Xcel Energy Inc. (NASDAQ:XEL) Q2 2025 Earnings Call Transcript

Xcel Energy Inc. (NASDAQ:XEL) Q2 2025 Earnings Call Transcript July 31, 2025

Xcel Energy Inc. beats earnings expectations. Reported EPS is $0.75, expectations were $0.645.

Operator: Hello, and welcome to Xcel Energy’s Second Quarter 2025 Earnings Conference Call. My name is George, and I’ll be a coordinator for today’s event. Please note, this conference is being recorded. [Operator Instructions] I’d like to call over to your hosts today Mr. Roopesh Aggarwal, Vice President, Investor Relations, to begin today’s conference. Please go ahead, sir.

Roopesh Aggarwal: Thank you, George. Good morning, and welcome to Xcel Energy’s Second Quarter 2025 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 second quarter 2025 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.

Robert C. Frenzel: Thank you, Roopesh, and good morning, everybody. In the second quarter of 2025, Xcel Energy continued to demonstrate our commitment to our customers, investors and communities to make energy work better. During the quarter, we delivered strong earnings of $0.75 per share. We invested $2.6 billion in resilient and reliable energy infrastructure for our customers, navigated and evolving energy policy landscape to ensure that we can continue to provide safe, clean, reliable and affordable electric and natural gas service. We continued our wildfire risk reduction efforts to enable safer and more resilient communities. Based on our results through the first half of the year, 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 our industry.

At Xcel Energy, we believe that we’re in the early stages of an infrastructure investment cycle in the United States that will define many industries for decades. Not just the often discussed AI boom, we see potential investment in onshoring and reshoring of manufacturing and other energy- intensive industries. And given our competitive reliability, cost and sustainability, we believe we will be attractive to those industries. And of course, we see strong investment in oil and gas and other energy infrastructure, particularly in our SPS region, where we power large portions of the Permian and Delaware basins. We continue to see strong energy demand from electrification of transportation, manufacturing and of home heating. Xcel Energy is here to meet the moment for our customers.

We set our capital plan — our 5-year capital plan last fall, we outlined a $45 billion infrastructure investment forecast to serve increased energy demand and make needed investments to strengthen our transmission and distribution systems. At that time, we also expected that our customers’ needs could exceed that base forecast. Today, we now believe that we’re likely to need an additional $15 billion of capital investment to meet our customer needs, largely within our current 5-year forecast and some beyond. There are several drivers to that incremental need. In June, we filed a generation plan to support energy needs in our fast-growing Texas and New Mexico region. Our recommended portfolio included nearly 5,200 megawatts of generation storage to be placed in service by 2030.

Over 4,500 megawatts is expected to be company-owned and operated. This includes 1,300 megawatts of wind, 700 megawatts of solar, 2,100 megawatts of natural gas CTs and 500 megawatts of storage. We anticipate filing for regulatory approval of these projects over the remainder of this year with commission decisions in 2026. We also anticipate issuing a second RFP later this year for additional resource needs in that region. In the Upper Midwest, we received approval in Minnesota for 2 firm dispatchment projects totaling 720 megawatts and at least an additional 2,800 megawatts of company-owned wind that will use our new Minnesota Energy Connection transmission line when it’s placed in service in 2029. RFPs for additional generation projects that are needed to meet customer demand and grid reliability are ongoing, and we expect commission decisions in 2026.

We expect to invest an incremental $3 billion to $4 billion in regional transmission projects to support reliability and regional growth, including two 765 kV lines, one from the MISO tranche 2.1 and the other from the Southwest Power Pool ITP portfolio. In addition to this $15 billion of incremental need, we are actively working through the resource planning process in Colorado that likely requires between 5 and 14 gigawatts of new generation to meet reliability and customer demand through 2031. We are still working through required regulatory approvals for a number of these projects, and we’ll provide updates as they materialize. We expect to formally update our 5-year forecast through 2030 on our third quarter earnings update. As we move to aggressively build the generation and transmission that the grid requires to support both growth and reliability needs, we’re also navigating a rapidly evolving energy policy landscape.

