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spk07: Thank you for standing by and welcome to Evergy's third quarter earnings 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 touchtone telephone. Please be advised that today's conference is being recorded. Should you require any further assistance, please press star 0. I would now like to hand the conference over to your host, Vice President, Investor Relations, and Treasurer, Lori Wright. Please go ahead.
spk00: Thank you, Lateef. Good morning, everyone, and welcome to Evergy's third quarter call. Thank you for joining us this morning. Today's discussion will include forward-looking information. Slide 2 and the disclosure in our SEC filings contain a list of some of the factors that could cause future results to differ materially from our expectations today. and include additional information on non-GAAP financial measures. The releases issued this morning, along with today's webcast slides and supplemental financial information for the quarter, are available on the main page of our website at investors.evergy.com. On the call today, we have David Campbell, Evergy's President and Chief Executive Officer, and Kirk Andrews, Executive Vice President and Chief Financial Officer. David will cover our third quarter highlights recap our recent investor day, and provide an update on our near-term resource plan. Kirk will cover in more detail the third quarter results, the latest on sales and customer information, and our financial outlook for the remainder of the year. Other members of management are with us and will be available during the question and answer portion of the call. I will now turn the call over to David.
spk04: Thank you, Lori, and good morning, everyone. I'll begin on slide five of our presentation. This morning, we reported third quarter adjusted earnings of $1.98 per share, compared to $1.73 per share a year ago, equal to a 14% increase. On a period-over-period basis, these results were driven primarily by favorable weather, higher transmission margin, higher other income, and lower income taxes, partially offset by decline in weather normalized demand. For year-to-date September 30th, adjusted earnings were $338 per share, compared with $282 per share a year ago, equal to a 20 percent increase. As with the quarter, favorable weather is the most significant driver. With these strong results, we are raising and narrowing our adjusted EPS guidance range to $350 to $360 per share, an increase from $320 to $340 per share. I commend and thank our team's ability to execute and focus on providing safe and reliable electric service to our customers throughout the first nine months of the year, notwithstanding the lingering pandemic impacts and the significant winter weather event in February. Kirk will detail the drivers of our financial performance that resulted in the upside guidance provision. In addition, we are affirming our 2022 adjusted EPS guidance of $3.43 to $3.63 per share, as well as our targeted annual adjusted EPS growth target of 6 to 8 percent through 2025, as we laid out during our investor day. Lastly, this morning, we also announced a 7 percent increase in our quarterly dividend to 57.25 cents per share, or $2.29 per share on an annualized basis. This increase is consistent with our growth trajectory and reflects our board's confidence in the execution of our plan. Moving on to slide six, I'll provide a brief recap of the business plan highlights from our recent investor day. As part of the event, we rebased and extended our key targets through 2025. Our five-year capital investments are estimated to be $10.4 billion through 2025, of which nearly $1.5 billion is for renewables projects. This spending plan drives our projected rate-based growth of 5 to 6 percent annually over that same time period. We also extended our target for cost efficiencies and added nearly 20 million of savings in 2025, increasing our total estimated annual O&M savings from our 2018 base year to $345 million annually in 2025. This represents more than a 25 percent overall decline. Building on the strong performance and realized cost savings achieved over the last three years, this trajectory implies a 1% to 2% annualized cost productivity gain through the five-year forecast period. The planned beneficial infrastructure investment and additional O&M savings enable us to extend our top-tier 6% to 8% annual growth rate and adjusted earnings per share through 2025. We're able to fund this plan with significant cash flow and modest incremental debt allowing us to maintain our strong balance sheet and credit metrics with no planned incremental equity through 2025. Lastly, we showcased our strong ESG profile, including our significant progress in clean energy and changing our generation mix. In 2020, 50% of our energy was emissions-free, and we achieved a 51% reduction in energy CO2 emissions relative to 2005 levels. We stack up well relative to our Midwest peers in terms of both clean energy delivered to our customers and our reduction in carbon emissions. We have ambitious but achievable goals as we advance toward our target of net zero carbon by 2045. Slide seven outlines our resource plan through 2026. To further lower energy costs for customers and reduce emissions, we plan to add more than 1,300 megawatts of new renewables split between over 500 megawatts of solar and 800 megawatts of wind through a series of yearly additions. We also plan to retire coal operations at our plant in Lawrence, Kansas. In September, we initiated a regulatory proceeding in Kansas called predetermination, seeking approval in advance for the Lawrence coal retirement and for the first 190 megawatts of solar generation. We expect to have an order in this proceeding by mid-2022. In October, we also issued a request for proposal for 800 megawatts of wind generation projects we have sequenced across 2024 and 2025 for the benefit of Kansas and Missouri customers. Bids are due later this month, and we plan to select a short list of projects