Evergy, Inc. (NYSE:EVRG) Q2 2023 Earnings Call Transcript August 4, 2023

Evergy, Inc. misses on earnings expectations. Reported EPS is $0.777 EPS, expectations were $0.79.

Operator: Good day, and thank you for standing by. Welcome to the Q2 2023 Evergy, Inc. Earnings Conference Call. [Operator Instructions]. Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your speaker today, Pete Flynn, Director of Investor Relations. Please go ahead.

Peter Flynn: Thank you, , and good morning, everyone. Welcome to Evergy’s Second Quarter 2023 Earnings Conference Call. Our webcast slides and supplemental financial information are available on our Investor Relations website at investors.evergy.com. Today’s discussion will include forward-looking information. Slide 2, in the disclosures in our SEC filings contain a list of some of the factors that could cause future results to differ materially from our expectations. They also include additional information on our non-GAAP financial measures. Joining us on today’s call are David Campbell, President and Chief Executive Officer; and Kirk Andrews, Executive Vice President and Chief Financial Officer. David will cover our second quarter highlights, our integrated resource plan and regulatory and legislative priorities.

Kirk will cover in more detail the second quarter results, retail sales trends and our financial outlook for 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.

David Campbell: Thanks, Pete, and good morning, everyone. I will begin on Slide 5, and I’m pleased to report that Evergy had a solid second quarter as we delivered adjusted earnings of $0.81 per share compared to $0.84 per share a year ago. The decrease was driven by less favorable weather as well as higher depreciation and amortization interest expense partially offset by growth in weather normalized sales, transmission margin and lower O&M expenses. Kirk will discuss these earnings drivers in more detail in his remarks. Our reliability metrics were strong for the year, through June as average duration and frequency, otherwise known as SAIDI and SAIFI, were favorable to relative to our target. I’d like to call out the work of our distribution and transmission teams for the improvements in system resiliency that we’re seeing.

Weather has been less cooperative to start the third quarter and on July 14, our service territory experienced a severe storm. The storm produced 80 to 100-mile per hour winds resulting in our most impactful storm in recent history. As the storm’s peak, nearly 200,000 Evergy customers were without power, as high winds down countless turbulence and damaged or destroyed nearly 500 power poles. We estimate total O&M costs of $6.5 million for the storm recovery efforts. I’d like to thank the nearly 3,500 Evergy employees contractors and personnel from neighboring utilities that assisted in making repairs, working with customers and restoring power. Our crews worked 16-hour shifts through hot and humid conditions as well as follow-on storms that disrupted the restoration efforts, and our customer teams also worked over time to field calls and support our customers.

Our front-line workers are the bedrock of safely delivering affordable and reliable power to our customers and communities. We’re extremely proud of and grateful for their contributions to these challenging conditions. Our team’s consistent execution has resulted in a solid start to the year, and we are reaffirming our 2023 adjusted EPS guidance range of $3.55 to $3.75 per share as well as our target long-term annual adjusted EPS growth of 6% to 8% from 2021 to 2025. Slide 6 highlights our annual integrated resource plan updates, which were filed on June 15 in both Kansas and Missouri. This year’s updates reflect the impacts of the renewable support provided by the Inflation Reduction Act, revised load forecast, increase Southwest Power Pool capacity margin requirements, potential changes to environmental regulations and updated commodity price forecasts.

As a reminder, in 2022, nearly half of the energy that we generated for our retail customers came from carbon-free resources. Reflecting the contributions of our Wolf Creek nuclear plant and the 4,400 megawatt portfolio of renewable resources that we own or contract with long-term power purchase agreements. Over the next 10 years, taking advantage of the ample resource potential of our region as well as substantial federal subsidies, we plan to add more than 3,000 megawatts of new end and solar resources. The timing of these additions reflects the outputs of our recent all resource request for proposal, which was no doubt, affected the global supply chain challenges impacting solar wind and battery project availability and costs. Tightening capacity conditions in the Southwest Power Pool and higher demand also factored into the annual IRP update, reflecting higher capacity needs, this year’s preferred plan includes the introduction hydrogen capable combined cycle gas turbines in the latter half of the decade.