While we predominantly navigate resource plans and transition initiatives at a state level, we’re also very focused on federal legislation as it pertains to how tax credits and permitting can impact customer outcomes. On July 4, the budget reconciliation bill was signed into law. While we saw some challenges to wind and solar tax credits, there are also positive outcomes for customers in the bill. Lower corporate tax rates result in lower energy bills, all else being equal. Accelerated depreciation of capital is beneficial to customers as is the efficiency of transferability of eligible credits, both of which were continued in the One Big Beautiful Bill. As with the incentives for qualifying energy storage and for carbon-free dispatcher resources like advanced geothermal, nuclear generation, and carbon sequestration, all beneficial for customers in the country’s energy future.

Not surprisingly, renewable tax credits were front and center on the debate around this legislation. Accordingly, we expected limitations to credits as Congress tried to narrow a significant budget gap. For several years now, we’ve been working with our state commissions and other stakeholders on the substantial generation required in our operating regions to meet the reliability and growth needs of our customers. In total, we estimate that we need between 15 and 29 gigawatts of new generation before 2031, which is a significant amount could be sourced from wind and solar. Accordingly, we’ve already invested substantial capital and/or physically commenced construction of the clean energy resources included in our base capital plan as well as enough to execute on our incremental investment pipeline, which we believe are necessary to meet the data center and electrification needs of our customers.

We’ll continue to monitor and manage through the recent executive orders, agency, rule makings and trade and tariff actions and make adjustments as needed as we continue to develop the energy assets that we need in our regions. In addition, we’ve procured 19 gas turbine reservations to meet the reliability needs of our customers. We serve customers in the most resource-rich regions of the country and pairing wind and solar and energy storage and gas backup means that we can deliver clean, reliable and affordable energy for our customers at the speed that they require. Xcel Energy also continues to make progress to mitigate risk from wildfires and extreme weather. This includes investments in advanced camera and weather station technologies, enhanced power line safety setting installations, pole inspections and replacements and operational measures such as wildfire safety operations and public safety power shutoffs.

We’ve also seen strong support from our commissions and states to invest in wildfire risk reduction. In June, the Colorado PUC approved our unanimous settlement for our $1.9 billion Wildfire Mitigation Plan, which included a partial securitization mechanism to manage customer bill impacts, and an extension of our excess liability insurance deferral. And in July, the Texas Commission approved our $500 million system resiliency plan. Both investment plans enhance the reliability and resiliency of these systems to mitigate the impacts of evolving and volatile weather patterns. And on the legislative front in both Texas and North Dakota, constructive wildfire legislation was signed into law. And North Dakota legislation path establishing that one of utilities in compliance with an improved Wildfire Mitigation Plan, it has exercised a reasonable standard of care.

In Texas, similar legislation passes states and electric utilities not liable for damages from a wildfire, provided it’s not negligent and is in compliance with an approved wildfire mitigation plan. Finally, I want to take a moment to thank our incredible line worker crews and other employees who have been working in tough conditions this week to get the lights back on for our customers after two rounds of major storms in the Upper Midwest. All told, about 200,000 customers experienced outages from storms, Sunday and Monday nights, mainly in Minnesota, Wisconsin and South Dakota. More than 2,000 crew members joined in the effort, including crews from our Colorado and our Texas service areas as well as contractors and mutual aid partners. Their dedication to serving our customers when things get challenging is what they’re known for, and I am very proud of everything they’ve accomplished in the past few days.

With that, let me turn it over to Brian.

Brian J. Van Abel: Thanks, Bob. Good morning, everyone. Starting with our financial results. Xcel Energy delivered earnings of $0.75 per share for the second quarter of 2025 compared to earnings of $0.54 per share in the second quarter of 2024. Most significant earnings drivers for the quarter included the following: higher revenue from electric and natural gas service reflecting rate case outcomes and sales growth, increased earnings by $0.24 per share and higher AFUDC increased earnings by $0.07 per share. Offsetting these positive drivers, higher interest charges decreased earnings by $0.04, reflecting higher debt levels and interest rates. Higher depreciation and amortization decreased earnings by $0.03, driven by increased system investment, and increased O&M decreased earnings by $0.02 per share.

