© 2024 Alpha Spread Limited. All Rights Reserved.
www.alphaspread.com is not operated by a broker, a dealer, or a registered investment adviser. Under no circumstances does any information posted on www.alphaspread.com represent a recommendation to buy or sell a security. The information on this site, and in its related newsletters, is not intended to be, nor does it constitute, investment advice or recommendations. The information on this site is in no way guaranteed for completeness, accuracy or in any other way. In no event shall Alpha Spread Limited be liable to any member, guest or third party for any damages of any kind arising out of the use of any content or other material published or available on www.alphaspread.com, or relating to the use of, or inability to use, www.alphaspread.com or any content, including, without limitation, any investment losses, lost profits, lost opportunity, special, incidental, indirect, consequential or punitive damages. Past performance is a poor indicator of future performance.
You don't have any saved screeners yet
Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Thank you for standing by and welcome to EVRG 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. [Operator instructions] I would now like to hand the call over to Lori Wright, Vice President of Investor Relations and Treasurer. Please go ahead.
Thank you, Richie. 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 and the disclosure in our SEC filings contain with some of the factors that could cause future results to differ materially from our expectations and include additional information on our non-GAAP financial measures. 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.
Thanks, Lori, and good morning, everyone. I'll begin on Slide 5. This morning, we reported full year 2021 GAAP earnings of $3.83 per share compared to a $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 6% to 8% 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 deploying $2.05 billion or $100 million higher than our Investor Day estimate to replace ageing 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 rate reduction to our customers. At the same time, we have reduced our total operating and maintenance expenses by 18% 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% 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 STP dockets in both Missouri and Canada 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 6, you will see our recent earnings and dividend growth trends. As we have 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 the 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 6% to 8%. Alongside the earnings, you will see the attractive dividend growth that is tracked within our 60% to 70% dividend payout policy. I would like to thank my fellow Evergy employees for their continued focus and team works and 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 7, we made significant progress on emission 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 by 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 gigawatt to 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 retired nearly 2 gigawatts of coal over the next decades. 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 70% reduction in CO2 emissions from 2005 levels by 2030 with a long-term objective of net zero carbon by 2045. Slide 8 summarizes our five year capital expenditure plan, which totals $10.7 billion from 2022 to 2026. On a comparative basis, the current 2021 to 2025 plan is in line with what we presented in 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 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 distributions. 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 cost to serve customers, which helps to create a virtuous surplus which has on these savings. Slide 9 summarizes our progress in driving cost savings and capturing efficiencies and how we work enabled by the 2018 merger and a comprehensive program across the business, we have reduced cost by $233 million or 18% since 2018. We are laser-focused on operational excellence as we leverage investments and technology to operate more effectively and efficiently. We are also building more and more flexibility into our generation operating model in the southwest power pool market which continues to see an increase in penetration of renewable generation. And we are not done, as we are targeting a further 11% reduction in total O&M by 2025 as part of our five year plan. Thus far we have 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 we’ve been seeing across the country to create higher levels elsewhere than what we see 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 layout 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 features as a priority objective in our five year plan. Let’s turn to Slide 11, I’ll give an update on our ongoing Missouri rate reviews we filed this January. Starting on the left hand side with Missouri Metro, we have requested a $44 million rate increase including the rebates – excuse me, excluding the rebates to fuels, based on a 10% return on equity, a 51.2% common equity ratio and a projected $3.1 billion rate base as with the proposed May 31, 2022 WHO update. The primary drivers of the rate requests include our increased infrastructure investments, which improve reliability enhanced customer service and enable the company’s transition to cleaner energy resources, updated depreciation rates that better align with the estimated remaining lives of IFRS and increased power pre-taxes. These increases are significantly offset by roughly $55 million of lower annual operating cost 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, a 51.8% common equity ratio and a projected $2.5 billion rate base as of the proposed 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 Staubli power plant. We’ve been deferring the revenues associated with the foregone O&M resulting for 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 and 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, any infrastructure and grid monetization investments that are consistent and advance the objectives of Missouri policymakers and stakeholders. We are 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 the Slide 11 you will see our estimated timeline from here. We expect stats and intervenor testimony we filed in June which will bundle testimony in July, potential hearings in early September and finally commission orders in November. If approved as filed excluding the fuel, the rate request which represent an increase of 5.2% for Missouri Metro customers and a 3.85 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, the retirement of Lawrence Unit 4 with recoveries through securitization and the addition of a 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 with 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 see pre-determination approval for the cessation of coal, the retirement of Lawrence 4 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 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 wind resources that would come online in the 2024 to 2025 timeframe. Kirk and his team are overseeing our renewable 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 the 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 on the Missouri West cost 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. The bills have been introduced to extend and update legislation that was passed in 2018 widely referred to as plant and service accounting or PSA. We’ve been utilizing this legislation since 2019 supporting our investments in grid monetization and improve reliability. We believe that the build has good policy and enjoys wide support. But whether it ultimately advances this year will depend most likely on unrelated issues and receive the bulk of legislative attention. We are focused on working with key stakeholders to advance the PSA extension this spring but given the provisions of the currently existing PSA 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 Evergy value proposition. The left side of the page covers the core tenets of our strategy to advance affordability, reliability, and sustainability through relentless focus on our customers supported by stakeholder collaborations, sustainable investments and financial and operational excellence. The right hand side of the slide 13 features what we believe are particularly attractive and distinctive features for Evergy given our business mix and geographic locations. We are excited about the opportunities for our company and we are committed for the sustained effort required to deliver against our high performance objectives. I’ll now turn the call over to Kirk.
