Operator: Hello, and welcome to Xcel Energy’s Second Quarter 2023 Earnings Conference Call. My name is Melissa, and I will be your coordinator for today’s event. Please note, this conference is being recorded and for the duration of the call, your lines will be listen-only. [Operator Instructions]. Questions will only be taken from institutional investors, reporters can contact Media Relations with inquiries and individual investors and others can reach out to Investor Relations. I will now hand you over to your host, Paul Johnson, Vice President, Treasurer and Investor Relations to begin today’s conference. Thank you.

Paul Johnson: Good morning, and welcome Xcel Energy’s 2023 Second 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 2023 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 of the 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 our 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. And with that, I’ll turn it over to Bob Frenzel.

Robert Frenzel: Thanks, Paul, and good morning, everybody. Let’s start with our results. We faced some headwinds from weather and other items in the second quarter, recording earnings of $0.52 per share for the second quarter of 2023 as compared to $0.60 per share in 2022. We’ve got tangible plans in place for the second half of the year to overcome the inflationary pressures as well as the impact of the lower-than-expected ROE in the Minnesota electric rate case and allow us to deliver on our 2023 guidance. But our strategic priorities are unchanged. Leading the clean energy transition, enhancing our customers’ experience and keeping our customers’ bills low. And we’ve delivered on this strategic vision across our eight states for the past decade.

We invest in clean energy resources that provide both financial cost savings to our customers while transitioning to a lower carbon economy. We invest in network infrastructure to foster economic development for new businesses to provide top quartile reliability and to provide resiliency in the face of more volatile and unpredictable weather. We’re also building infrastructure to accelerate clean transportation for all of our customers and exploring innovative technologies like batteries and clean fuels to enable the policy objectives and the customer desires for a lower carbon economy, and we focused on continuous improvement to operate efficiently with a lower expense burden to our customers. And as a result, we’ve been able to keep our operating expenses nearly flat for over the past — for over a decade.

Our customers benefit from these actions, including significant carbon reductions and residential bills that are 20% below the national average. As you can see, we have a long history of delivering on our commitments to all of our stakeholders and are confident in our ability to meet our earnings guidance again in 2023. This quarter, we made progress on our clean energy transition plans with a growing portfolio of both company-owned resources and power purchase agreements. In our NSP solicitation, we recommended an incremental 250 megawatts of self-build solar generation in a 100-megawatt power purchase agreement. This brings our total company-owned solar projects at Sherco to over 700 megawatts which will utilize the transmission rights for the first of the three retiring coal units there.

In the SPS RFP, we recommended a portfolio of 418 megawatts and self-build solar projects and a 230-megawatt power purchase agreement. We’re also proposing a battery storage project to one of the new self-build solar facilities. In addition, later in the quarter, we expect to file our recommended Colorado portfolio for nearly 4,000 megawatts of potential resources. And based on our interim analysis, the outcomes should be very beneficial to our customers. Across our eight-state footprint, we enjoy a geographic advantage for wind and solar resources, which enables higher capacity factors. And as a result, Xcel Energy can deliver new renewables at low and competitive prices due to a combination of high capacity factors, IRA tax benefits and the ability to reuse transmission from retiring plants, all of which provides significant benefits to our customers.

enables a faster transition to a clean energy economy. Each of these RFPs would represent incremental opportunities as compared to our base capital forecast. We anticipate commission decisions on these proceedings in the second half of 2023 for Minnesota and Colorado, and in the first half of 2024 for SPS. In May, Breakthrough Energy Ventures announced a $20 million grant to support our two 10-megawatt pilot projects for Form Energy’s 100-hour battery technology. In July, the Minnesota Commission unanimously approved the Form Energy pilot to be installed at our Sherco site alongside our new solar projects. We plan on filing for our second Form Energy pilot later in the quarter and are evaluating sites that could be supportive of this exciting new clean energy technology.

We’re also working with the Department of Energy and additional funding opportunities to further reduce the cost of these projects for our customers. In May, we filed our second transportation electrification plan in Colorado, the proposed plan, which covers the 2024 to 2026 period includes expanded solutions and rebates to support new public charging stations and charging at homes, businesses, multifamily buildings and community locations. It also proposes programs supporting electric school buses, innovation and income qualified customers. Our focus is to bring clean transportation to all customers and communities and to expeditiously assist in the build-out of quarter charging to reduce range anxiety of EZ purchasers. Next month, we plan to file our Clean Heat plant in Colorado and will follow with our natural gas innovation plan for Minnesota during the fourth quarter.

