Xcel Energy Inc (XEL) — Q1 2025 Earnings Call Transcript

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.

Thanks, Roopesh, and good morning, everybody. Xcel Energy knows that the economic growth and prosperity of our communities and country depend 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 of 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 surprisingly, 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, as well as 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. In the medium-term, we expect to see continued trends toward electrification as well as re-onshoring as potential outcomes 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 technology-neutral tax credits for wind, solar, storage, and nuclear as well as their associated transferability provisions in various loan and grant programs. It 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. Lastly, it 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, with a majority of this being 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 risks. 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 consider 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 continued to make progress 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. This includes 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 New 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. 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 a 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. We 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 technology-neutral and nuclear PTCs have also proven to be 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 the 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 that these incentives play an important role in helping us meet that objective. Xcel Energy also continues to make significant progress to protect our customers, 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 the third quarter of 2025, and we'll continue to prioritize these investments to improve resiliency and reduce risk in our systems. 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 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.

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 quickly 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. We're 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 resettled 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 and are seeing 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.

Hey, thanks so much for taking the questions.

Hey, morning, Nick.

I just 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 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?

Hey Nick, it's Bob. I'll start and then I'll give Brian some time to get to some details. There's been a lot of conversation around transferability in general, at least in the investor community, but not actually a lot in D.C. I've spent a lot of time there. Transferability was architected as part of the IRA, and we think it's explicitly linked to the credit program themselves. There’s a lot of support, as evidenced by letters that Congress and the Senate have written to their respective Finance and Ways and Means Committees around support for the continuation of the credits in some fashion and form. 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 we've safe harbored. Depending on where the credits go, in general, I think the transferability stays aligned with those credit profiles over time. But let me let Brian comment a little bit on some of the details you asked about rate base and/or cash flow implications.

Yes, Nick, and maybe I'll talk about it in two different avenues. Feel free to ask further questions if I don't hit on exactly what you're thinking about. I think about one is there's been a lot of discussion around the bill introduced by Representative Fedorchak. 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. We would expect those to have credits and transferability associated with them. So really the Fedorchak 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 are 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. Your question I get is a little bit more about what would happen if transferability 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, you hit it on the head, right? Rate base goes up because you're less tax efficient. We would have an impact on our cash flow. You might look at issuing some equity to manage some of those credit impacts. In the longer term, it just becomes a timing issue where you're pushing those cash flows out into the future. But there are alternative ways you could look at tax equity in the regulated environment. One interesting concept we do in one of our jurisdictions is 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 improves your cash flow in the near-term, reduces tax efficiency, and also provides a pretty stable customer profile from bill impacts. So there are things we think of internally that may not be understood externally about how we manage those scenarios. Like I said, we don't expect that scenario will happen, but how we manage if it did happen.

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 seem 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.

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 and hear 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. There is a lot of conversation, potentially 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. We used the word in our prepared remarks of dynamic or fluid. I continue to believe that we don't see many impacts right now on the customer side. But I’m cautiously optimistic that we work through this through the balance of the year. Obviously, we've reiterated our guidance and sales forecast accordingly.

Yes, Nick, I can just provide a little bit of 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. So far, we haven't seen that impact on us. Our sales to the mining and transportation sector were up 9% year-over-year, specifically down in SPS. So we're 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 it’s something that we're watching. Overall, right now, we feel comfortable reaffirming our 3% sales growth for the year.

Thank you.

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 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 could emerge from going back to the prior regime? I just want to make sure I understand 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 could be bifurcated. It seems like you can speak to that a little bit too.

Yes. Julien, let me first reiterate that we don't expect transferability to go away, particularly for projects that are in service and for those that have already been safe-harbored under the old regime. But yes, this alternative mechanism significantly reduces our equity impact. You also have to remember that any taxes drive rate base goes up too when you have tax inefficiency. However, we think about this alternative fallback mechanism; we'd work with our regulators on the approval of it. We think it's a very good solution in terms of how to manage some of the credit impacts. And we also have a strong balance sheet, which maintains that strength for a reason. If you have to manage through any of these impacts, it's a timing issue in terms of when you can monetize it. Overall, I wanted to provide some color on scenarios that may not be understood externally. When we think about how we manage, if that scenario happens, we don't expect it, but we can manage it if it does. Your question about bifurcating different treatments related to credits; certainly, the Fedorchak bill was just focused on wind and solar. It didn't impact the storage credits or the nuclear credits. 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 letter that had 21 Republicans signed on, and the Senate letter that had four Republican senators signed onto it. I think there's an understanding of the importance of the economy from these credits and what they do. There are good studies out there about the economic impacts and the 14 million-plus jobs that the IRA will create over the next 10 years. That's how I think about it in terms of overall and transferability being a key part.