We now expect to cease all coal operations in Lawrence units 4 and 5 and to convert Lawrence Unit 5 to natural gas in 2028. In aggregate, the 2023 preferred plan includes 4,800 megawatts of new resource additions through 2032, an increase of 1,200 megawatts when compared to the 2022 Integrated Resource Plan update. As our generation fleet evolves, we are focused on achieving a responsible balance between non-carbon emitting inter-median resources typically with low or negative marginal costs and older firm dispatchable generation with higher marginal costs, all while ensuring reliability and affordability for our customers and communities. We’re excited about the potential investment opportunities ahead of us as we continue to transition our portfolio over the coming years.

Moving to Slide 7, I’ll provide an update on our regulatory and legislative priorities. In Kansas, we’re awaiting intervenor testimony, which is due to be filed by August 29 and our pending Kansas Central and Kansas Metro rate cases. Activity in September picks up with rebuttal testimony due September 18 and the settlement conference scheduled for September 21. Should an agreement be reached, we’d be required to file it by September 29. Otherwise, hearings would run from October 9 through the 13. We look forward to working with all parties to achieve a constructive outcome and advance regionally competitive rates for our Kansas customers and communities. Shifting to Missouri, the order approving our request to securitize extraordinary costs from Winter Storm Uri remains in the state of pellet process with oral arguments to be held September 7.

We believe the Missouri Commission’s decision and support of securitization is well supported by the record. As a reminder, we will complete the securitization financing after the appeal plays out, but incremental carrying costs incurred prior to approval will ultimately be recovered when we issue the debt. We anticipate resolution later this year. I’ll conclude my remarks with Slide 8, which highlights the core tenets of our strategy, affordability, reliability and sustainability. On the affordability front, advancing regional rate competitiveness is one of our primary objectives. Our focus on delivering benefits to our customers since the 2018 merger is reflected and demonstrated in the EIA data on rate trends across states in the Central United States over the past 5 years.

In addition, direct market evidence is provided by ongoing wins in economic development in our territory. We’re pleased by our progress in improving regional rate competitiveness and keeping our rate trajectory well below the rate of inflation. Affordability is and will always be an area of focus. Ensuring reliability is also a core element of our strategy. And along with SAIDI and SAIFI, this includes a focus on metrics relating to customer service, the commercial availability of our fleet, safety and all elements of our operations, including infrastructure investment. This summer has brought resiliency and reliability to the forefront as storm activity in our service territory has been more prevalent than normal. Including the July 14 storms, of straight-line wins in excess of 80 miles an hour.

These types of conditions reinforce the importance of our ongoing transmission and distribution investments. And with respect to sustainability, we continue to advance the transition of our generation fleet as detailed in our 2023 IRP update and continuing the progress of the last 2 decades. Since 2005, we significantly and cost effectively transformed our generation fleet, reducing carbon emissions by nearly half, reducing sulfur dioxide and NOx emissions by 98% and 88%, respectively, and we look forward to the ongoing portfolio transition. Our mission is to empower a better future, and our vision is to lead the responsible energy transition in our region, always with an eye on affordability and reliability as well as sustainability. With that, I will now turn the call over to Kirk.

Kirkland Andrews: Thanks, David, and good morning, everyone. Turning to Slide 10, I’ll start with a review of our results for the quarter. For the second quarter of 2023, Evergy delivered adjusted earnings of $186.1 million or $0.81 per share and that’s compared to $194.5 million or $0.84 per share in the second quarter of 2022. As shown on the slide from left to right, the year-over-year increase in the second quarter adjusted EPS was driven by the following: first, a 13% decrease in cooling degree days compared to last year, drove an $0.08 decrease in EPS. Compared to normal, weather for the second quarter was favorable by approximately $0.03 per Share. Weather-normalized demand growth of 1.1%, driven by the residential and commercial sectors contributed $0.04 per share.

