WEC Energy Group Inc (WEC) — Q2 2022 Earnings Call Transcript

Hot town summer in the city. Good afternoon, everyone. Thank you for joining us today as we review our results for the second quarter of 2022. First, I'd like to introduce the members of our management team who are here with me today. We have Scott Lauber, our President and Chief Executive; Xia Liu, our Chief Financial Officer; and Beth Straka, Senior Vice President of Corporate Communications and Investor Relations. Now as you saw from our news release this morning, we reported second quarter 2022 earnings of $0.91 a share. A warm start to the summer, solid results from our Infrastructure segment, and continued execution of our capital plan were major factors that shaped yet another strong quarter. In light of this strong performance, we're again raising our earnings guidance for 2022, this time by $0.02 a share, to a new range of $4.36 to $4.40 per share. We expect to reach the top end of this new range. This, of course, assumes normal weather for the remainder of the year. Our balance sheet and our cash flows remain strong. And as we've discussed, this allows us to fund a highly executable capital plan without any need for new equity. During the quarter, we continued to move forward on major initiatives across the enterprise, including investments in our $17.7 billion ESG progress plan. Our focus remains on building and maintaining a highly reliable infrastructure, delivering energy that's affordable, reliable, and clean. Scott will provide you with a project update in just a few moments. Now you may recall our recent announcement about an adjustment that we made to our schedule of power plant retirements. We plan to extend the operating lives of the four older units at our Oak Creek site. The retirement of units 5 and 6 will be delayed by a year until May 2024. Units 7 and 8 will be delayed for about 18 months until late in 2025. These coal-fueled units have a total rated capacity of 1,100 megawatts. We based this decision on two critical factors: first, tight energy supply conditions in the Midwest power market; and expected delays in the delivery of solar panels and batteries, delays that will clearly affect the in-service dates of renewable projects that are now going through the regulatory approval process in Wisconsin. Keeping the older units at Oak Creek online a bit longer for capacity purposes makes great sense for our customers because we can avoid the need to purchase higher-cost capacity in the MISO market. But even with the extension of the Oak Creek units, we remain committed to our aggressive environmental goals. Across our generating fleet, we're still targeting a 60% reduction in carbon emissions by the end of 2025 and an 80% reduction by the end of 2030. And by the end of 2030, we expect to use coal only as a backup fuel and we're aiming for a complete exit from coal by the end of 2035. The capital investments we plan fully support this transition. Of course, for the longer term, we remain focused on the goal of net zero carbon emissions from power generation by 2050. And as you know, we're working to help shape the future of clean energy, engaging in policy discussions, and on the ground, carrying out innovative projects that can drive decarbonization of the economy. For example, we've now finalized the test plans for blending hydrogen with natural gas at one of our modern gas field units in the Upper Peninsula of Michigan. We've teamed up with the Electric Power Research Institute for this leading-edge project. The field work will take place this fall, and the results will be shared across our industry. Separately, for our natural gas distribution business, we're making great progress in securing supplies of renewable natural gas. Scott will update us shortly, but as a reminder, our plan is to achieve net zero methane emissions from our gas distribution networks by the end of 2030. Switching gears now. Let's take a brief look at the regional economy. The latest data show Wisconsin's unemployment rate at 2.9%, well, of course, below the national average, and we continue to see major investments from growing companies in our region. For example, Gulfstream Aerospace is expanding its operations at the Appleton Airport. That's in Wisconsin's Fox Valley, southwest of Green Bay. The company is planning to build a world-class facility for painting and finishing aircraft exteriors. This expansion is expected to open in the third quarter of 2023 and could add 200 new jobs to Gulfstream's existing workforce in Wisconsin. And just last month, Komatsu Mining celebrated the official grand opening of its new headquarters here in Milwaukee. The campus is already hosting about 600 employees. It includes offices, a training center, and state-of-the-art manufacturing space to build heavy mining equipment. During the second quarter, groundbreaking also took place for a major expansion of the Georgia-Pacific paper mill in Green Bay. Georgia-Pacific is investing $500 million in its new facility, which is expected to bring about 100 new jobs to the region. So with a wide range of developments in the pipeline, we remain very optimistic about the long-term future of the regional economy. And with that, I’ll turn the call over to Scott for more information on our utility operations and our infrastructure segment. Scott, all yours.

