Xcel Energy Inc. (NASDAQ:XEL) Q1 2025 Earnings Call Transcript

Xcel Energy Inc. (NASDAQ:XEL) Q1 2025 Earnings Call Transcript April 24, 2025

Xcel Energy Inc. misses on earnings expectations. Reported EPS is $0.84 EPS, expectations were $0.921.

Operator: Hello, and welcome to Xcel Energy First Quarter 2025 Earnings Conference Call. My name is Melissa, and I will be your coordinator for today’s event. Please note, this conference is being recorded and for the duration of the call, your lines will be on listen-only. However, you’ll have the opportunity to ask questions at the end of the presentation. [Operator Instructions]. I’ll now turn the call over to Roopesh Aggarwal, Vice President, Investor Relations. Please go ahead.

Roopesh Aggarwal: Good morning, and welcome to Xcel Energy’s 2025 first quarter earnings call. Joining me today are Bob Frenzel, Chairman, President and Chief Executive Officer; and Brian Van Abel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer your questions if needed. This morning, we will review our 2025 first quarter results and highlights, provide updated 2025 assumptions, and share recent business and regulatory updates. Slides that accompany today’s call are available on our website. Some comments during today’s call may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and SEC filings.

Today, we will discuss certain metrics that are non-GAAP measures. Information on the comparable GAAP measures and reconciliations are included in our earnings release. I will now turn the call over to Bob.

Bob Frenzel: Thanks, Roopesh, and good morning, everybody. Xcel Energy, we know that economic growth and prosperity of our communities, and country depends on our ability to deliver energy to our customers, when and where they need it, while keeping their bills as low as possible. This commitment to our communities and customers is demonstrated in our results this morning. In the first quarter 2025, Xcel Energy delivered earnings of $0.84 per share, invested $2.3 billion in resilient and reliable energy infrastructure for our customers, and accelerated our wildfire risk reduction efforts to enable safer and more resilient communities. Brian will provide more details in a minute. But based on our results for the first quarter, we remain confident in our ability to deliver on our earnings guidance for the 21st year in a row, one of the best track records in the industry.

As you can imagine, over the past several months, we’ve been engaging at the federal level with legislators and administration officials as executive orders, trade and tariff actions and pending legislation will likely have impacts on future energy infrastructure. Not surprising to anyone on this call, we’re in an unprecedented period of electric demand growth and believe that we need a broad scope of energy resources to meet those needs. We see increased electric demand from the oil and gas sector. We see demand from residential customer growth, EV adoption and beneficial electrification across our service territories. We see demand from data centers in Texas, Colorado, Wisconsin, and Minnesota. And in the medium-term, we expect to see continued trends towards electrification as well as re-onshoring as potential outcome of federal actions.

The infrastructure to serve this demand growth needs to be thoughtfully planned as well. We and many in our industry have been advocating in D.C. for policies that allow for cost effective and rapid adoption of new energy resources. That includes preservation of tech neutral tax credits, wind, solar, storage and nuclear, their associated transferability provision in various loan and grant programs. That includes advocating for siting, permitting and other federal actions that would allow for more rapid construction of the assets needed to serve this growing demand and that includes advocating for federal actions that can mitigate the potential for wildfires and their associated financial impacts. Additionally, we’re paying close attention to ongoing tariffs and other recent federal actions.

As you are all aware, this remains a highly fluid situation, potentially positively changing as recently as yesterday. On the tariff front, we believe that our base capital plan remains intact and that the impacts are both modest and manageable. While we’re still evaluating, we estimate that roughly 40% to 45% of our capital expenditures are material based with the balance being labor permitting and other items, and of this percentage a majority is domestically sourced. There are some notable exceptions though. In particular, our industry has exposure to Chinese tariffs related to battery storage. In our base capital plan, we only have one significant battery project, which we continue to work to mitigate any risks, but in our longer-term plans we see a need for more battery and other related energy storage assets.

Based on these recent tariff actions, we expect a relatively rapid evolution of the battery supply chain similar to what we’ve experienced in solar panels over the last three to four years. We estimate that our total tariff exposure on our $45 billion base capital plan for 2025 to 2029 is approximately 2% to 3%, and that’s before we work through any incremental vendor mitigation actions. We remain confident in our ability to navigate this evolving environment and keep delivering for our customers and investors. We see incredible energy and demand needs across the country. In total, Xcel Energy anticipates that we will need to deliver between 15,000 and 29,000 megawatts of new generation by year-end 2031 to serve our customers and communities.

During the first quarter, we continue to make progress on our — with our various commissions on these needs, which also helped give line of sight to our $10 billion plus incremental investment pipeline. In February, the Minnesota PUC approved our integrated resource plan settlement for nearly 5,000 megawatts of generation. Included are 720 megawatts of company-owned natural gas generation and battery storage and approximately 2,800 megawatts of wind generation which will reuse the transmission interconnect from our Sherco facility. RFPs for resources that make up the balance of the IRP will work their way through regulatory processes in 2025 and 2026, details of which are included in our disclosures and in the attached presentation. In Texas and the Mexico, our teams continue to evaluate proposals for generation to meet growing demand.