Higher transmission margins resulting from our ongoing investments to enhance our transmission infrastructure, drove a $0.02 increase. A $53 million decrease in adjusted O&M drove a positive $0.17 variance year-over-year. This was partially due to the continued execution on operational efficiencies and partially the result of timing of O&M expenditures within 2023. The net impact of higher depreciation and amortization was $0.07 for the quarter, which includes the offsetting impact of new retail rates. The combination of higher interest expense and lower AFUDC drove a $0.13 decrease with interest expense representing about $0.12 of that variance. The increase in interest expense also reflects the lower rate environment comparatively in early 2022.

And finally, other items, both positive and negative, drove a net increase of $0.02. I’ll turn next to the year-to-date results, which you’ll find on Slide 11. Through the first 6 months of 2023, adjusted earnings were $322 million or $1.40 per share compared to $324 million or $1.41 per share for the same period last year. Again, moving from left to right, our year-to-date EPS first drivers that is versus 2022 include the following: when combined with the mild winter weather in the first quarter of this year, our year-to-date results reflect an approximate 13% decrease in heating degree days and in cooling degree days, driving a $0.16 decrease in EPS versus the first half of 2022. And as compared to normal, weather was approximately $0.04 unfavorable through the first half of 2023.

Solid weather-normalized demand growth of 1.6% year-to-date, in line with our annual estimate, driven by the residential and commercial sectors contributed $0.09 per share. Higher transmission margins resulting from our ongoing investments drove a $0.04 increase. Decreased O&M drove a positive $0.29 variance year-over-year. As I mentioned earlier, the decrease is partially a result of timing of O&M expenditures within 2023, a $0.13 decrease from higher depreciation expense due to increased infrastructure investment which again is net of the offsetting impact of new retail rates. $0.04 of year-to-date proceeds from company-owned life insurance and higher interest expense and lower AFUDC, which drove a $0.26 decrease with interest expense representing $0.22 of that variance.

The increase in interest expense again reflects both a higher carrying balance and the lower rate environment in the first half of 2022. We expect rate-driven variances to decrease in magnitude as we move through the year, consistent with the original assumptions of our guidance. And finally, other items but positive and negative drove a net increase of $0.08, which was primarily driven by other income and income tax items. Turning to Slide 12. I’ll provide a brief update on the recent sales trends. Weather-normalized retail sales increased 1.1% in the second quarter as compared to last year. This was primarily driven by increases in both residential and commercial usage. While year-to-date weather-normalized demand is up by approximately 1.6%.

The Lower industrial demand continues to be driven primarily by 2 refining customers. Excluding these 2 customers, remaining industrial weather-normalized demand would’ve increased during the first half of this year. Demand growth continues to be supported by a strong local labor market with Kansas and Kansas City Metro area unemployment rates of 2.8% each, which continue to remain below the national average of 3.6%. And finally, on Slide 13, I’ll wrap up with an overview of our long-term financial expectations. With a solid start to the year, we are reaffirming our adjusted EPS guidance range of $3.55 to $3.75 for 2023. We are also reaffirming our long-term compounded annual EPS growth rate target of 6% to 8% from 2021 to 2025. And we expect to address our outlook for earnings growth beyond 2025 on our year-end call in February.

Our $11.6 billion 5-year capital plan through 2027 is focused on new infrastructure investment to improve customer service, enhance reliability and resiliency as we transition our generation fleet while continuing to advance regional rate competitiveness and meet the evolving needs of our customers and our communities. With that, we’ll open up the call for questions.

Q&A Session

Operator: [Operator Instructions]. Our first question comes from the line of Durgesh Chopra from Evercore ISI.

Durgesh Chopra: I have two questions. I appreciate the fact that with the IRP moves, you guys kind of reaffirmed your CapEx and rate base outlook. Maybe can you just get a little bit more granular and quantify how much CapEx was there associated with renewables in the current plan? And then what are the opportunities on the grid mod side or other opportunities that you think that as a result of those moves, that CapEx and rate base growth profile is still intact. Any color there?

