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spk09: Thank you for standing by and welcome to Evergy, Inc.' 's fourth quarter 2021 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1 on your telephone. Please be advised that today's call is being recorded. Should you require any further assistance, please press star 0. I would now like to hand the call over to Lori Wright. Vice President of Investor Relations and Treasurer. Please go ahead.
spk00: Thank you, Lateef. Good morning, everyone, and welcome to Evergy's fourth quarter call. Thank you for joining us this morning. Today's discussion will include forward-looking information. Slide two in 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 our non-GAAP financial disclosures. The releases issued today along with today's webcast slides and supplemental financial information for the quarter and full year 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 2021 highlights, an overview of our recently filed Missouri rate cases, along with other regulatory and legislative priorities. Kirk will cover in more detail the fourth quarter and full year financial results, information on sales trends, and provide an outlook of our 2022 objectives. Other members of our 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.
spk08: Thanks, Lori, and good morning, everyone. I'll begin on slide five. This morning, we reported full-year 2021 gap earnings of $3.83 per share compared to $2.72 per share in 2020. Adjusted earnings per share were $3.54 in 2021 compared to $3.10 in 2020. These results reflect strong execution relative to our objectives for the year. We entered 2021 with a midpoint guidance of $3.30 per share in line with our 68% target growth rate range. We were able to deliver $3.54 per share, representing a 14% increase over 2020 and a 7% increase over our initial guidance midpoint. Kirk will discuss the drivers of this year's results as part of his remarks. A critical part of the company's five-year sustainability transformation plan involves a comprehensive program to modernize our grid and invest in infrastructure. We advanced this capital plan in 2021 to pulling $2.05 billion, or $100 million higher than our investor day estimate, to replace aging equipment and improve reliability, resiliency, and security. We also maintain our focus on advancing affordability and regional rate competitiveness. Since 2017, we have delivered a 4.2% overall average rate reduction to our customers. At the same time, we have reduced our total operating and maintenance expenses by 18 percent since 2018, enabling us to pass on these cost savings in our upcoming Missouri and Kansas rate cases. In 2021, our total CO2 emissions were 46 percent below 2005 levels, reflecting strong progress relative to our long-term emissions reduction targets. And last, but certainly not least, we continue to prioritize constructive interactions with our key regulatory and legislative stakeholders. In 2021, we wrapped up the STP dockets in both Missouri and Kansas, and securitization legislation was enacted in both states. We expect that securitization will serve as a helpful tool in managing the company's ongoing fleet transition in the coming years. On slide six, you'll see our recent earnings and dividend growth trends. As we've emphasized over the past year, consistent execution remains at the forefront of everything we do. The $3.53 midpoint of our 2022 adjusted EPS guidance tracks with a 7% compound annual growth rate from 2019, which was Evergy's first full year as a company. This is squarely in line with our targeted long-term annual earnings growth of 68%. Alongside the earnings, you'll see the attractive dividend growth that is tracked within our 60% to 70% dividend payout policy. I'd like to thank my fellow Evergy employees for their continued focus and teamwork in driving these results, overcoming the challenges of another unprecedented year, including extreme weather during winter storm Uri and the ongoing pandemic. We look forward to working together to further advance this track record of execution. As noted on slide seven, we've made significant progress on emissions reductions as we've transitioned our generation fleet over the last decade and a half. Since 2005, we've reduced carbon emissions by nearly half while reducing sulfur dioxide and NOx emissions by 98% and 88%, respectively. Our renewable energy portfolio is approaching 4.5 gigawatts, and we've responsibly retired nearly 2.5 gigawatts of fossil generation over the last 15 years. Our updated integrated resource plans, which were filed last spring, outlined our intention to add nearly 4 gigawatts of renewable generation and retire nearly two gigawatts of coal over the next decade. In 2021, nearly half of the electricity we provided to customers came from carbon-free sources, and we are on pace to reach our goal of a 70 percent reduction in CO2 emissions from 2005 levels by 2030, with a long-term objective of net zero carbon by 2045. Slide eight summarizes our five-year capital expenditure plan, which totals $10.7 billion from 2022 to 26. On a comparative basis, the current 2021 to 2025 plan is in line with what we presented at our investor day last September, with some timing shifts reflected in higher base capex in 2021 and 2023, and slight reductions in the other years netting to a roughly $100 million increase overall. With the addition of 2026, the rolling five-year capital expenditure plan is $235 million higher than the 2021 to 2025 plan. The largest portion of our infrastructure investment is targeted towards transmission and distribution. The program is focused on replacing aging equipment and modernizing the grid, driving benefits for our customers by improving reliability, enhancing resiliency, and the ability to withstand extreme weather, upgrading customer systems and the customer experience, and increasing security. As we advance the use of smart grid technologies and transition towards a lower cost, lower emissions generation fleet, Our investments will also enable us to reduce costs to serve customers, which helps to create a virtuous circle as we pass on these savings. Slide 9 summarizes our progress in driving cost savings and capturing efficiencies in how we work. Enabled by the 2018 merger and a comprehensive program across the business, we have reduced costs by $233 million, or 18%, since 2018. We're laser-focused on operational excellence as we leverage investments and technology to operate more effectively and efficiently. We're also building more and more flexibility into our generation operating model in the southwest power pool market, which continues to see an increasing penetration of renewables generation. And we're not done, as we are targeting a further 11 percent reduction in total O&M by 2025 as part of our five-year plan. Thus far, we've been able to manage the impacts of inflation on our O&M costs, and we have developed plans to capture the vast majority of our targeted savings. The back half of 2021 brought increasing pressures on fuel and purchase power costs, as has been seen across the country, typically at higher levels elsewhere than what we've seen in our jurisdictions. And it appears that those trends may continue in the current macro environment and geopolitical context. Affordability and improving regional rate competitiveness are core elements of Evergy's strategy. As shown on slide 10, since 2017, Evergy has been able to reduce rates by an average of 4.2%. outpacing regional peers, and at a level well below inflation. On the slide, we lay out how we've been able to deliver these savings across each of our four jurisdictions from 2017 to 2021. This topic remains at the forefront for our customers and stakeholders, and going