Thanks, David, and good morning, everyone. I’ll start with the results for the quarter on Slide 15. For the fourth quarter of 2021, Evergy 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 a seasonally warm weather across the end of the quarter, particularly in December, resulting in significantly fewer heating days as compared to the fourth quarter of 2020 and driving $0.07 of unfavorable contribution from weather. When compared to normal weather assumed in our original plan, the mild weather negatively impacted our results by $0.10. The unfavorable weather was offset by a 4% increase in weather normalized demand or approximately $0.08 per share relative to our expectations for the quarter, weather normalized demand was approximately $0.04 favorable as we began to see demand recovery which we had previously forecasted to be delayed into 2022. Stronger performance in our Evergy Ventures in Power Marketing businesses drove $0.03 of EPS versus the fourth quarter of 2020, which offset $0.03 of lower EPS from COLI as we did not received proceeds during the fourth quarter of 2021, while the prior fourth quarter included the majority of our COLI in 2020. Income tax-related items drove a net decrease of $0.04 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 a result of pulling forward certain cost items from Q3. 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 lock-up 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 in 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 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 first transmission investment resulted in a $0.13 increase. Favorable income tax related items of $0.07 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 grey bars, higher depreciation and increase in property taxes, lower year-over-year COLI proceeds and a slight year-over-year increase in share count combined, led to a $0.12 year-over-year decrease. And finally, stronger year-over-year performance in Power Marketing and Evergy Ventures, partially offset by the pull forward cost from two three years I mentioned during my fourth quarter comments, combined to drive EPS $0.12 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 this slide, you will 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 a more robust increases in particular in commercial and industrial. Looking to the right side of this 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 industries. 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, logistics industries in particular has seen strong employment growth that continued to a solid economic recovery. Although as I mentioned last quarter the forward plan 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 regular 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 of $3.43 to $3.63, which I will review next on Slide 18. Starting on the left side of the 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 Evergy 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 nearly 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 of a 1% increase in year-over-year weather normalized demand. About half of this increase reflects the realization of a more normal demand in 2022, which we had originally expected to occur in 2021. This shift is due to the observed way 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 $0.02 for the year-over-year increase. Turning next to Slide 19, our strong results in 2021 reflect our ongoing focus on continuing to build the 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 base 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 worked hard to invest in our utilities to improve reliability and enhance customer service. Our successful efforts in driving efficiencies to reduce operating cost 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 stakeholders. On the renewable front, as David mentioned earlier, we have recently withdrawn our pre-determination filing in Kansas, which included the addition of $190 megawatts of solar. We are 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 import delays. We are focused on resolving these remaining issues, while ensuring certainty of schedule, and affordable cost for the benefit of our Kansas customers. And should the expansion of the tax incentives for solar, including the BTC and Direct Pay ultimately see passage conserve 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 1 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 shortlisted our initial bids to a select group of projects which when combined represent a multiple of our targeted 800 megawatts. The proposals received provided the opportunity to select the project 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 a proposed refresh of the 100% PTC, we believe there is potential for this opportunity even if tax reform does not see passage. We are 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.
Thank you, Kirk. So, for those on the call, we appreciate your time today and we’d like to open it up to questions.
[Operator Instructions] Our first question comes from the line of Shar Pourreza of Guggenheim. Your line is open.
