Xcel Energy Inc (XEL) — Q2 2023 Earnings Call Transcript

Good morning, and welcome to 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.

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 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 of 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, enabling 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 the range anxiety of EV purchasers. Next month, we plan to file our Clean Heat plan 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’s 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 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. The 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 that 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 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. 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.

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 by $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 by 3% for the year. During the second quarter, we also made progress on several regulatory proceedings. Starting with our completed proceedings, in June, the 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 a $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% and an 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. Operator, we will now take questions.

Hi, good morning.

Hey, good morning, Jeremy. How are you?

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.

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 the 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 were 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 this year. So as I think about that, bad debt expense levels should be more sustainable. You have some timing and generation outages, but then we're also looking at a number of what I call 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 organizations. 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.

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 to 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?

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 expect to leverage on upper half of that long-term guidance.

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?

Hey, Jeremy, it's Bob. I appreciate the question. As you know, we've been operating in Colorado under a Wildfire Mitigation Plan that has been in place for over three years. This plan is set to be updated at the end of this year. We plan to propose the continuation of existing programs and introduce new ones in Colorado, taking into account the unpredictable weather in the west and the specific needs of our Colorado operations. We're still evaluating our options, and while nothing specific is on the table right now, we are definitely looking at all possible risks and opportunities to strengthen our system and ensure the safety of our communities and customers.

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 any way?

I believe, as I mentioned earlier, that we have effectively operated as a utility in Minnesota and throughout our eight states, prioritizing our customers and communities while aiding our states in achieving their clean energy and transportation goals. However, the outcome was disappointing for two reasons. One was mentioned by Paul and Brian, which is that it conflicted with earlier decisions in Minnesota that were 94 to 965. Equally important, it seemed to overlook that Xcel Energy is a national leader in promoting many of these initiatives, ensuring we do so reliably, affordably, and sustainably. We will keep reviewing our investment opportunities and programs in the state, but generally, we are very confident that this is our headquarters state. We aim to work collaboratively with the Governor, the legislature, and the Public Utilities Commission to promote these initiatives.

Got it. That's very helpful. I'll leave it there. Thanks.

Hey, good morning, team. Sorry, I was on mute.

Hey, Durgesh.

Three years later, we're still getting caught by the mute button.

Okay, can you hear me now? I'm sorry.

Yes, great.

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?

We need to submit our request for reconsideration within 20 days of the written order, so that deadline is approaching. We plan to file for reconsideration around the time of the decision regarding the prepaid pension asset and other expense levels. We are optimistic that the Minnesota Commission will thoroughly review our reconsideration filing, and they have 60 days to reach a decision. That's the process.

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?

Yes.

Thank you. You mentioned that the transferability guidance was in line with your expectations. There has been considerable discussion within the industry, among investors, and credit agencies about the implications for CFO. I know you have significant knowledge on this subject. Could you share your thoughts on how this is unfolding and its effects on your credit metrics?

Yes, we have collaborated significantly with our peer utilities and the major accounting firms on how to navigate these elements within our financials. Each renewal will comply with GAAP and follow an income tax approach, impacting our income tax expense line and cash from operations. This process is quite clear. There have been many discussions about whether it will be reflected in the FFO to debt metrics. I am confident it will accurately represent the economics of our financials and provide us with a recurring cash flow benefit as we aim to utilize these tax credits. I'm optimistic about how this will be perceived by rating agencies, as we have engaged with them to clarify our approach, alongside our collaboration with the major accounting firms and the industry as a whole.

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?

Yes, as of today, six months into the year, we are on track to meet the midpoint of our guidance. To elaborate a bit more, I see it in three main areas. First, the execution of our operations and maintenance plans, which I've described earlier. Second, we anticipate additional revenue from rate cases that will be realized in the latter half of the year, particularly with the ongoing Colorado and New Mexico rate cases, along with benefits from last year's outcomes in Wisconsin. Lastly, we expect continued sales growth in our service areas. These three areas are key to reaching the midpoint of our guidance. As is customary in the third quarter, we will assess our position and make adjustments to our guidance accordingly.

Very clear. Thanks so much, Brian. Appreciate the time.

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?

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 Sheriff 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, 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 disclosures.

Yes. And Julien, the insurance coverage is included in our disclosures is approximately $500 million.

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?

Yes, it's all included in disclosures and an entire page of disclosures in the earnings release in the Q.

All right. Fair enough. We will leave it there. Thank you guys very much. Appreciate it.

Thanks, Julien.

Good morning, Bob, Brian, and Paul. I didn't mean to leave you out. I have two quick questions, the first one regarding Julien and the Marshall fire. Is there an expected timeline for when that situation will be resolved, or is it just a matter of letting it go through the courts without any indication of when the proceedings might conclude and the uncertainty might be cleared?

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.

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.

Okay. Great. And then on Slide 11, regarding the pending settlement in Colorado, you mentioned an alternative rate increase of $47 million, which is dependent on some coal plant deferrals. I'm curious about how the commission will handle this. Will they address the coal plant deferrals when they approve the settlement, or will it be part of a separate process?

No. Anthony, that will all be determined with the rate case decision that the commission will make in Q3. They held hearings on it in July, and it is all part of the record. So it's basically the $95 million option or, alternatively, if you defer some additional depreciation, it's $47 million. The $48 million difference is simply due to the deferral of depreciation. So everything will be resolved.