forward, maintaining affordable rates will continue to be featured as a priority objective in our five-year plan. Turn to slide 11. I'll give an update on our ongoing Missouri rate reviews, which we filed in January. Starting on the left-hand side with Missouri Metro, we have requested a $44 million rate increase, excluding the rebase of fuel, based on a 10% return on equity, a 51.2% common equity ratio, and a projected $3.1 billion rate base as of the proposed May 31, 2022 crew update. The primary drivers of the rate request include our increased infrastructure investments, which improve reliability, enhance customer service, and enable the company's transition to cleaner energy resources, updated depreciation rates that better align with the estimated remaining lives or assets, and increased property taxes. These increases are significantly offset by roughly $55 million of lower annual operating costs, savings that we are pleased to be able to pass on to customers. Moving on to Missouri West, we requested a $28 million rate increase, excluding the rebates of fuel, and based on a 10% return on equity at 51.8% common equity ratio, and a projected $2.5 billion rate base as of the proposed true update. Missouri West rate request drivers are similar and include an increase from infrastructure investments, updated depreciation rates, and increased property taxes partially offset by ongoing customer savings and cost reductions of roughly $57 million per year. These savings effectively lowered the rate increase request by more than 60%. The Missouri West case also includes the handling of our previously retired Sibley Power Plant. We've been deferring the revenues associated with the foregone O&M, resulting from the plant's retirement in 2018. As part of this case, we've offered to return these revenues back to customers over the next four years, which would reduce annual revenues by roughly $10 million, though with no impact on earnings. To summarize, we believe that the pending Missouri rate reviews are relatively typical and straightforward, with two main elements. First, passing on the benefits of cost savings, and second, adding infrastructure and grid modernization investments that are consistent with and advance the objectives of Missouri policymakers and stakeholders. We're excited about the benefits that these investments will deliver to our Missouri customers. Now, the procedural schedule is not yet final, but on the bottom of slide 11, you'll see our estimated timeline from here. We expect staff and intervener testimony will be filed in June. with rebuttal testimony in July, potential hearings in early September, and finally commission orders in November. If approved as filed, excluding fuel, the rate request would represent an increase of 5.2% for Missouri Metro customers and a 3.8% increase for Missouri West customers, both of which are well below the rate of inflation we've seen since our last rate cases. Moving to slide 12, I'll provide an update on other regulatory and legislative priorities, beginning with our predetermination docket in Kansas. As a reminder, last September, we initiated a proceeding to approve the elimination of coal at the Lawrence Energy Center, retirement of Lawrence Unit 4 with recovery through securitization, and the addition of 190 megawatts of solar generation in Kansas. Later in the year, last year, we filed a request to temporarily suspend the procedural schedule to allow time to develop more clarity on solar tariffs, the potential for tax incentives to improve customer economics, and the resolution of supply chain and customs issues that could impact pricing and availability. Given the lingering uncertainty around those issues, rather than keeping this docket on hold, we have withdrawn the filing and plan to file a new application once definitive agreements are reached with the solar developer. The elements of the plan are unchanged, and we still expect to seek predetermination approval for the cessation of coal, the retirement of Lawrence IV, and the addition of 190 megawatts of solar. While this may impact the timing of the solar farm addition, it does not have a meaningful impact on our earnings expectations as the structure for the new solar farm was expected to contribute less than a penny to annual adjusted EPS in both 2024 and 2025. This is due to the market-based rate construct that was pursued in this case, under which the earnings profile is tied to the time that Evergy can monetize the value of the ITC tax benefits of the project in the back half of this decade. In parallel, we are in the process of evaluating competitive proposals for up to one gigawatt of new-owned wind resources that would come online in the 2024 to 2025 time frame. Kirk and his team are overseeing our renewables efforts, and he will highlight our priorities in his remarks. Other regulatory items include recovery of costs incurred during winter storm Uri. In Missouri, we are awaiting commission approval of our request to defer approximately $300 million at Missouri West with plans to securitize the costs and smooth the impact on customers over multiple years. We are also seeking approval to defer and return approximately $25 million of net benefits to Missouri Metro customers. We expect to reach resolution on the deferral request in the second or third quarter and a commission decision on the securitization of the Missouri West costs by the end of the year. In Kansas, last month, the KCC staff filed its recommendation to approve our recovery plan of approximately 115 million of URI costs in Kansas Central and the return of approximately 35 million of benefits in Kansas Metro. We are working closely with all parties, and we expect to finalize the details of the path forward in the first half of this year. In 2021, we filed our integrated resource plans in Missouri and Kansas, providing an updated 20-year roadmap for our generation fleet transition in conjunction with our announcement of our long-term emissions reduction targets. We will file our annual update to the IRP in both states by July 1st. I'll wrap up this slide with a legislative update focusing on Missouri. Bills have been introduced to extend and update legislation that was passed in 2018, widely referred to as Plant and Service Accounting, or PISA. We've been utilizing this legislation since 2019, supporting our investments in grid modernization and improved reliability. We believe that the bill is good policy and enjoys wide support, but whether it ultimately advances this year will depend most likely on unrelated issues that may receive the bulk of legislative attention. We are focused on working with key stakeholders to advance the PISA extension this spring, but given the provisions, of the currently existing piece of legislation, this is an initiative that we would also be able to pursue next year. In addition, in Missouri, we are pursuing mechanisms to enable the efficient recovery of costs outside of our control, notably property taxes. Before handing it over to Kirk, I'll wrap up on slide 13, which summarizes the Average E-Value Proposition. The left side of the page covers the core tenets of our strategy to advance affordability, reliability, and sustainability. through a relentless focus on our customers, supported by stakeholder collaboration, sustainable investment, and financial and operational excellence. The right-hand side of slide 13 features what we believe are particularly attractive and distinctive features for Evergy, given our business mix and geographic location. We are excited about the opportunities for our company, and we are committed to the sustained effort required to deliver against our high-performance objectives. I will now turn the call over to Kirk.