As a reminder, we’re seeking 5,000 to 10,000 megawatts through a competitive RFP process including projects being proposed by the company. We’re encouraged by the early results and plan to make a recommended filing in Q2. And in Colorado, we continue to make progress with our energy resource plan filing that we made in October of last year. We’re recommending the addition of 5,000 to 14,000 megawatts of new generation to meet projected sales growth of 3% to 7% per year. The commission decision is expected in the fall of this year. As part of these resource planning processes, I’ve been asked to comment on the impacts of recent executive orders on coal plants. Our generation retirement strategy is the product of long-term planning process with state commissions and other stakeholders that seeks to balance energy demand with long-term assets that we need for our customers.

With access to some of the country’s best wind and solar resources as well as incremental natural gas generation, we’ve demonstrated that we can retire these inefficient and aging coal plants while ensuring reliability and keeping customer bills low. Continue to evaluate the executive orders and work with federal and state agencies as well as our communities and customers on any next steps. Alongside our access to some of the country’s lowest cost renewable resources, our thoughtful investments and focus on continuous improvement have helped keep our residential electric bill growth below the rate of inflation for the past decade and among the lowest in the country. As we continue to grow, the tech neutral and nuclear PTCs have also proven a critical tool for customer affordability.

Since 2018, Xcel Energy customers have saved over $5 billion in avoided fuel costs and PTCs from wind generation and this year our Upper Midwest customers will see an additional benefit of nearly $250 million on their bills from nuclear production tax credits. We continue to actively engage with elected officials in the U.S. House and Senate, and key agencies such as DOE to reinforce the critical importance that these incentives play in keeping bills low for our residential and business customers. We believe that policymakers are aligned in the belief that lowering energy costs for Americans is a key policy objective. We continue to remind them these incentives play an important role in helping us meet that objective. Xcel Energy also continues to make significant progress to protect our customers and communities and systems from the threats of extreme weather.

On the regulatory front in Colorado, we reached a constructive settlement on our updated $1.9 billion wildfire mitigation plan, including a securitization mechanism to manage customer bill impact. In Texas, we also reached a constructive settlement on our $500 million system resiliency plan. We expect commission decisions in both proceedings by third quarter 2025, and we’ll continue to prioritize these investments to improve resiliency and reduce risk on our systems. And on the policy front, we’ve seen progress with several pieces of constructive wildfire legislation. In Texas, legislation was introduced where material compliance with an approved wildfire mitigation plan provides an affirmative defense to civil liability related to wildfire damage.

In North Dakota, legislation that provides a utility similar protection was passed by both chambers and awaits the Governor’s signature. We believe these bills could also serve as frameworks in our other states for future legislation. Looking forward, our focus for 2025 remains unchanged. Xcel Energy is working to deliver on our earnings for the 21st year in a row to capture the unprecedented opportunities for growth we laid out in our capital plans, to deliver on our incremental capital opportunities backlog, advance our clean energy leadership and raise the bar on delivering a compelling experience for our customers in order to make energy work better for them and the communities we serve. With that, let me turn it over to Brian.

Brian Van Abel: Thanks, Bob, and good morning, everyone. Starting with our financial results, Xcel Energy had earnings of $0.84 per share for the first quarter of 2025, compared to earnings of $0.88 per share in the first quarter of 2024. The most significant earnings drivers for the quarter include the following: electric and natural gas sales growth and regulatory outcomes increased earnings by $0.21 per share and other items combined to increase earnings by $0.01 per share. Offsetting these positive drivers, higher O&M expenses decreased earnings by $0.11 per share. Higher depreciation and amortization reflecting our capital investment programs decreased earnings by $0.09 per share and higher interest expense decreased earnings by $0.06 per share.

Now let me comment quick in more detail on O&M expenses for the first quarter, which totaled $686 million or $81 million higher than in 2024. We expected O&M expenses to be front loaded this year with the increase due to known items such as higher nuclear outage amortization costs, increased insurance premiums, benefit costs and the impact of a 2024 gain on land sale. Some of the increased wildfire related expenses are subject to regulatory decisions later this year. These results are in line with our year-to-date O&M expense budget and we reaffirm our full year guidance of a 3% increase in O&M expenses relative to 2024. Turning to sales, first quarter weather and leap year adjusted electric sales increased 2% driven by growth across most operating companies and customer segments.

For 2025, we continue to expect full year weather adjusted electric sales to increase 3%, as the current tariff and economic outlook evolves, we will continue to monitor any potential impacts to our sales outlook. Shifting to rate case activity, in Wisconsin, we filed our 2026 to 2027 electric and natural gas rate cases requesting a total revenue increase of $151 million and $24 million respectively, over two years. That’s based on a forward test here, a 10% ROE and an equity ratio of 53.5%. We were evaluating filing electric and natural gas rate cases in Colorado and an electric rate case in New Mexico later this year. Moving to data centers, we are making solid progress on our high probability pipeline and remain on track to meet our goal of contracting our total base plan by this fall.

Xcel Energy continues to receive requests for new data centers in its service territories. We are managing a robust pipeline and remain committed to our data center contract principles, ensuring new contracts maximize benefits to all customers and protect Xcel Energy from stranded asset risk. We also continue to make strong progress in the Smokehouse Creek wildfire claims process. We’ve resolved 151 of the 225 submitted claims, which we continue to view as constructive. We have committed $113 million in settlement agreements of which $79 million have been paid through Q1. Based on current information and settlement activity, we have updated the low end of our estimated liability to $290 million, which remains well below our insurance of $500 million as we described in our earnings disclosure.

