Hello, and welcome to the Xcel Energy Third Quarter 2023 Earnings Conference Call. My name is George, I'll be a coordinator for today's events. Please note, this conference is being recorded. [Operator Instructions]. I'd now like to hand the call over to your host today, Mr. Paul Johnson, Vice President, Treasurer and Investor Relations to begin today's conference. Please go ahead, sir.

Thank you. Good morning, and welcome to Xcel Energy's third 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 questions if needed. This morning, we will review our third quarter results and highlights, share recent business and regulatory developments, update our capital and financing plans and provide 2024 guidance. 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'll discuss certain measures that are non-GAAP measures. Information on comparable GAAP measures and reconciliations are included in our earnings release. Early this week, a jury in Denver District Court found Xcel Energy liable and its dispute with core cooperative regarding prior year's lost power damages at our Comanche power plant. We intend to appeal the decision. For the third quarter of 2023, we recorded GAAP earnings of $1.19 per share, which includes a onetime nonrecurring tax charge of $34 million related to the ongoing legal dispute. As a result, we have taken a nonrecurring charge of $0.05 per share, which we don't consider part of ongoing earnings. All for the discussion in our earnings call will focus on ongoing earnings. For more information on this matter, please see the disclosure in our earnings release. I'll now turn the call over to Bob.

