Xcel Energy Inc. (NASDAQ:XEL) Q2 2024 Earnings Call Transcript

Xcel Energy Inc. (NASDAQ:XEL) Q2 2024 Earnings Call Transcript August 1, 2024

Xcel Energy Inc. misses on earnings expectations. Reported EPS is $0.54 EPS, expectations were $0.57.

Operator: Hello, and welcome to Xcel Energy Second Quarter 2024 Earnings Conference Call. My name is George, and I will be coordinator for today’s event. Please note this conference is being recorded. And for the duration of the call, your lines will be in a listen-only mode. However, a question-and-answer session will follow-up at the prepared remarks and questions will only be taken from institutional investors and analysts, reporters can contact media relations with inquiries and individual investors and others can reach out to Investor Relations. [Operator Instructions] I’d now like to hand the call over to your host, Mr. Paul Johnson, Vice President, Treasurer and Investor Relations to begin today’s conference. Please go ahead, sir.

Paul Johnson: Thank you. Good morning, and welcome to Xcel Energy’s 2024 second quarter earnings call. Joining me today are Bob Frenzel, Chairman, President and 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 questions if needed. This morning, we will review our 2024 second quarter results and highlights and share recent business developments. Slides that accompany today’s call are available on our website. As a reminder, some comments made 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’ll also discuss certain metrics that are non-GAAP measures. Information on comparable GAAP measures and reconciliations are included in our earnings release. With that, I’ll now turn the call over to Bob.

Bob Frenzel: Thank you, Paul, and good morning, everyone. Thank you for joining us today. I’m pleased to report that the company delivered another quarter of solid operational and financial progress. Our long-term business model remains robust. We continue to deploy capital for the benefit of our customers and communities. We enable a future powered by cleaner fuels and a more resilient and intelligent grid. We partner with stakeholders to encourage economic development, we provide products and services capable of meeting our customers’ most important needs. In the most recent quarter, we invested $1.7 billion in resilient and reliable energy infrastructure. We delivered earnings per share of $0.54 for our owners. We provided industry-leading storm response and strong customer reliability despite challenging weather conditions for our customers.

We accelerated wildfire risk reduction measures to enable safer and more resilient communities. Xcel Energy’s commitment to our communities and investors is anchored by our core investment thesis as an integrated pure-play utility and a clean energy leader. For more than two decades, we’ve been a leading provider of wind energy to our customers, and we were the first US energy company to commit to a carbon-free electric future. We delivered our earnings guidance for 19 straight years, one of the best records in our industry, and we look to make it 20 this year. We have a long-term and transparent growth plan, making investments in clean generation new to and enhanced energy grids and economic development programs to support our communities vitality.

In 2020, our continuous improvement programs have saved $400 million in recurring O&M expense, while improving operating outcomes and reducing enterprise risk. Our steel for fuel strategy delivered more than $4 billion in customer fuel-related savings since 2017. This discipline alongside support of state and federal policies enables us to reduce emissions and keep residential electric and natural gas bills 28% and 14% below the industry average and growth well below the rate of inflation. With our 11,000-plus employees commitment to serving customers, we’re $0.14 ahead of 2023 year-to-date earnings, and as a result, we are reaffirming our 2024 earnings guidance. During the quarter, continued our progress on our clean energy transition through multiple resource planning and RFP processes.

We issued an RFP for 1,600 megawatts of wind, solar, storage and hybrid resources in the Upper Midwest. These are due in September, we expect commission decisions in 2025. We now have active RFPs for over 4,000 megawatts of resources in the Upper Midwest . In Mexico and Texas, commissions approved 418 megawatts of company-owned solar generation that’s expected to be in service between 2026 and 2027. And last week, we issued an RFP and SPS seeking 3,100 megawatts of accredited capacity which could ultimately yield more than 5,000 megawatts of renewables and firm dispatchable generation. Bids are due in January of 2025, and we expect commission approval in 2026. Last quarter, I discussed a number of initiatives that Xcel Energy is taking to reduce wildfire risk.