spk05: Thanks, David, and good morning, everyone. I'll start with results for the quarter on slide 15. For the fourth quarter of 2021, Averagy delivered adjusted earnings of $37 million or $0.16 per share, compared to $64 million or $0.28 per share in the fourth quarter of 2020. Fourth quarter adjusted EPS was driven by the following items as shown on the chart from left to right. First, we had unseasonably warm weather across the end of the quarter, particularly in December, resulting in significantly fewer heating degree days as compared to the fourth quarter of 2020, and driving 7 cents of unfavorable contribution from weather. When compared to normal weather assumed in our original plan, the mild weather negatively impacted our results by 10 cents. The unfavorable weather was offset by a 4% increase in weather normalized demand, or approximately 8 cents per share. relative to our expectations for the quarter, whether normalized demand was approximately 4 cents favorable, as we began to see demand recovery, which we previously forecasted to be delayed into 2022. Stronger performance in our Average Ventures and Power Marketing businesses drove 3 cents of EPS versus the fourth quarter of 2020, which offset 3 cents of lower EPS from Coley, as we did not receive proceeds during the fourth quarter of 2021, while the prior fourth quarter included the majority of our Coley proceeds in 2020. Income tax related items drove a net decrease of four cents per share. This was primarily due to the impact of the Kansas income tax rate exemption, which led to a lower tax yield in the fourth quarter, as well as the expiry of certain tax credits in November of 2020. Finally, shown in the final two bars, adjusted EPS for the quarter was $0.09 lower due to the expected timing and phasing of certain cost items. $0.06 of this variance was due to the realization of higher O&M, including bad debt expense during the fourth quarter, resulting from timing shifts within the year. The remaining $0.03, as shown in the final bar, was the result of pulling forward certain cost items from future years. Of note, our fourth quarter and adjusted EPS for the full year excludes the mark-to-market impact of one of our Evergy Ventures investments, which went public during the quarter via a SPAC acquisition. We continue to expect to monetize this investment when the lockup restriction expires later this quarter, and have elected to adjust the gains and losses related to investments which are subject to a temporary sales restriction, such as this one. I'll turn next to full year results, which you'll find on slide 16. For 2021, adjusted earnings were $813 million, or $3.54 per share, compared to $716 million, or $3.10 per share, in 2020. As shown on the slide from left to right, the key drivers of this 14% year-over-year increase include the following. Favorable weather, which benefited us through the first three quarters of the year, was partially offset by the warmer-than-normal fourth quarter and drove a $0.17 increase. Higher EPS in 2021 versus 2020. Weather was $0.08 favorable compared to normal weather assumed in our original 2021 plan. Weather normalized demand increased about 1.6% and contributed $0.07 versus 2020. As expected, revenues from higher FERC transmission investment resulted in a $0.13 increase. Favorable income tax-related items of 7 cents were primarily driven by the impact of the Kansas income tax exemption and higher amortization of excess deferred income taxes, partially offset by lower tax credits. As shown in the next three gray bars, higher depreciation, an increase in property taxes, lower year-over-year COLE proceeds, and a slight year-over-year increase in share count combined led to a 12-cent year-over-year decrease. And finally, stronger year-over-year performance in power marketing and energy ventures, partially offset by the pull forward of costs from future years I mentioned during my fourth quarter comments, combined to drive EPS 12 cents higher. While the net effect of these items help us drive our strong year-over-year results into 2021, we don't expect this outperformance to be recurring, and our guidance for 2022 reflects a more typical earnings contribution from these areas. Turning to slide 17, I'll provide a brief update on the recent sales and customer trends. On the left-hand side of the slide, you'll see that partially aided by weather, our retail sales increased 3.1% in 2021, with all three sectors experiencing year-over-year increases led by more robust increases in particular in commercial and industrial. Looking to the right side of the slide, after adjusting out the effects of weather, retail sales increased 1.6% for the full year. The industrial sector, which is least weather sensitive, saw the largest increase, primarily driven by the oil and petrochemical industry. Commercial demand also increased nearly 3% year-over-year as both employees and customers returned. Weather normalized residential sales decreased in 2021 as some employees returned to in-person office work. The overall 1.6% demand increase was below our original expectation of 2%, which assumed a more accelerated pace of return to pre-COVID conditions, in particular in the commercial sector. Underlying the continued growth in residential and commercial customers is a strong labor market. Highlighted by Kansas and Kansas City Metro, unemployment rates of 2.2% and 2.5%, respectively, beating the national unemployment rate of 3.7%. Manufacturing and logistics industries in particular have seen strong employment growth that continued to a solid economic recovery. Although, as I mentioned last quarter, the Ford plant in our jurisdiction has been experiencing headwinds from chip shortages, the plant has begun to ship its all-new electric E-Transit cargo van produced right here in Kansas City. Overall, we experienced a positive bounce back in the second year of the pandemic, and our economy is well positioned to continue the trend back towards pre-pandemic levels. As a result, we expect about a 1% increase in weather normalized demand in 2022, which is part of the bridge to our reaffirmed 2022 adjusted EPS guidance of $3.43 to $3.63, which I'll review next on slide 18. Starting on the left side of slide 18 and beginning with 2021 adjusted EPS of $3.54, We removed the $0.08 impact of weather compared to normal from our 2021 results, as well as the $0.12 impact from the outperformance of our power marketing and average ventures businesses, again, net of the cost that we pulled forward into 2021. Although we expect these businesses to continue to contribute earnings going forward, this adjustment is merely associated with the outperformance in 2021, leaving their expected contribution in our 2022 guidance. After adjusting for these items, the drivers to our 2022 guidance midpoint include $0.08 of increased retail demand. And overall, again, this represents about 1% increase in year-over-year weather normalized demand. About half of this increase reflects the realization of more normal demand in 2022, which we'd originally expected to occur in 2021. This shift is due to the observed delay in returning to a normal demand mix due to lingering COVID effects in the past year. The remaining portion reflects normal year-over-year load growth in 2022. We expect approximately $0.09 of additional earnings from transmission revenue as we continue to make investments to improve transmission infrastructure. And finally, additional O&M savings and the expiry of merger-related bill credits contribute $0.06 and $0.04, respectively, and when combined, serve to offset the impact of higher depreciation expense not yet reflected in rates while other items, both positive and negative, drive the remaining two cents of the