Thanks, Paul, and good morning, everybody. Let's start with the quarter. We had solid results recording ongoing earnings of $1.23 per share for 2023 compared to $1.18 per share in 2022. As a result, we're narrowing our '23 ongoing earnings guidance to $3.32 to $3.37 per share. We're also initiating 2024 ongoing earnings guidance of $3.50 to $3.60 per share, which is consistent with our 5% to 7% long-term EPS growth rate. Consistent with past practices, we've reviewed our customer and operational needs and have updated our infrastructure plan for 2024 to 2028. This revised forecast reflects $34 billion of needed capital investment, an increase of $4.5 billion from our previous plan. This base infrastructure investment plan includes substantial resiliency investments in both transmission and distribution including additional upgrades required to support the Colorado Energy Plan. However, it does not include clean energy generation investments that could result from the resource plans in Colorado, Texas, New Mexico, or in the Upper Midwest. If approved by our commissions, these cost-effective clean energy generation investments could result in an additional capital need totaling $10 billion from 2024 to 2028 and dramatically reduced carbon emissions in various states. Xcel Energy's resource plans also demonstrate the benefits of the Inflation Reduction Act, our state's geographic advantages that enable high-capacity renewable generation and our operational expertise and commercial acumen can bring to our customers. In September, we filed our recommended plan in Colorado. This plan seeks to double the amount of renewable energy in the state, making it the largest clean energy transition ever in Colorado history and demonstrates our strong element with the state's environmental goals. Our proposal contemplates the shutdown or conversion of our remaining coal units replaces them with approximately 6,500 megawatts of renewable energy and battery storage and 600 megawatts of dispatchable gas resources to ensure system reliability in times of low wind or solar conditions. These amounts include 4,800 megawatts as proposed to be owned and operated by Xcel Energy for the benefit of our customers. Including the approximately $3 billion in required transmission investments to ensure deliverability and reliability, this Colorado energy plan represents nearly an $11 billion total investment by Xcel Energy. In addition, this portfolio also includes $10 billion in IRA savings to customers. It creates local jobs, promote economic development and provides over $2 billion in tax benefits to local communities in the coming decades. At the same time, it will reduce carbon emissions by over 80% from 2005 levels in Colorado while having expected annual rate impact of only 2.3%. This competitive portfolio provides our Colorado customers an industry-leading opportunity for a cleaner economy at a fraction of the cost most other states would incur. Moving to Minnesota. In September, the commission approved 350 megawatts of new renewable generation, including an additional 250 megawatts at our Sherco facility. This brings the total amount of company-built solar at Sherco to over 700 MW making it one of the largest solar facilities in the country. In October, we also issued an RFP seeking 1,200 megawatts of wind that will utilize our transmission interconnect at our retiring Sherco coal facility and we'll be issuing additional RFPs to fulfill the remainder of the approved Upper Midwest Resource Plan in 2024. Finally, in October, we filed a resource plan in New Mexico. Based on our filing, SPS could require additional 5,000 to 10,000 megawatts of new generation by the end of the decade to accommodate increasing demand, plant retirements, and ensure resiliency and reliability of the grid. We've already proposed 418 megawatts of company-owned solar and battery projects that are pending commission approval. We anticipate filing another RFP in 2024 and for the additional generation resources. Shifting to our clean energy innovation projects. The Department of Energy recently announced nearly $1.5 billion in awards to support multiple Xcel Energy affiliated projects. Starting with the Heartland Hydrogen Hub, this estimated $5 billion initiative, which includes multiple projects from Xcel Energy and others received an award of up to $925 million by the DOE. This game-changing funding will serve as a catalyst for clean hydrogen ecosystem in the Upper Midwest and the foundation of our clean fuels efforts at Xcel Energy. Fortunately, the Western Interstate Hydrogen Hub in Colorado, New Mexico, Wyoming and Utah were not successful in this round of DOE funding. And that said, we remain committed to working with policymakers and federal offices with the hopes that our projects can progress to advance our shared clean energy goals. The DOE also awarded Xcel Energy up to $70 million to support two 10-megawatt 100-hour battery pilots with Form Energy. Combined with the grants from Breakthrough Energy's Catalyst Fund, we secured up to $90 million to support these long-duration energy storage pilots, a critical asset class to ensure cost-effective, reliability in a high renewable grid. With respect to DOE grid resilience and innovation partnerships program, Xcel Energy was selected as part of 2 different awards. First, the DOE we awarded Xcel Energy a $100 million to support projects to mitigate the threat of wildfires and ensure resiliency of the grid through extreme weather. Projects include vegetation management, selective undergrounding, advanced infrastructure technologies, drones, and several additional resiliency projects. Xcel Energy was also partied to grid's $464 million grant to expand transmission as part of the MISO and SPP program to fund high-voltage transmission to improve interregional transfer capability, reliability, and resolve grid constraints. We're appreciative of the DOE support as well as many of our partners in these projects, including our state and regional transmission organizations. Funding support helps us accelerate critical carbon-free technologies, enhance safety and resiliency while keeping costs low for customers. Turning to our natural gas utility. In August, we filed our Clean Heat program in Colorado. This first-of-a-kind plan provides a framework, reduce greenhouse gas emissions consistent with state goals in our net zero emissions target. The Plant fast track solutions such as electrification, demand side management, clean fuels and certified natural gas. The proposed Clean Heat Plus portfolio reduces greenhouse and gas emissions by 28% by 2030, ensures customer reliability and choice while optimizing customer bill impact. We plan to file a natural gas innovation plan, a corresponding framework for our Minnesota gas utility in the fourth quarter. In September, Meta announced construction of a $700 million data center in Minnesota, which eventually could be one of the largest customers in the state. We continue to evaluate a number of additional data center and commercial opportunities that will further support growth and economic development in our committees. Finally, there are not many new material developments with the Marshall Wildfire litigation. We currently have 14 complaints with 675 plaintiffs which have been consolidated into a single case. For the past four years, Xcel Energy has been operating under a commission-approved wildfire mitigation program in Colorado. We intend to file an updated wildfire mitigation plan next year which will include a wide range of options for stakeholder consideration, including the technologies, undergrounding additional vegetation management, composite poles, selective use of covered conductor and preventative power system shutoffs. Let me wrap-up with just a few summary comments before I turn it over to Brian. As we look forward across the next five years and beyond, we see a future that is bright for our communities, our customers and our investors. Xcel Energy is committed to providing a clean energy economy in our regions and it will require meaningful