before the end of the year. We are targeting having negotiations completed by mid-2022. In parallel, we will continue to evaluate potential opportunities to buy in and repower existing power purchase agreements as initial production tax credits expire. Before handing it over to Kirk, I'll wrap up on slide eight, which summarizes the average value proposition. The left-hand side of the page covers what we're focused on and how we plan to execute our strategy, which I discussed in depth during our investor day. The core tenets of our strategy are to advance affordability, reliability, and sustainability through a relentless focus on our customers, supported by stakeholder and collaboration, sustainable investment, and financial and operational excellence. The right-hand side of slide eight features what we believe are particularly attractive and distinctive features for our company. First, we are an all-electric regulated utility with significant benefits delivered since the merger and further opportunities that we will capture through continuous improvement, performance management, and sustained, consistent execution. Second, we have significant opportunities ahead for the ongoing transition of our generation portfolio. And we can do so cost-effectively, given that we'll be replacing coal with low-cost renewables, which is a win-win for affordability and sustainability. Third, we are geographically advantaged, given our proximity to world-class wind resources in Kansas. We are well-positioned to participate in the renewables and transmission build-out that will occur as part of the national transition to a clean energy economy. And finally, we are targeting a high-performing 6% to 8% annual growth rate in adjusted earnings per share through 2025 at the top rank with our peers. We are very excited about the opportunities for our company, and we are deeply committed to the sustained effort required to deliver against our high-performance objectives. I will now turn the call over to Kirk.
spk01: Thanks, David, and good morning, everyone. I'll start with results for the quarter on slide 10. For the third quarter of 2021, Evergy delivered adjusted earnings of $455 million, or $1.98 per share, compared to $393 million, or $1.73 per share, in the third quarter of 2020. The 14% increase in third quarter adjusted EPS was driven by the following items as shown on the chart from left to right. First, there were significantly more cooling degree days this past quarter as compared to the third quarter of 2020. resulting in 20 cents of favorable contribution from weather. Adjusting for milder than normal weather experienced in the third quarter of 2020, the third quarter of this year saw 13 cents of EPS versus normal weather assumed in our original plan. The strong favorable weather impact this quarter was partially offset by a 1.2% decline in weather normalized demand, or approximately 6 cents per share. Higher transmission revenue, resulting from our ongoing investments to enhance our transmission infrastructure, drove about $0.06 per share. Other income increased $0.04 per share, driven by higher investment earnings from some of our investments in early-stage energy solution companies. Income tax-related items, which include the impact of Kansas income tax rate exemption effective this year and higher amortization of excess deferred income taxes, partially offset by the timing of tax credit recognition to maintain our effective income tax rate for the year, drove a net increase of 4 cents per share. And finally, other items, which consist primarily of higher depreciation and amortization and property tax expense, as well as the impact of shares issued to Bluescape in April, were partially offset by lower O&M, which, when combined, represent a net 3 cent decrease. I'll turn next to year-to-date results, which you'll find on slide 11. For the nine months ended September 30th, 2021, adjusted earnings were $775 million, or $3.38 per share, compared to $642 million, or $2.82 per share for the same period last year. Again, moving from left to right on the slide, our year-to-date adjusted EPS drivers versus 2020 include the following. Favorable weather from the first half of the year, when combined with the warm weather in the third quarter, contributed 25 cents year-to-date. When compared to normal weather, assumed in our original 2021 plan, weather was 18 cents favorable. And although weather normalized demand increased about 1% year-to-date, the margin impact of higher commercial and industrial sales was more than offset by an estimated 2% decline in residential sales, resulting in about a penny of lower margin versus the first nine months of 2020. As expected, higher transmission revenues driven by our first transmission investments resulted in a 12-cent increase. Other income was also 12 cents higher, driven primarily by an increase in investment earnings due to a realized gain from the monetization of an investment in the first half of the year, combined with investment gains in the third quarter, as well as higher AFUDC. The impact from the Kansas income tax exemption and higher amortization of excess deferred income taxes contribute 11 cents of favorability year-to-date. And finally, higher depreciation and amortization, property taxes, and a slight increase in share count were partially offset by lower O&M and interest expense, leading to a net decrease of 3 cents per share. Turning next to slide 12, I'll provide a brief update on recent sales and customer trends. Weather normalized retail sales decreased 1.2% during the third quarter compared to last year. This was primarily driven by lower residential sales, down 3% compared to last year, with fewer customers working from home compared to 2020. Weather normalized commercial sales were up slightly, reflecting the slow, steady return to normal. Industrial sales were flat with some puts and takes from multiple sectors. The Ford plant in our jurisdiction is still experiencing headwinds from chip shortages, which have slowed down production