I’m incredibly proud of what our team has been able to accomplish in a short amount of time. Since March, we’ve developed the capability to deliver enhanced daily wildfire safety operations across the enterprise as well as the ability to conduct proactive, public safety power shutoff as evidenced by recent events in Colorado, Texas and New Mexico during threatening conditions. We’ve accelerated pole inspections, including replacing priority 1 and priority 2 poles across our system. We’re expanding visual coverage with our Pano AI-enabled camera system to over 50,000 square miles in Colorado, enabling first responders access to critical information, including precision triangulation and fire locations. And we’ve accelerated deployment of Technosylva’s risk modeling system and expect it to have it operational enterprise-wide by the end of the year.

We recently filed an updated Colorado wildfire mitigation plan that integrates industry experience incorporates evolving risk assessment methodologies, adds new technology and expands the scope, pace and scale of our programs to reduce wildfire risk. The plan has four primary programs that include enhanced situational awareness, the improved meteorology, area risk mapping and modeling, artificial intelligence cameras and continuous monitoring. Operational mitigations that include enhanced power line safety settings and public safety, power shutoff capabilities, system resiliency through increased asset assessment and remediation, Pole replacements, line rebuilds, targeted undergrounding and vegetation management and improved coordination, technology and real-time data sharing with customers and other stakeholders as well as PSPS resiliency rebates.

We expect to file resiliency plans with SPS that will include wildfire mitigation later this year and are developing former wildfire mitigation plans for the rest of our states. Finally, we’re working with stakeholders at both the state and federal level on legislation to enhance the safety of our communities from evolving weather risks while protecting the financial integrity of companies that provide these essential services. Moving to economic development. We’re seeing a material shift in long-term electric demand on our system after several years of relatively flat sales growth. Our current five-year electric sales forecast assumes approximately 3% annual growth. Nearly half of that growth is driven by electrification of oil and natural gas production, electric vehicle adoption, and beneficial electrification, economic growth and increasing customer counts.

The remainder of that growth is driven by contracted and high-probability data center load, including previously announced deals of Meta and Microsoft in Minnesota and QTS in Colorado as well as others. We believe this forecast is now conservative, given a pipeline of data center requests totaling 6,700 megawatts by 2030. If all of the data center requests came to fruition, our data center sales CAGR would be over 9%. We continue working through the request and plan on updating our sales and capital investment forecast on the third quarter call. Xcel Energy is strategically positioned to secure economic data center load with high-quality partners due to our access low-cost renewable generation, the availability of water and fiber infrastructure, unencumbered land and our speed to market.

At the same time, we’ll continue to focus on the impacts to all customers, ensuring we have both economic contracts and system resources to provide safe, clean and reliable power to our communities. During the quarter, there were two regulatory outcomes that provide for cleaner and more resilient electric and natural gas distribution system, First, Colorado passed a bill that enables qualified electric utilities to make necessary distribution investments with timely recover to achieve state policy goals, including transportation and building electrification and enabling distributed energy resources. This was the result of extensive stakeholder process supported by the Colorado Energy office, our IBW labor partners, environmental advocates, NRDC and WRA as well as the Colorado Solar and Storage Association and others.

Second, the Colorado Commission approved the modified clean heat plant, which establishes a starting point for reducing greenhouse gas emissions from our natural gas distribution system. Full year budget of up to $441 million was approved, which sets funding primarily for beneficial electrification and natural gas efficiency. We look forward to working with the stakeholders and regulators to implement these initiatives to meet our long-term sustainability goals in Colorado. Finally, we recently released our 19th sustainability report. We’re proud of our history at Xcel Energy. And as we look forward, we’re committed to delivering the essential energy services our customers value and need while driving positive change that supports the environment and communities.

I’m deeply appreciative thankful for the commitment and hard work of our employees and partners to deliver a clean energy future. We remain relentless in our pursuit of our vision and will continue to deliver long-term value to shareholders an affordable, reliable and sustainable energy for the communities in which we live work. With that, I’ll turn it over to Brian.

Brian Van Abel: Thanks, Bob, and good morning, everyone. Starting with our financial results. Xcel Energy had earnings of $0.54 per share for the second quarter of 2024 compared to $0.52 per share in 2023. The most significant earnings drivers for the quarter included the following: revenues from electric rate cases and riders to recover capital investments combined to increase earnings by $0.26 per share. Higher AFUDC increased earnings by $0.04 per share, and revenues from natural gas rate cases increased earnings by $0.02 per share. Offsetting these positive drivers were higher depreciation and amortization decreased earnings by $0.18 per share, reflecting our capital investment programs. Higher interest charges decreased earnings by $0.07 per share.