So it would be earnings neutral, but it would have a cash flow impact, obviously.

Great, thanks. I'm good from here. Thanks again for taking the questions.

Yes, thank you.

Hi, good morning. Thank you for taking my questions. Many of my questions have already been addressed, but I'd like to ask a couple more. Regarding volumes, could you elaborate on what influences the variability in volume aside from weather? It appears that commercial and industrial volumes were similarly weak as the residential ones. What are the key factors driving this year-over-year change?

If I consider sales and focus on weather-normalized figures, we are witnessing robust growth in the commercial and industrial sector from our SPS operations. In the second quarter, weather-normalized sales showed strong performance in Minnesota, Wisconsin, and Colorado for the year to date in the C&I category. There was a significant manufacturing facility in Colorado that experienced downtime in the first quarter, which contributed to some weakness in the residential segment. Although residential sales are down nearly 1% for the year, they align with our expectations. We are still seeing positive customer growth, but we are also experiencing a decline in certain customer metrics due to our effective energy efficiency and demand-side management programs. Overall, both the C&I and residential segments are tracking according to our expectations for the first half of the year and for our sales guidance moving forward.

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 one of your territories? Just kind of curious how you're still thinking about that and if it's been a new progress to report.

It's Bob. As a company, we certainly have a perspective on nuclear, both currently and in the future. A key priority for us is to preserve the existing nuclear fleet and ensure there is potential for a nuclear future in the country. We have been collaborating with a company called NuScale on their technology. Their small modular reactor technology primarily involves assisting them through the nuclear regulatory process to ensure their applications comply with NRC guidelines, and we hope that their technology can successfully navigate the regulatory process. Currently, we do not plan to own or operate a small modular reactor. Instead, we are leveraging our nuclear expertise to support the future of nuclear energy for that company, so we don't have any specific plans to announce regarding small modular reactors at this time.

Okay, thank you. That's all from me.

Hey, good morning. Thanks for taking the questions.

Hi, Carly. Welcome aboard.

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?

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, 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 counterparties 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 one 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 Granholm and Senator Manchin. 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.

And Carly, I would just add that we have another pilot in Colorado, which involves liquid metal technology that will be operational in 2024. It's a mid-duration technology, and we are dedicating a lot of resources to this new approach. Additionally, if we expand our understanding of energy storage, green hydrogen can also be seen as a form of energy storage that allows us to store and later utilize it through some of our firm stash all units in the long run. We are quite enthusiastic about these new technologies and are thrilled to see how enthusiastic our Minnesota commission is about form energy following the unanimous approval of that project.

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?

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 two 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 our preferred plan or with the Colorado Commission around our RFP going into that, those decided pre-IRA with the commission ruling on that resource spend before we could layer on the 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 storage 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 net-zero 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.

Great, thank you.

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?

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.

Okay. For my second question, I would like to ask about the Colorado settlement. You mentioned Q3 for the final order. Is there a specific date for that approval?

There's not a date, Steve, but we expect that the commission will rule probably in the middle of August, hold deliberations in the middle of August.

Okay. Lastly, I know you have been focused on several IRA provisions, including the one related to hydrogen. I'm curious about your current thoughts on the potential for green hydrogen production and the key aspects involved. When do you think we will have that information available, and could nuclear energy be part of that discussion? Will the concept of additionality pose any challenges?

Yes, Steve, this is Bob. Thank you for the question. We've been actively engaging in clean fuels, especially hydrogen. We believe that the next 10 to 20 years will see significant electrification in our country and our company. However, there will still be sectors of the economy that remain challenging, costly, or even impossible to electrify. Therefore, we require a clean alternative for these areas, which is currently natural gas, but we see green hydrogen as a promising option for the future. This presents an opportunity for us, as the government and states are supportive of it. We have two hydrogen hub applications: one in the Rocky Mountain region with memorandums of understanding from four states, including Colorado and New Mexico, as well as Utah and Wyoming. The other is in the upper Midwest with a five-state agreement involving Wisconsin, Minnesota, North Dakota, and Montana. We are engaged with the Department of Energy and expect to learn by the end of the year about potential grants for hydrogen. There are some challenges regarding what qualifies for tax credits in this sector, and we believe there are three key areas under discussion. We aim to balance costs for customers while encouraging original equipment manufacturers to develop technology for electrolyzers and related systems. We are considering location, generation matching, and additionality. Regarding location, we have supported a balancing area type approach without advocating for a national standard due to market issues. For generation matching, we understand the need for hourly matching but believe a transition period is necessary to reach that goal. We are supportive of a timeline that could see us move to hourly matching by the end of the decade, while possibly allowing for annual matching initially. Concerning additionality, we are in favor of the concept, but we see a need for flexibility. We are particularly supportive of nuclear energy in this context, as well as any back-down energy that could return to the grid. We are actively involved with EEI and are aligned with the principles that both organizations support.

Steve, you asked about timing. The statutory deadline is 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.

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

Thank you.

Hi, everybody. In terms of the $500 million insurance, what was the cost of that insurance and when was it incurred? 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?

We haven't disclosed the cost, Ryan, and every year we renew our insurance program, and we continue to look at that. The 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.

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

We're still in the process.

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?

It's recovered through rate cases, yes, and it's included in O&M.

Okay, appreciate the color. Thank you.

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