Thank you, Gale. As Gale mentioned, we're making good progress on our capital plan. Construction is underway on a number of regulated projects. We have started work on the reciprocating internal combustion engines, or as we call them, RICE units, at our western site in Northern Wisconsin. These units are expected to provide 128 megawatts of dispatchable capacity with an estimated cost of $170 million. Also, work on our liquefied natural gas storage is underway. As you recall, the commission approved two LNG units in Southeastern Wisconsin. This $370 million investment will provide needed peaking capacity for our gas distribution business. On the renewable front, we've deployed $155 million towards refurbishing projects at two of our regulated wind farms. When completed, these projects will enhance reliability and performance at these farms. These investments will qualify those sites for production tax credits for an additional 10 years. Also, we expect our Red Barn Wind Park development in Southwestern Wisconsin to come online around the end of the year. It will provide about 80 megawatts of renewable energy to our Wisconsin Public Service customers. On the solar and battery front, work continues on the Badger Hollow II solar facility and the Paris Solar Battery Park. We still expect these solar projects to go into service next year, supplying more clean energy to our Wisconsin customers. However, we've informed the Wisconsin Commission that the battery portion of the Paris project is expected to be delayed until 2024. As you may recall, we have filed for approval of two other solar battery projects, Darien and Koshkonong. We initially planned to add these to our fleet in 2023 and 2024. We now project them to enter service in 2024 and 2025, respectively. In addition, we now expect the retirement of Columbia Energy Center to take place in 2026. As you know, Alliant Energy operates the Columbia facility and we are a part owner. Of course, we’ll keep you updated on any further developments. As you recall, we filed a rate review last quarter with the Public Service Commission for our Wisconsin utilities. Our proposed rate increase would support important capital investments and grid hardening projects. Recently, we provided an update to our filing. We factored in the extended operating lives of the older Oak Creek units and the Columbia units. This update also reflects other variables, including higher interest rates and costs associated with the completion of our solar projects. We expect final orders by the end of the year with new rates effective in January 2023. We have no other rate reviews pending at this time. In our gas business, we’ve discussed plans to bring high-quality renewable natural gas to our customers. The Wisconsin Commission recently approved our pilot project for this initiative. Just last month, we signed our third RNG contract which will connect our distribution system to a large dairy farm in Northeast Wisconsin. The three contracts in place are projected to bring us 80% of the way toward our goal of net zero methane emissions. We plan to have RNG flowing in our system by the end of this year. Outside of our utilities, our WEC infrastructure segment was once again a positive driver for the quarter. The Thunderhead Wind Farm located in Nebraska will be the next project to go into service scheduled for later this year. We also expect the Sapphire Sky Wind project in Illinois to come online by year-end. Together, the two projects represent approximately $800 million of investment, keeping us well ahead of our 5-year capital plan. As you know, MISO, the Midwest grid operator, has set out a long-range plan to address transmission needs across the Midwest. And last week, the MISO board approved the transmission projects for tranche 1. At this time, American Transmission Company estimates that its investment opportunity in tranche 1 is approximately $900 million. That’s in today’s dollars. Investment in these long-dated projects is expected to start as early as 2027. And with that, I’ll turn things back to Gale.

Scott, thank you very much. Now as you may recall, our Board of Directors at its January meeting raised our quarterly cash dividend by 7.4%. We believe this ranks us in the top decile of our industry. We continue to target a payout ratio of 65% to 70% of earnings and therefore, I expect our dividend growth will continue to be in line with the growth in earnings per share. And today, we are reaffirming our projection of long-term earnings growth at 6% to 7% a year. Next up, Xia will provide you with more details on our second quarter financials and she'll touch on the likely impact of the reconciliation bill that appears to be headed for a vote in the U.S. Senate. We view the legislation as broadly positive for customers, for the energy transition, and for our future investment opportunities. Xia?