Higher O&M expenses decreased earnings by $0.04 per share and other factors combined to reduce earnings by $0.01 per share. Turning to our sales discussion. Year-to-date weather and leap year adjusted electric sales decreased by 0.4% and natural gas sales increased by 0.4%. We’re updating our 2024 forecast to reflect a 1% increase for electric sales with expected increases in C&I load in the second half of the year. Longer term, we continue to see robust demand in our C&I sector, driven by data center loads in Minnesota and Colorado, along with oil natural gas electrification and SPS. During the quarter, we continued to make progress on a relatively light rate case calendar. In June, we reached an uncontested settlement in our Minnesota natural gas case, providing a $46 million rate increase based on a 9.6% ROE and a 52.5% equity ratio.

The final commission decision is expected by year-end. In our Colorado natural gas rate case, we received intervener testimony in July. There’s a settlement deadline at the end of August with hearing scheduled for September. We expect a commission decision in in the fourth quarter. And July, the Texas Commission approved our $13 million distribution rider request. This represents our first distribution rider requests in Texas, and we expect it will allow us to reduce the frequency of future rate cases. We also continue to make progress on the claims process for the Smokehouse Creek wildfire. We’ve received 141 claims, of which 43 have been settled, which we view as a positive and constructive outcome. 21 lawsuits have also been filed. In addition, there is no change to our estimate of our accrued liability of $215 million.

As a reminder, we have approximately $500 million of excess liability insurance coverage for the fire. Finally, we are reaffirming our 2024 earnings guidance range of $3.50 to $3.60 per share, which is consistent with our long-term EPS growth objective of 5% to 7%. In addition, we’ve updated key assumptions to reflect the latest information, which are detailed in our earnings release. With that, I’ll wrap up with a quick summary. We continue to expect to deliver 2024 earnings within our guidance range as we have for the past 19 years. We’re executing on our capital investment plan, including clean generation, transmission and distribution to support reliability and resiliency economic development to support our communities. We’re proactively enhancing our wildfire mitigation actions to manage the risk to our systems to protect our customers from extreme weather.

We remain confident we can deliver long-term earnings growth at or above the top end of our 5% to 7% range starting in 2025. This concludes our prepared remarks. Operator, we’ll now take questions.

Q&A Session

Operator: Thank you very much, sir. [Operator Instructions] Our first question is coming from Jeremy Tonet of JPMorgan. Please go ahead.

Jeremy Tonet: Hi. Good morning.

Bob Frenzel: Hey, good morning, Jeremy.

Jeremy Tonet: I just wanted to start off with the wildfires, if I could, and risk mitigation there. How do you think system risk stands now? How do you expect it to, I guess, improve over time with the wildfire mitigation plan, is were kind of even across the system? Or are there certain parts in focus? And then finally, it seems like there’s some fires in Colorado right now. Just wondering if any of your equipment was involved in any way?

Bob Frenzel: Yes, I appreciate the question. Look, as I said in my prepared remarks, I’m really proud of what we’re going to accomplish on the operational side to provide the real-time risk reduction that we need today to give us the time to make the necessary enhancements and system resiliency and hardening for our system over time. Clearly, we’re further ahead in Colorado. We just filed our second wildfire mitigation plan, and we’ve been working on the first one for over four years. But that shouldn’t be taken as anything other than a huge focus that we also have in Texas and in Mexico around our plans there. Our capability to do wildfire safety operations and PSPS exists on a daily basis across the entire enterprise, which drives real-time risk reduction.

We’re benefited as a company by all the hard work of the people that have come in front of us in California. We expect to dramatically reduce our wildfire risk based on their experiences and doing some of the lessons learned from all of those organizations. They’ve been more than accommodating and helping us and others across the country. And clearly, the need is there and evidence, we think there’s a real supportive backdrop in our states to help us pursue these necessary investments to continue to risk reduce our business.

Brian Van Abel: And Jeremy, this is Brian. Good morning. Just on the second part of your question about the current fires in Colorado, our assets were more than a mile away from any of those believed ignition points.

Jeremy Tonet: Got it. That’s all very helpful. Thank you for that. And then I just wanted to pivot here a little bit to the data center opportunity, as you outlined there, it seems like the opportunities are accelerating from when you discussed it with the market. Just wondering if you could frame that a bit more what you’re seeing and where across your footprint that’s happening? And just any more color would be helpful.

