Good day, and thank you for standing by. Welcome to the Q2 2022 Evergy Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star one one on your telephone. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Lori Wright, Vice President, Investor Relations and Treasurer. Please go ahead. Thank you, Michelle. Good morning, everyone, and welcome to Evergy's Q2 call. Thank you for joining us this morning. Today's discussion will include forward-looking information. Slide 2 and the disclosure in our SEC filings contain a list of some of the factors that could cause future results to differ materially from our expectations and include additional information on non-GAAP financial measures. The releases issued this morning, along with today's webcast slides and supplemental financial information for the quarter, are available on the main page of our website at investors.evergy.com. On the call today, we have David Campbell, Evergy's President and Chief Executive Officer, and Kirk Andrews, Executive Vice President and Chief Financial Officer. David will cover our Q2 highlights, our integrated resource plan, and our regulatory and legislative priorities. Kirk will cover in more detail the Q2 results and discuss the latest on sales and economic trends. Other members of management are with us and will be available during the question and answer portion of the call. I will now turn the call over to David. Thanks, Lori, and good morning, everyone. Thanks for joining us today. I'll begin on Slide 5. I'm pleased to report that we had a solid Q2 as we delivered adjusted earnings per share of $0.86 compared to $0.85 in 2021. The increase in adjusted earnings over last year was driven primarily by favorable weather, an increase in weather normalized demand and higher transmission margin, partially offset by higher planned operations and maintenance expense and lower other income net of expense. Kirk will discuss these Q2 drivers in more detail. On our Q1 Earnings Call, I highlighted that we had just participated in a safety roadshow and that our focus on safety contributed to strong safety performance in the Q1. Our employees continued this positive trend through mid-year, reducing work-related injuries, including recordable and restricted events, by 60% compared to the same period last year. Our customer reliability has been solid despite challenging weather, reflecting the beneficial impacts of our ongoing grid investments. Compared to the five-year trend in our service territory, so far this year, the number of days with sustained winds over 25 miles per hour increased 89% to 65 days, and days with wind gusts over 40 miles per hour increased nearly 50% to 78 days. 2021 was in line with this five-year average for both measures, so, 2022 has been a clear outlier. In contrast, relative to the five-year trend, average daily outage events have decreased by 14% in the first six months of 2022, notwithstanding the more extreme weather, indicating improved system resiliency. I would like to thank all Evergy employees for their focus on safety and their dedication to providing safe, reliable, and affordable power to our customers. I would also like to highlight a recent generation milestone. As you know, we have been expanding our wind portfolio for over a decade with about 4,400 megawatts of owned and contracted wind generation. Our portfolio recently marked 100 million megawatt-hours of cumulative wind energy production. In 2021, factoring in the production from our Wolf Creek Nuclear Plant, our emission-free generation was equivalent to 56% of our total retail customers' usage. Our team's consistent execution has resulted in a solid start to the year, and we are reaffirming our 2022 adjusted EPS guidance of $3.43 per share-$3.63 per share, as well as our target long-term annual EPS growth rate of 6%-8% from 2021 to 2025. Slide 6 highlights our annual Integrated Resource Plan update, which was filed in June for both Kansas and Missouri. Our preferred plan for the next decade is consistent with the resource plan laid out in last year's Triennial IRP filing and the renewables development plan Kirk discussed during our Investor Day last September. The minor tweaks in the plan reflect updates to the sequencing of our near-term investments. Specifically, we shifted the 190 megawatts solar addition and the Lawrence coal retirements to 2024, primarily due to the dynamic market conditions facing the solar supply chain and the benefits to customers of keeping Lawrence online with current high natural gas prices. In 2026, we shifted a planned solar project to wind and increased the capacity assumption for the project by 100 megawatts. Beyond 2026, we slightly reduced megawatt assumptions for our solar projects, which on a net basis offset some upward pressures on pricing. Overall, by the end of 2032, our preferred plan now includes 3,500 megawatts of renewables additions while also responsibly retiring nearly 2,000 megawatts of coal, balancing both affordability and