Thanks, Gale. Our 2022 second quarter earnings of $0.91 per share increased $0.04 per share compared to the second quarter of 2021. Our earnings package includes a comparison of second quarter results on Page 17. I'll walk through the significant drivers. Starting with our utility operations. The impact of weather was flat quarter-over-quarter. On a weather-normalized basis, retail electric deliveries in Wisconsin, excluding the iron ore mines, were up 0.30%, led by our small commercial and industrial customers. Overall, retail demand for electricity is tracking our forecast. Across our regulated business, we grew our earnings by $0.05 compared to the second quarter of 2021. Rate-based growth contributed $0.09 to earnings. This is partially offset by $0.03 of higher depreciation and amortization expense and a $0.01 increase in day-to-day O&M. At our investment in American Transmission Company, earnings increased $0.01 compared to the second quarter of 2021, driven by continued capital investment. Earnings at our Energy Infrastructure segment improved $0.04 in the second quarter of 2022 compared to the second quarter of 2021. This was mainly driven by production tax credits related to stronger wind production across our portfolio as well as our Jayhawk Wind Farm that went into commercial operation at the end of last year. Finally, you'll see that earnings at our Corporate and Other segment decreased $0.06, primarily driven by rabbi trust performance and a gain last year on our investment in a clean energy fund that we recognized in the second quarter last year. Remember, rabbi trust is largely offset in O&M. Overall, we improved on our second quarter performance by $0.04 per share compared to last year. Looking now at the cash flow statement on Page 6 of the earnings package. Net cash provided by operating activities increased $536 million. Cash earnings and a normal recovery of commodity costs contributed to this increase. And total capital expenditures were $1 billion during the first half of 2022. As you can see, we have been executing well on our capital plan. Before I turn it back to Gale, I'd like to give a bit of color on the recently proposed Inflation Reduction Act. I'll also provide our guidance for the third quarter. We're still analyzing the details of the proposal. From what we understand now, we believe the proposal would provide additional benefits to our customers from investments in renewables. An option to choose production tax credits for solar projects and the ability to transfer tax credits would provide more flexibility for future renewable investments. This would apply both at our utilities and at the WEC Infrastructure segment. So overall, we see benefits to customers, future investment opportunities, and stronger credit metrics. Now, let me give you the guidance for the third quarter. We are expecting a range of $0.82 to $0.84 per share. This accounts for weather and storm recovery costs in July and assumes normal weather for the rest of the quarter. As a reminder, we earned $0.92 per share in the third quarter last year, which included $0.05 of better-than-normal weather. And as Gale mentioned earlier, we’re raising our full-year guidance to a range of $4.36 to $4.40 per share with an expectation of reaching the top end of the range. With that, I’ll turn it back to Gale.

Xia, thank you. Overall, we're on track and focused on delivering value for our customers and our stockholders. Operator, we're ready now for the question-and-answer portion of the call.

Can we discuss the MISO policy briefly, particularly the generation context after the PRA earlier this spring and your retirement modifications or, as you mentioned, delays? Gale, from your perspective, do you foresee any structural changes to the auction in the coming years? Is there a chance WEC might consider additional retirement extensions due to the supply-demand dynamic, potentially causing an O&M headwind? Or is there a definitive timeline at this point?

That's a great question, Shar. Based on everything we're seeing today, I don't sense that we're going to enter into any other significant extensions of plants. The dates we gave you, we feel pretty good about in terms of the retirement of the older Oak Creek units. And I think really what's going on here and MISO has said this, I think, fairly clearly, that there's been so much retirement up to date of older coal-fired units, that really they found themselves in a couple of regions in really, really tight capacity situations. Luckily, we've had the diverse supply here. We've been well prepared. We were basically unaffected by the big increase in capacity costs in the last auction, but it was very prudent for us to make sure that we have that capacity online. And remember, Shar, these plants that we're extending, these older Oak Creek units, they're not projected to run a great deal. We need them for capacity purposes at high demand times and this protects our customers from continuing to incur high auction costs in future capacity markets. But as we continue to bring the units online that Scott talked about, I think our current plan is likely to hold in terms of the retirement dates. I hope that answers your question.

No, it does. And I appreciate that. And then I think Xia kind of mentioned a little bit on sort of the IRA or the Inflation Reduction Act but there's obviously some linkages to your capital program and taxes as well. As you kind of work to finalize the roll forward this fall, could we see additional spend from the program, especially as we’re heading into the conference, how do we think about that? And then there’s obviously the counteractive force which is the minimum tax that will probably be borne by the customer, right?

Yes, we are evaluating all of that in our models. Currently, based on our observations, some of the advantages from that legislation appear to offset the minimum tax concerns. We believe, as Xia mentioned, that this could lead to a positive impact on our credit or funds from operations. Xia, would you like to elaborate on this?

Yes, exactly. As Gale mentioned, we anticipate a very manageable impact from AMT, likely around a $20 million to $30 million increase in cash tax payments. However, as Gale pointed out, we also see several benefits to our credit metrics, whether from the monetization of tax credits or lower financing costs, which are partially offset by a reduced debt balance. Overall, when considering all these factors, we actually expect an improvement in our credit metrics.

And an additional point that we'll keep highlighting is the investment opportunities arising from this legislation, not only within the utilities but also in the Infrastructure segment. It is clear to us that this is beneficial for our customers, as it can help lower the investment costs that our regulated customers must bear. There are several overall positives here.