Bob Frenzel: Yes, Jeremy, Bob again. Look, we’re really excited about what we’re seeing. Obviously, we believe we have a very attractive service territory across all 8 of our states for different reasons in all of them. But when we speak with hyperscalers and other data center developers, we have what they’re looking for low-cost clean energy, access to fiber access to water and other infrastructure, human capital, land that makes us attractive. Right now, we’re seeing most of opportunities materialize in the Minnesota and Colorado footprint, but our deeper backlog, I would say, is across all of our service territories in all of our states.

Brian Van Abel: Yes, Jeremy, I can just expand on that a little bit. If you could pop the slide that we put in our earnings release today, which is updated from the data center slide that we had a couple of months ago. You can see it’s a significant increase in the customer requests. As Bob said, the biggest opportunity was in Minnesota, now it’s growing. We’re seeing significant opportunity in Colorado now and even expanding outside of Minnesota and Wisconsin and South Dakota. And so we’re working closely internally with our economic development team. We think about it as we’re updating our long-term sales forecast right now, which will roll out in Q3. Our long-term sales forecast right now is in the 2% to 3% range. I would expect that to look more like the 4% to 5% range and our base long-term sales forecast when we roll that out as we incorporate some of these high probability loads into our five-year guidance.

Just another good example about how we look to proactively work with our commissions. The Minnesota commission here in Minnesota has publicly stated, they didn’t have planning sessions around how do we accommodate and meet this both economic development opportunity for our communities and also, how do we provide benefit to all of our current customers and create more opportunity for investment.

Bob Frenzel: And Jeremy, I think this is part of a much broader theme that I’ve been talking about as it pertains to our company. If you put those criteria that data centers are looking at today, I would suggest that’s true for almost any energy-intensive industry and our view that they’re at some point going to overly co-locate in parts of the country where energy costs are lower and green energy could be cleaner, and that sits right across the footprint that we straddle. And so, as you look at stuff like hydrogen and clean energy production, if we get to direct their capture as a means of carbon mitigation, you could see a lot of that headquarter in itself or locating itself in our backyard as well as other manufacturing probably where transportation isn’t as critical. I think all of those are economic development opportunities that are not in our forecast but areas that we think should beneficially accrue to the parts of the country that we serve.

Jeremy Tonet: Got it. Great to hear. Big numbers there. Congrats. I’ll leave it there. Thanks.

Operator: Thanks very much for your questions, sir.

Bob Frenzel: Thank you.

Operator: We’ll move to Carly Davenport of Goldman Sachs. Please go ahead.

Carly Davenport: Hey. Good morning. Thanks so much for taking my questions.

Bob Frenzel: Hey. Good morning, Carly.

Carly Davenport: Good morning. Wanted to just follow-up on a couple of Jeremy’s questions there. Maybe just first on the wildfire front, is there any sort of feedback from stakeholders, you can share so far on the wildfire mitigation plan you filed in Colorado? And then you had mentioned plans to file additional wildfire mitigation or system resiliency plans in other states. Can you just talk about what forms that might take and where you’re most focused in the near-term?

Brian Van Abel: Yes. Hey Carly, this is Brian. It’s now early in the process in the wildfire mitigation plan filing in Colorado. We’re just starting to see some discovery requests. But overall, we think about the work and the scope we’re getting from, call it, the first few responders and the community has been positive. Our investment in the Pano AI cameras is already — there’s been some recent articles where has helped identify fires not started by the utility, but helped work very proactively with the first responders to get them out and mitigate fire risk and protect our communities and our customers. So, I think overall, it has been supportive. But again, like I said, early in the process. Kind of the next kind of pivoting to your second part of the question, is we’re focusing on right now is developing our system resiliency plan in Texas, which is what will incorporate our wildfire mitigation plan.

So that will be later this year and look for a similar filing in New Mexico later this year, too, and then working through what it will look like in Minnesota in the Midwest for wildfire mitigation plans. We can incorporate a lot of the wildfire mitigation plan into our multiyear rate case in Minnesota as we think about which we’ll file in November of this year.