investment to accomplish. For our customers, we have the potential to deploy 15,000 to 20,000 megawatts of new clean generation on our systems by 2030, dramatically lowering our emissions profile, affordably powering our customers' homes and businesses, while ensuring 99.99% reliability that they come to expect from Xcel Energy. And through leveraging the benefits of the IRA and the IIJA, we are able to accelerate deployment of renewable resources in pairing them with affordable energy storage assets and other firm dispatchable clean fuel resources to provide reliability. We continue to invest in and innovate our transmission and distribution systems to ensure reliability and resilience and provide for regional and interregional deliverability. We're laying the framework to achieve net zero greenhouse gas emissions on our natural gas system. All the while our residential customer electric and natural gas builds are amongst the lowest in the country, 28% and 14% below the national average. And given that the regions where we serve customers are the most resource rich in wind and solar, we believe that we can lead this clean energy transition for our customers more cost-effectively than almost any other company. With that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. We had ongoing earnings of $1.23 per share for the third quarter of 2023, compared to $1.18 per share in 2022. The most significant earnings drivers for the quarter included the following: Lower O&M expenses increased earnings by $0.03 share which reflects the impact of cost containment actions, lower effective tax rate and conservation and demand side management expenses, which increased earnings $0.03 per share. Note that these items are apparently offset in lower margins are earnings neutral. In addition, other items combined to increase earnings by $0.04 per share. Offsetting these positive drivers, higher interest charges, which decreased earnings by $0.03 per share, driven by rising interest rates and increased debt levels to fund capital investment and higher depreciation and amortization expense, which decreased earnings by $0.02 per share, reflecting our capital investment program. Turning to sales. Year-to-date weather-adjusted electric sales increased by 1.1%, largely driven by strong C&I sales. As a result, we now expect annual electric sales growth of 1% to 2% in 2023. Shifting to expenses. O&M decreased $25 million for the third quarter, reflecting management actions to lower costs. We now expect our annual O&M expenses to decline by 1% to 2%. During the third quarter, we also made progress in several regulatory proceedings and we are getting close to wrapping up a busy regulatory year. 2024 will be much lighter from a rate case perspective. In our Colorado electric rate case, the commission approved our settlement that reflects a $95 million rate increase based on an ROE of 9.3% and an equity ratio of 55.7%. Rates were effective in September. In October, the New Mexico Commission approved our electric rate case settlement. That reflects a rate increase of $33 million, based on an ROE of 9.5%, an equity ratio of 54.7%, a forward test year an acceleration of total depreciation to 2028. Rates were effective in October. In our pending Texas electric rate case, we reached a settlement in principle on revenue requirements. We're hopeful the parties will reach agreement on class cost allocation and rate design so that we can file the settlement this year. We expect a decision in the implementation rates in the first quarter of 2024. And as a reminder, we have a relate back date to July 13. In New Wisconsin, we continue to work through the regulatory process for our electric and natural gas rate cases and expect the commission decision by year-end. With regards to future rate cases, we plan to file a natural gas rate case for Minnesota in the order and the potential Colorado natural gas rate case in the first quarter of next year. Updating our progress on production tax credit transferability, we recently executed 2 contracts totaling $250 million. We anticipate further PTC sales in the fourth quarter, consistent with our plan totaling $300 million to $400 million for the year. Transferability lowers the cost of our renewable energy projects for our customers and reduces near-term funding needs. Moving to our updated capital forecast. We've issued a robust $34 billion 5-year base capital plan with annual rate base growth of 7.6%. The base plan reflects commission approved renewable projects, including over 700 megawatts of new solar at Sherco. The base plan also reflects significant rate and resiliency investments, including our Colorado Power Pathway, transition to support our Colorado preferred plan, MISO transformer investments, as well as other system investments to maintain asset health and reliability. In addition, we have additional capital investment opportunities for our renewables and firm capacity associated with the Colorado preferred plan, 418 megawatts of proposed self-built solar and Solar SPS and further RFPs in NSP and SPS. We'll update our base capital plan after our various commissions complete their review and finalize their decisions regarding our proposals. These opportunities, if approved, could translate to $10 billion of additional investment through 2028, resulting in annual rate base growth of 10.7%. We've updated our base financing plan, which reflects $15 billion of debt and $2.5 billion of equity. We anticipate that any incremental capital investment would be funded by approximately 40% equity and 60% debt. It is important to recognize that we've always maintained a balanced financing strategy which includes a mix of debt and equity to fund accretive growth while maintaining a strong balance sheet and credit metrics. Maintaining solid credit ratings and favorable access to capital markets are critical to fund our clean energy transition, deliver strong shareholder returns and keep customer bills low, especially with rising interest rates. Shifting to our earnings. We've updated our 2023 guidance assumptions to reflect the latest information. We're also narrowing our 2023 ongoing earnings guide range to $3.32 to $3.37 per share. We have a long history of delivering on our financial objectives and expect to continue that trend in 2023. As a result, we anticipate strong earnings in the fourth quarter that will result in achieving our earnings guidance. Key drivers include incremental revenue from the Colorado and New Mexico electric rate cases, deferral of certain O&M depreciation and interest expenses as part of the Texas electric rate case, strong O&M cost management, and better-than-expected sales growth. Finally, we are initiating our 2024 ongoing 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%. Key assumptions are detailed in our earnings release. With that, I'll wrap up with a quick summary. We continue to execute on our clean energy plans, leveraging the benefits of the IRA to reduce cost for our customers. We proposed a game-changing preferred plan in Colorado, which results in one of the most aggressive renewable bill loads in the country. We secured DOE grants for our Heartland hydrogen hub, wildfire mitigation plants, four-man injury pilots, and transmission expansion, which will accelerate breakthrough technology and reduce risk at a lower cost for our customers. We resolved rate cases in Colorado and New Mexico, while reaching a settlement in principle in Texas. We're nearing our 2023 ongoing earnings guidance and continue to expect to deliver within our guidance range as we have for the past 18 years. We announced a robust, updated capital investment program and initiated 2024 guidance that provides strong, transparent rate base growth and customer value. And finally, we remain confident we continue to deliver long-term earnings and dividend growth within the upper half of our 5% to 7% objective range as we lead the clean energy transition and continue to keep bills low for our customers. This concludes our prepared remarks. Operator, we will now take questions.