These plans will be similar to our electric resource plans and provide a framework for our natural gas system to achieve our carbon reduction goals while meeting the reliability and affordability needs of our customers. Taken as a whole, these innovative projects and partnerships in electricity and clean transportation and home heating are essential for Xcel Energy to meet our sustainability goals and to continue to deliver our customers the safe, clean, reliable and affordable energy that they expect now and long into the future. In June, the Boulder County Sheriff office announced the findings of its investigation into the cause of the Marshall Fire in December of 2021. Our thoughts continue to be with the families and the communities impacted by this devastating fire, including our own employees whose homes and families were directly affected.

The report states that the first Marshall Fire started as a result of an ignition on a property affiliated with an entity called the Twelve Tribes and that this ignition had nothing to do with Xcel Energy’s power lines. The Sheriff’s report also discusses a second ignition that started more than an hour after the first fire at a different location, which the report estimates is approximately 80 to 110 feet away from our power lines. Sheriff’s report says that the most probable cause of the second ignition was PSCo’s power lines, and we strongly disagree with that conclusion. Because of the pending litigation has been filed, we’re not in a position to discuss the Marshall fire in more detail at this time, but we will vigorously defend ourselves and look forward to presenting our position in court.

Importantly, additional information about the lawsuits and some of the relevant legal standards is included in our earnings release and our 10-Q filing, and I would direct you there. Finally, we recently released our comprehensive sustainability report. The report focuses on four core ESG pillars: Reach Net Zero responsibly; strengthen our communities; operate with integrity and to value people. It details our progress in achieving our industry-leading ESG goals as well as our priorities moving forward. Some of the key highlights include Xcel Energy has reduced our carbon emissions by 53% since 2005. And more than half of the electricity we provide to our customers comes from carbon-free resources as compared to 41% nationwide. We outperformed the industry reliability standard restoring power to 94% of customers within 24 hours during major storm events.

In this past year, in addition to contributing over $10 million to local organizations through the Xcel Energy Foundation, our employees contributed $3 million and volunteered over 74,000 hours for nonprofit and community improvement projects. We’re proud of our track record. It’s keeping with our corporate strategy, and it’s based on our values of connected, committed, trustworthy and safe. With that, I’ll turn it over to Brian.

Brian Van Abel: Thanks, Bob, and good morning, everyone. We had earnings of $0.52 per share for the second quarter of 2023 compared to $0.60 per share in 2022. Please note that the line-by-line income statement comparisons are more complicated this quarter as a result of true-ups for the Minnesota rate case this year and the Texas rate case last year. Most significant earnings drivers for the quarter included the following: Lower depreciation and amortization expense increased earnings by $0.10 per share, largely due to the reversal of deferrals in the Texas rate case last year and the extension of depreciation lives from the Minnesota rate case. These decreases are partially offset by our capital investment program. Lower taxes other than income taxes increased earnings by $0.06 per share, reflecting property tax deferrals in Minnesota and Colorado.

In addition, other items combined to increase earnings by $0.04 per share. Offsetting these positive drivers, lower electric revenues less fuel decreased earnings by $0.23 per share, reflecting unfavorable weather, the impact of the Minnesota rate case and recognition of revenue from the Texas rate case last year. Higher O&M expense decreased earnings by $0.02 per share and higher interest expense decreased earnings by $0.03 per share. Turning to sales. Year-to-date weather-adjusted electric sales increased by 0.6%. We continue to expect annual electric sales growth of approximately 1% in 2023, which is driven by growth in C&I sales, partially offset by projected declines in residential sales. Now shifting to the expenses. O&M expenses increased $14 million for the second quarter.

This increase was primarily due to the timing of generation outages, higher bad debt expense, insurance costs and inflation, partially offset by the recognition of previously deferred costs from the Texas electric rate case in 2022. Given these drivers as well as the Minnesota rate case decision, we are taking actions to mitigate O&M, which will include evaluating discretionary programs, staffing levels, consulting, employee expenses, variable compensation and other management actions. As a result, we now expect O&M expenses to decline 3% for the year. During the second quarter, we also made progress on several regulatory proceedings. Starting with our completed proceedings. In June, Minnesota Commission approved a three-year electric rate increase of $311 million based on an ROE of 9.25%, an equity ratio of 52.5% in a forward test year.