Carly Davenport: Great. That’s really helpful. Thank you for that. And then the second one is just on the load growth in the data center piece. Could you just talk a little bit about your process for working down the request into the pipeline? Or I guess, said another way, what is sort of your bar for including load in that near-term pipeline estimate, which goes into your broader load growth estimate?

Brian Van Abel: Yes. So, if you think — I’ll give you a little bit of color. We kind of highlighted on that slide in our earnings deck is one. We have a contract with them, for example, QTS and Meta that’s included in our five-year forecast. And then we have something called near-term pipeline which, for example, maybe we’ve sold a parcel of land to them. And what we consider is 80% probability. So very high probability that it’s going to come into our sales forecast within the next five years. And this is working very closely with our operating companies and our economic development team with these customers. And then everything above that, we do not have in our sales forecast. So there’s a huge opportunity above what we call 80% high probability load.

And so that’s a little bit of color. So, as we continue to kind of march through time, you think some of the stuff that we don’t view as 80% probability today becomes more of an opportunity and we drop into that what we included in our base forecast.

Carly Davenport: Got it. Okay. Thank you so much for the time.

Operator: Our next question today will be coming from Julien Dumoulin-Smith of Jefferies. Please go ahead.

Julien Dumoulin-Smith: Hey, good morning, team. Thanks guys very much. Good to chat again.

Brian Van Abel: Hey, Julien congratulations, I heard you proud papa these days.

Julien Dumoulin-Smith: Thank you. Appreciate that. Absolutely. Guys Nicely done here. I got to say, lots on that pipeline. Maybe to pick up where Carly lifted off here on just kind of probability weighting here. How do you think about that filtering through your processes? For instance, I know you didn’t emphasize as much the relative load growth of the SPS, for instance, in the context of data centers. But how do you think about even the numbers that you guys were throwing out there of the 5 gigawatt number getting updated here sort of pro forma for that process that you’re working through right now? Effectively, as you probability weight and update with 4Q, how does that filter into the processes you already have in flight for procurement given what seems like a perhaps more pressing need to address the RFPs that would need to be necessary?

Bob Frenzel: Yes. Thanks, Julien, so I’ll start and then Brian can add on. I think you know the company pretty well we’ve generally taken a pretty conservative approach to forecasting whether it was capital investment opportunities in this case, sales opportunities. Our process is alive and well right now and is geared towards a comprehensive update in the third quarter earnings call. And so we’d expect for, as Brian walked through the sales funnel on Carly’s question and then the update on our capital forecast, whether that’s the RFP results coming into our forecast whether that’s new sales or whether that’s capital needs driven by our wildfire mitigation plans, our needs to serve customers to the extent that we see high probability load growth that needs investment as well as all of our resiliency and reliability plans as we roll forward in time.

So expect something at the end of the third quarter into the fourth quarter from us on a fulsome enterprise-wide look at all the parameters.

Brian Van Abel: Julien, just let me add to that a little bit. If we think about all the RFPs we have in flight, for example, Minnesota. We have multiple RFPs in flight while we’re looking at this potential new load that’s rapidly evolving. So we have that opportunity as we go through these RFPs and we’re in a resource plan filing with the Minnesota Commission, which we provided kind of what call a base view, but also in electrification in a high load view. So we have processes in flight that helps us move quickly on the staff and secure resources and work with our stakeholders, similar in SPS. We just followed an RFP for over 3,000 megawatts of accredited capacity. Now that was based on our resource plan in New Mexico that had a base plan, but also a high electrification plan working with all of our oil and gas customers.

And that’s why you see us talking about this 5,000 to 10,000 megawatt nameplate capacity range in SPS because we see that load up there, we’re working with our oil and gas customers. So SPS is much more of an electrification in the oil and gas industry. Down there, we’re in Colorado, Minnesota, in the Midwest is much more of a potential data center opportunity.

Julien Dumoulin-Smith: Excellent, guys. Thank you. And then maybe on the other side of this, nicely done in Colorado on some of this legislative effort here. How do you think about the time line and implementation of that legislation just given the sub 8% earned ROE on a trailing basis, how do you think about that improving said number of 50 basis points or what have you from the legislation here over time?