[Operator Instructions] Our first question today is coming from Julien Dumoulin-Smith of Bank of America. Julien Dumoulin-Smith: Nicely done. Got to say, what a set of updates quarter-over-quarter here. So maybe just to pick things up here real quickly, on the credit side, I mean, I appreciate the commentary about 60-40. Can you comment a little bit about the latest monetization policies for the credit rating agencies and thoughts about monetizing in terms of flowing tax credits through FFO? To what extent does that change or impact your financing plan at all? Just to come back to that a bit.

Yes. So we met with the credit rating agencies in September. And as we are sitting right now, we've included tax credit transferability in our financing plan, and we expect that they will include it in the way they look at our credit metrics. And for us, we use the income tax election method, so it will flow through our cash from operations in our financial statements. So all of that is included in our baseline as we think about it. Julien Dumoulin-Smith: Excellent. And then separately, just as you think about the upside plan here, I mean, just incredible numbers here. I mean, and I know there's a lot of fixation here in Colorado. Can you walk through a little bit of just the timing here in some of the other jurisdictions in terms of coming to fruition, especially through 2020, it's practically around the corner. Do you want to talk a little bit about the specific timelines to getting some of that full 10 reflected in the plan here just as it goes to aligning against the full update with 4Q or beyond?

Yeah. Hey, Julien, it's Bob. We're really excited about the Colorado Energy Plan. It's great to see it sort of nearing conclusion and approval milestones. We've been working on this for two years. We've actually been working with the counterparties on the bids for over six months. I recognize that it might be quick timing for the external world, but we've been working with these people for a while and we're really excited about what we've done here. We've been working with stakeholders very collaboratively and the PUC over the past two years to bring this plan to life for our Colorado customers. Obviously a great wrinkle, right in the middle of it with the IRA, right? And so we've basically been able to double the renewable portfolio, have the fossil portfolio, increase our storage component dramatically. So we think the plan meets the policy guidelines. The process from here is relatively quick in the grand scheme of things. So we received the independent engineer's report that validated our proposal last week –-- actually Monday of this week I think. We get comments –-- external comments to early November. We applied to those comments late November and then we turn it over to the commission for deliberations. We think that happens in December and early next year and probably early Q1 of next year we'd expect a decision from the commission. So pretty quick given the long time frame of the process in total.

And Julien, a couple of the other pieces in that steel for Fuel 2.0 plan is the SPS Solar plus Storage, we should get the decision in Q2 of next year. And then we just launched in a sort of 1200 megawatt wind RFP. Bids are due in December, should get a short list in Q2 of next year on that. And then not in any in our steel for Fuel 2.0, but really looking forward to working with our stakeholders in SPS. Bob mentioned this in his opening remarks of our New Mexico resource plan. We'll launch an RFP in mid next year and that's 5,000 to 10,000 megawatts of potential generation resources and should get a project selection in call it early to mid-2025 for that. So nowhere in the $10 billion is a great opportunity as we look forward to transitioning to SPS's generation outage. Julien Dumoulin-Smith: Yes. It's incredible, again, update. With that, though, and then given the timing early 1Q for at least a good chunk of that. I mean, 4Q could we see an update to your earnings CAGR outlook and/or any other related metrics as you get that clarity affirmed here, at least on the preponderance of it?

Yes, Julien, I mean, certainly we'll wait until we get through the commission approvals. But if that timing aligns, then yes, it would be fair to think through that.

We'll now move to Nicholas Campanella coming from Barclays.

So a couple for me. I guess on Colorado, as you kind of layer in that to the next financing plan, and obviously, you had the 40% rule. Is equity continuing to be programmatic across the 5 years? Or does that drive more -- a larger need in the near years of the plan?

The way we look at it, the base capital plan pretty programmatic as we think about it, most likely in ATM with the base capital plan. When you look at the -- not just in Colorado, but the $10 billion of the Steel for Fuel 2.0 opportunities, this is really kind of the '25, '26, '27 time frame or the heavy spend. So I would look at it as that's in the time frame that would align with the spend for that incremental and additional opportunities.

Got it. And then one more on the Colorado plan. I just -- I know the commission is exploring some type of risk-sharing mechanism for the renewable assets. But can you just help us understand if that type of proposal is something that would tweak the plan in any way? Is it something that you're working with the commission actively on? And how could that kind of transpire through the remaining course of the year here?

Yes. Consistent with past practice, Nick, we would expect some forms of customer protection, capital costs or energy cost providers. We've submitted some proposals to the commission that they -- so they are purview. It will go along with their overall decision. And on the portfolio side, of course, there's always a chance to look at it, but we've looked at this sideways, back ways, front ways. I think we've put together a great plan that complements the geographic diversity in the state where the wind and solar physically come into the grid to provide high resilience and reliability from the renewable resources. And so always a chance to move it around a little bit, but we'll think the substantial changes coming from the plan.

And if I could just squeeze one more in. You talked about the data centers in your prepared remarks, your weather-normalized load for '24 is 2% to 3%, and that's higher than last year by 100 basis points. So just -- what are you seeing that's changing the demand profile? How are you thinking about the longer-term forecast and whether that's pressure higher in your 5% to 7%?

Thanks, Nick. I'll take that one. The way I think about it is -- yes. So we're starting to see a number of things in our long-term sales forecast. We updated our sales forecast for 2024, 2% to 3%. But we think over the 5 years at that 2% to 3% CAGR to hold, if not, call it conservative, given what we're seeing on the potential load from data centers. Data centers represent less than 1% of our sales right now. We see some potential where that could grow to 5% over this next 5 years. As I think about just next year, significant electrification happening in the oil and gas region in the Permian Basin, the Delaware Basin. We're working very closely with our large customers down there around -- it's not just -- it's not really about even more drilling. It's electrification of their pumps compressors as they hit their net zero goals in the Permian Basin and achieve the goals that the state of New Mexico has for them. And then also, we're starting to see an uptick in residential demand. We're starting to see penetration from the EV perspective. So overall, really great trends as we look out -- not only next year but longer term with kind of electrification and data center potential.