As part of the increase, we have resettlements related to some previously excluded categories such as compensation for railroad claims and settled claims related to tree damage. We’ve also updated our disclosures in Marshall in particular as it relates to two new causation theories introduced by plaintiffs in expert reports that were submitted in the first quarter of 2025. We remain in expert discovery until mid-July and are preparing for a trial in late September. Moving to guidance, we remain confident and reaffirm our ability to deliver earnings within our $3.75 to $3.85 guidance range for the year. Updates to key assumptions are included in our slides and earnings release. With that, I will wrap up with a quick summary. Xcel Energy posted first quarter 2025 earnings of $0.84 per share.

We continue to lead the clean energy transition while ensuring safe, clean and reliable service and keeping customer bills as low as possible. We are focused on reducing operating risk in our system from extreme weather. We reached settlements with our Texas and Colorado resiliency and wildfire mitigation plans to see progress on constructive legislation in Texas and North Dakota. We have strong line of sight with our $10 plus billion investment pipeline with approval for at least 5,000 megawatts of generation resources in Minnesota and awards for $3 billion to $4 billion of transmission in MISO and SPP. We continue to maintain a strong balance sheet and credit metrics using a balance of debt and equity to fund accretive growth. And finally, we reaffirm our 2025 EPS guidance of $3.75 to $3.85.

This concludes our prepared remarks. Operator, we will now take questions.

Q&A Session

Operator: Thank you. [Operator Instructions]. Our first question is from Nicholas Campanella from Barclays. Please go ahead.

Nicholas Campanella: Hey, thanks so much for taking the questions.

Bob Frenzel: Hey, morning, Nick.

Nicholas Campanella: I just wanted — Morning, morning. I wanted to ask, I appreciate all your comments in the prepared remarks. You are kind of a big transferability beneficiary. We’re going through budget reconciliations right now. If there’s any kind of outcome where the tax credits get sunsetted sooner within your five-year plan, how do you kind of think about the offsets to cash flow considering there might be a positive attribution to rate base as well? Do you still see some type of true cash impact and maybe you can kind of walk through how the plan could absorb that?

Bob Frenzel: Hey Nick, it’s Bob. And I’ll start and then I’ll give Brian some time to get to some of the details. But there’s been a lot of conversation around transferability in general, at least in the investor community, not actually a lot in D.C. and I’ve spent a lot of time there. Transferability was architected as part of the IRA. We think it’s explicitly — explicably linked to the credit program themselves. We know there’s a lot of support as evidenced by letters that, that Congress and the Senate have written to their respective Finance and Ways and Means Committees around support for continuation of the credits in some fashion and form. And by that measure, we think the transferability continues along with those credits.

So as I sit here today, I think very positively about the credits that come from our legacy projects, projects that are in service, projects that we’ve safe harbored and then depending on where the credits go in general, I think the transferability stays aligned with those credit profiles over time. But maybe I’ll let Brian comment a little bit on some of the details you asked on rate base and/or cash flow implications.

Brian Van Abel: Yes, Nick, and maybe I’ll talk about it in two different avenues and feel free to ask further questions if I don’t hit on exactly what you’re thinking about. No, I think about one is there’s been a lot of discussion around the bill introduced by Representative Fedorchak in terms of — but when you actually look at what that bill does, it doesn’t impact transferability on any projects in service and it doesn’t impact transferability on projects that would have been Safe Harbored last year under the old regime of tax credits. So when we think about it in terms of what we Safe Harbored last year for projects, we’re in a really good spot basically through 2028 when you look at the four-year Safe Harbor with projects last year.

And so we would expect those to have credits and transferability associated with them. So really the door check bill would be a 2029 impact. But how it steps down, it’s a 20% credit in 2029. Now certainly we’re not advocating for that bill because there’s significant long-term customer impacts. But from a transferability perspective, in our cash flow perspective, we are very comfortable with that in terms of how it deals with prior wind farms and what would have been Safe Harbor last year in the old regime. Now your question I get is a little bit more what happened if transfer really went away for all projects, even in service or future projects. We do not believe, as Bob said, that will happen. Congress generally does not disturb decisions that have been made by businesses.

They recognize the need for business certainty. But if that did happen, pick a point; you hit it on head, right? Rate base goes up because you’re less tax efficient. We have an impact to our cash flow. So you would look at issuing some equity to manage some of those credit impacts. But longer-term it just becomes a timing issue where you’re pushing those cash flows out in the future. But there’s also alternative ways. You could look at tax equity in the regulated environment. But one of the more interesting concepts, and we do this in one of our jurisdictions is you can flow PTCs back in an alternative method. Everyone thinks about PTCs being flowed back over the 10-year period as they’re generated in one of our jurisdictions, we flow them back over the life of the project.

So pick a wind farm, 30 years, flowing back over 30 years, that improves your cash flow in the near-term, reduces attacks and efficiency and also provides a pretty stable, call it customer profile from bill impacts. So there’s absolutely things that we think of internally that, that maybe not be understood externally. When we think about how do we manage if that scenario, like I said, we don’t expect will happen, but how we manage if it did happen.