Brian Van Abel: Julien, and maybe I’ll just take a step back and just say this is a really good piece of legislation now supported by a broad coalition of stakeholders. As we think about it, it’s really, kind of, how do we help advance state policy around beneficial expectation, whether that’s electrification of the transport sector, electrification of home heating and so worked with a very broad group of stakeholders to get support and passage of this legislation. As I think about it, there is a distribution system plan that we’ll file in November in Colorado, which is really kind of the basis of this legislation and think of it almost a resource plan for the distribution system above their capacity investments we need to make and how do we think about the different levels of penetration and how it accelerated some of this can be.

And so we’ll file that in November, work through that. And so there’s a — the full rider will be implemented in 2026 around the investments needed to kind of drive our distribution system forward. And now when we think about from an earned ROE perspective, we’ve earned about 8% approximately Colorado over the past few years. So this will really help us drive a significant closure of that gap as we think about it as we go through kind of like I said, 2026 when it’s fully implemented. But we also have other investments in Colorado as we think about the renewable investments we’re making and the transition investments that we’re making to help drive state policy and achieve our decarbonization goals of the state that could concur recovery too.

And so as those investments ramp up, that will help close that gap too.

Julien Dumoulin-Smith: Awesome. Nicely done guys. Perfectly.

Operator: Thanks for your question, sir. We’ll now move to Sophie Karp calling from KeyBanc. Please go ahead, ma’am. Your line is open.

Sophie Karp: Hi. Good morning. Thank you for taking my question. I have a question on the — going back to the data centers trend. So I guess is there a point at which this incremental loan growth and the acceleration of sales trends translates into the earnings growth at what point would you be comfortable sort of making that leap?

Brian Van Abel: Yes. Sophie, as I think about it, right? I mean, I think about this data center opportunity in two ways. One is really getting the contracts right and having the data centers — having — adding new data centers provide benefit to all of our customers on the system. And that’s really important to demonstrate benefit going to the commission with the contract that demonstrates benefit to our current customers. Now longer term, absolutely, there’s an investment opportunity or investment need here to support these customers. These are large loads. And so as I think about it, we’re moving through the planning process right now, both from, as I talk about a sales forecast perspective and the high probability loads and how did that translate into our capital forecast. So I expect a broader update from us bolt-on that 5-year capital plan and the sales forecast plan in Q3, and that should help address your question.

Sophie Karp: Got it. Got it. Thank you. And then a more higher level question. With all this new load coming in, and I’m not sure if load is going to be interruptible or not interruptible. But do you see the need for, I guess, more gas-fired generation on your grade anytime soon and how receptive do you think the regulators would be to those types of generation additions? Thank you.

Bob Frenzel : Hey, Sophie, it’s Bob. So look, I think that — great questions. We sit in a resource rich area for wind and solar. We see increasing needs for storage resources. But as evidenced by our most recent and our resource plans, we do have incremental combustion turbines that serve to back up and serve our customers to make sure that we have reliability when the wind or the sun or the storage is unavailable. So in our most recent ERPs in Colorado, our recent resource plan up here in the upper Midwest, we have incremental CTs coming back. And I think with increased load like of the magnitude we’re talking about, we would actually see increased numbers of backup generation, almost as an insurance policy for our networks to make sure that we have reliable and affordable energy for all.

Sophie Karp: But no plans to add CCGTs from now?

Bob Frenzel : I’m sorry, can you say that again?

Sophie Karp: No plans to add CCGTs, combined cycle?

Bob Frenzel : No. At this point, we don’t have any plans today to add any combined cycles to our network. But I mean, we have to evaluate the probability of real load and what the resource availability is to serve it. So not today, but I wouldn’t say that anything is off the table.

Sophie Karp: Got it. thanks so much.

Operator: Thank you. We’ll now take questions from Greg Oro [ph] calling from UBS. Please go ahead.

Unidentified Analyst: Hi. Thanks very much. Just regarding — the you’re working your way through the Smokehouse fire settlements. And just kind of how are you thinking about whether — how those are going in terms of — are there any groups that are precedential? How do you think about kind of resolving that and moving forward, sort of timing and process?

Brian Van Abel : Hey, Greg, I can provide some color on that. So 141 claims settled, and we’re moving expeditiously through those and have already reached settlement on 43 of those claims. And so how I look at it, these claims have spanned, call it, a variety items, everything from homes to agriculture buildings, to fencing cattle, feed, personal property. So it gives us a pretty good data point while so — well, 43 settled is not all encompassing, but it is a good data point. And I think the important point as we think about it, reassess our liability of $250 million and the claims so far support and help validate our accrual. Another data point, the report that received in Q2 was from the Texas A&M Agralife extension. And that report covered — it was an economic estimate of the agricultural losses from the entire complex of fires down there.