We plan to file for reconsideration of the decision as we felt the ROE was not consistent with the ALJ recommendation or recent commission decisions in other Minnesota proceedings. In our South Dakota electric rate case, the commission approved a settlement for approximately $14 million revenue increase. In our pending Colorado Electric rate case, we reached a partial settlement that reflects a $95 million rate increase based on an ROE of 9.3%, an equity ratio of 55.7%, and a 2022 historic test year. Remaining items for litigation are the structure of the TCA rider and treatment of depreciation. We expect the commission decision later this summer with rates going into effect in September. In our New Mexico electric rate case, we reached a contested settlement that reflects a rate increase of $33 million based on an ROE of 9.5%, equity ratio of 54.7% in the forecast test year.

We expect the decision and implementation of final rates by October. Both the Colorado and New Mexico settlements reflect significant negotiation and compromise by Xcel Energy and a wide range of interveners with varied interests. The parties believe that the settlements resulted in a just and reasonable outcome for our customers. As a result, we are hopeful our commissions will approve the settlements without modifications. We also have pending rate cases in Wisconsin and Texas which are early in the process. Intervener testimony is expected in the Texas case in August, with a decision in the first quarter of next year, while in Wisconsin we expect intervener testimony in the Fall and a commission decision by year-end. Turning to the Inflation Reduction Act.

As most of you are aware, the U.S. Treasury recently provided guidance on tax credit transferability, which was consistent with our expectations. We have considerable demand and anticipate monetizing excess tax credits later in the year. Finally, we are reaffirming our 2023 earnings guidance range of $3.30 to $3.40 per share, which is consistent with our long-term EPS growth objective of 5% to 7%. We’ve updated our key assumptions to reflect the latest information, which are detailed in our earnings release. Please note that the guidance assumption changes regarding capital riders, depreciation, property taxes and ETR primarily reflect regulatory decisions or changes to assumed PTC levels and are largely earnings neutral. However, the lower O&M and a portion of the interest expense assumptions will generally impact earnings.

With that, I’ll wrap up with a quick summary. We continue to expect to deliver 2023 earnings within our guidance range as we have for the past 18 years, managing through regulatory outcomes, changing economic environments, and periodic headwinds. We’re delivering on our capital plan and executing on opportunities including clean generation, transmission and distribution to support reliability, resiliency, and broader economic growth. And we remain confident we can continue to deliver long-term earnings and dividend growth within the upper half of our 5% to 7% objective range as we support our communities and states in the clean energy transition. This concludes our prepared remarks further. Operator, we will now take questions.

Operator: [Operator Instructions]. And our first question comes from Jeremy Tonet from JPMorgan. Please go ahead.

Jeremy Tonet: Hi, good morning.

Robert Frenzel: Hey, good morning, Jeremy. How are you?

Jeremy Tonet: Good, good. Thanks for having me. Just wanted to touch base with a bit on the targeted O&M reductions as you called out there for these efficiencies in 2023. I was wondering if you could peel back the onion a little bit more to see how much of this is one-time in nature versus carry forward into future years? Just any thoughts there would be helpful.

Brian Van Abel: Sure. Hey, good morning, Jeremy and thanks for the question. So I think I’ll hit on it a couple of different ways. Talk about kind of the near-term actions and we think about it. How do we hit our year-end O&M guidance? One is we look at second half of last year we had elevated O&M, if you look at versus the first half of last year, and particularly in Q4 as there was some one-time items in Q4 relative to having a good year, investing in the system. And then there are some impacts this year where we’ve had some timing of generation outages earlier in this year. And we also expect bad debt expense to decline. We saw some higher bad debt expense levels given the commodity price impacts earlier in this year. So as I think about that, bad debt expense level should be more sustainable.

You have some timing and generation outages, but then we’re also looking at a number of what I call it near-term and long-term opportunities. Near-term is what you’d call more one-time discretionary items around program spend, consulting, third-party contracts and variable compensation levers, more traditional management initiatives. But I think we’re spending a lot of time on longer-term initiatives around our Innovation and Transformation team. We’ve invested heavily in driving what we call waste elimination and process improvements across our orgs. And then we’re also investing heavily in technology. You heard me, I’ve talked about before something we call the Digital Operations Factory, which is focused on using AI in our operations. We started that in nuclear with our Corrective Action program.

Now we’re rolling that out to distribution and gas in our field operations and that’s using traditional AI. We’re also looking at now use cases for Gen AI. So as we look at it, our goal is to hit 3% down for the year. Longer term, our goal is to kind of keep O&M flat. And as Bob said, we’ve done that for nearly a decade and so we have some work to do to get there a balance of a year, but then think longer term O&M flat as we go forward.