David Campbell: Sure. So I guess, thanks for the question. It’s a good one. When we put out our integrated resource plan, you’ll recall that we also released a slide at the time, saying that our overall capital investment plan for 2023 — 2022, 2023 to 2027 was in line with our updates within the last quarter. Now there is some mix shift in that we haven’t published that overall change yet. We’re going through that process as we typically will through the course of the year. The Integrated Resource Plan has a higher overall total level of resource additions, but there’s some phasing shifts over the near term, particularly there’s a drop in window in the near term, and that reflects to a large degree, supply chain constraints and the impact of product availability and costs.

And why we reaffirmed our overall capital plans is for the factors that you highlighted. We have a wide range of beneficial infrastructure investments, particularly in the grid modernization and grid resiliency side that are the elements that we expect will be a little bit higher and will contribute to an overall capital plan that is consistent. Now again, over the 10-year time frame, we have a relatively significant addition of new resources. So in that time period, you can expect that they’ll all sequel be an uptick and capital expenditures, we only give a 5-year plan update. But you’ll see some elements of that when we get to year-end because we’ll add 2028 to our public disclosures, and you’ll start seeing — we start some of those resource additions that I mentioned, in particular relating to hydrogen capable new natural gas units, a lot of that capital expenditure, you’ll see showing up in the latter part of our capital plan, a 5-year plan.

Durgesh Chopra: Got it. Okay. So you remain confident in your CapEx and rate base outlook and we’ll look for more color on the Q4 call. That’s the key takeaway there. Okay. Just then on the Kansas rate cases, just can you give us any incremental data points? What’s the feedback pain from various stakeholders and the potential for a settlement? I know you put out some dates there, but just looking for any additional color that you can share?

David Campbell: Yes to guess for better worse, the way the process plays out. We don’t have a lot to share. We’ll see the — we’re still in the process of sort of a rigorous back and forth in terms of receiving a lot of questions with capital, if happens in all rate cases. So we’ll have a good sense and you can get some feel for where parties are focusing to the questions. We really get a sense of things when they’re — when the first round of testimonies filed. So August 29 is going to be a day that people will be doing a lot of reading, certainly on our side, so you’ll see staff and intervenor testimony on that day. So I get a lot more color on things as we head into in August and September. We will certainly look forward to the opportunity to work constructively with all parties and seeking a settlement.

It’s been 5 years since the last rate case. But otherwise, at least in our , it’s a pretty straightforward rate case in terms of the elements that are included, it’s primarily related to the infrastructure investments that have been made over that time period, plus the amount of cost savings that we’ve been able to achieve as a result of the merger with a couple of items that I think are pretty clearly described and laid out. So it’s a little less complicated than some elements at least of our Missouri West case last year, that’s again probably many years. So we look forward to constructively engaging with the parties, but you’ll learn more about that later this month and then particularly as we head into September and October.

Operator: One moment to our next question. Our next question comes from the line of Shar Pourreza from Guggenheim Partners.

Shahriar Pourreza: I just want to be crystal clear on the response that you gave to Durgesh because, I mean, obviously, this was a very deep IRP update a few weeks ago. So is the messaging that it is status quo from just a capital perspective to the current trajectory, but there could be some step function increases as we shift forward. I just want to get a bit of a sense there.

David Campbell: So as of my — to sharpen my response, I’ll ask Kirk go first. Kirk, go ahead and I’ll follow up.

Kirkland Andrews: So I think about it — first of all, I think Durgesh asked this question as well. I mean, I think our overall — and we put this in a broad category, new generation renewables, our fourth quarter update, the cumulative amount of that was a little over $2.1 billion. And that’s obviously contributes to the aggregate $11.6 billion. The way to think about that is, yes, our overall magnitude of capital expenditures is in line. We also expect the magnitude capital expenditure on new generation and renewals to be in line. We do expect some probably some timing shifts. We also expect the annual cadence of that capital expenditure is to accumulate up to that $11.6 billion to also be consistent, will probably be a little bit of a mix shift because if you look at the magnitude and the cadence specifically of renewables and new generation year-over-year informed by the IRP kind of plan over plan, that will probably imply a little bit of variation in the implied capital expenditure space over that period of time.