Hey, good morning, guys.
Good morning, Shar.
Morning. David, Kansas seems like it has been a little bit noisier maybe even somewhat hostel to actually both you and the KCC. We saw One Republic and others demoted from a committee because of an off paddy road. There was obviously recently legislation for in – for price cap some lawmakers have been really hounding on the KCC. I guess, could we just get any color on your conversations in recent weeks there? Any efforts to sort of pivot the conversation? It’s just been a little bit more noisier than we are used to.
Shar, it’s good question. We are in the legislative session, which is always active. Look, I think in Kansas, I think there is an active dialogue and we appreciate that. And part of why you see us feature the rate reductions that we’ve been able to deliver and our improving rate competitiveness and I would describe it as a lively conversation, but there is balanced inputs from all sides. There was a presentation for example that KCC’s staff gave in one of the committees, in a senate committee that highlighted how are rates over the last ten years in Kansas Central have been flat to declining over ten years. So well below the rate of inflation and now it’s certainly noted and of course, you will recall how securitization legislation was passed last year with overwhelming majorities in both houses. So, we are very focused on regional rate competitiveness. We know how important that is. There are some sickles in the stay as a variety of opinions around renewable and others as reflected in a variety of opinions around our country. But we think it’s a constructive dialogue overall and we are certainly – and we are very focused on the same priorities that our key stakeholders have in the stake.
Got it. Thank you for that. And just last maybe for Kirk, just maybe – just on the buy-in, how does that interact with the IRP update process? And just remind us or any buy-ins in the CapEx plan or is it sort of an opportunity that’s incremental?
Sure, sure. So, first, I’ll answer the second part of that question is, we know those buys are included in our capital expenditure forecast that would be flexing up if you will. In terms of the overall process around the IRP, as the PPAs that underpin those buy-ins already support our renewable and our ability to serve loads, this would simply be a shift in perspective of how we deliver that in the near-term if you will, right? So we be replacing an existing resource that we avail ourselves through a PPA within owned resource for the same number of megawatts. It’s the really repowering on the back end of that and the extension potential for it which is obviously beyond the scope of our, at least our five year plan that would have that impact, that makes sense.
Got it. No, no, that’s helpful. Very clear cut quarter. Thanks guys. I appreciate it.
Thanks, Shar.
Thank you. Our next question comes from Durgesh Chopra of Evercore ISI. Your line is open.
Hey, good morning, team. Thank you for taking my question. Kirk, just following up on the PPA buyout opportunity, in terms of like basically I’ve understand it, right, this is basically a PPA converted to a rate base, of course, am I thinking about that correctly? And then, do you need to sort of get regulatory approvals for it to ultimately accretive and what does the time line look like?
Well, the timeline as I’ve said, we are currently actively involved in discussions with multiple PPA counterparties for a potential buy-in which is why as I indicated we feel comfortable in at least targeting one of those who occurred 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, directionally speaking, I think the way you describe it is correct. We are 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 be associated impact on rates with that if you will, rate base investment provides customer savings, that’s the most important step. In terms of how that gets adjudicated, it would go through a similar processes, really any rate based investment. Right, if that was in Kansas, we’d go through pre-determination of those in Missouri. We’d actually pursue through different names and an ordinary rate case context. Combining that with powering, it’s just an increase in the overall capital would be well or an extension of that time line albeit rather in the pass through, it would be a rate base investment within all in savings, right. I think about that almost a blend and extend type approach if you will.
That makes ton of sense. Thank you for explaining that, Kirk and so essentially, maybe the earnings accretion comes from rate basis and the investment going through future rate cases if you will. Just maybe shifting gears, can you just talk about 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 for you to achieve your target for 2022 and beyond and how are you tackling those? Thank you.
So, that’s a good question thus far and obviously, in the macro environment, that continues to be dynamic. So, one we are highly attentive to as does everyone. Thus far we’ve been able to manage the inflationary pressures on the O&M side. It has some impact despite – some impact on the cost and building on the capital side we’ve also been able to work through those as well. And we are confident that we can continue to manage it. In our 2022 plan as you may have seen in the waterfall that Kirk walked you from 2021 to 2022, it’s an overall $0.06 uplift in O&M. So we have some cost savings this year. We also had some impact last year from the outperformance – unusual outperformance in our unregulated business should have some impact in 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 are going to drive in 2023. 2024, and 2025. 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 are 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 the same effort, it’s been a comprehensive program across our whole company, Kevin Bryant our Chief Operating Officer is coordinating that effort on our behalf, but the company has got a great track record in this year and we know how to do it. That’s going to take sustained execution. So, we don’t want to certainly acknowledge that but we have the tools and the compliance in place to make it happen.