Okay, got it. Got it. And then just real quick lastly, if I may. Just the rate case, the procedural schedule was obviously issued last week. You guys are great at settling. So as we're thinking about potential settlement options should we be looking at maybe the end of September, early October for that?

It's difficult to define a specific timeline for the settlement discussions as we are still in the early stages. We are actively engaging with the staff regarding their data requests, which is a normal and positive aspect of the process. The staff audit, initiated by our filing, is progressing smoothly and on schedule. The administrative law judge has suggested a timetable; however, some interveners may prefer additional time between certain dates, so the schedule may not be final yet but is very close. Overall, the situation remains stable. This case is quite straightforward, focusing on investments in grid hardening, renewables, and reliability, with over half of the capital projects already receiving approval. Additionally, our proposed operating and maintenance expenses are lower than those approved in the previous order, maintaining a positive backdrop. For now, we are continuing with our current pace.

I'd like to revisit a couple of details. When adjusting for large commercial and industrial, I understand it doesn’t significantly impact margin, but there is a discrepancy compared to your annual forecast as of June 30. What are you observing regarding this? You mentioned several positive industrial trends initially, but are you anticipating a decline in the second half? What is the outlook in that regard?

Great question, Julien. I have a question for you after I finish answering. We noticed a slight decline in large C&I, and keep in mind, we serve industrial customers across 17 different sectors of the economy, giving us a broad view of the situation. In the first half and the second quarter, we observed declines in three sectors: food processing, food and food processing. This is partly due to one of our major customers switching product lines, leading to a temporary outage. Interestingly, they will be producing more chocolate, which my wife approves of. The three categories that saw some decline were electronics, food processing, and printing. On the positive side, primary metals showed an increase. Overall, we are witnessing a strong recovery in small commercial customers and the commercial sectors of our economy. Every commercial area we examined, from entertainment to hotels to restaurants, is performing well. The Wisconsin economy is currently very active. When we assess everything together, as Xia mentioned, we feel confident that we are on track with our sales forecast for the year.

Nice. Okay, back half it is. Excellent. And before I answer your question, let me just squeeze in one more here. Xia, if I can put you on the spot a little bit here. Do you want to quantify a little bit as best even a range on what that credit metric, that net credit metric impact is? As well as if you this point beach method shift on, I think, $600 million of debt, give or take, if you can talk to that and how that might impact anything?

Sure. We don't have a specific number yet due to various factors affecting the production tax credit versus the investment tax credit, which could alter the situation for our regulated businesses. Therefore, we haven't been able to provide a quantified figure, but we'll have more information soon. Regarding the supplemental filing we made in Wisconsin, it pertains to a change in methodology from S&P. They have updated how they calculate the imputed debt related to purchase power agreements, and we adjusted our calculations accordingly using their new methodologies. This approach is consistent across the industry, so we are not alone in this adjustment.

Right. And would you say there is a recovery there?

Right.

It's pretty formulaic, yes. It's a pretty standaround type of thing. Yes, yes. So Julien, I just want to check, how's your married life going?

It’s going great. We bought a house, we’re keeping going.

Congratulations on another solid quarter. Xia, I hope you don’t mind me putting you on the spot again, but given your expertise on this topic, I wanted to ask about the monetization of tax credits and transferability. This bill does not include direct pay, which was part of the Build Back Better initiative. How do you see this as an opportunity? Is transferability a viable option for utilities like yours to monetize those credits? What other options do you consider when thinking about monetizing PTCs, ITCs, and similar elements?

Yes, I believe as I mentioned in my formal remarks, this overall bill offers benefits for customers, future investment opportunities, and credit metrics. Regarding customer benefits, one source is the PTCs versus ITCs from solar projects. The flow-through of ITC benefits on stand-alone batteries as opposed to normalization may also provide advantages to customers. You mentioned the marketing of tax credits, which could be beneficial for customers as well, particularly with the extension of tax credits. These are the sources of customer benefits. Additionally, concerning future investment opportunities, we are currently assessing our tax appetite to align with our investment prospects. The marketability of tax credits could change that. This could open up further opportunities, potentially allowing us to consider investments beyond just wind. I have already discussed the credit metrics, and overall, we view this as a potential positive. However, our current capital plan does not depend on any of these factors. If this is passed, we would likely see some advantages, but if not, we will manage just fine.