reliability as we advance our fleet transition and advance toward achieving our sustainability and emissions reduction goals. Moving on to S lide 7, I'll provide a summary of key regulatory and legislative milestones and ongoing constructive developments in both Kansas and Missouri. In Missouri, we continue to work our way through the pending general rate case. In early June, staff and other interveners filed their direct testimony, and in mid-July, all parties filed rebuttal testimony. In the next few weeks, parties will file true-up and surrebuttal testimony with a settlement conference to follow around August 22nd, and hearings later this month through early September. Revised rates in Missouri will go effective on December 6th. We look forward to working with the parties to constructively resolve the case. At Evergy Missouri West, we have also been advancing the securitization process to recover the roughly $300 million of Winter Storm Uri costs. Earlier this week, we filed a non-unanimous settlement that resolves all key issues with the Missouri Public Service Commission staff. In terms of timing, hearings are wrapping up this week, and we expect a commission financing order in mid-October. On the legislative front of Missouri, Senate Bill 745, which modifies Plant In Service Accounting, or PISA, was signed by the governor and became law in late June. The modifications reduced the revenue requirement cap to a 2.5% annual compounded growth rate and narrow the calculation to consider PISA deferrals only. Importantly, this bill also puts into law a property tax tracker effective later this month, which will eliminate a historical source of lag in our Missouri jurisdictions. The PISA extension marks the second consecutive year of passing new legislation in Missouri that will benefit customers and stakeholders. In 2021, HB 734 was signed into law, authorizing the securitization of extraordinary costs and the unrecovered book value of retired generation plans. Moving to Kansas, I'm pleased to report that in June, the Kansas Corporation Commission approved the non-unanimous stipulation agreement for Winter Storm Uri costs. The order allows us to recover roughly $120 million of deferred extraordinary fuel purchase power and non-fuel costs at Kansas Central over a two-year period beginning in April 2023. Similarly, the $37 million of net benefits at Kansas Metro will be returned to customers over a one-year period, also beginning in April of next year. Preparations are underway for our Kansas Central and Kansas Metro rate cases, which we will file in April 2023. We expect a test year ending September 30th, 2022, and a true update around June 30th, 2023, with new rates becoming effective in December of next year. Other important milestones in Kansas include the passage and signing of securitization legislation in mid-2021, as well as the completion last November of the docket before the Kansas Corporation Commission relating to the Sustainability Transformation Plan. In both Kansas and Missouri, the Triennial Integrated Resource Plans have completed their review process. The Missouri Public Service Commission approved the IRP in March of this year, and the Kansas Corporation Commission accepted the IRP in May. We will continue to work collaboratively with regulators and interveners in both states to achieve constructive outcomes that advance our core objectives of delivering affordable, reliable, and sustainable power to the customers in the communities that we serve. Overall, we are pleased with the strong start to the year, the progress that we have achieved in working closely with regulators and stakeholders to enhance our service to our customers, and the ongoing consistent execution of our business plan. I will now turn the call over to Kirk. Thanks, David, and good morning, everyone. I'll start with the results for the quarter on Slide 9. For the Q2 of 2022, Evergy delivered adjusted earnings of $198 million or $0.86 per share, compared to $195 million or $0.85 per share in the Q2 of 2021. The year-over-year increase in Q2 EPS was driven by the following. First, a 16% increase in cooling degree days drove a $0.06 increase in EPS compared to Q2 2021. Adjusting for the warmer than normal weather experienced in the Q2 of 2021, however, the Q2 of this year saw a $0.11 increase in EPS versus normal weather assumed in our original plan. We also saw a 4% increase in weather-normalized demand this past quarter, which drove $0.10 per share. Higher revenues driven by our transmission investments, combined with an increase in TDC revenues due to higher than expected volumes, drove a $0.06 increase. These positive drivers were partially offset during the quarter by O&M expense, which was approximately $29 million higher, or $0.10 per share, driven primarily by planned generation maintenance outages and higher transmission and distribution contractor expense. We saw $0.02 of higher depreciation and amortization expense due to increased infrastructure