Turning to sales. Weather-normalized electric sales increased 3.5% for the second quarter, driven by strong sales growth across segments in SPS and PSCo. For the full year, we continue to forecast 3% weather-normalized growth. Shifting to rate case activity. In South Dakota, we filed an electric rate case requesting a $44 million increase based on a 10.3% ROE and a 52.9% equity ratio. Looking forward, we are evaluating options to file an electric rate case in New Mexico, natural gas rate case in Minnesota and rate cases in Colorado later this year. Moving to data centers. We are making solid progress on our target pipeline and are in active negotiations on several ESAs. We remain on track to meet our goal of contracting our toll base plan by the end of this year, as we have spoken about before.

We also continue to make strong progress on the Smokehouse Creek wildfire claims process. We’ve resolved 187 of the 253 submitted claims, which we continue to view as constructive. In addition, we have settled or dismissed 11 of 27 lawsuits. We have committed to $176 million in settlement agreements, of which $123 million has been paid through the second quarter of 2025. Based on current information and the settlement activity, we are reaffirming the low end of our estimated liability of $290 million, which remains well below our insurance coverage of approximately $500 million as we described in our earnings disclosure. Regarding the Marshall trial, we are preparing for trial starting September 25 and expect it to conclude by mid- to late November.

Please see our earnings release and slides for additional disclosure on Marshall and Smokehouse Creek. Moving to guidance. We are reaffirming our 2025 guidance range of $3.75 to $3.85 per share. We remain confident in our ability to deliver long-term earnings growth in the upper half of our 6% to 8% target range. Updates to key assumptions are included in our slides and earnings release. With that, I’ll wrap up with a quick summary. Xcel Energy posted strong second quarter 2025 earnings of $0.75 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 now have visibility to $15-plus billion of opportunity in our investment pipeline. We continue to make investments to reduce risk to our system and communities from extreme weather, alongside constructive support from our states.

We 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. We remain confident in our ability to deliver long-term earnings growth in the upper half of our 6% to 8% target range. This concludes our prepared remarks. Operator, we will now take questions.

Q&A Session

Operator: [Operator Instructions] Our very first question today is coming from Carly Davenport of Goldman Sachs.

Carly S. Davenport: Maybe to start on the line of sight to the CapEx upside moving from that $8 billion up to $15 billion. I guess how should we be thinking about the potential conversion of that upside into the base capital plan next quarter? Is there a spend that could fall outside from a timing perspective or any regulatory considerations that could keep dollars out of the base plan update? Just any color there would be helpful.

Brian J. Van Abel: Carly, yes, I’ll try and keep this somewhat succinct. But when we think about it, the SPS RFP were relatively early in that process. We’ll be filing with the New Mexico and Texas commissions here in August and expect decisions of those certificates of need are in the first half of next year. Minnesota, we continue to work through the RFPs and then we have the transmission — the big transmission in SPP and MISO. A lot of that will be in the kind of ’26 to 2030 time frame with a little bit falling out. But as I think about it, we’re generally conservative with what we view from a regulatory perspective. So we’ll be really clear and transparent on Q3 in terms of what’s in our base plan. And what’s outside of it.

But overall, I think we feel really good about this. What we now change the $15 billion plus line of sight in terms of the progress we’ve made both in Minnesota and in SPS. And I think we have one of the best growth prospects in the industry, and we’ll be really clear on how we lay that out in Q3.

Robert C. Frenzel: Just to add on to what Brian said, I agree with everything. Look, these projects are largely generation and transmission related in the incremental need category. And while a lot of it is driven by reliability needs of the existing footprint, some of it’s driven by growth as well. And we know as a company, as an industry, there’s tremendous need for electricity in this country right now to meet growing demand from all the things I mentioned in my prepared remarks. And so we think that this incremental need is real. It’s going to materialize and whether it’s in the front 5 or 6 or 7, it’s definitely coming towards our territories to support reliability and to support growth.