Jeremy Tonet: Got it. That’s very comprehensive, very helpful there. And so that kind of touches on, I guess, the next question I had is just with regards to, will the Minnesota order, if and it caused you revisit any embedded assumptions over the remainder of your five year plan at this point, and has these kind of O&M items, as you called out, adjusted for that?

Brian Van Abel: No, I don’t think it does. I think about our long-term assumptions and our long-term 5% to 10% earnings growth rate. We continue to expected to leverage on upper half of that long-term guidance.

Jeremy Tonet: Got it. And then just at a higher level, if I could, given the growth of wildfire risk, has your mitigation strategy, I guess, evolved over time or do you have any other thoughts on that side?

Robert Frenzel: Hey, Jeremy, it’s Bob. I appreciate the question. As you know, we’ve been operating under — in Colorado under a Wildfire Mitigation Plan that was instituted probably more than three years ago. And that plan is due to be refreshed in Colorado at the end of this year. And we expect to propose continuation of existing programs and new programs in Colorado that understand the volatility of weather in the west and the footprint of the Colorado company in particular. So we’re still working through that. Nothing specific right now, but certainly looking at everything that we can in terms of the risk and the opportunities to strengthen our own system and make sure that we protect our communities and our customers.

Jeremy Tonet: Got it. Just one last one, if I could, post what we’ve seen in Minnesota here so far. Does your view of the relative attractiveness of Minnesota versus Xcel’s wider footprint change in anyway.

Robert Frenzel: Look I think, as I said in my opening remarks, we feel like we’ve run a really good utility in Minnesota and across our eight states, focusing on our customers and our communities and helping our states achieve their policy objectives around clean energy and clean transportation. And the outcome, I’ll say, was disappointing for two reasons. Paul and Brian mentioned one, which was — it was inconsistent with previous decisions in Minnesota that have been 94 to 965. But equally important, probably didn’t recognize what I think Xcel Energy is a national leading utility in advancing a lot of these initiatives. Making sure we do it reliably and affordably and sustainably. We’ll continue to review our investment opportunities and our programs in the state, but I think generally really confident that this is our headquarters state. We want to work proactively with the Governor and the legislature and the PUC to advance these initiatives.

Jeremy Tonet: Got it. That’s very helpful. I’ll leave it there. Thanks.

Operator: Thank you. Our next question comes from Durgesh Chopra of Evercore. Please go ahead.

Durgesh Chopra: Hey, good morning, team. Sorry, I was on mute.

Brian Van Abel: Hey, Durgesh.

Robert Frenzel: Three years later, we’re still getting caught by the mute button.

Durgesh Chopra: Okay, can you hear me now? I’m sorry.

Brian Van Abel: Yes, great.

Durgesh Chopra: Okay, perfect. Sorry about that, guys. Brian, I heard you mention the Minnesota rate case item. Just appeal or rehearing. Could you just give us a little bit more color there as to what the next steps are timeline?

Brian Van Abel: Yes, the reconsideration, its — we need to file for reconsideration 20 days after the written order, so that’s coming up. And so certainly we will file for reconsideration right around ROE, around the decision on the prepaid pension asset and some other expense levels. And we’re hopeful the Minnesota Commission will take that up and look at hard at our reconsideration filing, and they have 60 days once — they have 60 days to decide. So that’s the process.

Durgesh Chopra: Got it. Okay, so that should be coming out shortly, and then 60 days after is a decision whether they take it up or not. That’s just the Minnesota Commission?

Brian Van Abel: Yes.

Durgesh Chopra: Okay. Thank you. And then know you mentioned the transferability guidance was in line with your expectations. There’s been a lot of discussion within the industry, investors and credit agencies on the implications to CFO — I know you’re very knowledgeable on this topic in general. So just get your thoughts there, how you’re seeing this play out and implications for your credit metrics?

Brian Van Abel: Yes, so I mean, we’ve spent a lot of — I would call it an industry collaboration on how we work this through our financials. And so not only worked with a lot of our peer utilities who’ve also worked with the big four accounting firms. And so every renews going to be in accordance with GAAP, it’s going to — we’ll take the income tax approach. It’s going to flow through our income tax expense line. That will also flow through cash from operations. And so I think it’s pretty straightforward. And I know there’s been a lot of discussion whether it will show up in the FFO to debt metrics. So I feel pretty good about it because it absolutely will reflect economics of our underlying financials. And it is — for us, right, it will be a reoccurring cash flow benefit as we look to monetize these tax credits.