And that report for a value of $123 million agriculture losses. And that report included some very large buckets, cattle, feed, agricultural structures. And so when we look at that report, and that number and what we’ve included for our accrual, it does support our assumptions. And so that’s the latest information we have through Q2, and we’ll continue to try updates as we move through time.

Unidentified Analyst: Helpful. Thanks.

Operator: Thank you. Our next question will be coming from Nick Campanella calling from Barclays. Please go ahead.

Nick Campanella: Hey good morning everyone. I hopped on late, so hopefully I’m not repeating others, but just first, just as you’re progressing through Colorado gas, what’s the ability to settle this in your mind at this point? Is that something that you’re open to? Or is this taking a fully litigated pass? And then I just have one follow-up. Thank you.

Brian Van Abel: Yes. Nick, yes, we sort of received intervenor testimony relatively recently. We have a settlement deadline of August 27. And we certainly look forward to working with our stakeholders with interveners to attempt to reach a settlement. So, we’ve reached settlement in the past few cases in Colorado, so we’re hopeful that we can reach this settlement, also ready to go through the fully litigated process if we need to, that’d be hearings in middle September and this CPUC decision by the end of the year.

Nick Campanella: That’s great. I appreciate it. And then I guess if I could just ask on the financing quickly. I know you priced a little bit of ATM in the quarter. Is ATM the primary vehicle to use here for the rest of the year in terms of your equity needs?

Brian Van Abel: Yes. I mean the ATM will be our primary vehicle. It doesn’t mean we wouldn’t be opportunistic if there’s a potential block. We’ll also look at some of the other equity content products as we go through the time. But overall, ATM is our plan. But also I look at where our CFO to debt is at 17%, right. Now we have flexibility, given we have strong credit metrics, and that’s why maintain a strong balance sheet as we have flexibility in terms of when we can look at issuing equity.

Nick Campanella: Great. Thanks a lot.

Operator: Thank you, very much. Mr. Campanella. We’ll now go to Travis Miller calling from Morningstar. Please go ahead.

Travis Miller: Good morning. Thank you. I wonder if there was any update on timing or plans for a Minnesota electric rate case and then tied to that, any lessons learned or takeaways from the settlement in gas case that could be applied to any timing or requests on the electric side.

Brian Van Abel: Travis. Yes, we’re looking — we’re planning on November 1 filing for sort of a multiyear plan on the electric side. If you remember, we’re in year 3 of our multiyear plan right now. So we’ve communicated that. As we think about the gas side, no, we always look to see if we’re going to reach a constructive settlement with the parties, and we’ve been able to on the gas side. So I think that’s a good data point as we think about it. So early days given that we haven’t made the filing yet, but I think November 1 filing, it’s longer process in Minnesota. But once we get through kind of the intervenor direct testimony or robotic testimony, we’ll certainly look to see if there’s an opportunity to settle.

Travis Miller: Great. Okay. Thanks. And then back to the data center, that 6,700 or however much it ends up being in terms of requests and potential, how sensitive is that number to regulatory proceedings, whether it’s the planning process that what you’re talking about was going on in Minnesota, whether it’s rig cases, RFPs, how much sensitivity is that to just all regulatory proceedings?

Bob Frenzel: Hey Travis, it’s Bob. Look, when I think about the opportunity here that’s in front of us, our obligation is the company is to make sure that we were able to serve current customers as well as our future customers and make sure that everyone is treated economically and fairly. I’ll be honest, we don’t have — we’re 21, 22 gigawatt peak load system today. We don’t have 6,000 megawatts of capacity available today. We have some, but we would need to, as part of our existing RFPs and resource plans to add more generation to the stack. So that would take a resource planning process and a regulatory process. I think we’ve proven over the last seven or eight years, our ability to do that and do that with efficiency to make sure that we can address the expanding needs of our customers and states.

So we will need generation over time. But I think we have plans and processes that are in place that allow us to speed the market to address the needs that our new customers might need today, as well as the growth that they forecast through the end of the decade.

