC subpoena you got? Any more color that you can share with us? No, nothing new there. We've been communicating with the SEC, and we're responsive to any requests they have from a documentation standpoint, and we're going to continue to work with them and be supportive and constructive in the process, but nothing new to report there. Understood. Thank you for taking my questions. Yep. Thank you. Our final question comes from the line of Michael Lapides with Goldman Sachs. Please go ahead. Nice try on that one. Michael who? Yeah, exactly. Michael, the guy who's excited about the changes in the Southeastern Conference they had. Hey, guys, real quick question or two. First of all, one on O&M this year. Obviously O&M at the VIU segment is up a lot. How do you think about what the second half of the year O&M trajectory looks like versus the first half? How should we think about both for VIU and T&D segments, the long term, the 2022 and beyond trajectory for O&M? Yeah. I'll just generally say, and Julie can certainly follow up on this. As you have expansions in customer load, you're going to have higher O&M associated with that, but that's a good expansion. The issue for us and what we typically do is, we're evaluating the true impacts of our Achieving Excellence Program against what our forecast needs to be in terms of bending the O&M curve. We continue to take account of the good O&M that supports expansion from a customer load perspective, but also continue to not only optimize that, but also continue the overall optimization of the O&M budget itself. Yeah, you may see it, and that's why obviously we're watching what third quarter looks like and fourth quarter and what the load does. We want to make absolutely sure that we're continuing to make progress consistent with that plan of consistent earnings and dividend improvements in that 5%-7% growth trajectory. That's what we're doing. We're not just saying, "Oh, yeah, load is going up. Let's spend more O&M." It really is a measured approach from our perspective. Julie? Yep. No, that's spot on, Nick. Thanks for the question, Michael. As I'm sitting here thinking about this and as we were preparing for the earnings call, one of the things I'm looking at is to Nick's point, you look at where load is coming in. As mentioned in a previous answer to a question, we do expect that load on a relative basis when you compare it to last year for the second half would not be as pronounced. Although we do expect it to continue to improve. That's a good thing. That allows us to be a little more comfortable with O&M costs where they are because that does help the customer in the long run. We keep that top of mind and continue to be very diligent about managing costs. If you're trying to model for the rest of the year, let me start by saying this, we are not changing our guidance. As you know, once we start the year and we give you that plan, so you see that waterfall that we give to you, how we get to the end of the year obviously changes, right? Because it's a dynamic business. I wouldn't be surprised if relative to that plan, if you saw O&M be running a little richer. I would hope that load would be hanging in there, too. As you know, we're doing well on the transmission holdco segment, already kind of clicking along where we thought we would be for the full year. There may be some benefit there, too. Do keep that in mind when you go back and compare and contrast to that guidance walk that we gave to you. I think it was on February 25th during our earnings call. We're happy to help you with any modeling that you have offline. Sounds great. Thanks, guys. Much appreciated. Sure thing. 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. Tony, would you please give the replay information? Ladies and gentlemen, this conference will be available for replay after 11:30 AM Eastern today through July 29th, 2021. You may access the AT&T replay system at any time by dialing 1-866-207-1041 and entering access code 4754105. International participants may dial 402-970-0847. Those numbers again are 1-866-207-1041 and 402-970-0847 with access code 4754105. That does conclude our conference for today. We thank you for your participation and for using AT&T conferencing service. You may now disconnect.