investment, $0.02 of higher interest expense due to increased debt outstanding at higher interest rates. Finally, we had $0.07 of lower other income net of expense, due primarily to lower COLI proceeds year-over-year, as well as lower AFUDC equity. I'll turn next to year-to-date results, which you'll find on Slide 10. For the six months ended June 30th, 2022, adjusted earnings were $332 million or $1.44 per share, compared to $320 million or $1.40 per share for the same period last year. Again, moving left to right on the slide, our year-to-date EPS drivers include the following. When combined with relatively normal weather in the Q1 of this year, our year-to-date results reflect the $0.06 impact from weather during the Q2. Weather normalized demand year- to- date increased about 2%, driving approximately $0.10 of EPS. Higher transmission revenues driven by ongoing investments, combined with an increase in TDC revenues due to higher volumes, led to an $0.11 year-to-date increase versus 2021. Year- to- date, these items were partially offset by the following. O&M expense due to higher plant generation maintenance outages and increased T&D contractor expense incurred during the Q2 drove approximately $0.05 per share. $0.06 of higher depreciation expense due to increased infrastructure investment. $0.09 of lower other income net of expense driven by COLI proceeds and AFUDC equity. Finally, we had $0.03 of higher income tax expense, and that was primarily due to tax smoothing, which reflects a shift in intra-year timing of the recognition of certain tax items in order to maintain our projected effective tax rate for the year. This is not expected to result in a variance in our FY results. Turning to Slide 11, I'll review a bit more detail behind the weather normalized demand growth for the quarter and year-to-date, as well as an update on economic trends and developments. For the Q2, as I mentioned previously, total weather normalized retail demand increased by approximately 4%, led by a robust year-over-year increase in industrial demand, driven in particular by the chemical and oil and gas sectors. Year-to-date, weather normalized demand increased approximately 2%. Over the balance of the year, we expect a more moderated increase in year-over-year weather normalized demand given the H2 of 2021 largely reflected post-pandemic working conditions. Overall, total retail demand is now above pre-pandemic levels. On the economic development front, in July, Panasonic announced plans to build a new electric vehicle battery manufacturing facility in DeSoto, Kansas, which is just outside the Kansas City metro area. This facility, which will be one of the largest of it's kind in the U.S., represents an estimated investment of approximately $4 billion and is expected to create up to 4,000 new jobs. The facility will be located in the Evergy Kansas Central jurisdiction, and when fully constructed and operational, is expected to be one of our largest customers. Finally, on Slide 12, I'll wrap up with an overview of our long-term financial expectations. With our strong start to the year, we are reaffirming our adjusted 2022 EPS guidance of $3.43-$3.63. We plan on giving our 2023 annual guidance on our typical timeline as part of the year-end call early next year. As David noted earlier, we are also reaffirming our long-term compound annual EPS growth rate target of 6%-8% from 2021 to 2025, based on the midpoint of last year's original adjusted EPS guidance of $3.30. We continue to expect growing the dividend in line with our long-term earnings and target a 60%-70% dividend payout ratio. Our $10.7 billion five-year capital plan through 2026 is focused on new infrastructure investment to improve customer service, enhance reliability and resiliency, and transition our generation fleet, while at the same time continuing to advance regional rate competitiveness and meet the evolving needs of our customers and communities. With that, I'll hand the call back over to David. Thank you, Kirk. We appreciate your time with us today, and we'd now be happy to take your questions. Just as a reminder, to ask a question, please press star one one on your telephone. Please stand by while we compile the Q&A roster. Our first question comes from Michael Sullivan with Wolfe Research. Your line is now open. Hey, everyone. Good morning. Good morning. Hey, David. Wanted to just start with pretty strong quarter in terms of just the sales growth, weather normal, and then also the weather benefit. Maybe if we could just get a little color on how the weather normal compared to plan and just given the strength, why not raise the guidance at this point in the year? Michael, good questions. We obviously are pleased to see the demand growth, weather normalized that we saw in the H1 of the year. We had some expectations for reasonably strong demand growth, and that was front-end loaded. We had a relatively softer recovery from the pandemic in a couple sectors the H1 of last year. We did expect