year-over-year increase. Turning next to slide 19, our strong results in 2021 reflect our ongoing focus on continuing to build a track record of consistent execution. We've reaffirmed our adjusted EPS guidance of $3.43 to $3.63 in 2022, as well as our long-term compounded annual EPS growth rate of 6% to 8% from 2021 to 2025, which is based on the midpoint of our original 2021 guidance. As David mentioned earlier, our updated five-year CapEx plan from 2022 to 2026 totals $10.7 billion and is consistent with a targeted rate-based growth of 5% to 6% from 2021 to 2026. These financial targets enable us to achieve our overarching objective to improve affordability, enhance reliability and customer service, while advancing our sustainability and transitioning our generation fleet. In order to realize these objectives over the multi-year plan, we are focused on achieving our key goals in 2022, which I'll summarize on slide 20. Building on the positive momentum from our strong 2021 results that exceeded our original guidance, we remain focused on continuing to meet or exceed our financial targets, including our reaffirmed 2022 guidance range, while driving operational efficiencies and maintaining our balance sheet strength. Over the last few years, we've worked hard to invest in our utilities to improve reliability and enhance customer service. Our successful efforts in driving efficiencies to reduce operating costs since the merger now allow us to pass approximately $110 million of annual savings back to our customers in Missouri to help offset a significant portion of the rate request, allowing us to deliver the benefits of those needed investments while keeping rates affordable for customers. This year, we look forward to a constructive outcome in the Missouri rate cases as the next important step in achieving our objectives for the benefit of all stateholders. On the renewables front, as David mentioned earlier, we've recently withdrawn our predetermination filing in Kansas, which included the addition of 190 megawatts of solar. We're actively working with the developer to resolve remaining issues to finalize the definitive agreement for this project and file a new application with the KCC later this year. Since our initial filing last fall, we've completed much of the documentation associated with the project. The only significant items which remain relate to issues arising from global supply chain uncertainty, and customs enforcement leading to importation delays. We are focused on resolving these remaining issues while ensuring certainty of schedule and affordable costs for the benefit of our Kansas customers. And should the expansion of tax incentives for solar, including the PTC and direct pay, ultimately see passage, this could serve to improve project economics for our customers as well. Turning to wind in the fourth quarter of 2020, We launched a request for proposal process for up to one gigawatt of new wind in order to achieve our targeted 300 megawatts in 2024 and 500 megawatts in 2025. We saw robust participation and have since shortlisted our initial bids to a select group of projects which, when combined, represent a multiple of our targeted 800 megawatts. The proposals received provide us the opportunity to select the projects that offer the best balance of risk and price for our customers. We are targeting completing due diligence and negotiating definitive agreements through mid-2022 with a notification to proceed on construction issued to developers in the first half of 2023. And finally, since we introduced the concept of potential PPA buy-ins on Investor Day, we've made progress in engaging with project owners and continue to believe that there is a path to make this opportunity a win-win-win for our customers, shareholders, and counterparties. While we saw the viability of this strategy as being enhanced by potential federal renewable tax reform and the proposed refresh of the 100% PTC, we believe there is potential for this opportunity even if tax reform does not see passage. We're currently involved in active discussions with multiple counterparties with the objective of executing at least one buy-in this year. With that, I'll hand the call back to David.
spk08: Thank you, Kirk. So for those on the call, we appreciate your time today, and we'd like to open it up to questions.
spk09: As a reminder, to ask a question, please press star 1 on your touchtone telephone. To withdraw your question, press the pound key. Again, that's star 1 on your touchtone telephone to ask a question. Please stand by while we compile the Q&A roster. Our first question comes from the line of Char Parisa of Guggenheim. Your line is open. Hey, good morning, guys.
spk05: Good morning, Char. Good morning.
spk10: David, Kansas seems like it's been a little bit noisy or maybe even somewhat hostile to actually both you and the KCC. You know, we saw one Republican obviously demoted from a committee because of an op-ed he wrote. There was obviously recently legislation floating around for a price cap. Some lawmakers have been really honed in on the KCC. I guess, can we just get any color on your conversations in recent weeks there and any efforts to sort of pivot the conversation? It's just been a little bit more noisier than we're used to.
spk08: Sure, it's a good question. You know, we're in the legislative session, which is always active. Look, I think in Kansas there's an active dialogue, and we appreciate that. It's part of why you see us feature the rate reductions that we've been able to deliver and are improving rate competitiveness. And I would describe it as a lively conversation, but there's balanced input from all sides. There was a presentation, for example, that KCC staff gave in one of the committees, in a Senate committee that highlighted how our rates over the last 10 years in Kansas Central have have been flat to declining over 10 years, so well below the rate of inflation. And that was certainly noted. And, of course, you recall how securitization legislation was passed last year with overwhelming majorities in both houses. So we're very focused on regional rate competitiveness. We know how important that is. There are some stakeholders in the state, and there's a variety of opinions around renewables and others, as reflected in a variety of opinions around our country. But we think it's a constructive dialogue overall, and we're certainly in the middle of it, and we're very focused on the same priorities that our key stakeholders have in the state.
spk10: Got it. Thank you for that. And then just lastly, maybe for Kirk, just maybe just on the buy-in, how does that interact with the IRP update process? And just remind us, are any buy-ins in the CapEx plan, or is this sort of an opportunity that's incremental?
spk05: Sure, sure. And so the first answer to the second part of that question is none of those buys are included in our capital expenditure forecast. That would be flexed up, if you will. In terms of the overall process around the IRP, As the PPAs that underpin those buy-ins already support our renewables and our ability to serve load, this would simply be a shift in perspective of how we deliver that in the near term, if you will. So we'd be replacing an existing resource that we avail ourselves through a PPA with an owned resource for the same number of megawatts. It's really the repowering on the back end of that and the extension potential for it, which is obviously beyond the scope of at least our five-year plan that would have that impact, if that makes sense.
spk10: Got it. No, that's helpful. Very clear cut quarter. Thanks, guys. Appreciate it.
spk09: Thank you, Sean. Thank you. Our next question comes from Durgis Chopra of Evercore ISI. Your line is open.