Nick, just to add on to that, this is Bob. When I think about some of the comments I made in the opening remarks, about the ability to deliver clean energy more cost effectively in our regions of the country than other parts. I think over the long term, that should absolutely accrue to our state's benefits in terms of economic development. Energy and energy-intensive resources are going to come back in onshore in the United States. We should be a very attractive destination for them as we can deliver renewable energy and clean energy much more cost effectively. We serve customers where the wind blows and the sun shines and that translates to high capacity factors and lower energy cost to our customers, which should lead to long-term economic development in our states.

We'll now move to Durgesh Chopra coming from Evercore ISI.

You guys have been sort of the leader in transferability. I mean you were kind of one of the first ones to introduce the concept and start working on it. It seems like you're making great strides here. The target for the year, if I recall this, if I have this correctly, it was increased from $200 million to $300 million to $400 million. I just wanted to see if I'm thinking about that correctly. And then what does that do to the prior point had $1.8 billion in total amount raised from transferability? What does that number look like in the current plan?

Yes. So you're actually thinking about it correctly. When we went into this year before the market has even fully set up, we're a little bit conservative in saying around $200 million. We've already executed 2 contracts for $250 million and working on another. So we feel very good about our $300 million to $400 million in total for the balance of the year. And when we think about our baseline, we've layered in the Sherco solar projects now that they've been approved. So we have a little bit over 5 -- think about it about $500 million run rate annual transfer of PTC credits. So it's about a total of $2.7 billion over our 5-year forecast from '24 to '28.

That's really helpful. And then maybe just -- I didn't see this in your prepared remarks on slide deck and maybe I missed it, but just any update on the gas price risk management plan that you have to file in Colorado? I believe that's due next month.

Yes. So we'll file it by November 1, absolutely right. So due next week, working with the stakeholders are working on the plan, and we've seen compounded in a couple of different veins. One is this idea of the smoothing mechanism where we can reduce volatility by using our balance sheet. And so if commodity prices spike to a certain level, we would take that on our balance sheet and spread over 1, 2, 3, 4 years and get a carrying cost on it or really reduce that volatility that our customers experienced last year. So that's important because we need to maintain a good balance sheet, strong product quality to be able to use our balance sheet to help our customers out. The second part is really focused on what are the proposals we can make to reduce volatility and that's whether there's additional physical storage, potential for fixed physical contracts or additional financial hedging. So you see all out of par proposal here coming up next week and look forward to working with the commission and the stakeholders and helping reduce the volatility for our customers in Colorado.

Durgesh just to add on to that, one of the best things we've done for our customers is our renewables portfolio. We have lowered our reliability on fossil fuels dramatically over the past five years and the customers have accrued over $4 billion of fuel savings and tax benefits from that since 2017. So as we continue to look forward obviously the Colorado Energy Plan our Upper Midwest Energy plans certainly derisk our customers from a commodity volatility on the electric side. And as we lean into clean fuels, you start to see that on the gas LDC side as well.

And just to clarify, we meant that we've reduced our reliance on fossil fuels, not the reliability of our fossil fuels.

We'll now move to Carly Davenport of Goldman Sachs.

Maybe just a quick follow-up on your comments just then on tax credit transferability, the color that you've done already kind of $250 million of contracts. Can you just talk a bit about kind of how the market's been evolving relative to your initial expectations and how you kind of think about the competitiveness of that space?

Carly, thanks for the question. So it's evolved pretty close to how we expected it to this year, bilateral transactions in kind of the pricing we anticipated. There has been significant amount of demand. The demand is much, much greater than our supply of PTCs. Now we're still waiting for a little -- for the treasury staying up their portal and additional administrative requirements. So we feel comfortable executing contracts. I think also what we found and this is the strength of us, as we are a major player in this market. We have a great tax department. And with our balance sheet strength and our credit quality, we have no issue with identifying these credits, which makes it really easy to do business with us. And as a certain evolve, we're getting in the longer-term discussions is not just a 2023 or 2024 transaction, but hey, let's look at longer-term multiple years signing up a single counterparty. So we're very pleased with how it's developed, and the amount of interest from their counterparties there. And for us it's great. We have almost 20 Fortune 500 companies in our backyard in Minneapolis in Minnesota. So, it is great to have those relationships at the C-suite level to drive some of these.

Got it. That's super helpful. And then maybe to follow up just on the Hydrogen Hub process now that that's been awarded, I guess, how should we be thinking about timeline there? And is there any dependence on that investment cadence going forward on kind of how the tax credit structure looks for hydrogen once we get that from the treasury?