to see that demand growth, particularly in the H1 of this year. We're a little bit ahead of plan, but only a little bit. If that's sustained, that's obviously would be a nice tailwind. Haven't yet seen recessionary pressures, but of course, we'll be on a close lookout for that. Now in terms of our performance overall, it has been a solid start to the year. Q3 is our biggest quarter, and you know, July was relatively robust weather. Our approach to guidance is typically we will make that assessment and give an updated view after the Q3 since it's our largest quarter. We are pleased with the start to the year. Okay, great. Thanks. Just wanted to shift to the rate case. Maybe if you could just talk about where there may be outstanding sticking points and potential for settlement. I think one of them is obviously the Sibley issue. If that were not to go your way, is that something that you see as manageable? There are a couple questions there. Yep. The Missouri rate case, which you're asking about, is. This is my first general rate case in Missouri, and it's an interesting process in the state. There's a tremendous wave of activity towards the end of the process. While we filed back in, gosh, in the Q1, this month, we will see our final true-up filings. We'll also see surrebuttal testimony. We've got the settlement conference scheduled, and then hearings will begin at the end of the month, scheduled through early September. There's a lot of action that will happen then. Now, I know you have been tracking the filings closely, the gap, particularly when you've seen some adjustments in staff's filings and their filing on revenue requirement. I think the gaps are relatively reasonable and the issues are pretty well understood. We look forward to engaging constructively in discussions, just as we did in the Winter Storm Uri securitization proceeding, where we were able to file a non unanimous settlement resolving all issues with staff earlier this week. It's a pretty typical rate case. We'll be looking to finalize ROE, some items related to depreciation, some other factors, some tax items. As you noted, Sibley is as we expected a matter that generated a lot of ink or a lot of I guess digital ink. I'm using the old metaphor. Sibley will be an active discussion. We do think it's manageable, and I think we've gone through this before in the past. Kirk has related to it. There's you know three main components. One is the O&M recovery that we have actually been setting aside, created a regulatory liability for, so the discussion on that is really the time period for returning it. There's a return on component since the last rate case. Cumulatively is roughly by the time that rate case is over, we're gonna be $40 million-$50 million range. You know, depending on what the decision is on that's a one-time item, not an ongoing issue. The last issue is one that could have some impact on performance, and that's a residual rate base in Sibley. We think it makes sense and consistent with the initial settlement was filed four years ago, that will be retired in the normal course like other assets. There'll be discussion around that. It's a relatively modest amount. It's, you know, we think it can be managed. Those will be discussion items in the final piece. We've appreciated the dialogue, and we look forward to advancing those discussions as we go through all the testimony, and the proceedings over the next few weeks. It'll be a busy time, but that's the crescendo that is typically the case in the Missouri context, as you know. Great. Thanks for that. Just last one, if I could throw it in, just initial thoughts on the Inflation Reduction Act and what it means for your company. We're obviously going to continue to track that closely. We think that the provisions relating to renewables should have the beneficial impact of further reducing the cost of our expected additions for our customers. It also appears to make sort of the transferability and ability to take advantage of the PTCs and ITCs simpler, so it simplifies tax equity or other approaches. On balance, we think it's a helpful enabler that will further reduce costs for customers as we move forward. There's some other provisions in there we'll track where the nuclear piece is. It's eligible for both merchant and regulated assets. That's not an earnings driver for us, but could be beneficial, for our customers in terms of reducing costs, 'cause there are times when our Wolf Creek plant does receive low, prices because of the wind resources, particularly in the spring, and the fall. It may well end up being eligible for some recovery there, too. We think that it's a beneficial set of provisions. We'll obviously watch closely as it weaves it's way through, in Washington and monitor closely any amendments and the ultimate, hopefully, the ultimate passes that we see. Great. Thanks, Dave. Appreciate it. Please stand by for the next question. The next question comes from Durgesh Chopra with Evercore. Your line