Over we have an abundance of very necessary and beneficial grid modernization projects. So you may see a little shift between those 2 categories year-over-year. But overall, the aggregate magnitude, the amount of generation as well as the annual magnitude will be in line. That helps.

Shahriar Pourreza: Yes, it does.

David Campbell: And I’ll add. So Kirk, thank you for the clarity. I’ll add an additional point is we’re very focused on affordability and as we think about our capital planning. We have and we were able to have the opportunity to go through this with. Our Kansas commissioners and we have a similar dialogue. Of course, Missouri, we’ve been able to go through, we’ve got an old system. We’ve got a lot of very wide range of beneficial projects that are available to us. We calibrate our level of expenditure with an eye towards affordability. There’s no doubt around that. So we’ll continue to shape that, but we’ve got a really robust capital plan informed by parts of our system are still very old. So we’ve got, if you will, a backlog of beneficial projects. So we’re always going to keep an eye on affordability as well.

Shahriar Pourreza: Got it. And David, can you just speak a little bit more broadly to sort of the transmission expansion backdrop in SPP and MISOs. Now looking at tranche 2 and 3, they’re spending billions on moving power through your neighboring systems. Do you see the RTO picking up the pace here in the years ahead? Just any color on the backdrop, especially as you guys continue to evaluate on the generation side?

David Campbell: Well, that’s a great question, Shar. I think it’s fair to say that the Southwest Power Pool, certainly, if you look at their strategic plan, the grid of the future and the future evolution of the long-term transmission plan is on their agenda. But it’s also fair to say that what’s on their agenda is a process that will lead to kind of tranches 1, 2 and 3. So in that sense, it’s — they’re not at the same stage as MISO in the Southwest Power Pool. In other words, it’s still some time away. Now we, as a big player in the Southwest Power Pool are certainly an advocate for going through the process. We know how important it’s going to be as you look at our integrated resource plan, especially as you get to the latter part of this decade in the 2030s.

And this is true across all of the players really in our space and will be impacted by things like the evolving federal EPA rules, there’s a lot of changes in our resource plan that are coming. And the transmission grid is going to have to be ready for that. So I think we, as a participant in SPP will continue to be an advocate for moving down the path. I think it’s fair to say that the where you see tranches 1, 2 and 3 mice, so you don’t yet see those in SPP, but it’s on their strategic agenda, and we’ll be working with them to try to advance it because it is evolving — further evolving the transmission grid is going to be very important to our region to keep rates affordable as we transition our fleet.

Shahriar Pourreza: I think that is fantastic. You guys covered everything. I appreciate it.

Operator: One moment for our next question. Our next question comes from the line of Julien Dumoulin-Smith from Bank of America.

Julien Dumoulin-Smith: Can you guys hear me? Excellent. Look just following up with the last question. Let me just jump to this. Obviously, the updated IRP had a fairly modest, if not flattish outlook on load a lot of the commentary that you’re making here would kind of perhaps suggest that, that certainly has an upside bias to it. We’ve seen that in other jurisdictions. How do you think about the evolution of your load forecast itself? What’s in that plan? What’s not in that plan? Again, obviously, you just filed this. So obviously, there’s a certain element of it being still relevant. But maybe you could talk about some of the pivots in it as you think about this IRP, just at the outside.

David Campbell: Yes, it’s a great question, Julien, because it’s a — I think it is an upside factor for our sector and for our region as well. We do have a low, medium and high demand case in the integrated resource plan. We typically, in the long-term planning elements I think in the mid-range at 0.5% rate of growth. We had a higher level of growth we expected in are embedded in our plan in 2023, which we’ve seen tracking with our results at least in the first half of the year. Over the long term, there are certainly structural factors that I would argue could take us more towards the higher end rather than that 0.5% per year, and that’s going to be from electrification and some of the large new loads that are coming in as we effectively are reshoring, if you will, here in the United States.