So I feel pretty good about how it will be reflected across the rating agencies and we’ve spent time with each of those talking them through that. And like I said, also worked closely with the big 4 accounting firms and generally approach the whole industry will take.

Durgesh Chopra: That’s very helpful. Thanks. And then maybe just to the extent you’re willing to comment on this, just a little bit more pointed question on 2023 guidance. Obviously, you mentioned the history of meeting and exceeding expectations. Just with the unfavorable weather and the regulatory decision, where are you tracking and with your sort of cost efforts in place, what are you targeting? Or where are you tracking within that guidance range?

Brian Van Abel: Yes. So sitting here today, six months of the year, right, we’re tracking to midpoint of the guidance. And I’ll give you a little bit more color, right? I think about it in kind of three buckets. First is execution of our — on our O&M plans, which I talked about earlier. Second is we build additional rate case revenue that will come in the door in the second half of the year, particularly with the Colorado rate case in flight, the New Mexico rate case in flight and then there’s still continued to benefit from Wisconsin last year. And then we do have expected continued sales growth in our service territories. And so those are really the three buckets that I think about it in targeting midpoint of guidance. And obviously, as we normally do in Q3, we will look at where we are in Q3, investing to tighten guidance.

Durgesh Chopra: Very clear. Thanks so much, Brian. Appreciate the time.

Operator: Thank you. Our next question comes from Julien Dumoulin- Smith of Bank of America. Please go ahead.

Julien Dumoulin-Smith: Hey, good morning team. Thank you so much for the time and appreciate it. I wanted to focus on the wildfire dynamics. Obviously, a lot of sensation on this, perhaps principally coming from out of state as well. Can you elaborate a little bit? I know in the prepared remarks, you said you referred us to the 10-Q immediately here, but can you elaborate at least on your insurance levels today, your insurance programs across the states as well as how do you frame the risk here from the lawsuits that have been filed? I imagine that some of the commentary you alluded to in the Q here, but can you help frame up your understanding as well as maybe some of the differences critically from some of the out-of-state considerations that are drawn with new scrutiny?

Robert Frenzel: Yes, hey Julien, it’s Bob, and thanks for the question. And here’s what I can say about Marshall right now. The Boulder County share report concluded that the Marshall Fire first ignited on the property of the Twelve Tribes and that this ignition was unrelated to our equipment. With respect to the cause of a second ignition which began an hour after the first, we strongly disagree with the conclusion of the Sheriff’s report, and we will vigorously defend ourselves in court. The Sheriff’s report concluded that there were no design or installation or maintenance defects or deficiencies in public services, electrical circuit in the area of the second ignition. And so regarding the litigation, there’s a hearing in September where we expect to learn more about the procedural next steps, additional information on the lawsuit and the legal standards are included in our disclosures in our earnings release and in our 10-Q.

Given the lawsuits, I don’t think we’re going to comment any further beyond those particular disclosures. I’ll let Brian comment on insurance coverage, but other than that, I think we’re going to stick to our disclosure statements.

Brian Van Abel: Yes. And Julien, the insurance coverage is included in our disclosure is approximately $500 million.

Julien Dumoulin-Smith: Got it. All right. Understood. And then any further commentary about the differences in context across different states, especially whether it pertains to legal recovery constructs and/or jury constructs?

Robert Frenzel: Yes, it’s all included in disclosures an entire page of disclosures in the earnings release in the Q.

Julien Dumoulin-Smith: All right. Fair enough. We will leave it there. Thank you guys very much. Appreciate it.

Robert Frenzel: Thanks, Julien.

Operator: Thank you. Our next question comes from Anthony Crowdell of Mizuho. Please go ahead.

Anthony Crowdell: Hey, good morning, Bob. Good morning, Brian. And good morning, Paul. Sorry, I didn’t want to leave you out. Just hopefully two quick questions, one on Julien — following up on Julien with the Marshall fire. Is there a timing when that resolves itself? Or you just have to let it play to the courts and you can’t give any real feel of when that proceeding will wrap up and that overhang lifted?

Robert Frenzel: As I mentioned, look, we have a September hearing where we’re going to learn a lot more about the procedural schedule, and we’ll know more of that.

Paul Johnson: Yes. And Anthony, we really can’t go beyond what we’ve already said in the disclosure. So we have to limit the questions on that.