Nicholas Campanella: That’s really helpful color. I appreciate that. Thank you. Just one quick question, just the broader kind of tariff outlook and how it’s affecting economic development in your service territory. Your C&I sales that you guys put up on a weather adjusted basis still seems strong. I know that’s at the end of March. Maybe you can kind of comment on how activity has changed in the service territory at all in real time. And clearly you’re kind of reaffirming your load outlook here. So it seems like you’re comfortable. But yes, maybe just a few more details there. Thanks.

Bob Frenzel: Yes. Hey Nick, let me start. Look, definitely the sentiment meter has changed over the last 45 days. I don’t think we’ve seen a lot of change in actual activity yet either on the consumer or the C&I side. But what you see in here in this earnings season from a lot of people who’ve already announced, whether it’s banks or industrial manufacturers, there’s a thoughtfulness around deploying capital right now, a thoughtfulness about the uncertainty of the regime that we sit in. And there is a lot of conversation and maybe sparked over the last couple, two or three days around how quickly could this environment change as well? We saw it hit very quickly. We’ve seen some peel back already. You’ve seen the market respond to that already.

And so we use the word in our prepared remarks of dynamic or fluid. And I continue to believe that we don’t see a lot of impacts right now in the customer. But we’re cautiously optimistic that we work through this through the balance of the year. And obviously we’ve reiterated our guidance and sales forecast accordingly.

Brian Van Abel: Yes, Nick, I can just provide a little bit extra color on that too. Obviously one of the areas when you think about where the price of oil has gone, we serve the Delaware Basin, the most prolific basin. But we’ve been in contact with our large oil and gas customers in terms of expectations there, and they haven’t changed. A little bit of feedback we got though is they’re watching tariffs and how that could impact their business. But so far we haven’t seen that impact on us. Our sales to that mining and transportation sector were up 9% quarter over — year-over-year, specifically down in SPS. So still seeing it there. One area we saw a little bit of weakness in March was just in Colorado on the small C&I sales. But again, one month doesn’t make a trend. So just something that we’re watching. But overall, right now we sit here feeling comfortable with reaffirming our 3% sales growth for the year.

Nicholas Campanella: Thank you.

Operator: Thank you. Our next question is from Julien Dumoulin-Smith from Jefferies. Please go ahead.

Julien Dumoulin-Smith: Hey, good morning, team. Thank you guys, very much, appreciate it. Look, if I can follow-up on Nick’s question, it’s really been a focus from a lot of folks on this transferability stuff. Just to go back to the, should we say alternative that you were talking to a second ago about the 30-year flow back? I mean, would that suffice in most of your cases? I get everything is discrete and specific, but do you see that sort of meaningfully offsetting the equity risk scenario here that, that could emerge from going back to, shall we say, the prior regime? I just want to make sure I understand kind of the total impact of what you’re contemplating there, as well as just to clarify your specific docs, I know there’s several different credits here and the eligibility for various credits to qualify for transparency, it could be bifurcated, it seems like. You can speak to that a little bit too.

Brian Van Abel: Yes. Julien, let me first let me again reiterate that we don’t expect transferability to go away particularly for projects that are in service and for the stuff that have already been safe harbored, particularly under the old regime as we think about it when the credits change from old regime to tech neutral this year. But yes, an alternative mechanism significantly reduces our equity impact. So you also have to remember that or how we think about financing it. We also have to remember this drives rate base goes up too when you have tax inefficiency. So — but now as we think about this alternative fallback mechanism, obviously we’d work with our regulators on approval of it. But it is what we think about a very good solution in terms of how to manage some of the credit impacts.

And another I’d say we have a strong balance sheet. We maintain a strong balance sheet for a reason. If you have to manage through any of these impacts, it’s a timing issue when you think about this in terms of when you can monetize it. So overall, I wanted to provide some color on scenario that probably most of our investors don’t understand that there are alternatives out there in terms of how you can flow back these and there are benefits to customers and to the company and how we do it, so. And then your question was around bifurcating different treatment accredits. Certainly the Fedorchak bill was just focused on wind and solar. It didn’t impact the storage credits or the nuclear credits. But also we think that is just a marker out there as Bob’s comments provided; there is a lot of support across Republican states.

If you think about the House of — the House letter that had 21 Republicans signed on to it. The Senate letter that had four senators signed onto it for Republican senators. So I think there’s an understanding of the importance of the economy of these credits and what they do. There’s a couple good studies out there about the economic impacts and the 14 million plus jobs that the IRA will create over the next 10 years. So that’s how I think about it in terms of overall and transferability being a key part of it.

Julien Dumoulin-Smith: Excellent guys. Hey, thank you for the details. Just following-up here nicely done. But can you provide some further elaboration on what’s in this Colorado wildfire mitigation plan settlement agreement? It seems like there’s some good stuff in there. But just want to speak to that a little bit more. If you can elaborate on what exactly is in that sort of plan.

Brian Van Abel: Yes, thanks Julien, I can handle that. Yes, overall, a very constructive settlement with a unanimous settlement with all the parties in that wildfire mitigation plan. Again, if you remember, that’s a three-year plan, $1.9 billion split between $1.6 billion of capital and $300 million of O&M. And how we think about it is it’s a win-win from all sides is we get constructive cost recovery here in the near-term. We also get an extension of our insurance deferral that we had a one year extension that, that expired in October. So we have an extension of that excess liability insurance deferral. But we also agreed to secure ties approximately 1 point or seek to securitize $1.2 billion of spend by 2020 — and by 2029.