spk03: Hey, good morning, team. Thank you for taking my question. Kirk, just following up on the PPA buyout opportunity, in terms of like basically as I understand it, right, this is basically a PPA converted into a rate base. First, am I thinking about that correctly? And then do you need to sort of get regulatory approvals for it to be ultimately earnings accretive? And what does the timeline look like?
spk05: Well, the timeline, as I said, we're currently actively involved in discussions with multiple PPA counterparties about a potential buy-in, which is why, as I indicated, we feel comfortable in at least targeting one of those to occur this year. Obviously, it's a two-party negotiation, so we've obviously got to get to closure on that. In terms of the regulatory process, directly speaking, I think the way you described it is correct. We're basically taking a PPA pass-through and converting that to capital. ultimately with the focus being for the benefit of the customer, i.e., the target and the first step of that is if we can buy in that PPA at an attractive overall capital price so that the associated impact on rates with that, if you will, rate-based investment provides customer savings, that's the most important step. In terms of how that gets adjudicated, it would go through a similar process as really any rate-based investment. If that was in Kansas, we'd go through predetermination. If it was in Missouri, we'd actually pursue that through different means in an ordinary rate case context. Combining that with repowering, it's just an increase in the overall capital, if you will, or an extension of that timeline, albeit rather than a pass-through, it would be a rate-based investment with an all-in savings, right? I think about that almost like a blend and extend type approach, if you will.
spk03: That makes a lot of sense. Thank you for explaining that, Kirk. And so essentially, I mean, the earnings accretion comes from, you know, rate bases, the investment going through future rate cases, if you will. Just maybe shifting gears, can you just talk about the, you know, the O&M savings? That's been a sort of very impressive execution on that front. How are you thinking about sort of inflation pressures, supply chain constraints? Are those hurdles, you know, for you to achieve your target for 2022 and beyond? And how are you tackling those? Thank you.
spk08: So it's a good question. Thus far, and obviously in the macro environment, that continues to be dynamic. So one we're highly attentive to, as is everyone. Thus far, we've been able to manage the inflationary pressures on the O&M side. It has some impact. The supply chain issues have some impact on the cost and availability on the capital side. We've also been able to work through those as well. And we're confident that we can continue to manage it. In our 2022 plan, as you may have seen in the waterfall that Kirk walked through from 21 to 22, it's an overall $0.06 uplift in O&M, so we have some cost savings this year. We also had some, you know, impact last year from the outperformances, the unusual outperformance in our unregulated business did have some impact on our O&M cost, modest, but that's part of the uplift we see going into next year. But it's an ongoing effort that we're going to drive 23, 24, and 25. So we have, as part of our five-year plan, we already have teams in place that have identified the bulk of those savings and how we're going to achieve them, and we'll be in execution mode in the back half of this year and in the upcoming years. So it's got to take sustained effort. It's been a comprehensive program across our whole company. Kevin Bryan, our chief operating officer, is coordinating that effort on our behalf, but the company's got a great track record in this area. We know how to do it. It's going to take sustained execution, We certainly acknowledge that, but we have the tools and I think the plans in place to make it happen.
spk03: Got it. Thank you for taking my questions. Appreciate it.
spk08: Thank you.
spk09: Thank you. Our next question comes from Michael Lapides of Goldman Sachs. Please go ahead.
spk02: Hey, guys. Thank you for taking my question and congrats to a strong year. I want to talk about the PPA buy-ins as well as any building transfer look uh you know congress obviously hasn't been able to get anything across the finish line we'll see if they try to do something in the lame duck session at the end of this year doesn't look like anything's happening before uh the midterms just curious do you think about pulling forward all of your renewable plans to capture what could be the safe harboring benefit that some of the developers we you know, who themselves may be thinking about repowering or thinking about building new solar, you know, bringing forward the safe harbor provision benefit that would happen because they've got it safe harbored at last year or two years ago PPP or IPP level versus what this year's or next year's would be.
spk05: Sure, it's a good question. I mean, certainly we've thought about that, at least in the context of the buy-ins and repowerings around that safe harbor. That would obviously require us to make a capital outlay to obviously safe harbor that component of it. We'd certainly be mindful of doing that, but we'd also be reasonably cautious about that around the context of having line of sight or certainty of our ability to get that PPA buy-in and repowering negotiated. But that's certainly something that we're looking at. At the same time, we're hopeful that ultimately, obviously, in the current political environment, there's a lot of distraction and chaos. But, you know, if ultimately those provisions of Build Back Better ultimately do get passed, that obviously gives us greater flexibility. But we're certainly mindful of availing ourselves of that option in the current context from a safe harbor standpoint.
spk08: And, Michael, all I'd add is the – yeah, the – from a – this is David. So from the Perspective of the integrated resource plan and our multi-year capital expenditure plan, we look at the overall level of capital we're expending. We look at the overall rate impacts and affordability. We do think that bringing on renewables is a win-win because it's typically lower costs as well as lower emissions, but we are going to track with the program with respect to the IRP. Part of the rationale for why there was some sequencing shift when relative to solar was in consideration of some of those factors around a safe harbor. So the category of truly new development, you know, we're sensitive to all those various factors and balancing them. Of course, we have an IRP update that we'll do this year, and it's a dynamic market, and, you know, we're going to be responsive to what we see. The PPAs are a little bit different, the buy-ins and repowerings, in that that's, as Kirk described, an existing set of resources. So that's, you know, that's more complicated to be able to negotiate with an initial set of counterparties, obviously, but For those, you know, if we have opportunities that are sooner, you know, we'll certainly look for that. But you're just subject to what you can accomplish with the counterparties. Though, of course, those are all basically wind. So if you're talking about the VBAs and repowerings, those are really on the wind side. But the safe harbor point that you made is relevant, and we'll seek to do as many of those as we can, but within the constraints of what the counterparties will do with us.
spk02: Got it. And then when we think about the buy-in and repowering, Can you just remind us how rate making for that would work? Meaning, if you bought the asset first, how do you get the acquisition in the rates? And then if you repower it down the road, how does the capital spent to repower the asset get in the rates?