I'd like to add to what Xia mentioned. She is correct that our $17.7 billion five-year capital plan does not anticipate any of these potential benefits, which is why we see this as broadly positive. Personally, I believe that the transferability of tax credits, essentially creating a market, is a better solution than direct pay. It's much simpler and eliminates the need for a complicated and time-consuming tax equity structure. I think this approach to the transferability of tax credits in the bill is quite clever. I hope that clarifies things.

That helps tremendously. But just so I understand, Gale, am I right in thinking about this transferability as that you don’t need ownership unlike tax equity where you actually need an ownership in the project, you don’t need ownership as an investor or buyer of these tax credits. So essentially, the market or interest in these tax credits is going to be much larger than just those select banks or those specific tax equity investors. Is that the right way of thinking about it?

Yes, I think you're right on. I think you're dead on, Durgesh. And in fact, a little bit of background. I know about some of the background of how this came to be in terms of discussions with Senator Manchin. And the idea that this really opens a much broader opportunity for these tax credits, not just with a tax equity investor, that was a major selling point, a major selling point, period, to all those who were crafting the bill. So I think you really analyzed it well.

I did. Thank you for attending the fireside chat, it was great. Just want to come back to the coal retirements a little bit, if I could, as it relates to the Wisconsin rate case. And just what have reactions been so far? And do you see any potential implications on settlement talks from this?

The short answer is that we don't see any implications regarding the rate case. The reaction has been uniformly positive. The Governor’s office, which we communicated with prior to the announcement, was very supportive. The staff at the Public Service Commission, responsible for ensuring reliability, was very positive. The industrial customers also expressed positivity. Overall, this is really not a significant factor in changing the revenue requirement.

No, not at all, Gale. And when we factored everything in, factoring and keeping these units running a little bit longer, extending those lives, factoring in the delay. And remember, we delayed these due to some supply chain challenges, building the solar and the batteries. Factoring those delays in, it was relatively revenue requirement neutral. And remember, for this particular case then, just in this case, you’re avoiding those additional capacity costs. So it was well received adding that reliability until we can get these renewables built and some of the other capacity online. So it was well received across the board from my conversations with individuals across the board like Gale said.

And in addition to that, Jeremy, we were able to reassure, as I mentioned in the script, we were able to reassure everyone that our commitment to really aggressive environmental improvement is unchanged by this action. So it just made a ton of sense both from a customer reliability and customer cost standpoint.

At this point in time, Jeremy, it's probably too early to give you how much bigger than a breadbox answer but I will say this. Right now, our significant investments that we've made which as we reported to you, are performing very well in the Infrastructure segment, those have all been wind projects. I think we have eight wind projects that were committed to and some of them operating already, a number of them operating already. What this does do and Xia pointed to it, which is giving companies like ours the option of production tax credits for solar. That could open up an entire avenue of investment in the infrastructure segment for solar simply because of the way the economics work today. So that just gives you an idea. They’re all wind right now in the infrastructure segment. We continue to see opportunities with wind but it could also open up a whole different technology investment with solar.

I will add, though, we have the 10% total investment as a portfolio from WEC so we don't see that change even with this bill passing.

Yes, that's a good point. The opportunity continues because our regulated business is growing as well. We intend to keep the Infrastructure segment at around 10% of earnings going forward.

I wanted to start by acknowledging that it’s a shoulder quarter for the gas business, but sales trends have remained quite strong in the first half of the year, really impressive. Can you provide any insight into what’s driving this and how sustainable you believe it is?

Your question is about how strong the trends are. Recently, while reviewing all the data, we found it quite interesting to analyze what we were observing. There are two key answers. First, I've mentioned many times that weather normalization is more precise than it is accurate. Therefore, I'm not entirely sure our weather normalization methods captured all the weather impacts we experienced, especially in Q2. April was unusually cold in Wisconsin, which likely influenced some sales, possibly beyond what our weather normalization techniques detected. Secondly, and this is not surprising but definitely positive, a significant portion of the increase we are witnessing comes from gas used in industrial processes. When we examine the segments of our gas customers, the largest increase in Q2 stemmed from industrial process gas usage, which reflects the strength of the economy and is encouraging. Overall, the last six months have been very strong, and while we will monitor what happens next, the major factor for the Q2 increase was the cold April, leading to higher gas consumption from residential customers, along with the growing gas usage by large industrial clients for processing.

Okay, very helpful. Regarding the pending renewable projects in the regulated part of the business that you're developing, I’ve noticed some cost increases for the near-term projects, while the long-term projects have remained stable so far. Are those numbers still accurate? Or do you anticipate some upward pressure on them as well?