Travis Miller: Okay, great. And then just real quick, transmission distribution capacity. You talked about generation capacity, is there enough T&D? Or would that also be a constraint?

Bob Frenzel: So largely, these customers are largely transmission customers, so we’ll talk transmission grid needs. And we’ve got, again, some capacity on the grid today to meet their needs today. In all of our jurisdictions, we’re expanding our transition pretty aggressively, whether it’s through the MISO LRTP processes, up here in the upper US and what’s been approved and what’s on the comment [ph], as well as the Power pathway in Colorado and other transmission proceedings in [indiscernible], and then our work in SPS with the Southwest Power Pool to build more transmission down there. So I think we’ve got transmission in flight. Again, the capacity today is available, but not the full extent of the 6,700. So our goal is to make sure the transmission generation needs are ramped according to what becomes our high probability customer needs.

Travis Miller: Got it. Okay. Thanks so much. Appreciate it.

Operator: Thank you for the questions Mr. Miller. Our next question will be coming from Ryan Levine calling from Citi. Please go ahead.

Ryan Levine: Good morning. Any color you could share around rate design for the data center opportunity? In an earlier answer, you mentioned economic development opportunity, does that signal a certain rate structure for this customer class? And on a similar vein, what role do you see VPPs impacting the ability of Xcel services, data center load in Colorado and more broadly across your service territories?

Brian Van Abel: Ryan, you broke up on the second part of your question, but first part of the question seemed like it was around the rate design as we think about these data center loads. So far, we’ve approached that on a contract-by-contract basis, and so it can be unique. But the principle is that we need to make sure that the revenue that we receive from these data centers covers more than the incremental cost that comes to our system. So what I mean simply is that our current customers are not harmed by adding these. And whether that means you have a provision in the contract, that’s a ratchet if they don’t deliver on the load they said they’re going to deliver or a take-or-pay type contract. So these are fluid conversations, but the principle is that we need to bring something to our commission that is in the best interest of our current customers.

And if you wouldn’t — I couldn’t catch up. You broke a little bit on the second part of your question, so if you could repeat it, it would be helpful.

Ryan Levine: Sure. What role do you see VPPs impacting the ability of Xcel to service this data center load in Colorado and across your service territories?

Brian Van Abel: Look, I mean I think VPPs can almost be another demand-side management tool as we think about it. So we think there could be a role there. I didn’t know that was part of our distribution legislation in Colorado to do some planning and study work around VPPs. So I absolutely think they can play a role in the future. Just like if you think about some of this potential large load, could you have it on an interruptible load uncertainty period. So I think there’s a lot of opportunity, as you think about the overall umbrella of more demand side management tools to address in sort of this significant loan growth that we see in our future.

Bob Frenzel: And Ryan, today, we have almost 10% of our peak load in Colorado is available for demand management tools already. And so we’ll continue to work with commission and providers as Brian said, with the distribution bill that was just passed to Colorado. So there’s an opportunity here, but we do have a very full demand response program already in existence in Colorado.

Ryan Levine: Thank you. And then, do you have a way of quantifying what percentage of historical Wildfire risk has been reduced or will be reduced by the implementation of the current WMP? And how do you see this risk evolving in the coming years?

Bob Frenzel: I don’t think we’ve got a quantitative number for you today, but as I made in my prepared remarks. As I think about the operational mitigations that we put place, dramatically reduce real-time Wildfire risk in our business. We do this on a daily basis, enterprise-wide, and that affords us the time to go in and then do some of the situational awareness and some hardening and enhanced operational things that we want to do in our system. Today, the tools we have are pretty Blood Tools we’d like to get to more surgical use of those tools overtime. And that’s a big piece of what our Wildfire Mitigation plans to is just use the operational tools we got today, make them more surgical so they’re less customer impactful overtime.

Brian Van Abel: Yeah. And Ryan, if you run our wildfire mitigation plan in Colorado, we say that the WMP investments and plan will reduce our risk similar to that of what we see in the leading utilities in this space.

Ryan Levine: Thank you for the time.

Operator: Thank you, sir. We do not have any further questions at this time. I’ll turn the call back to CFO, Brian Van Abel, for closing remarks. Thank you.

Brian 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 very much, sir. Ladies and gentlemen, that concludes today’s conference. We wish everyone a good day. And you may now disconnect.