Got it. Thank you for taking my questions. I appreciate the time guys.
Thank you.
Thank you. Our next question comes from Michael Lapides of Goldman Sachs. Please go ahead.
Hey guys. Thank you for taking my question and congrats to a strong year. I wanted to talk about the PPA buy-ins as well as any build own transfer of loads. Congress obviously hasn’t been able to get anything across the finish line both CFA can try to do something in the Lame-Duck Session at the end of this year, it doesn’t look like anything to happen before the mid-terms. Just curious, do you think about pulling forward all of your renewable plants to capture what could be the safe harboring benefit that some of the developers who themselves maybe thinking about repowering for – thinking about building new solar. The reason toward the Safe Harbor provision benefit that would happen because they’ve got it Safe Harbor that last year or two years ago PPP or ITP level versus what this year through next year would be?
Sure, it’s good question and we certainly – we 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 are looking at. At the same time, we are hopeful that ultimately, obviously in the current political environment. There is a lot of distraction and chaos, but if ultimately those provisions of back better ultimately do get passed, that obviously gives us greater flexibility. But we are certainly mindful of availing ourselves of that option in the current context from a safe harbor standpoint.
And Mike, I’ll also add is the – from, this is David, so, from the perspective of the integrated resource plan and our multiyear capital expenditure plan, we look at the overall level of capital we are spending. We look at the overall rate impacts and affordability. We do think to bring on renewable as a win-win, because it typically lower cost as well as lower emissions. But we are going to track with the program and with respect to the IRP, part of the rational for why there is some sequence in shift, wind relative to solar was in consideration of some of the factors around a safe harbor. So the category of truly new development we are 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 we are going to be responsible for what we see. The PPA is a little bit different, the buy-ins and repowerings and that’s as Kirk described in existing set of resources, so that’s for complicated new issue with the initial set of counterparties obviously, but for those, we have opportunities that are sooner and we’ll certainly look for that. But it’s subject to what you can accomplish with the counterparties. They’ll of course, those are all basically wins. So, talking about the PPAs for repowering 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 others as we can, but within the constraints of what the counterparties will do with us.
Got it. And then, when we think about the buy-in and the 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 spends and repower of the asset given the rates?
Well, first of all I could comment in two forms, right. Buy-in and repowering can be a single negotiation with the counterparty that we can contract with on both elements of that. Obviously, that would be the owner of the existing asset, that was our counterparty end of the PPA. And a potential repowering initiative, almost again the kind of bill transfer expect with that seem counterparty 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 base 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 that we can substantiate that capital investment when combined to result in a savings to the customer, relative to the PPA that’s being pass through and obviously supplemented by greater certainty of what those costs are in the long run. There is the possibility that 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 will mean we go through and say, here is the capital investments replaces existing PPA pass through. Here is the savings around that, that will be separately adjudicated and then we’d approach the repowering separately.
Got it. And then, finally, can you get them in your rates between rate cases or do you have to – can you remind me, I thought Kansas had a track or wider where you can put it in. But can you remind me on the Missouri rule as well?
Not a tracker on the Missouri side if I understand what your question is there.
Got it. So you just have to wait for the next ERC to get it?
Correct. Yes. That’s right.
Thanks guys. Much appreciated.
Yes, Michael, again, I want to add on that as the – you could take your pre-determinations. So you get a sense for Kansas, the weather how 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 couple different pathway if you can go down starting with the pre-determinations to get at comfort at how it will be treated and then you can do it either in the general rate case or an abbreviated rate case and nearly filing one that you complete.
Got it. Thank you, David. Looking to [Indiscernible] guys.
Thank you.
Thank you. Our next question comes from Julien Dumoulin-Smith with Bank of America. Your question please.
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 say that you’ve got a few contracts at least one year. What’s the order of magnitude of megawatts that we are talking about here? I am not sure I pin you guys down, just curious if you can speak to that?
Yes, sure, Julien. First of all, we are focusing on that subset of those PPAs that total for us about 300 megawatts and sure I think we had that as part of our presentation in Investor Day. It’s about at little more than about 1.25 gigawatts of that where the PTCs are either already expiring or approaching expiry and that’s kind of the sweet spot. So we are 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 the 200 megawatts would probably a good rule of thumb to think about.