Brian J. Van Abel: Yes. And I think about above the Colorado resource plan that we’re working through right now and expect a commission decision here in Q3 that spend, the commercial operations for those projects is through 2031. So that’s both going to be in this 5-year and kind of that incremental CapEx for longer.

Carly S. Davenport: Great. I appreciate all that color, super helpful. And then maybe just on the SPS resource plan, as you pointed to that in your previous answer. Just could you remind us on your turbine procurement position just as we think about executing on the gas generation included in that plan, if I recall, when you initially filed it, it was supposed to come into service by kind of the 2030 time frame. So could you just lay out the details on that front?

Robert C. Frenzel: Sure. Happy to, Carly. In the prepared remarks, I said that we had 19 turbine reservation slots to support either projects that we already know are coming or we will need them for. I think the SPS portfolio requires 9 of those 19. And so I think we’re largely ready to supply those on time.

Brian J. Van Abel: Yes. And Carly, this is something that we think about our overall scale and relationships with our OEMs and the need for gas generation we see across our footprint. We look at — we reserve turbine slots in kind of that ’27-’28 time frame well ahead of the market so we could deliver on these projects because we see a significant need of gas generation across all of our operating companies to integrate the renewables and ensure reliability. So we’re well positioned from that perspective, not only on the EPC side, but also on the OEM side, but also on the EPC side given the demand on EPCs and the construction of the gas units across the country.

Operator: Next question will be coming from Nicholas Campanella from Barclays.

Nicholas Joseph Campanella: I just wanted to — I wanted to kind of hit OBB, but more specifically, I guess, the treasury order that’s coming in the next few weeks here. It seems like your appetite for renewable build-out is unchanged now that we’re on the other side of this. But just if the window for safe harbor is shortened, just how do you kind of see that affecting your plan? And I know that you did a lot of safe harbor on the original 45. So I just wanted to kind of confirm that you don’t really see an impact on any outcome, but I’ll let you talk.

Brian J. Van Abel: Nick, yes, kind of a lot wrapped up in that question. So if I don’t hit on all of it. Just remind me the pieces that you want me hit on. I think stepping back, we’re — when we look at our $45 billion base plan, we’ve taken steps, as you’d expect us to start physical construction on a number of projects last year, started physical construction on projects this year in the first half. So we feel very good about our $45 billion base plan plus a $15 billion-plus line of sight projects that we have. So we feel good at delivering those projects for our customers and having them in a good place from a start-up construction or physical work perspective. So overall, in a good place. And I think about the treasury guidance from our perspective, the statutory language is beginning to construction, and that term has been defined for a long time.

But we’ve been engaged in D.C. along with our industry partners, and I think we do expect something to come out here by mid- August, not going to opine on what that might be. But as we look at it, we’re continuing to start physical work on the projects and we value that guidance as it comes up. But overall, we feel really well positioned with where we are today and the generation needs to serve our customers.

Nicholas Joseph Campanella: Okay. And then just with the $15 billion of CapEx upside becoming more of a reality now, just that should boost pressure higher on rate base growth. Your cash flow profile is already improving from the investments you’re making today? And then you kind of talked about the depreciation benefits of OBBB and we could have sales growth later in the plan as well. So just as we kind of think about getting further out in the plan. How should EPS growth kind of track against rate base growth? Should we be kind of expecting similar types of equity issuance? Or is that kind of improving in your view?