Anthony Crowdell: Okay. Great. And then on Slide 11, the pending settlement in Colorado. Just — you talked about, I think an alternative rate increase $47 million, but that’s dependent upon, I guess some coal plant deferrals. I’m just curious if you could talk about how the commission will they hopefully, when they approve the settlement, is that when they will address how they handle the coal plant deferrals? Or does that get rolled into a separate proceeding?

Robert Frenzel: No. Anthony, that will all be decided within the rate case decision that the commission will make here in Q3. So they deliver — they had hearings on it in July, and so it’s all part of the record. So it’s kind of either the $95 million one or the alternative if you defer some additional depreciation is $47 million. And that $48 million difference is just the deferral of depreciation. So all will be decided.

Brian Van Abel: So it would be earnings neutral, but it would have a cash flow impact, obviously.

Anthony Crowdell: Great, thanks. I’m good from here. Thanks again for taking the questions.

Brian Van Abel: Yes, thank you.

Operator: Thank you. Our next question comes from Sophie Karp of KeyBanc. Please go ahead.

Sophie Karp: Hi, good morning. And thanks for taking my questions. A lot of my questions have been answered, but maybe I can just ask a couple of questions here. So on volumes, I’m just curious if you could discuss a little bit what drive the volume variability here like aside from weather — it seems like C&I volumes were equally or closed equally weak as well as residential. So what are some puts and takes that drive it, I guess, year-over-year?

Brian Van Abel: Sophie, yes, if I think about sales and really looking at the weather normalized sales, we continue to see really strong growth on the C&I side out of SPS and in Q2 on a weather normalized basis. We had strength in Minnesota and Wisconsin to Colorado on a year-to-date basis on C&I. There is a large manufacturing facility was down for the first quarter in the first quarter of this year in Colorado. So that had some weakness on the residential side, the residential while we’re down close to 1% for the year. It’s tracking in line with our forecast or expectations for the year, right? We continue to see good customer growth, but we do see continued use for customer declines as our — we have really strong energy efficiency and DSM program. So I think overall, it is tracking both on the C&I side and on the resi side, is tracking to expectations for kind of through the first six months and for the balance of the year with our guidance on sales.

Sophie Karp: All right. And maybe I can just ask the bigger picture question here. I know you’ve been looking at potentially involvement in operating into 1 of your territories? Just kind of curious how you’re still thinking about that and if it’s been a new progress to report.

Robert Frenzel: It’s Bob. We look, we — as a company, we certainly have a view on nuclear, both current and future. Key priority for us is preserving the existing nuclear fleet and making sure that — there’s a potential for a nuclear future for the country. We have been working with a company called NuScale on their technology. It’s an SMR technology mostly helping them through the nuclear regulatory process and making sure that their applications meet the NRC guidelines and hoping to get that, that technology can get through the regulatory process. We don’t have plans as a company to own or operate a SMR at this point. We really are just taking our nuclear expertise and helping with the nuclear future for that company with — so we don’t have any specific plans to announce on SMRs in specifics.

Sophie Karp: Okay, thank you. That’s all from me.

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

Carly Davenport: Hey, good morning. Thanks for taking the questions.

Robert Frenzel: Hi, Carly. Welcome aboard.

Carly Davenport: Thank you, appreciate that. Bob, you’ve been vocal about sort of an all of the above approach kind of on the energy transition from a technology perspective. And you talked a little bit about the grant to support the Form Energy pilot. Could you just talk a little bit about kind of how that pilot is evolving and other opportunities that might exist in that space for itself, if you think about long duration storage?

Robert Frenzel: Yes, happy to. Look, as we think about it as a company, first utility to announce 100% carbon free. Given our geographic position, our ability to transition with wind and solar cost effectively for our customers through the end of this decade allowed us to make an interim target of an 80% carbon reduction, we feel very confident in that. But we’ve always been focused on we need new technology, new research, development and deployment of new technologies to achieve our 100% goal in the nation’s clean energy goal One of the big pieces of that is obviously energy storage. We have a lot of lithium ion for our batteries around the country, and we have some on our own systems. The long-duration energy storage is a critical part of the energy future.