is now open. Hey, good morning, team. Thank you for giving me time here. Just a quick clarification in the Missouri rate case. The residual amount, David, on Sibley, that's about $100 million, correct? So it's relatively small, the residual rate base amount? Yes. Okay. Perfect. The residual rate base. You know, there are some parties who may argue for a different number, but that's the residual rate base in Sibley at this time. Pretty modest numbers you described. Got it. Just I think this might be for Kirk, if he likes, but the AMT, it doesn't really, you know, apply to you because you're sort of below the 1 billion pre-tax marker, right? At least through 2020, you know, this year, the plan. That's correct. I'd add to that on that 15% minimum tax. Part of it is aided by our, you know, our inventory of tax credits as we move forward. You're correct, we expect to be below that threshold. I would think about that, something that we'd potentially if we rise to that level, it would be beyond or coincident with, at the very least, our expected cash taxpayer year, which is beyond the middle of this decade. Okay. Basically no impact from the AMT over the next few years. Second half of the decade is when we could potentially see if something is passed on this front. That's correct. Again, that'll also be somewhat dependent on the ongoing generation of tax credits as we move forward to some extent as we progress around our renewables plans. You're right directionally in terms of all things being equal, that timeframe and that inflection point. Correct. Got it. Just one final one. Just anything on the PPA buyout opportunity. Is it still looking like more likely to happen this year, or your chances have increased given the extension of these tax credits? Anything you could share there? Thank you. I would say that the extension of the tax credits, first of all, if passed, and certainly we're hopeful and optimistic that that takes place, gives us greater flexibility on the repowering side of that equation. That's a benefit, especially as we focus on earnings and certainly affordability for our customers. We're continuing to hold that objective. We're continuing to advance our discussions with counterparties, and I'm maintaining that target to announce at least one of those this year. It may be a buy-in or it may be a buy-in combined with a repowering, but we continue to be focused on that. At the same time, we had robust responses to our RFP that we launched toward our renewables objectives, in particular the 300 megawatts of wind in 2024, followed by 525. We've had good results from that as well, and we're expecting to have some news on that front as we progress through the balance of the year as well. Thanks, guys, appreciate the time. You bet. Thank you. Please stand by for the next question. Our next question comes from Paul Patterson with Glenrock. Your line is now open. Hey, good morning. Morning, Paul. Hi. Can you hear me? Yep. Okay, good. Sorry. I wanted to, and I apologize, but you guys made some comments about, I think, wind production at the beginning of the call. I was wondering if you could, if possible, sort of just summarize what you're seeing in terms of wind production. I apologize, I just wasn't able to completely comprehend it on my end. Sorry. Sure. What I referred to, Paul, was that we achieved a milestone this past quarter. We surpassed 100 million megawatt hours of cumulative wind generation across our portfolio since the company start. Obviously that's a significant milestone in terms of our cumulative wind production. To calibrate it in terms of our total fleet, about a third of our total production last year in generation terms was from wind. If you include our nuclear generation from Wolf Creek, nearly half of our total generation was from emissions-free sources. Wind generation as a share of total portfolio is, and we're higher than virtually every other utility at a third of our total generation. That's what I was citing was that cumulative milestone passing 100 million megawatt hours. Okay. I got it. I think you also, or maybe I misunderstood, you guys were also talking about the performance of wind. I'm just wondering, has there been any issue in terms of production year- over- year? As I recall, there might have been a decrease. I just was wondering how has wind been performing sort of on a same store, if you follow me, kind of how's production been going? Also I was just wondering, we've seen around the country sort of some curtailments in different areas due to transmission constraints and what have you. Have you seen any not just with you guys, but with any neighboring, because you guys have a significant sort of area in terms of wind. Have you seen any projects or what have you in your neighborhood, so to speak, experiencing any curtailments due to transmission constraints? It is a complicated great question, but stepping back to the different elements of your question, I think overall the wind portfolio continues to