spk05: Well, first of all, I could come in two forms, right? You know, buy-in and repowering can be, you know, a single negotiation with a counterparty that we can contract with on both elements of that. Obviously, that would be the owner of the existing asset, who is our counterparty under the PPA, and a potential repowering initiative almost akin to kind of a bill transfer aspect with that same counterparty. So negotiating those in tandem, that's sort of my blend and extend example. So it's sort of a single view of the capital required to buy in the remaining years of the PPA combined with the capital and the repowering. That would be an overall rate-based investment. And again, that would need to be viewed by us especially through the lens of affordability for our customers. It only makes sense for us to do this as a first order if we can substantiate that capital investment when combined to result in a savings to the customer relative to the PPA that's being passed through and obviously supplemented by greater certainty of what those costs are in the long run. There is the possibility that, you know, there could be a negotiating of a buy-in and a later repowering. That would really be a bifurcation of really two capital investment considerations, right? A little bit more challenging in one sense because you've got to substantiate the affordability and the prudency of both of those two things individually, which is why I think it's a cleaner path to do them combined. But there are opportunities to do both. That would mean we'd go through and say, here's the capital investment to replace this existing PPA pass-through. Here's the savings around that. That would be separately adjudicated, and then we'd approach the repowering separately.
spk02: Got it. And then finally, can you get them in the rates between rate cases? Can you remind me? I thought Kansas had a tracker or a rider where you could put it in, but can you remind me on the Missouri rule as well?
spk05: Not a tracker on the Missouri side, if I understand what your question is there. Got it.
spk02: So you just have to wait for the next GRC to get it? Correct.
spk05: Yes, that's right.
spk02: Cool. Thanks, guys. Much appreciated.
spk08: Yeah, Michael, again, all I'd add on that is that you could take it through predetermination. So you get a sense for whether how it will be treated in the upcoming rate case. And we've got a rate case scheduled for 2023, as you know. And following a rate case, you can do an abbreviated rate case six months into 2024. So there are a couple different pathways you can go down. Starting with the predeterminations to get comforted as to how it will be treated, then you can do it either in the general rate case or an abbreviated rate case immediately following one that you complete.
spk02: Got it. Thank you, David. Look, appreciate it, guys.
spk09: Thank you. Thank you. Our next question comes from Julian Dumoulin-Smith of Bank of America. Your question, please.
spk11: Excellent. Hey, good morning. Thanks, team, for the time. Perhaps, listen, I don't want to hammer too much on this buy-in opportunity, but just, you know, you say that you've got a few contracts, at least one here. What's the order of magnitude of megawatts that we're talking about here? Again, I'm not trying to pin you guys down, just curious if you can speak to it.
spk05: Yeah, sure, Julian. First of all, we're focusing on that subset of those PPAs that total, for us, about 3,800 megawatts. I think we had that as part of our presentation in Investor Day. There's about 1.25 gigawatts of that where the PTCs are either already expiring or approaching expiring. That's kind of the sweet spot. So we're really currently focusing on counterparties in that particular category. I would say in the near term around our objective of at least getting one of those executed this year, which is our goal, one to 200 megawatts would probably be a good rule of thumb to think about.
spk11: Right. Effectively establishing a framework for how to scale that up to, you know, around that one, two, if you can make it work.
spk05: I think that's a fair way to characterize it.
spk08: At some level, Jim, we view that – PPA base as a pipeline. Now, that pipeline is nearer term than longer term, but we view that as a long-term pipeline for us.
spk11: Absolutely. Yeah, that's transparent. I appreciate that. And then related, I mean, I saw this bylaw tweak, if I can call it that, to have a larger shareholder of 15% be able to call a meeting. Admittedly, I know we've been through a lot. What drove that specific change of late here, if you can speak to it?
spk08: Sure. We thought that was just an improvement to our governance processes. We didn't have the ability for a shareholder to call that kind of meeting. So in evaluating our overall governance practices, we saw that it would be viewed as an enhancement to create that ability to call the meeting. So we looked at where the thresholds were for peer companies and where other companies are. A lot of companies still don't offer that, but we wanted to add that as an additional capability of shareholder-friendly proposals. But I view that as – I put that in the category of our overall evaluation of our ESG policies and approaches of trying to continue to improve on those.
spk11: Got it. I know you alluded to this earlier. Just in brief here, the Kansas rate cap legislation, I mean, how much support does the proposed law that would cap increase that 1% per year have? I mean, tough question to ask, but curious if you can provide any context as to the positioning here a little bit more.
spk08: We do not think that it has broad support. We don't think that it's going to even get out of committee. So, you know, lots of proposals get offered. I've seen that over my career and all the legislative sessions that I've seen in various states. But, no, we don't even think that will get out of committee. It's had some discussion, but we don't think it's got wide support. Excellent. Thanks for closing out. You bet. Thank you, Julian, for joining us.
spk11: Have a great day. Cheers. You too.
spk09: Thank you. Our next question comes from Nicholas Campanella of Credit Suisse. Please go ahead.
spk01: Hey, good morning. Thanks for taking my question. I was just curious in light of the comments on the 190 megawatts of solar. You talked about looking for more clarity on tax incentives, supply chain, pricing impacts. Can you just help us think about how that translates to the overall roughly 2 billion renewables CapEx program that you have outlined here? I know it's fairly back-end loaded, but are you kind of taking a wait-and-see approach to this capital because it's so far out, or does the CapEx that you have in the slides today kind of reflect this supply chain and pricing pressures that you're seeing? Thanks.
spk08: So I'll start and then hand it over to Kirk. So I would characterize the solar project in particular as pretty unique in that it's got that market-based structure, and that's really because of the ITC benefits that are currently in place and how – how to take advantage of those most effectively working with our counterparty. And we're seeking a level of certainty in that agreement, and that's part of why we decided to withdraw the docket and we'll file it once we have the certainty. So it's really related to supply chain issues in particular, and we're seeking the certainty because of the importance of the affordability point that we mentioned. But because of the structure of that agreement, feel it's, you know, it's a minimal contributor to earnings in 24 and 25. Our wind additions that we've got slated in 24 and 25 in the end of both years, we believe we'll be able to pursue in a more traditional way. So, there is some supply chain pressure, but obviously those are a little out further in time, and those reflect our latest view in light of what we've seen in the RFP process that we went through. We got some pretty robust bids. So, that continues to be our expectation. It's, you know, they're ongoing wild cards. I would say it's a macroeconomic situation that's pretty dynamic, but that reflects our best expectation as of now.