And so the Form Energy battery is a 100-megawatt hour battery. So instead of 4 hours, it’s 4 days. And that’s a nice asset class as we think about periods when the wind doesn’t blow and the sun doesn’t shine. And we’ve seen evidence of that as recently as early June of this year. In the Southwest, where we had very limited wind production. We’ve seen it in polar vortexes, where in Winter Storm Uri, where we had no wind production for almost a 3-day period. So this idea of a long-duration battery is really interesting. What’s exciting about Form, in particular, it’s a pretty old technology really. This was found by the Department of Energy almost 60 years ago. But it’s becoming commercializable by a new company, Form Energy and they’re a breakthrough energy VC-funded company, an Energy Impact Partners-funded company.

And the technology is pretty interesting. I want to call it simple because that would minimize the impact and the efforts of the development team and the founders of that company but it’s basically resting and de rusting iron. And the great part about that is iron is readily available. It’s domestically available, not subject to counter parties and regimes in the world where we have challenges. And so when I think about new technologies, sometimes it’s not the best that wins, it’s the one that’s most commercializable and the 1 that can deploy the fastest. And I was really proud to be in West Virginia last month and breaking ground with the Form Energy team with Secretary Grand Home and Sender Mansion. We’re building an 800-megawatt capable factory in West Virginia as we speak, with low guarantees and grants from the government.

So this is a technology that’s going to come to fruition. It’s a technology that’s going to be scalable. We’re really pleased to be their first partner in sales of that, but it’s a pilot. It’s 10 megawatts and we’re going to put it on a 9,000 megawatt system. So we have a great opportunity to build it with them and invest alongside and then the breakthrough energy grants and the potential DOE grants buy down that cost and buy down that risk for the company. So very exciting technology, really excited about the future, what this can mean.

Paul Johnson: And Carly, I would just add, we have another pilot in Colorado [indiscernible], which is a liquid metal technology that we’ll have online in 2024. That’s a to duration, so kind of call it mid duration. So we’re spending a lot of time on this new technology. And I think also longer term, if we kind of broaden the definition of energy storage, green hydrogen is a form of energy storage as we think about longer term, be able to store and then burn it through some of our firm to stash all units longer term. So we’re pretty excited about a lot of you call it new technologies and glad really happy to see how excited our Minnesota commission is on form energy with the unanimous approval of that project.

Carly Davenport: Awesome. I appreciate those perspectives. And then the follow-up just around earnings guidance, and obviously, you’re reiterating the guidance for 2020. I just wanted to check in on temperature on the 5% to 7% long-term guidance. As you kind of think about the incremental spending opportunities from a CapEx perspective along with some of the regulatory outcomes that you’ve seen kind of how are you thinking about that long-term range?

Brian Van Abel: Yes, Carly, good question. And we fully expect to continue delivering in the upper half of our 5% to 7% long-term guidance. So that’s unchanged. I think you mentioned the incremental opportunities that we have. And I think in Bob’s comments, he mentioned the Sherco Solar free Farm, the SPS, the 418 megawatts of solar farms that are going to provide significant customer benefits in SPS. We filed that CCN yesterday. So those 2 together are north of $1 billion of clean energy investments that will benefit our customers that are outside of our current capital plan. And I think longer term, right, we’ll file here in Q3 or preferred plan or with the Colorado Commission around our RFP going into that, those decided pre IRA with the commission ruled on that resource spend before we could layer on the significant benefits significant customer benefits of the IRA.

So when we look at how the costs are coming in relative to what was approved, we believe we will go bigger and faster and above what the initial 4,000 megawatts of renewables in stored showed. So we’re excited to work with our Colorado Commission on that, look for that filing in Q3 and hopefully give a decision then even more longer term in the next 18 to 24 months, we’ll be filing more RFPs in Minnesota, Colorado and SPS for further significant additions of clean energy assets as we march towards a 0 by 2030 goal. So I’m pretty excited about it, pretty excited about long-term opportunities, and we do feel good about delivering in the upper half of our long-term guidance range.

Carly Davenport: Great, thank you.

Operator: Thank you. Our next question comes from Steve Fleishman of Wolfe Research. Please go ahead.

Steven Fleishman: Yes, hi. Good morning. Good to have all of you. On the phone including Paul. Just first, one Marshall fire question. Is there a deadline when any claims need to be filed by?

Robert Frenzel: Yes. Steve, it’s Bob. My understanding is that claims are a 2-year deadline. So that would say the end of this year is when claims need to be filed.

Steven Fleishman: Okay. Second question, a different topic on the Colorado settlement. Is there — I know I think you mentioned Q3 for the final order. Is there a specific date for that approval?

Paul Johnson: There’s not a date, Steve, but we expect that the commissioner rule probably in the middle of August, whole deliberations in the middle of August.