and, in turn, electricity usage. On the positive side, extensive oil refineries and pipelines in our jurisdictions are seeing a surge in usage as the commodity market was driven higher in demand for their products. The pandemic recovery continues to be slower than we originally planned and year to date weather normalized demand has only increased about 1% compared to our original full year expectations of around 2%. And as I mentioned during our investor day in September, we adjusted our demand expectations for the balance of 2021 as likely due to the impact of the resurgence of COVID-19 over the summer. We now expect some of the recovery to more normal demand and mix to take place in 2022. Turning next to slide 13, I'll provide greater details on the drivers of our increased and narrowed guidance range for 2021. Starting with our previous guidance range to the left of the slide and moving again from left to right, due to the shift in expected demand recovery from 2021 to 2022, the earnings contribution of weather normalized sales is about 14 cents per share lower versus our original expectations. However, favorable weather through the first three quarters, which as I mentioned earlier, we estimate contributed 18 cents, has more than offset the delay in normalized demand recovery. The net of these two items is a positive 4 cents in total sales compared to our original plan. Continuing across the chart, the remaining positive drivers of our revised guidance include 9 cents from income tax benefits driven by higher excess deferred income tax amortization, $0.07 from higher AFUDC and lower interest expense. And finally, our revised guidance includes the impact of the amount by which we expect our non-regulated businesses to exceed our original 2021 plan. Specifically, Evergy Ventures, the entity through which we make investments in early stage energy solution companies, as well as our power marketing business, are on track to contribute greater than normal earnings in 2021. It's partially offset by the timing and phasing of certain costs, resulting in a net increase of $0.05 versus our prior guidance. Together, these items lead to our revised 2021 adjusted EPS guidance of $3.50 to $3.60 per share. Of note, although, as I mentioned, our Evergy Ventures business outperformance is one of our contributing factors to our revised guidance, this outperformance is primarily based on year-to-date results. In October, an equity investment in which we own a minority state went public through an acquisition by a special purpose acquisition company, or SPAC, and Evergy received shares in the public company at closing, subject to a lockup. As a result, we expect to record an unrealized gain on this investment in the fourth quarter. Although this fourth quarter item is not yet reflected in our revised guidance, we expect this impact to be positive, And depending upon the fair value accounting for the investment, it could cause our results for the year to even exceed our updated guidance range. However, we consider any potential gain from this investment, which we expect to monetize in 2022 when the lockup expires, to be additional non-recurring earnings for the year relative to our ongoing expectations for this part of our business. Lastly, we also recognize our updated 2021 guidance implies a lower fourth quarter compared to last year. So on the right-hand side of the slide, we've included the key drivers which will impact the expected year-over-year fourth quarter results. These drivers include the following. First, given our strong year-to-date and expected earnings, we've made a few changes in the timing and phasing of certain cost items which are expected to drive about $0.06 per share in the quarter. Second, although we've seen favorable bad debt expense in 2021, largely due to lower write-offs resulting from the extended moratorium on disconnections, which expired in May, we've now begun to see write-offs increase and believe this temporary trend is likely to continue, resulting in the realization of write-offs later in the year than we originally expected. As a result, we expect to make a change in our receivable reserve calculation in the fourth quarter, which will lead to about $0.03 of additional bad debt expense. These two factors, combined with other items, including the expiry of certain tax credits in 2021, lead to the implied difference in expected fourth quarter earnings versus 2020. And finally, turning to our affirmed 2022 adjusted EPS guidance on slide 14, We've updated the bridge from our revised 2021 adjusted EPS guidance range of $3.50 to $3.60 to our 2022 adjusted EPS guidance range of $3.43 to $3.63. Starting on the left-hand side of the slide with our 2021 guidance, we normalized $0.18 of favorable weather and the roughly $0.05 of earnings primarily from power marketing and average ventures. 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 run rate contribution in our 2022 guidance. After adjusting for these items, the drivers of our 2022 guidance midpoint are largely unchanged from the walk we provided on Investor Day and include 12 cents of increased retail demand, about two-thirds of which reflects the realization of more normal demand in 2022, which we originally expected to occur in this year. And this shift is due to the observed delay in returning to normal demand mix due to lingering COVID effects in 2021. The remaining portion, or about a third of this 12-cent demand impact, 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. Next, additional O&M savings are expected to add around $0.05 as we continue to progress toward Tier 1 cost efficiency and our more robust long-term O&M savings objective, now representing an over 25% reduction in O&M from 2018 to 2025. The remaining drivers include the impact of expiring merger-related bill credits and a slight increase in interest savings and AFUDC equity, all of which are offset by depreciation expense not yet reflected in rates and a penny of other items. With that, I'll hand the call back to David.