Right. Effectively establishing a framework for how to scale that up to around that one, two or whatever if you can make it work.
I think that’s a fair way to characterize it.
Yes, it’s some level and we view that PPA base as pipeline, now it’s – some of that pipeline is near term to longer term. But that’s at least long term pipeline for us.
Absolutely. Yes, that’s turns down. I appreciate that. And then, related, I mean, I saw this by last week if I can call it that to have a larger shareholder of 15% deal to call a meeting. Admittedly, I know we’ve been through that, what drove that specific change of late if you can speak to it?
Sure, that we felt that was just an approving our [Indiscernible] process have the ability for a shareholder to call that kind of meeting. So, we are evaluating our overall governance practice. We felt – that we saw that would be an enhancement to create that ability to call a meeting. So, we looked at where the threshold work for peer companies where other companies or a lot of companies still don’t offer that. But we wanted to add that as an additional capability of the shareholder family proposal. But I view that as – I would put that in the category of our overall evaluation of our ESG policies and approaches of trying to continue to approve on those.
Got it. I know you alluded to this earlier, embrace your Kansas rate cap session. I mean, how much support does the proposed law that would – gap increase the 1% tier have, I mean, a tough question to ask, but curiously if you could provide any context of the positioning here?
We do not think that it has broad support. We don’t think that it’s going to giving it out. So it’s lots of proposals get offered. I’ve seen that over my career and all the legislative discussions that are seen in every states, but now we don’t even think that would get out a committee. I had some discussions but we don’t think it’s got large support.
Excellent, thanks for closing that.
You bet.
Have a great day.
Thank you.
Thank you. Our next question comes from Nicholas Campanella of Credit Suisse. Please go ahead.
Hey, good morning. Thanks for taking my question. I was just curious in light of the comments on the 190 megawatts of solar and you talked about looking for more clarity on tax incentives and supply chain pricing impacts. Can you just help us think about how that translates to the overall roughly $2 billion renewable 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 so far out or does the CapEx that you have in the slides today kind of reflects this supply chain and pricing pressures that you are seeing. Thanks.
So, I’ll start and then hand it over to Kirk. So, I would characterize the solar project in particular is pretty unique and that it’s got that market base structure and that’s really because of the IPC benefits that are currently in place and how to take advantage of those most effectively and working with our counterparty and we are speaking a level of certainty in that agreement and that’s part of why we decided to withdraw the docket and we will file and once we have the certainty. So it’s really related to supply chain issues in particular and we are seeking the certainty because of the importance of the affordability point that we mentioned. But because of the structure of that deals, it’s a minimal contributor to earnings in 2024 and 2025. Our wind additions that we’ve got slated in 2024 and 2025 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 an ongoing wildcard. It’s a macroeconomic situation that’s pretty dynamic, but that reflects our best expectation as we got. Kirk?
Yes, the only thing I’d add to that on the 190 megawatt solar project, as David characterized it I agree that’s unique around some of those supply chain issues. I think I have mentioned in my remarks. Coming out of our initial pre-determination 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 board reduction, there these withhold release orders around, concerns around certain products from China and of course 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 ministration give clarity around the least around what their attentions are in terms of the tariffs. So gives us a better backdrop to do that. And 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 first for 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 array perspective, but 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.
Yeah, I'll go ahead and describe just maybe a corollary or questions, even in – we've given earnings guidance, or our target growth rate ranges to 2025. In 2025, the total contribution from the new renewables in our plan is less than 2% of it. So it's 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.
Got it. Yeah, that's very clear. Super helpful. Really appreciate that. 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 kind of filing an update to the IRP this July. And I'm just curious if we're going to get into a tipping point where there's just an argument to kind of further accelerate some of the fossil fleet and how you're kind of thinking about that, in terms of the closures? Thanks.