So the — and then the last element which gets more and more focused is the transformation of electricity demand driven by AI and the need for more and more data centers. So I do think there’s some upside factors. Those 3 electrification onshoring and proliferation of data centers. I think it’s also fair to say that, that could be upside to the long-term plans. Now a lot of that will manifest itself the latter part of this decade into the 2030s. But I think those long-term fundamentals are strong and should present some, if you will, bias towards the higher — it’s in the IRP, but it’s more in the high case close the mid. And I think for our region, the additional piece that we have relative to some others is, of course, a lot of our portfolio transition does occur in the 2030s well, right?

We’ve — as we know, we’ve got a — we have an interesting mix in our generation portfolio. We’ve got half — basically half its emissions free and half that’s fossil-based relatively higher share of coal. There’s several utilities have a similar share. But a lot of that transition for us will happen in the 2030. So I think the long-term fundamentals from a resource planning perspective, from a demand perspective, are strong. And as we know, when there’s demand growth, that helps with affordability because you’re spreading across costs across a bigger pie. So I think it’s a great question, and I think it’s something that leads us to have a bullish outlook in the long term.

Julien Dumoulin-Smith: Just pivoting here to the guidance and just year-to-date results, if you will. I know you guys have a cost legacy and kudos on that front. $0.29 is pretty impressive as a headline number here on O&M. Can you talk a little bit about what those items are, the sustainability of them into ’24. Maybe some of the puts and takes within guidance that you contemplated at the start of the year, i.e., how are you tracking against those guidance items? Because it would seem as if with weather still fairly modest as a headwind $0.29. I know you offset the persimmons here, but like it’s certainly a nice showing on the cost front in year-to-date sense.

David Campbell: So Julien, there’s a lot there. I think — and I’ll ask Kirk to supplement. It’s — we like our peer utilities try to manage our business in an overall perspective based on managing as best we can the things in our control, as things outside of our control move. Weather has been a headwind this year. July was on the mile side, at least in our region, I know it’s been quite variable across the U.S. We’re in the milder side in July, but it did even vary across our service territory. So proud of the team and how we manage costs. You asked about which elements it really is, and we review this on a rigorous basis across the entire part of our business from ops to our generation side, transition distribution, our customer operation in the corporate center.

So some of this is timing and phasing, as Kirk mentioned in his remarks, but we are going to be managing the business dynamically and just as our peer utilities do, because we reaffirm our annual guidance this year, and we seek to, again, manage the things that are within our control so that we are in a position to offset factors that are outside of our control. So proud of the team for their cost management we’ve laid out is no ongoing cost savings as part of our plan. So I think that, that continues to be our plan as we look through to 2025. But it’s a testament to the work of the team and the efforts of our enterprise to drive affordability and benefits for our customers and manage our business so that we can hit our plan and deliver results.

Julien Dumoulin-Smith: Got it. So it sounds like there could be some items here, but you’re not ready necessarily to say the…

David Campbell: Yes. Yes, we’re sticking with our guidance for the year, Julien, and it’s — we’ll manage the business dynamically just as you’ve seen us do in for the first part of the year and the prior year.

Kirkland Andrews: Yes. And without quantification, Julien, just to add on to that. I mean, you’re correct. I mean, you’re the keen observer, right? You got that large number year-to-date. I even said in my remarks, it was partially to do inter-year timing, partially doesn’t mean all of it. And that’s our job through the year, right? Making sure that we stay vigilant around our cost, so we’ve got that cushion to be able to offset some of the unknown variables, right? We can’t control weather. David mentioned, we had a little bit of storm cost past the first half of the year, that storm-related cost, that gives us a cushion to absorb that. And obviously, the variability that we’re all experiencing on interest rates. So staying ahead of the game and being vigilant around those costs away from that intra-year timing.