spk04: Thank you, Kirk. So for everyone on the call, we appreciate your time with us today, and now we'd be happy to take your questions.
spk07: As a reminder, to ask a question, you will need to press star 1 on your telephone. To withdraw your question, press the pound key. Please stand by while we compile the Q&A roster. Our first question comes from the line of Char Perez of Guggenheim Partners. Your question, please.
spk06: Hey, good morning, guys. Morning, Char. Good morning, Char. Just a couple of questions here, if I may. First, the updated guidance for 21, which obviously even X, you know, weaker weather normalized demand is somewhat noticeably higher, right? Are you including any pull forward of OPEX from 22? Just trying to get a sense on potential flexibility in next year's guide, especially as we're seeing some demand drag continuing into 22 versus your prior expectations.
spk04: So, Char, as Kirk mentioned, we do have a series of timing and phasing of operating costs. Some of that's timing within this year. Some of that's pull-forwards from the forward plan. We're not adjusting our guidance for 2022. You know, anytime you have the opportunity to do prudent management of your costs, you know, you look at that across the forward plan years, and it can help with your competence and execution. But given the size of the numbers, we're not changing our guidance for 2022. But as companies do in this circumstance with some favorable weather, we are certainly looking at how, and we'll continue to look at how, are there pull-forward items or are there items that we can address this year. There are limits in what you can do in that range, but all companies look at that piece. The chunk of it does relate to timing into a year in 21. Got it.
spk06: See, you have some contingency there to cushion it.
spk04: We're not changing our guidance in 22, but we feel good about our ongoing execution trajectory.
spk06: Okay, got it. And then just on the O&M side, obviously some pretty sizable reductions you're expecting through 25. How do we sort of think about where you're currently guiding versus the overall kind of opportunity set, right? Do you see more to squeeze, especially as you guys are kind of shooting for tier one utility status, right, and even further looking at, you know, asset level transition opportunities. I mean, 25% reduction is a lot. I guess the question is, can you do more?
spk04: So that's a great question, sir. I know we've talked about this on prior calls. I think the company's done a terrific job for Kirk's and my rival going into this year, a lot of cost savings achieved post-merger in 19 and 20. ongoing trajectory of those reductions. And we've teed up, as part of our investor day, we describe how we think there's an ongoing opportunity for 1% to 2% productivity gains. So we think it will be along the lines of executing a plan that we've laid out and then continuing to drive improvements across our business through a systematic process. So I think that that's how we view our opportunity set is really driving that continuous improvement over time consistent with what we've laid out in the investor day plan.
spk06: Got it, got it. And then just lastly for me, if I may, just on the IRP summits you filed earlier this year, we've already seen, you know, multiple stakeholder groups make some noise in the Kansas docket. Staff made some positive and constructive comments. What should we be watching for in the process for the balance of the year across the states? And, you know, more importantly, is there any concerns around, you know, the IRP-related spending opportunities in light of some of the input cost pressures that we've seen in the renewable space. I mean, how do you price in these headwinds as we think about future generation opportunities, you know, through 26 and beyond? Thank you.