Sure. So Carly, it's Bob. We're really excited about our clean fuels program, but it is fairly long dated. We are at a place where we are invited to negotiate with the DOE on this upper Midwest Hydrogen Heartland hub. Negotiations, final engineering, those processes are going to take probably 2 years. I wouldn't say we'd start capital deployment until probably the end of our 5-year plan and runs through the end of the decade. I would think that parts of the hub could be activated by 2029 -- 2028, 2029. So it's long-dated investment cycle. It's a $5 billion project. About half of that was attributable to projects that we proposed. So about $2 billion of company capital paired with $0.5 billion of federal money, is sort of how I think about it. None of that is in our financial plan, and that's about the timeline it's going to go on. So we'll still work on -- that does not include any investments also that we would look at some of the projects in Colorado were really attractive as part of our hub application there. We still want to work with the federal offices and our state partners, to see if we can advance some of those projects as well. Again, none of that's in our base case or in our Steel for Fuel portfolio.

And Carly, the second part of your question, you asked about kind of the guidance around. Obviously, we're still waiting for the guidance from Treasury unless we provided our comments, industry's driver comments. One of the things important to us is on the nuclear qualifying for hydrogen PTC. So hopeful that we get guidance here, rumor sometime in November, but it could push a little bit.

We'll now move to Jeremy Tonet coming from JPMorgan.

Clearly, an incredible update in Colorado here and just wanted to dive in a little bit more, if I could. Just given the rate base growth as you outlined there, and how should we think about, I guess, the EPS growth relative to the rate base growth, given the higher interest rate environment here, thinking about potentially greater than 10% rate base growth, do you see the gap kind of widening at that point? Or how should we think about that at a high level?

Jeremy, good question. Obviously, we are in a higher interest rate environment, higher financing market and also have some issue equity -- equity to fund accretive growth which we're very comfortable with. It's important to maintain a strong balance sheet. And we've been very consistent about how we'll fund incremental growth. So, as you go through you do see a little bit of a divergence from rate base growth and EPS growth, but certainly, not hard to do the math, and I'm sure all of you have done that math already.

Got it. Yes. No, good math to do there. So that makes sense. And just wanted to kind of come in on the O&M side for the guidance there. And I think it's been kind of flat to down, if I recall correctly, but targeting a little bit of an uplift in '24 here. I'm just wondering, if you could provide a bit more color on the increase here and how this O&M, I guess, impacts how '24 guidance could fall out, particularly given Minnesota being a bit lighter than expected?

Yeah. We take everything that happened in this year from a regulatory perspective rate case perspective taking into account as we give 2024 guidance. When we think about O&M, we're down for this year our guidance for this year is down 1% to 2%. So as we think about next year up 1% to 2% we did some management actions in this year. And so really when I put the 2 years together it's about essentially maintaining flat O&M. It's a big focus from a long-term perspective is investing in technology to improve processes and take cost out of the business. We have innovation and transformation arm focused on eliminating waste and improving processes. We call it One Xcel Energy Way that we've deployed at the start of this year. And also as you go longer term we start to see tailwinds from coal plant shutdowns as we start to shut down a unit of the year almost. So next year is just a little bit of a balance in this year and next year but over flat is how I'd look at it overall.

Got it. That makes sense. On the other side of the coin, as it relates to the sales outlook, you talked about the data center opportunity in supporting the 2% to 3% growth. Is that kind of like the right base to think about beyond '24? Do you anticipate some further acceleration over the 5-year plan? Just trying to calvary, if like the environment is just different now given some of the tailwinds as you talked about. And clearly, as well, oil and gas, a Delaware Basin really click on all cylinders here, a lot of activity that we see on the pipeline side. So just, I guess, curious for those drivers and how that could carry out over time.

Yes. And I think really next year, as you mentioned, in the Permian Basin, significant growth down in SPS as we're supporting electrification and working closely with our large customers there. From a data center perspective and thinking about the longer-term growth, I do think right now our 5-year sales growth is -- we're projecting 2% to 3% over the 5 years. So kind of think about 2024, and that will continue over the next 5 years. And I think there's even opportunity beyond that as you start to look at what generative AI means from a load perspective and a data center perspective. So pretty excited. We think about -- obviously, there's investment opportunity when we think about loan growth, helping us keeping customer bills low and affordable and that's really important as we look to invest significantly into our system.

Got it. That's very helpful. Real quick last one, if I could, just kind of rounding things out here. Any updates on the ongoing Marshall wildfire litigation? Any update on whether total liabilities we go to reach the 560 insurance coverage? Or any color you could provide there.

Yeah. Hey, it's Bob. I don't think we've seen a lot of material updates in Marshall, I think in our disclosures in our Q and in our earnings release are up-to-date. We've seen 675 plaintiffs. To put it in perspective we think there are about 1,100 structures that had some amount of physical damage and estimated by the by the state of Colorado at about $2 billion worth of damage. None of that's changed or been updated. The cases into 14 complaints and has been consolidated into a single case right now. The statute of limitation ends at the end of the year. So we think it will be pretty quiet until then maybe a couple of other plaintiffs trickle in through the process and then we'd expect to get a litigation calendar sometime in early next year.