spk05: Kirk? Yeah, the only thing I'd add to that on the 190 megawatt solar project is, as David characterized it, I agree, unique around some of those supply chain issues. I think I've mentioned in my remarks that Coming out of our initial predetermination filing, there was still some lingering uncertainty about what the administration was going to do around whether or not they were going to extend and what the scope of that extension might look like when it comes to tariffs. And there are existing, I mentioned this as well, in terms of customs and border protection, there are these withhold release orders around concerns around certain province from China and forced labor provisions, which are kind of holding things up a little bit. So those are the best two examples of the uncertainty, and I think that's more unique to solar in this particular project. We wanted to get some clarity on that. Our counterparty wanted to as well. We've obviously seen the Biden administration give clarity around the, at least around what their intentions are in terms of the tariffs. So it gives us a better backdrop to do that. We thought it was prudent to do so because we're very focused on this next step in our evolution of moving from what's been primarily a PPA-dominated strategy to an own renewables-dominated strategy. Very important to us that, you know, that first floor, at least in the solar side, we do so with an eye toward affordability. So we didn't want to move too fast in negotiating this for the sake of getting it done. We wanted to do it with clarity and certainty about, as I said, cost and schedule for the benefit of our customers. And the reason David mentioned the unique nature of that particular project from a structural rate perspective, it is not, as David indicated, I think, in his remarks, a major contributor in the early years of our plan due to some of the tax aspects of it. So it gives us a little bit greater flexibility to work through some of those unique issues in the near term.
spk08: Yeah, I'll go ahead and describe maybe a corollary of your question. We've given earnings guidance to our target growth rate range through 2025. In 2025, the total contribution from the new renewables in our plan is less than 2% of earnings. So it's, you know, a factor we'll continue to watch. We're optimistic we'll be able to make it happen and drive benefits for our customers in doing so, but it's still a relatively modest portion, even in 2025.
spk01: Got it. Yeah, that's very clear, super helpful. You know, really appreciate that. You know, Just on your comments about the higher fuel costs and inflation and trying to translate more savings to customers, obviously, you guys have already done a great job in the base plan today, but you're also going to be filing an update to the IRP this July. I'm just curious if we're getting to a tipping point where there's just an argument to further accelerate some of the fossil fleet and how you're thinking about that in terms of the closures. Thanks.
spk08: You bet. So, yeah, lots of intersection points. You know, inflation is a broader issue in the energy sector. We're happy that we've been able to manage inflation better than certainly you see across other parts of the electric space, but it's still an issue. We hope that it's going to be temporary. In terms of the implications for our generation fleet transition, you know, we try to be thoughtful in our integrated resource plan. We'll take the same approach in our update this year and beyond in terms of the pace and sequencing. New renewables do offer some very attractive features in terms of relative costs and relative emissions profile. Now, it's hard to accelerate that in the very near term given the supply chain issues, which have had some knockout effects on pricing. So I would guess as we go through our update, you're going to see a similar pacing and sequencing in our plan rather than in acceleration, again, because acceleration runs into some of the, you know, you may not be able to achieve all the same benefits in terms of lower costs. And who knows what's going to happen in Washington, but if There is momentum around some features in terms of additional incentives for renewables. Of course, that would drive incremental benefits for customers. So you can't wait and depend on something that's uncertain in Washington, but at the same time, if there are some factors over the near term that are raising costs, that bounces against rushing into things. And the other dynamic is, you know, I think we'll have to make sure we have a measured pace to this approach. Yesterday in In our jurisdiction, there was very low wind and it was very cold weather. And the reliability of the nuclear fleet and the fossil fleet was an important contributor. So we think we can manage it over time as we have. Nearly half of the electricity that we provide our customers was from emergency resources last year between nuclear and wind. So we think we've been on a great track record. We've been able to do that while maintaining reliability. And we're going to be focusing on that balance going forward. But to your broader point, I do think there's a way to drive that transition And with lowering costs and lowering emissions while ensuring reliability, but it won't happen overnight. It's got to be in a paced program.
spk01: That's helpful. And one more, if I can, just, you know, if I'm hearing you right, the PPA buyout opportunities are an upside to the capital plan. And just, you know, as we think about putting more CapEx into the model, what's your ability to just raise CapEx without additional growth equity capital?
spk05: So it's a good question. One of our primary objectives, as we've said a number of times, we have the ability and we're targeting being able to fund our capital expenditures through our five-year plan without the need for new equity. We do have some degree of flexibility. Obviously, it's not unlimited from an internal generated equity capital standpoint. But I think in the context of my answer to Julian's question earlier, We have enough flexibility, at least in the near term, to get that targeted least one PPA buy-in done within the context of our plan. So we've got enough flexibility to do that, but it's certainly not unlimited. But we're not planning on doing a significant order of magnitude of those, at least in the near term of our five-year plan. It would be additive, obviously, not only from a capital perspective, but also from an earnings perspective.
spk01: Really appreciate the time today. Thank you. Thank you.
spk09: Thank you. Our next question comes from Travis Miller of Morningstar. Your line is open.
spk07: Good morning. Thank you. Good morning. Wondering, holistically, if you look at that CapEx program, $10 billion plus, and then you think about the regulatory activity that you have going on right now in Missouri and essentially in Kansas here coming up, how could the outcome of those kind of near-term regulatory outcomes impact that full CapEx plan? And thinking about if things go well, then you might upsize it. If things go poorly, you might downsize it. What are your thoughts there in terms of sensitivity?