Brian J. Van Abel: If I think about it, I’ll take that in a couple of different ways, again, really excited about the growth prospects and delivering for our customers here as we see the demand growth increase. From an equity perspective, no, we’ve always been managing a strong balance sheet. We do a balanced mix of debt and equity. If you look at our earnings release in our Q, we issued over $1 billion of equity via ATM in Q2. And so that really our base plan had $4.5 billion of equity, and we already accomplished $2.5 billion between before late last year and this ATM issuance. So we’re in a really good place, and we’ll continue to do that. We do see the incremental capital as we always said, coming with a balanced mix of debt and equity and roughly rule of thumb we’ve always given is that 40% equity and we view that ATM is our plan to be, but we’ll also look at other products, mandatory converts as our equity needs to grow to fund our accretive growth.

As I think about that translating from rate base growth to EPS growth, obviously, we’ll provide a holistic update in Q3 around our new 5-year capital plan, our incremental pipeline, our sales growth, rate base growth. And even what we said last year when we moved to 6% to 8%, we talked about being above the high end at times, and I think that’s a good way to think about it.

Nicholas Joseph Campanella: Okay. Very fair. And just one last one on Marshall. I know that trial in September, I think mediation deadline was today, but just is settlement of that fully off the table for now? Or is there still an opportunity to do that into trial and just taking your temperature there?

Robert C. Frenzel: Nick, it’s Bob. Thanks for the question. Look, so technically, the court order mediation concluded at the end of July, but that doesn’t mean the parties don’t continue to talk. As we step back and think about the trial broadly in the fire broadly, we continue to maintain that our equipment didn’t start the second ignition in the wildfire, and we’re prepared to go to court, as Brian indicated in his prepared remarks at the end of September, and that trial is likely to last through middle to late November. Between now and then, you’re probably going to see some filings back and forth from plaintiffs and us around pre-child briefs and things like that. But we’re planning to go to trial. We’re always open to settlement discussions, but we have to start with the idea that our equipment didn’t cause that second condition, and we maintain that.

Operator: Next question will be coming from Jeremy Tonet of JPMorgan.

Jeremy Bryan Tonet: I was just wondering if you could turn to the competitive transmission opportunities. How do you think about incorporating them into your plan? Do you probability weight the chance of winning contracts here? Or do you include them kind of on a binary basis?

Brian J. Van Abel: Jeremy, I can speak broadly about it. We don’t include them in our capital plan unless they’re one. And we’re very disciplined on the competitive side. You don’t see us bidding on projects generally outside of our service territories. So pretty disciplined. I mean we look at all of our growth capital that we have within our service territories, the transmission we need to build in SPP, MISO longer term Colorado and all the generation. You don’t expect us to be chasing competitively bid transmission projects kind of outside of our service areas.

Jeremy Bryan Tonet: Got it. Understood. And I just want to, I guess, turn to the data centers a little bit more. What is your contracting progress on the base data center assumption here. And can you provide any more color on the counterparty type, long-term ramp for the portion of your base forecast currently contracted?

Robert C. Frenzel: Jeremy, let me start. This is Bob, and then I’ll kick it over to Brian. As a company, we’re very excited about the opportunity to serve this type of critical infrastructure. We have about 1.1 gigawatts of data centers under construction and under contract. And our plan is for by the balance of the year to hit another sort of gig of data centers ultimately hitting about 2.5% by 2030 time frame. And then we’ve got a really robust pipeline behind that high-quality stuff that we’re working on right now of 7 or so gigs that I would talk about is maybe Tier 2 opportunities, and then there’s even Tier 3 and beyond stuff beyond that total. So really excited as I sit and think about our business, we have interest in all parts of our 3 operating areas, the upper Midwest, Colorado and the Desert Southwest and for different reasons.

Each of those regions are very attractive to our data center counterparts, either whether you’re a hyperscaler or a data center developer. With specific contract stuff, I’ll kick it over to Brian tell the ramp profile. But big picture, I think we see this as a real growth opportunity, a real opportunity to grow sales on our system, bring rates down for all of our customers and be beneficial for both hyperscalers as well as our existing customer base.