We'll now move to Anthony Crowdell of Mizuho.

Just hopefully, easy one, everything has been answered. Great news on Colorado, but just following up on Jeremy's question. You talked about, I think, the company is going to file a wildfire mitigation plan, I believe, in 2024 in Colorado. Is there a potential for even additional CapEx associated with wildfire mitigation like magnitude, is that similar to what we've seen in the Steel for Fuel 2.0?

Anthony, Look, we've been operating under WMP in Colorado for the past 4 years. I think that plan was around $400 million in total. We are looking at more capital investments as we roll forward. I think a lot of that's going to be built into the base plan already. I don't think it has anything of the magnitude of Steel for Fuel 2.0. Obviously, the big needle in there would be if we did something very dramatic on undergrounding. I don't see a proposal that will move the needle necessarily in capital expenditures going forward, but something worth looking at.

We'll now move to David Arcaro calling from Morgan Stanley.

I was wondering, it's clearly a step change in the renewables aspirations and opportunity for Colorado. Could this also apply to Minnesota in terms of potentially seeing an acceleration and a step change in renewables there as you fully realize the benefits of IRA going forward?

Maybe -- David, it's Bob. Thanks for the question. When I think about my prepared remarks, I made the comment around 15,000 to 20,000 gigawatts of -- 15,000 megawatts of generation by the end of the decade. If you think 7 of that's in Colorado, then the balance, 8 to 13 is a combination of SPS and NSP. There's very little in our capital plan, our Steel for Fuel plan that's included for those 2 regions in our capital plan or in our Steel for Fuel 2.0 that Brian laid out. So we have real generation upside investment opportunities. They're a little longer dated. So I think '28 to '30 maybe outside of the plan period. Some might creep into this 5 years, but I think it's really more backdated. But that's a substantial amount of generation in each of those two -- to those jurisdictions. We did go through a resource plan in Minnesota, the 1,200 megawatts that we referenced in terms of RP for next year as part of that program. But there's probably 4,000 to 5,000 megawatts of that is in the Upper Midwest, largely approved as part of our last resource plan that we need to go execute upon.

Yes. And we have -- as we mentioned we have the 1,200 megawatts of wind RFP in flight. We actually have Wisconsin RFP, solar RFP in flight that we're working on. we think we'll file another resource plan, but also significant opportunities in Minnesota longer date is around our wind repowerings. And the assets that we put in service in the 2018 to 2021 timeframe, we're requiring a couple of older ones that we brought forward to the commission and it's a great way to increase output and save our customers' money. And so we'll look at those as we get closer to the time period as another opportunity in terms of being able to buy savings for our customers and invest in steel in the ground.

Got it. That all makes sense. That's helpful to frame it up. And I was curious what's the latest that you're seeing in Renewables economics in terms of LCOE? In your service territories there's been market concerns about rising PPA prices inflationary pressures in the renewable supply chain. But just curious what your experience has been in terms of latest data points how attractive have renewables projects looked?

Yes, David, look, so the great benefit of the last couple of years is obviously the Inflation Reduction Act. We've definitively seen higher capital costs in wind and in solar, the IRA and the tax benefits of 100% PTCs have been able to offset that, at least in our jurisdictions on an LCOE business. So probably I'll give you some data points. I'd say we've seen probably 30 -- from our last approved wind project, which would have been our Dakota Ridge project, we built that for around 1,200, 1,250 kW, we've probably seen capital cost increases on wind or 30% to 40% on top of that. But the IRA has offset all of the capital cost improvements as well as NCS improvements as well as NCS improvements from better technology and the bigger turbines. Those 2 combinations have put our LCOEs on those projects in line with what we put wind into service for in 2018 and 2019. So we're really favorable participants. Our customers are great beneficiaries of the Inflation Reduction Act keep the levelized cost of energy very, very affordable for our customers. And when I think about -- I made the comment earlier around sort of economic development opportunities. We're putting wind in -- let's say we're putting wind in around $20, $22 a megawatt-hour. You compare that to offshore wind on the East Coast at north of $100 and we think over time lower cost energy will accrue an economic benefits to our regions of the country.

We'll now move to Travis Miller of Morningstar.

Just a couple of quick follow-ups to some of the earlier questions in your comments. That 1% to 2% moving the sales number to 2% to 3%, what's the approximate earnings impact there incremental, all else equal?

Just easiest rule of thumb is I'll call it a 1% change in sales, there's about a $25 million change in the revenue from our sales. So, that's a good rule of thumb for you, Travis.

Okay. After-tax, that's earnings, right?

No. That was revenue -- sorry, that's revenue. And that takes into account our true-up in decoupling mechanisms.

Okay. So, pre-tax. Okay. Got it. And then on the Heartland and some of the other projects you've mentioned in terms of new technology other hydrogen projects, is your thought for us is to put that through some of those things through the regulatory traditional regulatory process? Or do you foresee potentially coming up with another financing structure another corporate structure, is something that would house some of those projects that are say unusual in a positive way obviously?