spk04: So, thank you, Char. On the – and I'll ask Kirk to supplement the commentary. We filed for predetermination relating to the 190 megawatts of solar. So, we'll have the chance to review that spend program and our planned addition as part of a regulatory filing before we advance the process. You know, part of why that program was sized down a little bit in scope from the initial estimates of 350 megawatts reflected the overall supply chain environment and the maturity of the solar pipeline in SPP relative to the more mature pipeline on the wind side. So we'll continue to evaluate that, but we like that we have the opportunity to have that dialogue proactively as part of the predetermination process. And we've launched the RFPs for wind in 2024 and 2025, as we described. So we'll see where those bids come out. Now we'll see how long the supply chain pressures advance. But I noted that we've got a target for reaching agreements related to the RFPs, at least for the first year in mid-2022. So we'll have a good sense. We'll have plenty of time to evaluate what we're seeing in the supply chain to make sure that what we're achieving drives our objectives of reliability, affordability, and sustainability. So we'll always keep a focus on that. I think the intervener comments in the IRP proceedings are relatively consistent with what you'd expect, which probably reflects that we're striking a balance in what we're striving to do. And we'll continue to do that, being mindful of the affordability impacts, as you note, of some of the supply chain pressures. And that's why we're trying to take a pretty systematic and diligent approach to how we tackle it.
spk01: Kirk, anything you'd add? Oh, yeah, just building on that last point, I mean, certainly we're mindful of and, you know, not immune to seeing the cost and supply chain pressures that are affecting across many sectors, including but not limited to renewables. Part of the reason why we made the slight shift that we did around the magnitude of the solar and advancing wind. But beyond that, as we indicated on Investor Day, we're looking at all facets of opportunities. Obviously, David mentioned we launched recently our RFP. That's our primary focus. But we have some self-development opportunities, the potential around some of those PPAs, buy-ins, and repowerings, and given the existing dialogue around some of the aspects of the Build Back Better framework. which is still a framework, but some of the potential for tax incentives, that can be potential mitigants and help aid affordability, help offset some of that cost pressure for us. So I think we've got a lot of levers and flexibility where that's concerned, but we're certainly laser-focused on finding the right blend from an affordability and a reliability standpoint on the renewables front.
spk06: Appreciate it. That's great color. Thanks, guys. Thank you.
spk07: Thank you. Our next question comes from Julian Dumoulin-Smith of Bank of America. Your question, please.
spk05: Hi, good morning. This is Darius on for Julian. Thanks for taking my question. Good morning. Good morning. I just wanted to start off thinking about average customer bills as we head into the heating season. Obviously, quite a bit of news out there about fuel prices. volatility and the impact that could have on bills. Do you have a, have you quantified sort of your average estimate for how much bills could increase either on a percentage basis or on a dollar per customer basis? And could you perhaps maybe speak to how that compares to your regional neighbors? I know there's fuel mix differences, so I think that might go in your favor, but if you could speak to that, please.
spk04: Sure, so. You know, it's obviously something we track closely, and we have a much smaller natural gas position than some of our neighbors. I can't comment on where their bill trajectory will go, but I'm sure you've been able to note the relative mix of gas relative to others. In 2020, only about 5 percent of our fuel and purchase power was natural gas related. So, natural gas price movements have not had a significant impact. We do have a relatively sizable amount of coal, so a 40 percent range, and there has certainly been movement in PRB pricing. We've got some protection around that from a hedging perspective over the near term. If those pricing pressures persist all the way through 2022, then obviously we'll have to see what those impacts are and see what the net impacts are in the wholesale market, of course, as well. We have a very sizable wind portfolio, and that wind portfolio will benefit relatively from higher prices when their fuel prices don't move, of course, on the wind side. So net, we are in a lower general bill season. We're an enterprise that's summer heavy. So the highest customer bills are typically in the summer. So in the fall, we are rolling into what are typically significantly lower customer bills. But it's something we're very focused on. Again, net relative to those who are more natural gas intensive, they are likely to be facing more intensive fuel costs. But, again, it all depends on what their hedge approach is. But on a relative mixed basis, we don't have the same exposure to natural gas as others.
spk05: Okay, great. Thank you for that detail. And just on the predetermination filing in Kansas that you referred to in the opening remarks, Could we potentially see – I know you talked about the timeframe for when you expect an order. I think you said mid-22. Should we expect to see a securitization filing shortly thereafter, assuming you get a favorable order in that predetermination docket?