Brian J. Van Abel: Yes. And just to add a little bit of color. We talked about — we continue to make really good progress in the ESA negotiations with those counterparties. We talked about one in Minnesota, one in Wisconsin, one in Colorado. A couple of them are your — what you expect your hyperscalers, and we continue to make progress. And that’s when I think about progress, they have their system impact studies, facility studies, land and now we’re on to actually the terms of the agreement and discussing that. We also had a new opportunity in Texas and Amarillo that we’re working on. But again, we don’t expect us to update our data center slide every quarter. Our pipeline is robust, as Bob mentioned, we continue to see inbounds and looking forward to executing on the agreements we talk about for the balance of the year and bring that forward.

Jeremy Bryan Tonet: Got it. Very helpful there. And just a quick last one, if I could. If you could speak a bit more on the gain on debt repurchases there? And was this contemplated or the plan or any other color there?

Brian J. Van Abel: Yes, Jeremy. No, it wasn’t part of our plan. What we saw is we use it opportunistic. It’s a great tool. When you think about we saw some headwinds in our venture capital investments related to clean energy. And you know this is a challenging market for clean energy. And so you saw some negative mark-to-markets this year in the first half, and we just used that to that — to offset that. So not an earnings driver at all.

Operator: Next question will be coming from Julien Smith of Jefferies.

Julien Patrick Dumoulin-Smith: Bob, let me ask you this. I mean, you say at times, we can do the math. But if I heard you right earlier in the call, I mean, it seems like you might actually be doing the math for us here, at least as it pertains to the third quarter update. I mean, are you guys actually going to refresh the full suite of guidance in a more affordable way with that roll forward?

Robert C. Frenzel: Yes. So I think, as always, our third quarter update has a full and comprehensive update on all of the assumptions, whether it’s sales or capital deployment, rate base growth, earnings growth, financing needs, et cetera, and we plan to do a full roll forward on the third quarter call.

Julien Patrick Dumoulin-Smith: And then just going back to the — your ROEs in the PSCo backdrop. Obviously, you got the distribution rider, et cetera. How do you think about the improvement in earned returns there just a little bit again, that might be one of the disintermediating factors between rate base and earnings here, at least one of the bigger factors in the medium term. How are you feeling about that prospects, et cetera, just given the 7.8?

Brian J. Van Abel: Yes. Julien, I can take that one. Yes, you’re talking a rolling 12-month average of 7.8%. The distribution rider has been a good mechanism. We have a lot of investments on the distribution systems that deliver for our customers, both from a resiliency perspective and a growing capacity perspective. So — and that rider this year had — was capped. So it’s kind of partially implemented this year than full implementation next year. That 7.8% we do expect improvement through balance of the year and then continued improvement next year. And so we are working on that and the distribution rate once fully implemented, should help address some of that next year.

Robert C. Frenzel: Yes. I also think Brian mentioned in his prepared remarks, we were looking at potential cases in Colorado at the end of the year. And that’s a composite ROE. And so we’ve done a lot of work to improve the electric side of that ROE and the gas still has lag in some of its mechanisms. If you think about the preponderance of the capital in that company going forward, it’s largely electric. And as Brian mentioned, whether it’s a distribution rider, a renewable energy rider, a transmission rider or a new rate case, we expect — certainly, the electric side of that ROE to continue to improve.

Julien Patrick Dumoulin-Smith: Got it. Excellent. And sorry, I’m going to press it too much on this. But given what you have here already, and I know we can do the math, but just to verify. I mean it does seem like a low teens rate base CAGR, which admittedly would it be all that different from your, should we say, regional peers necessarily. Curious if you want to verify that?

Brian J. Van Abel: Julien, we did kind of give you that rule of thumb of 25 bps of rate base or 25 bps of rate base equals roughly incremental $1 billion of capital. So yes, you’re doing the math correctly. Now, we do — we’ll roll forward off a higher base for 2026 to 2030 rate base guidance as we always do. But you are correct, and we believe we have one the best growth prospects in the industry, and we’re going to deliver these projects for our customers, right? We’re really focused on reliable in affordable and clean energy for our customers. And so we have a lot of investments ahead of us to deliver on that.