And that’s really a helpful way to manage overall customer affordability. So when we look at this total package, we think it’s a really good outcome to reach a unanimous settlement with a number of parties in that proceeding was again a good outcome. And we look forward to having the hearing in front of the commission here I think within a month.

Julien Dumoulin-Smith: Excellent. Thank you guys. See you soon.

Operator: Thank you. Our next question is from Carly Davenport with Goldman Sachs. Please go ahead.

Carly Davenport: Hey, good morning. Thanks for taking the questions. Maybe just to start on your comments on the tariff exposure that 2% to 3% on the capital plan, could you just talk a little bit about the process or the timeline over which you’d expect to have those discussions with vendors and any sense of where you think that exposure could potentially go post having those discussions?

Brian Van Abel: Yes. Hey Carly, good morning. I can take that one. Some of these discussions have already happened. When you think about certain project specific contracts that, that we’re working on, whether it’s renewable projects, storage projects, I think about that 2% to 3% being as absolutely manageable. When you think about that’s a five-year time period, so the conversations have started working through specific ones but also working with various suppliers in terms of how much do they absorb, what happens there. But we also are already looking at how do you diversify from a supply base. So I’ll give you a recent example. We recently signed an agreement for substation power transformers. This is, I believe last week that we signed it.

This is where scale and scope comes in. So we signed an agreement with nine different suppliers, five U.S. domestic manufacturers, four global manufacturers, to give us that kind of ability to source where we think it is most effective for our customers. So I would say these discussions have been going on and not only just recently, but there was an expectation that tariffs were coming. When the election happened back in November, we expected tariffs. We included tariff impacts into the bids we made in our RFP and down in SPS in January. So I wouldn’t view it as conversations have just started, but it’s now as we understand where they are, then it’s how do you navigate.

Carly Davenport: Got it. Appreciate that, that’s helpful. And then maybe just a quick follow-up on the liability related to Smokehouse Creek going up to 290. I think you had highlighted in the prepared remarks inclusion of some previously excluded verticals. But just curious if there’s anything else that you see at this point that could pose risk to that number continuing to move higher or you guys still feel good about wherever that number goes relative to the insurance coverage.

Brian Van Abel: Yes. I’ll give you a little bit more color. No, the way I think about it is we’re making really good progress on the overall claims. If you look at the details, we’ve settled 151 of the claims that come through our process. So we’ve settled more than we took in, in Q1. So making progress in terms of closing that from our internal claims process. We also have 25 lawsuits filed against us. What I didn’t say in the opening remarks is we’ve settled or dismissed five of those already. So we’ve turned to settling the represented claims. And as you said in your question, and as I said in my opening remarks, we’ve now had settled with the railroad entities which was not in our low end accrual before we settled with utility entity that was not in our low end accrual.

And we have made some settlements for tree damages and so we’ve included the settlement payments in our $290 million accrual. There’s also one other call large claim that we’ve gone through the discovery process and included in our accrual. So from that perspective, again, it is following accounting guidance. It’s a low end accrual and you can see what we excluded in our disclosures. But overall, I was pointing to people that we have approximately $500 million of insurance coverage and we are well under that policy limit as we sit here today and we’ll continue to make progress over the balance of the year on these claims.

Carly Davenport: Great. Great to see the progress there. Thanks so much for all the color.

Operator: Thank you. Our next question is from Durgesh Chopra with Evercore ISI. Please go ahead.

Durgesh Chopra: Hey team, good morning. Thank you for taking my questions. I actually just have one. All of the questions have been asked. Just any updated thoughts on the Marshall Fire, any conversations with stakeholders as we’re approaching trial here this fall? Anything new there? Thank you.

Brian Van Abel: Hey Durgesh, yes, I think, just as I noted in my prepared remarks, that in the plaintiff’s expert reports, we received two new causation theories, one related to a partially unattached piece of telecom equipment making contact with our line and the other one, that being an unidentified flying object making contact with our line. So four theories in total. When you look at the Sheriff’s report, the Boulder Sheriff’s report, which had the ignition being our first line, and then the underground coal seam. So that’s where we are, I think a little bit of discussions just from a process perspective. We have mediation process in this case that’s standard for trials such as this; deadline for mediation is May 29. So we’ll work through that process. But as we sit here today and as we said before, we’re diligently preparing ourselves for trial, which starts September 26.

Durgesh Chopra: Awesome. Thanks, Brian.

Bob Frenzel: Yes. Hey, Durgesh, just one thing I’d add on there that I think is important is the — that we believe that our indemnity agreements on our poll attachments are strong. As we think about the causation theories that have been proposed, that’s just an important one to think through.

Durgesh Chopra: Got it. Thank you.

Operator: Thank you. Our next question is from Jeremy Tonet with J.P. Morgan. Please go ahead.

Jeremy Tonet: Hi, good morning.

Bob Frenzel: Hey Jeremy, how are you?

Jeremy Tonet: Good, good, thanks. Just want to, I guess, start off, could you elaborate on potential regulatory treatment of wildfire related O&M expense and are you expecting to recover some of these costs and what type of — what kind of assumptions underpin your guidance at this point?