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 I just want to speak to that a little bit more and provide some clarity on that plan.

Yes, thanks Julien, I can handle that. Overall, a very constructive settlement with unanimous agreement from 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. How we think about it is it's a win-win from all sides as we attain constructive cost recovery here in the near-term. We also achieve an extension of our insurance deferral, which we had a one-year extension that expired in October. We also agreed to seek to securitize approximately $1.2 billion of spend by 2029. That's a helpful way to manage overall customer affordability. 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. We're looking forward to having the hearing in front of the commission here within a month.

Excellent. Thank you guys. See you soon.

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 after having those discussions?

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 we're working on, whether it's renewable projects or storage projects, that 2% to 3% figure is manageable. When you think about projecting it over a five-year time period, the conversations have been ongoing, not just recently. We anticipated earlier discussions regarding tariffs, especially after the election in November when we expected them. We included tariff impacts in the bids we made in our RFP down in SPS in January. It's important to note these discussions are not new but now that we understand where they are, we're navigating through them. For example, we recently signed an agreement for substation power transformers that come from nine different suppliers, five U.S. domestic manufacturers and four global manufacturers, giving us the ability to diversify our supply base. These discussions have been happening and we've been preparing all along.

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 a risk to that number continuing to move higher or do you still feel good about wherever that number goes relative to the insurance coverage?

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 came through our process. So we've settled more than we received in Q1. We're making progress in closing that from our internal claims process. We also have 25 lawsuits filed against us. I didn’t mention in my opening remarks that we've settled or dismissed five of those already. We've turned to settling the represented claims. As you said in your question, and as I mentioned in my opening remarks, we've settled with the railroad entities, which was not in our low-end accrual before we settled with utility entities that were not in our low-end accrual. We also included settlement payments for tree damages in our $290 million accrual. There's also one other large claim that we've gone through the discovery process and included in our accrual. So from that perspective, we’re following accounting guidance. It's a low-end accrual, and you can see what we excluded in our disclosures. But overall, I'd reassure people we have approximately $500 million of insurance coverage and we are well under that policy limit as we stand here today, and we'll continue to make progress on these claims throughout the year.

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

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.

Hey Durgesh, yes, I think, just as I noted in my prepared remarks, in the plaintiffs' 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 relating to an unidentified flying object making contact with our line. So there are four theories in total. When you look at the Sheriff's report, the Boulder Sheriff's report had ignition being our first line, and then the underground coal seam. We have a mediation process in this case that's standard for trials such as this; the deadline for mediation is May 29. So we'll work through that process, but as we sit here today and as we've said before, we're diligently preparing for trial, which starts September 26.

Awesome. Thanks, Brian.

Yes. Hey, Durgesh, just one thing I'd add on there that I think is important is that we believe our indemnity agreements on our pole attachments are strong. As we think about the causation theories that have been proposed, that's just an important factor to consider.

Got it. Thank you.

Hi, good morning.

Hey Jeremy, how are you?

Good, good, thanks. Just want to start off, could you elaborate on potential regulatory treatment of wildfire-related O&M expense and whether you are expecting to recover some of these costs? What type of assumptions underpin your guidance at this point?

Hey, Jeremy, I think underpinning our guidance is generally constructive regulatory treatment. I'll touch on a couple of points. One, we talked about the Colorado Wildfire Mitigation Plan, a unanimous settlement we’re awaiting commission hearing and approval. This includes concurrent recovery for our O&M expenses related to our wildfire investments. As I said, it's a good constructive outcome we await the decision from the commission. We have filed deferrals for regulatory deferrals around our insurance premiums in Wisconsin, Texas, and New Mexico. We expect decisions around those in Q2, Q3 timeframe. In Minnesota, that's part of our rate case where we included our wildfire O&M expenses and investments in the rate case, which has a forecast year for 2025. That decision will come out later. But overall, we do assume constructive regulatory outcomes as part of our general guidance assumptions year in and year out.

Got it. Thank you. And then maybe pivoting 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?

Yes, I think, as we've spoken about in the last few calls, you're correct about opportunities regarding Minnesota and the interest we've seen there. We've seen it expand beyond Minnesota as you allude to. We already have a data center in construction in Colorado, which was one of our signed contracts. The three contracts we’re working on to sign includes one in Colorado. We also worked on what we call a large load cluster study in Colorado focusing on a colocation area near the Denver Airport in Aurora, which has some data center customers, a large industrial customer, and a large distribution center. So there's increasing interest in Colorado. But we also have a lot of interest in Wisconsin too. We've signed agreements in three different states today and we also have three agreements that we're working on: one in Wisconsin, one in Minnesota, and one in Colorado. There is growing interest in the Dakotas as well. A land sale last year in South Dakota to a data center shows increasing requests and interest. Our goal is to execute on fulfilling that high probability pipeline by this fall for our investors and customers, considering the benefit it creates for affordability.