Some of it can’t really extrapolate that over the balance of the year. But having that in our pocket to look towards the back half of the year allows us to maintain our commitment because as we’ve said, one of the things that we are very focused on here is making sure we deliver on those commitments, right? The means by which we do that is dynamic during the year because there’s anything but a static environment because of some of the elements I’ve addressed.

Julien Dumoulin-Smith: Got it. All right. I got more I’ll leave them offline. Thank you very much. Have a great day.

Operator: One moment for our next question. Our next question comes from the line of Michael Sullivan from Wolfe.

Michael Sullivan: Just wanted to put a finer point on that last line of questioning. So the mild July weather and then that storm impact is — are both of those factored into the ’23 guide reaffirmation?

David Campbell: So Michael, obviously, we don’t have our full results for July yet. We are able to quantify the storm costs and include that in the script. But we did affirm — we are affirming our annual guidance range today. So we’ll — so to the answer to your question is yes. Based on the information we have now, we are affirming our guidance for the year. And as Kirk described, very important for us to we’ll stay ever focused on that and keep working those things that we are in our control to help offset if the other nation can shift day-to-day factors that are outside our control. But yes, we’re affirming our guidance for 2023 today.

Michael Sullivan: Okay. Great. That’s helpful. And then a lot of what you updated in the IRP, I think you mentioned, was formed by the recent RFP process? When will we see the results or more detail on that RFP?

Kirkland Andrews: Hey Mike, it’s Kirk. I think you’ll expect to see that from us later and you can’t discount the possibility we may have some more information once we get to the third quarter call in November. But as we move through the back half of the year, we’ll certainly have some more information about that.

David Campbell: And part of it Michael, you can appreciate it relates to ongoing negotiations that are currently — that’s the main driver as to why, you’re not hearing more.

Operator: One moment for our next question. Our next question comes from the line of Paul Patterson from Glenrock Associates.

Paul Patterson: I just have one question at this point. And that is there’s a rate design change with time of use that’s coming up here, I guess, in Missouri for you guys. And I’m just wondering, it looks like there’s a potential for some significant changes. And is there any I guess, is there any risk that customers might be — some customers might be implicitly surprised by the change even though it’s a rate design issue, people don’t necessarily know what’s going on and it’s time of use and they’re just not prepared for it. And sometimes in certain jurisdictions, we’ve seen, it happens from time to time where people are very upset by something that kind of a change, if you follow me.

David Campbell: Paul, it’s a good question again. You’re correct. It’s from Missouri jurisdictions only and as a result of the last rate cases, there is a Missouri Commission. I feel strongly about this topic and included in their order a move towards time use rates for all customers in Missouri. Now fortunately, partially as a result of a revision that was made for the order that’s being implemented in the fall. So it is being implemented in — later this year when we’re out of the hot weather season, we’ve had time and we’ve put out a lot of communications around the Tommy use transition, and we’ll continue to have a lot of communications. There are several different options, one of which is a relatively modest change relative to the historical rate plans.

So we think with the level of communication tools we now have, the number of folks who have online accounts, that the level of information will be high. So a big part of what we’ll need to do and adhering to the commission’s order on this is just having a high level of communication. And fortunately, again, with it being implemented in the fall, in a milder weather time, I think that it will be a little more explainable to customers. And it primarily relates to the hours of 4 to 8 p.m. weekdays, so it’s a concentrated approach. So even though it is, as you know, rate design is not intuitive to many customers. I think our team has done a nice job laying out what it entails, what it means and how customers can work with it. So we’re working to be commissions order, and we think we’ll be able to communicate with our customers, make sure we work with them as they go through the transition and select the plan that’s best for them.

Operator: Thank you. At this time, I would now like to turn the conference back over to David Campbell for closing remarks.

David Campbell: Great. Thank you. I’d like to thank everyone for your interest in Evergy this morning, and hope you have a great day. That concludes the call.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.