Brian Van Abel: Hey, Jeremy, I think underpinning our guidance as such is always constructive regulatory treatment. I’ll kind of hit on a couple. One, we talked about the Colorado Wildfire Mitigation Plan. Now that’s a unanimous settlement, still awaiting commission hearing and approval. But that includes concurrent recovery for our O&M expenses related to our wildfire investments. And so that, as I said is a very good constructive outcome in awaiting the decision by the commission there. We have filed regulatory deferral for regulatory deferrals around our insurance premiums. We made a filing in Wisconsin, Texas, and New Mexico. And so we expect decisions there probably Q2, Q3 time frame on those three filings. And then in Minnesota, that would just be part of our rate case.

We’ve included our wildfire O&M expenses and investments in the rate case, which has a forecast year for 2025. And that decision will play out that proceedings a little bit longer dated. But overall, we do assume constructive regulatory outcomes overall just as part of general guidance assumptions year in and year out.

Jeremy Tonet: Got it. Thank you. And then maybe pivoting towards — back towards data centers here. It seems like a lot of the pipeline has been in Minnesota, but just wanted to see, I guess, how you see things developing across other service territories, especially Colorado. Could there be kind of a broadening of this?

Brian Van Abel: Yes, I think, as we’ve spoken about this, the last few calls we talk about, you’re absolutely right. You’ve heard us talk about the opportunities in Minnesota and the interest we’ve seen there. We’ve seen it expand beyond Minnesota as you allude to. One, we already have a data center in construction in Colorado. That was one of our signed contracts. And the three contracts we’re working on right now is what I talked about in my opening remarks that we expect to have signed by this fall. One is in Colorado. We also worked on what we call a large load cluster study in Colorado. And you look at looking at called this colocation area near the Denver Airport in Aurora, which was not only some data center customers but also a large industrial customer and a large distribution center.

So gaining interest in Colorado. But we also have a lot of interest in Wisconsin too. So as we think about it, we have signed agreements in three different states today. And then we also the three agreements that we’re working on, one in Wisconsin, one in Minnesota, one in Colorado. So it’s helpful to kind of see that interest across our states. And we’re also seeing growing interest in the Dakotas. There was a land sale last year in South Dakota to a data center. So we continue to receive inbound inquiries and have a strong pipeline. So our goal is to execute on fulfilling that kind of what we call high probability pipeline by this fall for our investors and really for our customers. When we look at the benefit it creates for our customers and maintaining affordability.

Bob Frenzel: Yes. I’d add in the Southwest as well, we filed AQ studies with the Southwest Power Pool for thousands of megawatts of data center inquiries down there. A little bit further back in our probability pipeline for data centers. But we’re still seeing lots of interest down there. Think about it, our SPFC and I-tariff is one of the lowest in the country and has attracted some attention as well.

Jeremy Tonet: Got it. That’s helpful there. And just want to go back to Colorado if I could one last one. How do you think about pacing a high Colorado investment against high sales growth as you’ve outlined there? Do you see any periods of relatively elevated bill inflation as investments come in ahead of load? Just wondering, stakeholder feedback on bill inflation in Colorado?

Brian Van Abel: Yes. I mean we have a significant investment plan in Colorado and I think we are very focused on affordability. Maybe I started from a little bit higher level is if we look at our customer bills in Colorado on the electric perspective, they’re the second lowest in the nation from an affordability perspective as share of wallet. And then when you looked at the combined electric and gas, it’s lowest in the nation from an affordability perspective. So we’re in a really good place in Colorado from an affordability perspective. Significant investments, certainly, working with commission, that’s an avenue of additional requests we made in our current resource plan in terms of providing the longer-term affordability looks.

So working closely with our commission and stakeholders on that and that’s also part of the wildfire mitigation plan that, that we just settled here in terms of looking at securitization, some of these unique investments we’re making to protect our customers and communities. So certainly, top of mind, like you said, it could be a little bit elevated, call customer bills here in the near-term as we work to get that loaded online later, call it, in the five years but certainly something we’ll work with our commission and stakeholders on managing that affordability.

Bob Frenzel: The other lens of this is we talked in our prepared remarks about $5 billion across all of Xcel Energy on savings from wind energy and tax credits. Colorado sits in one of the windiest and sunniest parts of the country. We have the ability to make an energy transition there very cost effectively. Our forecast for Colorado was to be more than 80% carbon reduced by the end of this decade, tapping into those great resources. We think that, that footprint allows us to be very attractive in economic developments as well. And when you think about low-cost energy and the attraction to bring economic development, whether it’s data centers, whether it’s the oil and gas load in the DJ Basin or whether it’s new onshoring and reshoring, we think Colorado is a great home for economic development.

And as we all know, more sales is beneficial to the broad customer base. So our continued focus on bringing businesses to Colorado, minimizing the bill impacts from an energy transition and from a growth perspective, it’s a real focus for the company.

Jeremy Tonet: Got it. That’s very helpful. Thank you.

Operator: Thank you. Our next question is from David Arcaro with Morgan Stanley. Please go ahead.

David Arcaro: Hey, thanks so much. Good morning.

Bob Frenzel: Good morning, David.

David Arcaro: Wanted to clarify is the — I think you called out 2% to 3% total tariff impact on your investment plans. Does that consider all of the renewables investment as well? And like specifically the AD CVD ruling that we had just recently and the potential increased cost in the solar supply chain.