Steven Fleishman: Okay. And then lastly, just I know you all have been pretty focused on a number of IRA provisions, including the hydrogen one. And I’m just kind of curious latest thoughts on the ability to look at hydrogen production green hydrogen, all those kind of pillars of the green hydrogen, when do you think you’ll get — we’ll get that out and whether nuclear might be included in that or this additionality going to be a problem for that?

Robert Frenzel: Yes, Steve, it’s Bob. Thanks for the question. We’ve been very active in clean fuels in general and hydrogen in particular. Look, philosophically, we believe that we’re going to undergo a large period of electrification over the next 10 or 20 years as a country and as a company, but that there are parts of the economy that are going to be difficult or expensive or even in some cases, impossible to electrify. And therefore, we feel like we need a clean molecule to help in those areas. And today, that’s natural gas. But tomorrow, most promising molecule that we see is a green hydrogen molecule. And this looks like it’s an opportunity for the company. It’s another version of fuel for fuel at some level. set of government supportive of it.

The states are supportive of it. And we’ve got two hydrogen hub applications. One in the Rocky Mountain region with MOUs from four states two of which we serve Colorado and New Mexico as well as Utah and Wyoming. And then here in the upper Midwest, five-state MOU, again, two of which three of it that we serve, Wisconsin, Minnesota, North Dakota and Montana. And we’re in front of the DOE, those have progressed through the process, and we expect to know by the end of the year, whether we’re going to get duly loan — grants for hydrogen. And I think you’re aware of some of the challenges around what qualifies for a tax credit in hydrogen land. And I think there’s sort of three areas of sort of debate. And what we’re trying to do is balance cost to the customer and a need to accelerate OEMs to build and take us down the technology curve of electrolyzers and balance of plant.

And I think about those as location generation matching and then additionality. So with respect to location, we’ve been — in all three of those on one end, we think we need flexibility in all three of those categories. On the location, we’ve been supporting as a company, a balancing area type location, but certainly not national, which causes real market distortions and challenges with generation nationally. Similarly on matching, I think that the pure level would say we need hourly matching, but we probably need some transition period to get to that strict hourly matching. And so we’ve been supportive of some period of time where maybe by the end of the decade or late this decade, we’ve got hourly matching, but we’ll go to annually matching for some period of time.

And then with additionality, again, very supportive of the additionality as a concept but areas of flexibility there. One, we would really support nuclear in regards to additionality, and we have supported pretty vocally that as well as any sort of otherwise back down energy we would support that as additionality if it came back into the grid. And so very active — we’re very active at EEI, we’re very active. And I think those are generally in line with principles that both of those organizations are supporting.

Paul Johnson: Steve, you asked about timing. The statutory deadline in August 22. And they haven’t missed a statutory deadline yet, but what we’re hearing is that there’s still a lot of uncertainty around the position of it outlined given some of the polarizing viewpoints. So it certainly could slip into September or October.

Steven Fleishman: Okay, that is a lot of good information. Thank you. Appreciate it.

Paul Johnson: Thank you.

Operator: Thank you. Our next question comes from Ryan Levine of Citi. Please go ahead.

Ryan Levine: Hi, everybody. In terms of the $500 million insurance, what was the cost of that insurance and when was it occurred? And then I guess, going forward, are you seeing changes in pricing for wildfire-related insurance? And what’s your strategy on a go-forward basis related to insurance?

Brian Van Abel: We haven’t disclosed the cost, Ryan, and every year we renew our insurance program, and we continue to look at that. Insurance program is for everything is based on market experience for the insurance companies. And as you can imagine, it gets more challenged all the time, that’s not just related to wildfire, but that’s what all we have to say about insurance.

Ryan Levine: Have you already procured it in ’23 for the next year? Or is that an upcoming event for the back half of the year?

Brian Van Abel: We’re still in the process.

Ryan Levine: Okay. And I guess one last question on that. I mean, so the $500 million, any associated costs with procuring it. Is that passed on to ratepayers? Or is that embedded in your O&M cost outlook?

Brian Van Abel: It’s recovered through rate cases, yes and it’s included in O&M.

Ryan Levine: It’s included in…

Brian Van Abel: It’s included in O&M expense.

Ryan Levine: Okay, appreciate the color. Thank you.

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

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

Operator: That concludes today’s conference. You may now disconnect.

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XCEL ENERGY INC

Q2 2023

Earnings Transcript

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