You bet. So yeah, there’s lots of intersection points. Inflation is a broader issue in the energy sector. We were happy that we've been able to manage inflation better than certainly see across other parts of the electric space, but it's still an issue. We hope it's going to be temporary. In terms of the implications for our generation fleet transition, we tried to be thoughtful in our Integrated Resource Plan, we'll do take the same approach and 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 or relative emissions profile. Now, it's hard to tell that in the very near-term, given the supply chain issues, which have had some knock-on effects on pricing. So we, I would guess, as we go through our update, you're going to see a similar pacing and sequencing in our plan rather than an acceleration, again, because acceleration runs into some of the – you may not be able to achieve the same, all the same benefits in terms of lower costs, and who knows what's going to happen in Washington. But 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 same time, if there are some factors of the near-term that are raising costs, that bounces against rushing into things. And the other dynamic is, I think we'll have to make sure we have a measured pace to this approach. Yesterday, 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 over time as we have nearly half of the electricity that we provide our customers was from a free sources last year, between nuclear and wind. So we think we've got – been on a great track record. We've been able to do that while maintaining reliability, or we're going to be focusing on that balance going forward. But to your broader point, I think there's a way to drive that transition. And with lowering costs and lowering emissions while entering the liability, but it's won't happen overnight. It's got to be in a paced program.
That’s helpful. And one more if I can just, if I'm hearing you, right, the PPA buyout opportunities are upside to the capital plan. And just as we think about putting more CapEx into the model, what's your ability to just raise CapEx without additional growth equity capital?
So it's 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 to our five-year plan without the need for new equity. We do have some degree of flexibility. Obviously, there is – 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 at 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.
Really appreciate the time today. Thank you.
You bet.
Thank you.
Thank you. Our next question comes from Travis Miller of Morningstar. Your line is open.
Good morning. Thank you.
Good morning.
I was 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, 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, things go poorly by downsizing. What are your thoughts there in terms of sensitivity?
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 toggle based on the – both of these rate reviews are pretty straightforward, that are underway in Missouri and we expect it 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 into early this year. I think they're very consistent with public policy. Missouri has reflected in the legislation which 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 and our level of rate base 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 the market. And will – that will be the primary lens as opposed to just reacting 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 and reductions in 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 in our overall rate trajectory.
Okay, great. That makes sense. The – you had answered my other question, so appreciate the time.
Thank you.
Thank you. Our next question comes from Paul Patterson of Glenrock Associates. Your line is open.
Hey, good morning, guys.
Hi, Paul.
Good morning.
I apologize if I missed this, but the – but for 2022 the power ventures telemarketing, what's the expectation for the contribution for that in 2022? It wasn’t fair to me, I’m sorry.
So overall – it's Kirk. The contribution to our earnings in 2022 from – I'm going to say power marketing and every event is combined, probably about $0.10 cents.
Okay. And then, again, I'm sorry, but the sales growth for 2022, you said was about 1%. And it wasn't clear to me is COVID, I mean, how far – I mean, it sounds like you're also still responding to COVID sort of longer-term, non-COVID recovery. What do you – what's your expectation for sales growth at this point?
Sure, you bet. So the $0.08 year-over-year growth I characterized in what's behind that $0.08, and 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 0.5% of that 1% is really the kind of a long-term load growth that we perceive.
Okay. And then finally, back to the Missouri piece of case, the piece of legislation, my understanding is that, without legislation that the PSC would have the flexibility to go with PISA or not. If under the current PISA setup, and I realize it's a 3% cap on the total rate in the 2.5%, does the 3% cover fuel, or just could just give us a little bit of a flavor as to the – what life under the current PISA or the current legislation is versus what it would be vis-à-vis the proposed legislation?
Sure. So, I'll start off and we've got Chuck Caisley 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 2023. 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 up to 2028. And in the current legislation, the 3% capita, it 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 tied to 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 we'd continue. So as I mentioned in my remarks, where we are engaging with stakeholders and he makes – it's good policy, it's consistent with the objectives that were behind the first – the legislation was first passed, and we think it was an 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 accomplish this year, then I'll continue to be initiative next year. And as you've noted and as we discussed, it is something even without new legislation, you can just ask the public service commission to extend, that is – request we could make next year.
Okay. Just in terms of with the increase in fuel prices that we're seeing in everything, is there a significant amount of deferred fuel recovery? Or are you projecting potentially? How does the outlook for fuel recovery, or any other I guess, cost recovery mean? Is there a big – are there are 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?
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 and as a result of that deposition. In Kansas Central, we've got a sizable baseload fleet, 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 than revenue in 2021 and 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 is – has a monogeneration that is less than its load, so it is more exposure to market prices. So again, in the back half of the year, we did see some fuel costs 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 increase 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 both two of our three jurisdictions.
Okay, thanks so much. I appreciate.
You bet. Thank you.
Thank you. At this time, I'd like to turn the call back over to President and CEO, David Campbell for closing remarks. 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. Operator This concludes today's conference call. Thank you for participating. You may now disconnect.