Roopesh Aggarwal: Yes. So next question is coming from Steve Fleishman, Wolfe Research. I think we lost our operator.

Steven Isaac Fleishman: Well, that might be me. I thought I lost the call. So just a follow-up on the question regarding the kind of OBBB and executive orders. How — do we need to be concerned at all about kind of federal land issue with respect to your kind of renewable projects.

Brian J. Van Abel: Steve, I can take that one. We don’t have any projects on federal land, just make it easy — an easy answer.

Steven Isaac Fleishman: Okay. I like easy answers. And then on the — going back to the — also the topic of the Marshall Fire, Bob, you mentioned the — you kind of don’t think you caused a second ignition. I think your slides also continue to show that a lot of the damage was already kind of happening from the first ignition. I assume that remains part of your court case as well?

Robert C. Frenzel: Yes, absolutely, Steve. So when I think about the trial broadly, I think the share report identifies that the start of the fire was on property owned by the 12 tribes. That first ignition was subject to almost 100-mile an hour winds for over an hour and 20 minutes causing a fire spread theory where we see propagation of that fire into the towns in Colorado. And then obviously, at some point, there’s a purported second condition. And so we believe that, again, on a on a trial basis, we have to have been found to have started a second ignition that we were negligent in the maintenance and operations of our lines. And then we get into sort of joint several — or not joined several liability on the call. It’s sort of a proportion damages based on causality. So again, we feel very good about the facts and circumstances of our trial and are prepared to go there.

Steven Isaac Fleishman: Okay. And then there is still an opportunity to kind of settle if you deem that it makes sense.

Robert C. Frenzel: Sure. There’s no prevention from a settlement proposal. We’ve got probably 2 months before the trial begins. And you could settle even during the pendency of the trial. So there’s lots of opportunity there. But again, we feel very good about our facts, and we’re prepared to go the trial.

Operator: We’ll now move to Sophie Karp of KeyBanc.

Sophie Ksenia Karp: I have a follow-up on the trial. Could you remind us if there was any sort of range of estimate on the damages? I know that ultimately that will be decided at the second trial, but what are the estimates that are currently being contemplated?

Robert C. Frenzel: Sophie, it’s Bob. I think you got it right. The structure of the trial is such that we look at liability in the first trial and in the second trial would be any damages if we get that far. We don’t have an aggregate estimate of damage claims. What we do believe is that from the insurance companies, there was about $2 billion worth of property damage that they paid off in their claim process.

Sophie Ksenia Karp: Got it. And then my second question is just kind of broadly speaking, you have a lot of growth opportunities ahead of you, right? Then you’re going to presumably have some equity needs for those — and given that your valuation does not reflect those growth opportunities right now in my opinion at least. Have you explored — or you likely to explore alternatives to equity rates, such as maybe selling of some of the noncore assets or assets you deem less core to your electric operation? Like how should we think about that?

Brian J. Van Abel: Sophie, I can take that. I commented a little bit more in terms of ATM is our plan to be, but we’ll look at that mandatory and converts. We have a strong balance sheet, and we’re comfortable issuing equity to fund that accretive growth. Now I’ve been on record. We’ve been on record that we’re not all that interested in minority interest sales. And if we think about — we view our assets is core. And if we were ever to do anything, it would be for strategic reasons not to fund our investments that we need to make, and we’ve been disciplined for the past 20 years on the strategic side.

Operator: We’ll now move to Paul Patterson of Glenrock Associates.

Paul Patterson: Can you hear me?

Roopesh Aggarwal: You’re breaking up again. So next question is Paul Patterson with Glenrock Associates.

Paul Patterson: Hello? Can you hear me?

Operator: Yes, sir. Your line is open, sir. Okay. Gentlemen it appears he did not hear us. Right now, we do not have any further questions. I’ll turn the call over to Mr. Brian Van Abel for any additional closing remarks.

Brian J. Van Abel: 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 much, sir. Ladies and gentlemen, that will conclude today’s conference. You may now disconnect. Have a good day and goodbye.