perform well. Our generation capacity factors, you know, we've got a very large number of sites. In general, the capacity factors in Kansas are as high as virtually any region. A lot of our sites are over 50%, capacity factors, and they continue to perform well. The broader issue of curtailments, it varies across the geography in Kansas, where the bulk of our generation sits, obviously the vast majority. There are pockets in Central and Western Kansas where there is congestion, and there is some curtailment that occurs. It's not an earnings driver for us because it flows through the fuel clause, but it is a factor that impacts customer rates. Obviously we're very attentive and attuned to it, and we advocate at the Southwest Power Pool for projects that can beneficially reduce congestion costs for customers. It's a factor with higher natural gas prices, where the price differentials can be higher. Congestion costs across the Southwest Power Pool and really across the country are higher because prevailing prices. If you have a price differential between a generation resource like renewables, that is no cost and effectively a negative cost because you get a PTC from many of them. The difference between those resources and a natural gas resource, for example, has been magnified at higher natural gas prices. It's something that we are working with the Southwest Power Pool and other constituents to seek to address. A lot of that takes transmission solutions, which takes time. Overall the wind profile across our territory is outstanding. We've got one of the best wind corridors in the U.S. and the world. It's gonna continue to be a great resource for us. Transmission has to keep up, and that's the perennial issue to manage with renewables. Awesome. Thanks so much for the clarity. Of course. You bet. Please stand by for our next question. The next question comes from Nick Campanella with Credit Suisse. Your line is now open. Hey, guys. Thanks for taking my question. A lot of questions been answered so far, but I guess just on resource planning in general, I think there's been discussion about SPP reserve margin increasing, and I'm just curious about, you know, how you're thinking about that and the overall effect on your resource planning if you went there. I know that you're already, you know, somewhat long capacity across the portfolio, but just wanted to check in on that. Thanks. You are tracking things well and closely. Their SPP did recently increase their reserve margin to 15% from 12%, and that will, in effect, next year. You are correct in that it's not gonna have a near-term impact on our capacity requirements, so we will be able to meet that. But it is gonna be a factor in our longer term planning, you know. As we think about our coal retirements, and an overall transformation of our portfolio, obviously we'll be factoring that in and making sure that we can meet it. I think as SPP continues to look at different seasonal reserve margins, so for example, a winter reserve margin, that will be very interesting as well. But the short answer is, we can accommodate that change in reserve margin with our portfolio. We'll factor it into our ongoing plans. On balance, obviously it'll have some impacts to the longer term plans, but relatively modest. You know, we'll be factoring that in as we consider our resource transition, and we'll be working closely with stakeholders as we think about that winter reserve margin requirement as well. Obviously, the winter peaks are lower, but as you look at the average capacity factors across the fleet, as you add more renewables, the winter's gonna be an important thing to consider as well. All right. Great. That's helpful. Then just one small one on the numbers. I know that COLI and AFUDC was $0.07 drag. Can you just remind us, like, what COLI is year-to-date and, in isolation and what's contemplated in your 2022 guidance from a COLI perspective? Sure. Happy to address that. COLI overall, I think we've said in the past, we generally expect about $20 million of COLI impact. That is both a pre-tax and after tax. COLI is not tax effective at the end of the day. year-to-date, relative to our expectations, we're probably $0.04 lower than we would've expected, basically half the year on that COLI, 'cause we've effectively had very little proceeds from COLI, and that's absolutely just a function of the performance of the underlying folks that are insured by that. So, year-to-date, think about that as about $0.04 short of what would normally be our ratable expectations for the year. All right. I'll leave it there. Thanks a lot. Thank you. At this time, there are no other questions. I would now like to turn the conference back to David Campbell, President and CEO, for closing remarks. Thank you. We appreciate all of you joining this morning. Thank you for your interest in Evergy, and have a great day. That concludes the call. This concludes today's conference call. Thank you for participating. You may now disconnect.