We'll let Scott give you his view on this. I will say this, the nearer-term cost changes, we fully anticipated and had communicated with our regulatory folks. Scott?

We anticipated and discussed this with them. I don’t think anyone is surprised by the incremental increases we have filed. We have indicated that we expect cost increases in the range of 20% to 30%. In fact, in our most recent filing for solar, the initial project was around $1,300 per kilowatt, and now it's approximately $1,540, with the latest figure being about $1,640. The costs are increasing slightly but are still in line with national trends. Looking ahead, we will need to monitor how things develop, but we have mentioned that increases could reach 30% to 40%. However, it’s important to note that there are many factors in the supply chain, and we are examining this over multiple years. Currently, the costs we are seeing have risen but are actually a bit lower than the national average.

Okay. And last one real quick. Any plans to file a people’s gas case anytime soon?

No time soon. No.

How is it going, Gale? I hope all is well.

Same here.

Married life is going well for me, in case you were wondering. I hope my wife doesn't see anyone from EEI, so I’d like to avoid any complications. I have two straightforward questions. One is regarding the guidance of 6% to 7% mentioned in one of the slide decks from the July presentation, while historically, it’s been a 9% CAGR. You noted the difference between GAAP and non-GAAP is negligible. With all the positive factors you've discussed in previous questions, what needs to occur for you to reach the 6% figure?

What has to happen for us to hit a 6% growth trajectory? Downsides that I really don't anticipate that would be kind of out of the blue right now. Remember, our projection is 6% to 7%. And certainly, what we have in the pipeline in terms of approved capital investments and simply our continued efficiency and driving best practices through our operations. It would take something that I don't anticipate. Scott?

No, I agree, Gale. We have really good value-added customer projects we’re putting in. When you think about like grid hardening. The storms that we’ve seen this summer and last summer, it makes a lot of sense to go as we do that, the additional transition to renewables. So we feel really comfortable with where we are to be able to execute. It’s a very executable capital plan also.

With no need for equity.

Exactly. We will continue to evaluate our growth. As we approach the fall and proceed with the capital projects, we will keep assessing the situation.

And Anthony, when I see your wife at EEI, I'll just say, what goes on in Boston stays in Boston. How's that?

I appreciate that. I appreciate that. If I look at on the cost side, so far, first half of the year, O&M is down 4% roughly when I look at the slides you put out. What is the more challenging part of maintaining the cost in O&M in this inflationary environment? What are you seeing as the biggest challenge? What part of your O&M budget?

I can provide an initial thought on that. Scott and Xia have a close understanding of the numbers, so we can also get their perspective. When considering our own situation, the first thing that comes to mind might not actually be the largest cost in our overall operations. One significant factor is the cost of gasoline for our fleet, including service and bucket trucks. With gasoline prices having more than doubled, that plays a major role in our expenses, especially since we are trying to minimize the number of trucks we roll out. However, during storms or outages, we must deploy trucks, making this cost largely out of our control. I wanted to highlight that aspect first. Scott, Xia?

No, you're exactly right, Gale. You really have to kind of pull yourself behind the numbers here. And when you look at the O&M, just to correct where we're at here, some of those decreases that we're seeing on the top level of the income statement are some of the items that we had in our rate review last year for transmission. There's a little detailed breakdown on a few additional pages in our packet. So some of that is related to transmission reductions that we agreed to. So Wisconsin actually was up a little bit year-to-date. So that’s because it’s reaction to storms and some of these inflationary pressures that Gale talks to. But overall, when we look at our forecast, we’re still projecting to be down about 1% flat to 1% in total O&M.

Xia, anything you’d like to add?

No, I think you covered it very well.

Okay. Terrific. Anthony, I hope that's responsive to your question.

Perfect. NFL schedule is out and I think my Jets may finally win one in Green Bay in October.

Yes. I'll take the over under on that one for you.

Greetings, Sophie. How are you doing today?

I am doing great. It's been a great discussion so far. If I could press you a little more on the IRA provisions. There’s more at play than just wind energy. We essentially have numerous incentives for electric vehicles and technology-agnostic production tax credits at some point. How do you view the possibility of moving beyond wind and solar and branching out into other areas? For instance, could you consider modular nuclear? Or have you explored fleet electrification opportunities like some of your competitors? You mentioned your own fleet regarding gasoline prices or possibly municipal fleets. Could you elaborate on what's beyond just wind and solar? Yes, I’m glad to. As Xia mentioned, the inclusion of batteries in this act is significant due to the credits associated with them. Batteries are already part of our plan and will likely play an even larger role moving forward. They present opportunities for all of us given this legislation. We also have set goals for electrifying our fleet, which we may not emphasize enough. That initiative is in progress, including a pilot program in Wisconsin approved by the Commission a few months ago. We're engaging with residential and commercial customers about installing individual chargers at their locations, which we would own, and it’s off to a promising start. Regarding small modular reactors, we are monitoring their progress and our strategy team regularly interacts with SMR developers. However, we are not focusing on the first ones in production. In the future, especially if applicable tax credits are in place, it could be a possibility, but not in our current or next five-year plans. Xia, do you have anything to add?