Bob Frenzel: Hey David, good morning. Yes, we’re — that sort of 2% to 3% is really just focused on our base $45 billion capital plan. And when we think about that over a five-year time period, very modest and manageable. In terms of AD CVD, we do not expect any impacts from that recent AD CVD ruling that came out from the commerce department on Monday. So we’re comfortable that, that was well communicated with that investigation, and we took steps with our suppliers to ensure that we would not get impacted by it. So we — and from so I think longer-term on the wind side in terms of our agreements with our OEMs, we feel good about in terms of managing the tariff impacts on the wind side and the solar side.

David Arcaro: Got it. Perfect. And then just curious on the data center side of things, I think your longer-term kind of data center target or the pipeline level didn’t change versus the prior quarter. It sounds like there’s been activity though, maybe in the earlier stage pipeline. Is that the right way to think about it, where you’ve seen, I guess, additional gigawatts coming in the earlier stages? But what — I guess, what’s the cadence of how you would update that more firm pipeline forecast?

Bob Frenzel: Hey David, yes, I don’t think it’s — I don’t think we’ve seen much of a timing in terms of pulling things earlier. What — we’ve made really good progress, I would say, with the three that we’re working on to sign. And like I said, there’s one in each of our states, Colorado — sorry, yes, Colorado, Minnesota and Wisconsin. But I don’t think the timing of it has changed necessarily when I look at it, now if we’re signing contracts for those three customers today, they’re going to be a little bit backdated in our five-year forecast. So yes, overall, we haven’t changed our kind of pipeline. Don’t expect us to update that 8,900 until Q3. We’ll just do with our normal kind of five-year sales cycle. But the timing, I would call it, is intact what’s kind of within the next five years and what we expect to bring on.

David Arcaro: Yes, got it. Okay, great. I appreciate it. Thanks so much.

Operator: Thank you. Our next question is from Anthony Crowdell with Mizuho. Please go ahead.

Anthony Crowdell: Hey, good morning, team. It’s just — it’s really nice calling Investor Relations and not hearing into Sandman in the background.

Bob Frenzel: He’s probably listening, Anthony.

Anthony Crowdell: I know. I know. I know. I know. So how to make fun of them. Just one clarification, one question. I think it was to Durgesh’s question earlier, on a new cause related to the Marshall Fire. I just apologize if I heard correctly, is a plaintiff claiming the cause of the fire was a UFO hit your wire and the wire fell and caused the fire?

Bob Frenzel: The cause — so what I said was there are two theories introduced by the plaintiff’s experts in their reports that they submitted. And that was their language that an unidentified flying object or something hit our lines and our lines — again, our lines did not fall to the ground. We had one line that came off of the insulator, but we had no down power lines, but that was the theory that they put forth. And the other theory was that piece of partially unattached telecom equipment hit our line. So those are the two theories, but you are correct in terms of how I phrased it in that first part.

Anthony Crowdell: Got it. Okay. And just if I could circle back, I think, Bob, you talked on it earlier on coal plant retirements. You highlighted just years of planning. I think you I think you maybe have scheduled maybe one or two plant retirements this year, maybe Comanche. Just thoughts if you go — I assume they’re still on schedule? Just any clarity you could provide to that?

Bob Frenzel: Yes. So the way I think about it is we probably have a coal plant a year through the balance of the decade. This year is the second unit at Comanche I think the unit, Anthony, is probably 60 years old, 50 to 60 years old. And so our expectation is at the end of the year that, that unit shuts down along with its sister unit, which shut down two years ago. And that’s the plan, and we’re working towards that. And when you think about the renewable build-out in the Colorado Power Pathway that is underway in the state right now, that’s the reliability replacement for that unit that is retiring at the end of this year. So we work with our states for years, including sometimes almost decades on the transition plans. We’ve been incredibly successful in maintaining reliability.

As Brian commented on, in particular, Colorado, one of the lowest electric bills in the country, while we’ve done a significant transition away from coal in that state, and we expect that to continue.

Anthony Crowdell: Great. Thanks so much. Appreciate you taking my questions.

Operator: Thank you. Our next question is from Ryan Levine with Citi. Please go ahead.

Ryan Levine: Good morning. What impact do you see from the potential new Texas legislation related to wildfires in terms of its impact to your mitigation plans and the future in Texas?

Brian Van Abel: Ryan, can you be a little bit more specific which piece of legislation that you’re talking about because there are several pieces of legislation that are out there?

Ryan Levine: Yes. So there’s a few bills being proposed by Congressman from your service territory around different ways to reduce risk to your service territory related to both private E&P land in terms of whose jurisdiction would be under and then a few others around mitigation plans. I don’t know if that had any implications for CapEx or risk reduction for the company.

Bob Frenzel: Yes. Let me start and then Brian can opine. But first of all, we feel really good about where our system resiliency plan, conversations went with stakeholders in Texas and unanimous settlement on that program is going to allow us to make hardening investments into the state that we think are important. The legislation that’s gone going — there’s probably two that I talk about. One is around pole inspection programs and having more of a state law around that. I think we’re generally supportive of pole inspections and pole inspection programs and reporting compliance with those programs. That pole inspections are generally operating expenses go through regular rate cases, and I don’t think it’s a material impact on the capital side for the business.