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. It's a little bit further back in our probability pipeline for data centers, but we're seeing lots of interest there. Our SPFC and I-tariff is one of the lowest in the country, attracting attention as well.

Got it. That's helpful there. And just want to go back to Colorado if I could one last question. 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 about stakeholder feedback on bill inflation in Colorado?

Yes. We have a significant investment plan in Colorado, and we're very focused on affordability. If we look at our customer bills in Colorado for electricity, they rank second lowest in the nation from an affordability perspective. When combining electric and gas, it is the lowest in the nation regarding affordability. We are in a really good place in Colorado. We will work closely with the commission and stakeholders on additional requests regarding our current resource plan to ensure long-term affordability remains a focus. Some customer bills may experience elevated levels in the near term as we look to get that load online later in the five years, but we will continue to manage that affordability with the commission and stakeholders. Furthermore, we discussed $5 billion across all of Xcel Energy on savings from wind energy and tax credits. Colorado sits in one of the windiest and sunniest regions of the country, enabling us to transition very cost-effectively. Our forecast for Colorado suggests it will achieve more than 80% carbon reductions by the end of this decade by tapping into those substantial resources. This allows us to attract economic development further. Bringing jobs reduces bill impacts from energy transitions and growth perspectives remains an absolute focus for the company.

The other perspective is that we've spoken about in our prepared remarks: $5 billion in savings from wind energy and tax credits. Colorado’s ability allows us for a smooth energy transition, affirmatively supporting economic development. Think about low-cost energy's appeal to attract economic development whether it be data centers, the oil and gas load in the DJ Basin, or onshoring and reshoring. Colorado is a prime location for economic development. More sales benefit the broad customer base. As such, we focus on bringing businesses to Colorado while minimizing bill impacts from energy transitions and growth perspectives.

Got it. That's very helpful. Thank you.

Hey, thanks so much. Good morning.

Good morning, David.

Wanted to clarify, I think you called out a 2% to 3% total tariff impact on your investment plans. Does that consider all of the renewable investment as well? Specifically, the AD CVD ruling that we had just recently and the potential increased costs in the solar supply chain.

Hey David, good morning. Yes, that 2% to 3% is focused on our base $45 billion capital plan. When we think about that over a five-year time period, it’s very modest and manageable. In terms of AD CVD, we do not expect any impacts from that recent ruling by the commerce department. We feel comfortable knowing these were well communicated by that investigation. We took steps with our suppliers to ensure that we would not be affected by it. So from a long-term perspective on the wind side, our agreements with our OEMs indicate we feel good about managing tariff impacts on both wind and solar sides.

Got it. Perfect. I’m curious about the data center side. It seems that your long-term data center target or pipeline level has remained stable compared to the previous quarter. There appears to be activity, possibly in the earlier stage pipeline. Is that the right perspective? Have you observed additional gigawatts entering the earlier stages? Also, how frequently will you update the more established pipeline forecast?

Hey David, yes, I don’t think we’ve seen much timing pulling things earlier. We've made good progress on the three we’re working to sign. One in each state, Colorado, Minnesota, and Wisconsin. I don’t think the timing has changed. Now if we're signing contracts for those three customers today, they'll be backdated in our five-year forecast. Overall, we haven’t changed our pipeline expectations, and I don’t expect us to update that 8,900 until Q3. We'll follow our normal five-year sales cycle. However, the timing is intact and remains consistent with the next five years, and we expect to bring that on.

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

Hey, good morning, team. It's just really nice calling Investor Relations and not hearing into Sandman in the background.

He's probably listening, Anthony.

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 that hit your wire and the wire fell and caused the fire?

The cause is based on two theories presented by the plaintiff’s experts. They suggested that an unidentified flying object or something else struck our lines. However, our lines did not fall to the ground; we only had one line that came off the insulator, but there were no downed power lines. That was one theory they proposed. The second theory was that a piece of partially unattached telecom equipment struck our line. So, those are the two theories I mentioned.

Got it. Okay. And just to follow up, Bob, you mentioned coal plant retirements earlier. You pointed out that this involves years of planning. I believe you stated there might be one or two plant retirements this year, possibly Comanche. Are they still on schedule? Can you provide any clarity on that?