No, I think the only thing is we are going through the hydrogen test process to learn more on that. And as part of this IRA, there's a new clean hydrogen production credit. So that's something that if it indeed is making sense, that would be something we would be happy to look into.

Yes. And I think the other point, you mentioned EVs. And we really see it more as not that but the adoption of EVs, how does that even expand our grid hardening as more and more EVs come onto the system. And like Gale said, we've got a robust program already, we see a lot of traction. But remember, we didn't put any of this in our future 5-year forecast that we talked about in our third quarter call. So we have nothing in our long-term plans related to EV. So adoption there could be a nice little tailwind there for some sales.

Yes. Sophie, you're likely aware of our guideline that for every two new electric vehicles added to our system, that roughly matches the energy usage of a single household. Considering the recent statistics from the State of Wisconsin projecting the rate of electric vehicle adoption in the area, if those estimates are even close to accurate, we will see a significant impact, particularly since we currently have only a few thousand electric vehicles in the state. They're forecasting substantial growth by 2030, but we'll have to wait and see if that materializes. This would necessitate a considerable investment, especially given our estimate that two new electric vehicles on our system correspond to the energy demand of one household.

I have an easy one for you. Actually, I have two questions that I’ll do sequentially. The first one, and it follows on the EV question that just came. Can you talk about what you think is the long-term role of the utility, the electric utility is, and the potential ownership of charging stations relative to kind of the various market models we have today in this country where the utility is generally not the owner of charging stations or is a very small component of that? How do you just think about that from a public policy standpoint?

That's a great question, Michael. I don't think there's a straightforward answer. As you mentioned earlier, there are many different models in place across the country, varying by state and even at the federal level with the charging plan. We are still in the early stages of developing the infrastructure needed for a significant shift to electric vehicles. The future of how much charging equipment utilities will own is still uncertain, and I don't believe anyone can provide a clear answer at this time. However, considering Scott's comment about grid hardening, picture a neighborhood cul-de-sac with eight homes. If two or three of those homes decide to adopt EVs, we will need to install a much larger transformer to support that demand. This underscores the considerable investment required for our basic infrastructure, quite apart from the charging equipment itself. There are significant investment needs that will arise as EV adoption increases, which could present substantial opportunities for our company. However, we need to ensure the grid can accommodate such a large influx of EVs. None of this is included in our current forecasts, and we will observe how EV adoption progresses. It is gaining traction in Wisconsin, without a doubt. I hope this somewhat addresses your question, but I don't believe there's a simple answer regarding ownership going forward, as there are too many models and ongoing discussions to provide a more definitive response.

I completely understand. My second question is more about policy. When you and your team meet with Governor Evers, state legislators, or leaders of major business groups, what are the utilities in the state not currently doing, or what plans do they have for the next one, two, or three years that they would like to see from you?

It all comes down to one word: reliability. Affordability is important, but reliability is the key. Whenever we engage with legislators, public service commissioners, or the governor's office, the focus is really on reliability. They want to ensure that what occurred in Texas does not happen here and that we will have the capacity to continue supporting the energy transition. Scott?

It’s reliability, not only on electric but also on natural gas, keeping the houses warm here in this cold environment in Wisconsin. So that’s also a key. So we just don’t want to look at it from one side.

Which again led to us talking with them and making the decision to briefly extend the lives of the older Oak Creek units. Again, it was all about assuring reliability.

Got it. Lastly, with the changes in the in-service dates for the storage and solar projects, how should we consider the impact on the CapEx forecast for the next 2 to 3 years?

Very little. It might shift from year to year but I mean, we have so much flexibility in that capital budget that, Scott, I don't see any major impact.

No, I don’t. We’re really looking at the numbers but every year, there’s a few things that we have to move around a little bit. So it’s not going to be a substantial change as we flow through our next iteration here.