spk08: You know, I think we try to be thoughtful in framing the capital expenditure plan that makes sense and drives benefits for customers and is a multi-year program, so it's not a program that we – you know, toggle based on a result. Both these rate reviews are pretty straightforward that are underway in Missouri, and we expect to be very similar in Kansas. In other words, you've got a set of infrastructure investments that we've had the chance to preview and review, actually, as part of the STP dockets that went on last year and through early this year. We think they're very consistent with public policy in Missouri, as reflected in the legislation that was enacted in 2018, and will drive similar benefits in Kansas. We look at our overall program in terms of what we expect the overall rate impacts will be because we're very focused on affordability. Our level of rate-based growth is a little lower than a lot of our peer utilities. We think that will actually further help us in that regional rate competitiveness. But we still have a robust program. So we always look at it year to year in terms of driving the benefits and reacting to what's in the market. And that will be the primary lens as opposed to just reacting to what's in the rate case. But again, the Our expectation is that the rate reviews will be pretty straightforward in light of the benefits these can deliver and the fact that we're offering a lot of cost savings to our customers for the rate case, as I described, in Missouri. So we're able to offset a lot of the – any potential increases by very sizable land reductions and costs. So net-net, we've got confidence in our program. We've got a robust backlog of additional projects we could do. that we believe will be beneficial. We've got a pretty old set of infrastructure, even just replacing aging equipment. We've got decades of runway on those. But we've calibrated our overall program, what we think makes sense for customers and our overall rate trajectory.
spk07: Okay, great. That makes sense. You had answered my other question, so I appreciate the time. Thank you.
spk09: Thank you. Our next question comes from Paul Patterson of Glenrock Associates. Your line is open.
spk06: Hey, good morning, guys.
spk09: Good morning, Paul. Good morning.
spk06: I apologize if I miss this, but for 2022, the Power Ventures, Power Marketing, what's the expectation for the contribution for that in 2022? It wasn't clear to me. I'm sorry.
spk05: So overall, it's Kirk, the contribution to our earnings in 2022 from, I'm going to say power marketing and average ventures combined, probably about 10 cents. Okay.
spk06: And then, and again, I'm sorry, but the sales growth for 2022, you said was about 1%. And it wasn't clear to me, COVID, I mean, how far, I mean, it sounds like you're also still responding to COVID. So longer term, non-COVID recovery, what's your expectation for sales growth at this point?
spk05: Sure, you bet. So the $0.08 year-over-year growth I characterized and what's behind that $0.08, that's about 1% year-over-year demand growth behind that. About half of that is just the continued recovery from COVID, almost all of which we would have originally expected to occur in 2021. And if you want to think about sort of ongoing – Normal way organic growth, it's the other half of that. So call it 50 basis points or half a percent of that 1% is really kind of the long-term load growth that we perceive. Okay.
spk06: And then finally back to the Missouri PISA case, PISA legislation. My understanding is that, you know, without legislation, you know, the PSC would have the flexibility to go with PISA or not. if under the current PISA set up, and I realize it's a 3% cap on the total rate and the 2.5%, does the 3% cover fuel or just give us a little bit of a flavor as to what life under the current legislation is versus what it would be vis-a-vis the proposed legislation?
spk08: Sure. So I'll start off, and we've got Chuck Casely with us, who leads our public affairs and legislative efforts, and he can correct me where I go astray. The current legislation, as you noted, runs through 23, but utilities can apply to the Commission to continue to operate under PISA, and the Commission can grant up to an additional five years, so through 28. And in the current legislation, the 3 percent cap, it is applicable broadly, so it is inclusive of fuel. Now the legislation that has been proposed to extend and expand PISA lowers the cap, but it narrows it to apply to just the investments and activities related to PISA. So it's a little more, you know, it ties the cap, a lower cap, to the actual investments that you're making and asking for to be treated under the PISA legislation. And the proposed legislation also does not have a sunset provision. So it would continue. So as I mentioned in my remarks, we are engaging with stakeholders. I think it's good policy. It's consistent with the objectives that were behind the legislation when it was first passed, and we think it would have been advanced successfully. And so we're having a good dialogue with stakeholders. Whether it passes, it's a busy legislative session, and other factors may sort of take all the oxygen in the room at the end of the day. But we're having good discussions, and we'll continue advancing. If it's not something we can then it will continue to be an initiative next year. And as you've noted, as we discussed, it is something even without new legislation, you can just ask the Public Service Commission to extend. And that is a request we could make next year.
spk06: Okay. And just in terms of with the increase in fuel prices that we're seeing and everything, is there a significant amount of deferred fuel recovery or are you projecting potentially I mean, how does the outlook for fuel recovery, you know, or any other, I guess, cost recovery? I mean, is there a big, are there significant deferrals? Let me ask it this way. Are you seeing significant levels of deferred expenses accumulating here, or what's the outlook for that under the current setup?
spk08: Yeah, we have seen some increase in deferrals. It varies by jurisdiction for us. So our metro jurisdiction, which is in both Missouri and Kansas, has the most significant amount of generation relative to load. So we've not seen significant deferrals in Metro. Metro is actually a jurisdiction also where we're able to return benefits from Winter Storm URI as a result of that position. In Kansas Central, we've got a sizable base load fleet, a sizable wind fleet. There were some cost pressures, particularly in the back half of the year. So we've had some deferrals that we'll be seeking to recover this year. In total, our fuel and purchase power expense in 2021, I think it was about $70 million higher than it was in 2020. Now, we actually collected less in revenue in 2021 than 2020, so our deferral is a little bit higher than that, but we'll be seeking recovery for that in the normal course as we do under the fuel clause. And then in Missouri West, Missouri West is a jurisdiction that has an amount of generation – that is less than its load, so it has more exposure to market prices. So again, in the back half of the year, we did see some fuel cost increases in Missouri West. We file twice a year for recovery of any deferrals, and then those are recovered in over a 12-month period. So we made a filing in Missouri West in December related to that. So we did see some increased amounts, again, relative to Other jurisdictions that have higher amounts of natural gas generation relative to the other elements of the energy complex is relatively lower, but you see those deferral amounts in two of our three jurisdictions. Okay. Thanks so much. I appreciate it. You bet. Thank you.
spk09: Thank you. At this time, I'd like to turn the call back over to President and CEO David Campbell for closing remarks.
spk08: Sir? Sir? Great, thank you. We appreciate all of you joining us this morning, particularly as this is the last day of a long earnings season. Thanks, and have a great day.
spk09: This concludes today's conference call. Thank you for participating. You may now disconnect.
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