Yes. So the way I think about it is we probably have a coal plant retirements plan to go one per year through the balance of the decade. This year is the second unit at Comanche, which is probably 60 years old, if not 50 to 60 years old. Our expectation is that by the end of this year, that unit shuts down along with its sister unit, which shut down two years ago. That's the plan and we're working towards that. When you think about the renewable build-out in the Colorado Power Pathway that is underway in the state right now, that's the reliable replacement for that unit that’s retiring at the end of this year. We’ve worked with our states for years, including sometimes almost decades, on transition plans. We’ve successfully maintained reliability. As Brian noted, particularly in Colorado, we have one of the lowest electric bills in the country while we've undergone a significant transition away from coal in that state, a plan we expect to continue.

Great. Thanks so much. Appreciate you taking my questions.

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

Ryan, can you be a little bit more specific about which piece of legislation you are talking about, because there are several being proposed?

Yes. A few bills being proposed by congressmen from your service territory around different ways to reduce risks to your service territory related to both private E&P land in terms of jurisdiction and others around mitigation plans. I don’t know if that had any implications for CapEx or risk reduction for the company.

Yes. Let me start and then Brian can opine. We feel really good about our system resiliency plan, with conversations I’ve had with stakeholders in Texas and unanimous settlements on that program, which will allow us to make hardening investments into the state that we think are important. The legislation that’s going through, there’s probably two that I can talk about. One is around pole inspection programs and having more of a state law around that. We’re generally supportive of pole inspections and compliance reporting. These inspections generally operate like expenses through regular rate cases, and I don’t think it'll have a material impact on the capital side for the business. The second involves wildfire liability and submitting a wildfire management program could provide an affirmative defense against civil lawsuits concerning liability. We think both pieces of legislation could be valuable. I don’t believe it will lead to significant investment, as our SRP is in place through a unanimous settlement and we’re continuing to seek commission approval for later this year.

Yes. Also, there's more legislation that is really directed specifically toward the oil and gas lines. There's other legislation we certainly support focused on improving Texas state firefighting capabilities, funding for firefighting aircraft, and for rural volunteer firefighting departments and new emergency management facilities. Overall, we don’t view these measures as having a material impact on how we protect our customers in the investments we are making.

Thanks. In terms of tax credit transferability, have you discussed or previewed 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?

Ryan, our annual meetings with agencies are in September. We think anything happening around transferability or tax credits without transferability is a very low likelihood. If something does occur, we would certainly engage in conversation with them. Our last discussions in September had good outcomes but didn’t focus on this issue, which we still view as low probability.

Okay. Appreciate the time.

Thank you. Good morning, everyone.

Hey, Travis.

Ryan teed up a little bit on Texas. That was my question. But from a different perspective here, obviously, a lot of headlines and talk about the power generation side. Given your regulatory framework outside of ERCOT, what's your take in terms of more uncertainty around the rest of the state? Does this impact you? Does it give you an advantage in attracting demand? Any implications there as these uncertainties on the power generation side contribute to demand forecasting?

Yes. Hey, Travis, the way I think about it is Bob alluded to this with the AQ studies. We have significant demand already, and that points towards our RFP currently in flight. That RFP implies between 5,000 and 10,000 megawatts of new generation at the upper end, which is intended to feed our oil and gas customers. So our focus is ensuring that we can serve our current customers while accommodating potential data center loads. We have substantial demand without including other impacts from other parts of Texas. Our focus remains on meeting current contract inquiries in the region.

Moreover, I don’t think your question was focused on risk. The interconnectivity between ERCOT and the Southwest Power Pool is relatively minimal, and it's through the D.C. tie. So there doesn't appear to be any contagion risks operationally between those two systems at this point.

Okay. Yes, that's helpful. Anything in the state legislation that is going on, again, outside of what you were discussing earlier with system resilience and wildfire, relating to other bills out there that would impact you directly at all, again, with a focus on power generation?

I did mention wildfire legislation in Texas. We've also had similar legislation in North Dakota, which we are buoyed by. On the generation side, I think there continues to be a trend and support for nuclear across the country and our regions. We have nuclear siting legislation in both Wisconsin and North Dakota. In Colorado, they amended the law to recognize nuclear as a clean energy resource under calculations for carbon-free generation. It’s not surprising there’s a national trend towards nuclear as a preferred generation form. We think it will be some years before small modular reactors (SMRs) are likely across the country. However, with data center loads and other large load growth across the country, we could see interest re-emerging in large-scale nuclear facilities to serve some of this big load.

Okay, great. Thank you for your time.

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