Hey Travis, it's Bob. Good morning. Our proposed plan would certainly put the assets into regulatory rate base here in the Upper Midwest. If you think about our proposals at the DOE, we've got green hydrogen off of wind and solar. We've got pink hydrogen off of nuclear plants and the end users are going to help partners create green fertilizers, green ammonia to green urea to fertilizer, as well as some amount of blending into our gas plants and into our LDCs with some of the output. So the expectation is they would go through a regular state process around that capital investment and those ultimate uses for the fuel.

Okay. Perfect. And then real quick, Minnesota, any update on the timing of your appeal process?

Yes, so sorry, thanks. We went through a reconsideration process in mid-September. I think our appeal plan would be early November.

Okay. And then about how long does that take -- would you think?

Sometime into next year.

We'll now go to Ross Fowler calling from UBS.

So Brian maybe one for you, since you guys are sort of on the leading edge of lets transferability and feel free to take us offline, if we can't do it in seven minutes. But I'm just thinking through like how do you think about the accounting? Do you record the nonmonetary assets at fair value and then book a sort of gain and loss against that when you get to cash? Or there's no FASB guideline here right if I've got it right. So how are you walking through the accounting of these source ones that you're doing? And can we get clarification from FASB or the IRS at some point about how the accounting should work?

Certainly, we work closely with our audit firm on this and the audit firm is working with the -- the Big Four are working together. The way we look at -- it's an income tax model election for us. And so what that means is we're going to run it through the gains and losses through income tax expense on the income statement. And so any discounts on the sales will run through that and then from a regulatory approval of regulatory mechanisms for that discount whether we'll be able to have deferral treatment of the discount with our regulatory approval. So really because this is a benefit of our customers to be able to have that regulatory deferral mechanism is helpful. And then it will run through our cash from operations. So I think income tax expense line item and then cash from operations.

We'll now take questions from Paul Patterson calling from Glenrock Associates.

So all my questions have been answered, except for -- and congratulations. But just on Comanche. I saw that -- can you hear me? The Comanche litigation, just was wondering with the jury [ award ] and everything, where we stand with that? Is that pretty much over? And just if you could elaborate a little bit more on that.

Yes. I mean it's -- we will appeal. We feel that we have a strong legal challenge against -- there's 2 items and the award is related to lost power. I mean the majority upon no liability in all the other allegations, including no word for diminution of plant value. So as Paul mentioned in the opening comments, we view it as a onetime charge, and we have a strong legal basis for challenging that $26 million of award.

Okay. So that was what -- that charge -- that jury award was what was reflected in the third quarter results. Is that right?

That's correct.

We'll now go to Ryan Levine calling from Citi.

What's your current thought on PPAs buy-ins in light of some of the tax tenability dynamics and some of the developments that you're having?

Ryan, it's something we have nothing in our capital plans for PPA buy-ins or PPA buyouts as we think about it. It's something that can come through the RFP processes. As we think about it, and we work closely with our developers to see if there's an opportunity. The way I think about the opportunities may come in, if you can buy out a wind farm and repower it, that's where we've been successful with our PPA buyouts. But we think it has an incremental very opportunistic -- call it opportunistic, hard-to-predict opportunities, and that's why we don't put anything in our capital plans. But we do work closely with our developers to see if there's opportunities from time to time.

Okay. And then regarding the -- looks like $100 million DOE grant or wildfire mitigation, that's been rewarded more recently. As you go into a lot of wildfire mitigation plan and look at more spending, is there opportunities to receive digital brands? Are you pursuing any capital to automate your plan?

Ryan, it's Bob. I don't know if there's more dollars in the DOE bucket in the grid resiliency program. Obviously, we're going to take these dollars and continue to do additional work. Those were discrete projects that were approved with the DOE and are earmarked across our various states. Some of which is for wildfire. Some of it is in technology development. So we're excited about partnering with the DOE. It's about 60-40 split in terms of their funding versus our capital, and our piece is embedded within our forecast. So it's not going to be a big upside in terms of capital investment opportunities. But as we look to the long term, on wildfire mitigation plan. We're going to work with all of our stakeholders in our various states. But the wildfire mitigation plan in Colorado should get filed late this year or early next and look to be very proactive in how we handle system hardening, new technology to bring to bear to minimize the risk of ignition for our customers in the state, obviously, protecting their assets and their help is our priority.

Yes. And I was in just taking a step back. We're proud of the 4 grants that we've received really focusing on how can we help lower the cost of our customers, others for new technology around and specifically on the form long-duration battery. And not only do we get $70 million in deal refunding for that, but we also got $20 million from Breakthrough Energy Ventures. So $90 million for those 2 pilots. So really a great story and looking forward to working with our commissions on all the DOE funding that we've received so far. And certainly, we'll look for other opportunities out there.

As we have no further audio questions. I turn it for closing remarks. I turn the call back over to CFO, 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.

Thank you so much, sir. Ladies and gentlemen, that concludes today's conference. We wish you a very good day, and you may now disconnect.