spk04: Yes. So that proceeding includes asking for securitization relating to the retirement of the coal facilities in Lawrence. That's retirement of Lawrence Unit 4. as well as the shared cold handling facilities. It's relatively modest in size, but we would expect securitization relating to that, assuming that proceeding goes as planned.
spk05: Male Speaker 1 Okay, great. I'll leave it there. Thank you very much. Male Speaker 2 Thank you.
spk07: Male Speaker 1 Thank you. Our next question comes from Michael Sullivan of Wolf Research. Your question, please.
spk03: Michael Sullivan Hey, everyone. Good morning. Male Speaker 2 Morning, Michael. Kirk, I just wanted to follow up on some of the comments you made a little bit ago on the Biden Build Back Better plan, if maybe you just want to give a little more color on what some of the changes there could mean for you guys in terms of the wind RFP, the PPA buy-ins, and then maybe also direct pay. Yeah, just how we should be thinking about some of the puts and takes there.
spk01: Sure, Michael. So starting on the wind side, obviously the prospects of an extension and kind of returning to full power, if you will, on the production tax credit side, that is certainly a net positive, both in the context, as I mentioned before, from an affordability standpoint, which we're very focused on, the magnitude of those tax credits and the reliability over a longer period of time. being more robust. I think that's just added benefit in terms of meeting our objectives around affordability. It also speaks to greater flexibility in terms of the cadence and pace and mix of renewable investment. As you recall, we sort of pulled forward some of our wind investments to take advantage or at least in account for the existing expiry of the production tax credits, obviously an extension thereof, and an increase thereof would give us greater flexibility where that's concerned. And I think the knock-on effect there is, as we mentioned, certainly the buy-in of PPAs is one thing, but combining those PPAs with repowerings, and those repowerings are going to be certainly dependent upon taking advantage of those production tax credits. So that gives us a greater tailwind on the latter portion of that two-pronged strategy about that PPA buy-in combining of repowerings. The last piece of it, I would say, is on the solar side, where the investment tax credit is concerned, certainly the prospects of direct pay, for example, which is a more efficient way to deal with that ITC, which we have to deal with all in one lump sum, also a benefit on the solar side to us, again, from the affordability standpoint and how that's reflected in rates. So a lot of details to come. There are certain requirements there around that that we need to see more details on in terms of things like wage fairness and domestic content. But we feel optimistic that both on the solar and wind side that certainly creates a tailwind for us both in terms of flexibility and affordability for our customers as we make good on our renewables objectives.
spk03: Great. Super helpful. And just to follow up there, any thoughts on potential cash flow or balance sheet impact from things like direct pay?
spk01: To some extent, yes. I think in terms of the direct pay aspect of things, I mentioned before, obviously, as we reach the middle of the decade, we gain a greater appetite for cash taxes. And obviously, the ITC is an offset to that, to the extent to which it becomes direct pay, then that isn't as directly impacting our cash flows. But, you know, an increase in the magnitude of the PTCs can help offset. It's just another form through which we can take advantage of that tax appetite. So, net-net, again, I'd say that's certainly a positive. Maybe it's just a different mix of how we, you know, take advantage of our increasing tax appetite once we reach the middle of the decade and thereafter.
spk03: Great. And just the last one, kind of small, but on the power marketing benefit that you guys are realizing in 21 that's in the new guide, that's separate from URI and just any more color on that?
spk01: Sure. Yes, that's correct. Good question. As you recall, we did have some power marketing margins that we earned during the winter weather event. Those remain and have been excluded from our adjusted EPS. The upside or the outperformance, as I termed it, is in addition to or above and beyond that item that we'd excluded from our adjusted earnings. So we had certain expectations going into the year, and the power marketing businesses just exceeded those expectations, again, above and beyond the excluded item there. Still a small proportion of our total business, Michael.
spk04: You look across power marketing, Evergy Ventures, TransSource, Prairie Wind, all together it's even in the revised guidance with the stronger performance, a little under 5% or less than 5% of the earnings.
spk03: Okay, great. Thanks a lot. Go D, Skirk. Thank you.
spk04: Your mouth has got to hear. Thank you. Okay, moving on from the Wake Forest inner joke circle. Other questions?