And the second is more around wildfire liability and the opportunity to submit a wildfire management program and then having it done so in compliance with that program, you’d have an affirmative defense against civil lawsuits on liability side. So we think both pieces of legislation could be valuable. I don’t think it leads to significant investment. I think that’s largely being done through our SRP, which again, is under a unanimous settlement and looking for commission approval later this year.

Brian Van Abel: Yes. And Ryan, there’s two more pieces I can touch on. Yes, there is some legislation that is really directed to the oil and gas lines. And then there’s other legislation that we certainly support is more around kind of Texas improving their state firefighting capabilities. That’s around funding for firefighting aircraft, funding for rural volunteer, firefighting departments, new emergency management facilities, things like that, which we certainly support. But overall, if I think about our system resiliency plan and the investments we’re making, whether it’s in Texas, New Mexico, Colorado, Minnesota, it’s all about protecting our customers and communities. And that’s how we think about the plan that we put forth is really protecting them in this legislation, we don’t see it having an impact on how we think about the risk and how we protect our customers in terms of the investments we’re making.

Ryan Levine: Thanks. And then in terms of tax credit transferability, have you discussed or previewed the credit implications for different transferability iterations with the rating agencies and how they may view the implications as it’s more of an industry-wide issue? Any color you could share around how different decisions may be interpreted from your credit metrics?

Brian Van Abel: Ryan, we — our annual meeting with the agencies are in September. Again, we think anything happening the transferability or having tax credits without transferability is a very low likelihood. So if certain — if something happen, we certainly would have a conversation with them. But again, overall, our conversations back in September were good conversations, but didn’t focus on this, which you think is a low probability outcome.

Ryan Levine: Okay. Appreciate the time.

Operator: Thank you. Our next question is from Travis Miller with Morningstar. Please go ahead.

Travis Miller: Thank you. Good morning, everyone.

Bob Frenzel: Hey, Travis.

Travis Miller: Ryan teed up a little bit on Texas. That was my question. But on a little different perspective here. Obviously, a lot of headlines, a lot of talk about the power generation side. And given your different regulatory framework, I’d say outside of ERCOT, what’s your take in terms of as there’s more uncertainty around the rest of the state. Does that either impact you? Does it give you an advantage of attracting demands? Any kind of implications there as there’s more and more uncertainty on the power generation side, demand forecasting outside of your area in Texas, if that makes sense.

Brian Van Abel: Yes. Hey Travis, the way I think about it, and Bob kind of alluded to this with the AQ studies, we have a significant amount of demand already. And that’s a little bit a kind of point towards the RFP we have in flight right now. We’ve — that RFP we have implied is between 5,000 and 10,000 megawatts of new generation in that upper end, that 10,000 megawatts is really to serve the — our oil and gas customers with the demand we’re seeing there. And again, I mean, that’s — so from our perspective, we have a significant amount of demand without even considering what’s happening in the other parts of Texas. So our focus is on ensuring we can serve our current customers and potential data center load that we’re seeing from it. So I would say we already had robust demand there even before any impacts from, call it, the other parts of Texas and if any entities want to locate in SPP territory.

Bob Frenzel: And just — hey Travis, I don’t know if your question was aimed at the risk side. I mean the interconnectivity between ERCOT and the Southwest Power Pool is relatively de minimis, and it’s through D.C. tie. So there’s no contagion risk, I would say, operationally between those two systems.

Travis Miller: Okay. Yes, that’s helpful. Anything in the state legislation that’s going on, again, outside of what you were discussing earlier with system resiliency and wildfire, anything in other — those other bills out there that would impact you directly at all, again, kind of the power generation focused stuff.

Bob Frenzel: Yes. So I did talk about wildfire legislation in Texas. We also had similar legislation in North Dakota as well, which we were buoyed by. I think the only thing I’d comment on really that’s broad on the generation side is really the continued trend and support for nuclear more broadly across the country and in our states; we’ve gotten nuclear siting legislation in both Wisconsin and North Dakota. And then in Colorado, they changed the law to recognize that nuclear accounts as a clean energy resource under their calculations for carbon-free generation. So not surprising, there’s been a national trend towards nuclear as a preferred form of generation. We think it’s years out into the next decade before nuclear becomes certainly, SMRs become likely across the country. But with data center loads and other large load growth across the country, you could see folks looking at even large-scale nuclear facilities again, to serve some of this big load.

Travis Miller: Okay. Great. Well, Sanjee [ph], part of that real quick. Texas policy in terms of nuclear, do you have a stance either way?

Bob Frenzel: Yes. So look, Texas has been broadly supportive of nuclear. I mean I think they want a big piece of the nuclear supply chain and whether it’s from R&D or manufacturing of large components to wholesale manufacturing of SMRs to the implementation onto the grid. So as a state, Texas has been pro nuclear for a host of reasons. And of course, we would support that as well.

Travis Miller: Okay, great. Thanks so much for the time.

Bob Frenzel: Thanks, Travis.

Operator: Thank you. As we have no further questions, I would like to turn the call back over to CFO, Brian Van Abel, for any closing remarks.

Brian Van Abel: Yes. Thank you all for participating in our earnings call this morning. Please contact our Investor Relations team with any follow-up questions.

Operator: Thank you very much. That does conclude today’s conference. You may now disconnect.