Regarding coal, in terms of the impact on operations and maintenance due to delays in solar and battery projects and the adjustments to retirement dates, you mentioned potential future savings from nonfuel operations and maintenance. How do you envision these changes affecting operations as coal transitions from baseload units to capacity resources that will operate less frequently?

Well, I think we basically said there'd be about a $10 million uptick in the O&M to use these older Oak Creek units as capacity machines offset by the other factors that Scott mentioned. Scott?

When you compare it to our rate case, looking back a couple of years when these were fully operational baseload plants, the operating and maintenance costs could decrease by about $10 million overall. We are still exploring ways to improve efficiency, as these plants are not being used as frequently. We are working on utilizing the staff effectively across various projects to enhance productivity. Ultimately, this approach is significantly less expensive than purchasing capacity from the market.

Right, that makes sense. Okay. And then how will that transition look for the coal units? Will they gradually decrease their capacity factors over a few months or seasons? Or will it flip like a switch on a predetermined day that all of a sudden, they're only for backup now?

No, it all depends. As you know, in the MISO market, we continuously inform the Midwest grid operator of the units we have available and their marginal costs, whether it's day ahead or hour ahead. These units will operate based on efficiency and demand in the MISO market. However, based on our modeling, we expect they will be utilized mainly during peak demand seasons, in winter and summer, and not operate much during lower demand periods.

No, that's exactly right. And it's not going to be a switch. We'll continue to look at the forecast and do the strategy as we do every other type of asset.

Okay. But dispatch is ultimately determined by MISO, right?

Yes, absolutely. Yes, just like every other unit. So basically, this just becomes an asset in our portfolio that we offer to MISO every day.

Okay. Great. Then one separate question. If I can attack the O&M question from a different perspective. Given the strength of the year-to-date results, are you thinking about or have you started pulling forward expenses from ‘23 and beyond to better position yourself? I know you’re in the midst of a rate case and you talked about pressures from inflation, from storms. Just wondering how to think about those puts and takes.

Well, the short answer is we have had, particularly in July, we've had some pretty serious storms, so we've had some additional operating costs in July that you're not seeing in our numbers yet, obviously. And we have a number of maintenance projects already scheduled in our normal plan for the second half of the year. Power plant maintenance, other maintenance. So we're not planning on pulling forward any additional O&M because we've got plenty of things to do in our normal plan. Xia?

I think that’s exactly right.

I wanted to follow up on the coal plant issue. I'm a bit confused about the impact of supply chain problems. From what I've read in the local press, it seems like these issues are related to renewables. I'm trying to understand which projects were delayed. Is it related to storage, transmission components, or something else? I'm curious about what actually caused the delays in the plant retirements.

That's a great question. And to clarify, there are really two elements to it and we'll let Scott cover the details. But the first is one of the major solar battery park investments that we are making have already been approved which is what we call the Paris Battery Solar Park. The batteries there are going to be delayed. So that's a piece of it. And then I think Scott, you mentioned during the prepared script, there are two solar projects that we are now going through the regulatory process on and they’re not going to come in on the original dates.

Correct. They're not going to come in. So we had several solar projects and those additional solar projects also had batteries attached to them. And with that uncertainty in the capacity, it just did not make sense to pull the trigger on those retirements.

Paul, just to kind of put all that in perspective. We're going to be running those older Oak Creek units over the next couple of years here as we extend their lives just a little bit, we're going to be running them as capacity machines. The solar that we were putting in on the batteries were also for capacity. So that's really the trade-off we're making here.

Got it. We are observing various constraints across different regions of the country, particularly transmission constraints affecting wind production. Are you experiencing similar issues in Wisconsin or in any other areas you are involved with? Have you noticed any impact on the curtailment of wind production?

So far in Wisconsin, very little. However, in our Infrastructure segment, we've seen some lengthy transmission maintenance outages in the Dakotas, for example. We've seen some transmission issues that seem to now be resolved in Kansas with our Jayhawk wind farm. So sporadically, yes, we have seen some transmission issues and there's no question that we have got to, as a nation, move forward with transmission projects. We've just got to do it to maintain reliability of the grid without a doubt. And that’s why we’re pleased that MISO has gotten to the point where they’ve gotten to and you probably heard Scott, actually, it’s $100 million higher than we thought originally. So the MISO tranche 1 for American Transmission Company is now up to a $900 million investment. All right, sports fans. Well, I think that concludes our conference call for today. Thanks so much for participating. Always enjoy talking with you. If you have any more questions, feel free to contact Beth Straka. She can be reached at (414) 221 4639. Thanks, everybody, so long.