spk07: Our next question comes from Michael Lapidus of Goldman Sachs. Please go ahead.
spk02: Hey, guys. Thank you for taking my question. Kind of a high-level one about the repairing opportunity, can you remind us how many megawatts of wind you have under PPA currently, and how many of those are contracts that are, call it, 10 years old or older?
spk01: Sure, Michael. Kirk, it's about 3.8 gigawatts in total in terms of our PPA portfolio. And as we had laid out, I think, on the investor day, one of our slides, we kind of showed the roll-off. And we're very focused on the subset of that portion in terms of contracts. Those contracts really don't begin expiring until just after the middle of the decade. But our focus here is on the expiry of the PTCs. We've got a little more than 1.2 gigawatts expiring. of that almost 1.3 gigawatts, of that 3.8 gigawatts, whose PTCs, rather, the production tax credits, are expiring between now and the middle of the decade. As those PPA or PTCs expire, we think that's probably the most meaningful subset of those 3.8 gigawatts of PPAs that we're focused on in the near term around repowering and buy-in opportunities because our counterparties have obviously taken full advantage at that point of all of the PTCs, and I think that's probably the target set we're looking at at Elson.
spk02: Got it. And if you do a buy-in, a couple of things. First of all, that's not embedded in your CapEx guidance, in your rate-based guidance. That would be upside to that. And then the second question, lots of those projects have project debt. How would you just basically take out the project debt or most of those have project debt that was an amortizing loan, so you're kind of near the tail end of that debt? I'm just curious about kind of taking a project off the books of a non-regulated developer and putting it into a utilities rate base.
spk01: Yeah, good question. I think we probably would not look to transfer, obviously, the project debt because it's relatively fully amortized. It would probably be a full buy-in, and so we'd purchase this on an unlevered basis, and obviously some of those proceeds would go to take out the existing project debt. So think about it as a pure rate-based investment on the PPA buy-in side.
spk04: And, Michael, your first part of your question, you are correct that None of this is in our current CAPEX guidance. The PPA buy-in and repowering, if we're able to get those negotiated, those would be upside or in addition to our current guidance. Yes.
spk02: Got it. Thank you, guys. Much appreciated.
spk04: Thank you.
spk07: Thank you. Our next question comes from Paul Patterson of Glenrock Associates. Your line is open.
spk08: Hey, good morning. Morning, Paul. Just a question. I apologize, but if we could just go over the investment income and the expectations for 2022. When I'm looking at slide 14, I assume that the investment income, let me ask you this. So what do you, and I apologize for not just completely getting this, but in 2021, what is the expected investment income in total? I see it's 12 cents so far today, just today. But with the SPAC and everything else that you're talking about, where is it going to sort of come in in 2021?
spk01: Sure. In 2021, on the power marketing side, we've probably got about five cents of total impact from investment income. That comes from a couple of sources. Some of that is we, like a lot of other utilities, invest in other funds. Energy Impact Partners is one of those. So some of that is the mark. Some of that is, as I mentioned before, earlier in the year. On a direct investment side, we actually had an actual monetization event, and that's probably the disproportionate share of that through the first half of the year is that monetization event. So it's a combination of those two things. Obviously, that contributed to exceeding our expectations on the upside, obviously.
spk04: And I'll just clarify, Kirk's absolutely right. You prefaced that and said power marketing, but that's the Evergy Ventures.
spk01: Oh, Evergy Ventures, yeah, sorry. Our average event is the investment model. Thanks, David. And then if you look forward into 2022 and beyond, as I mentioned before, that five cents is outperformance. You know, on an ongoing basis, certainly in our 22 guidance, it's more like a penny or two from the average event. Okay.
spk08: Okay. Great. Okay. And then the rest of my questions have been answered. So thanks so much. Thank you, Paul.
spk07: Thank you. Our next question comes from Travis Miller of Morningstar. Your question, please. Travis, please make sure your line isn't muted. And if you're in a speakerphone, lift your handset. All right. At this time, I'd like to turn the call back over to David Campbell for closing remarks. Sir?
spk04: Great. Thank you very much. We appreciate all of you joining us this morning. We look forward to seeing many of you in person next week at EEI. Signing off.
spk07: And this concludes today's conference call. Thank you for participating. You may now disconnect.
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