Hello, and welcome to Xcel Energy's Third Quarter 2024 Earnings 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 on listen-only. However, you will have the opportunity to ask questions at the end of the presentation. I'll now turn the call over to Paul Johnson, Vice President, Treasury and Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to Xcel Energy's 2024 third quarter earnings call. Joining me today are Bob Frenzel, President, Chairman, Chief Executive Officer; 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 updates, update our capital and financing plans, and provide 2025 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 releases and SEC filings. Today, we will discuss certain metrics that are non-GAAP measures. Information on comparable GAAP measures and reconciliations are included in our earnings release. In the third quarter of 2024 Minnesota Commission disallowed $46 million of replacement power costs associated with the extended outage at our Sherco plant in 2011. As a result, we recorded a charge of $35 million, or $0.04, in the third quarter, which was in addition to an $11 million, or $0.02 charge, that was accrued in the second quarter of 2024 related to that matter. Given the nonrecurring nature of these items, both charges have been excluded from third-quarter and year-to-date earnings. As a result, our GAAP earnings for the third quarter of 2024 were $1.21 per share, while our ongoing earnings, which exclude this charge, were $1.25 per share. All for the discussion in our earnings call today will focus on ongoing earnings. For more information on this, please see the disclosure in our earnings release. I'll now turn the call over to Bob.

Thank you, Paul. Good morning, everyone, and thank you for joining us today. I'm pleased to report that we delivered another quarter of solid operational and financial progress. We continue to deploy capital for the benefit of our customers and communities and we enable a future powered by cleaner fuels and a more resilient and intelligent grid. We partner with stakeholders to encourage economic development, and we provide products and services capable of meeting our customers' most important needs. In the most recent quarter, we invested $2 billion in resilient and reliable energy infrastructure. We delivered ongoing earnings of $1.25 per share for our owners. We provided industry-leading storm response and strong customer reliability despite challenging conditions, and we accelerated our wildfire risk reduction measures to enable safer and more resilient communities. Xcel Energy's commitment to our communities and investors is anchored by our core investment thesis as a clean energy leader. For more than two decades, we've been a leading provider of wind energy and with our filed resource plans we expect to stay in that position. We've delivered on our earnings guidance for 19 straight years, one of the best records in the industry and looking to make it 20 this year. We have a long-term and transparent growth plan, making investments in clean generation, new and enhanced energy grids, and economic development programs to support our community's vitality. We've deepened our commitment to serve and support customer needs efficiently. For example, since 2020, our continuous improvement programs have saved almost $0.5 billion in O&M expense while improving operating outcomes and reducing risk. In addition, we've kept our O&M costs significantly below the rate of inflation over the last 10 years. And our Steel for Fuel strategy has delivered more than $4 billion in customer fuel-related savings since 2017. And finally, this discipline, alongside support of state and federal policies enable us to reduce emissions and keep residential electric and natural gas bills 28% and 14% below the industry average and growth well under the rate of inflation. We're $0.16 ahead of 2023 year-to-date earnings, and as a result, we are reaffirming our 2024 guidance of $3.50 to $3.60 per share, and we are initiating our 2025 earnings guidance range of $3.75 to $3.85 per share. Today, we're introducing our updated 5-year $45 billion capital investment plan, which centers on four key areas. Clean Energy, which continues investment in generation that provides customers with a secure and clean energy future while helping our states and our customers meet their ambitious policy goals. Customer electrification, which helps customers electrify their transportation needs, transitioning homes and businesses away from fossil fuel heating and converting fossil fuel loads to clean electric power loads. New load growth, which expands our electric system to support customers' surging demand and requirements over the next decade and beyond, and safety and reliability, which modernizes and hardens our system to ensure continued safe operations and address increasing risks from severe weather. There's a lot of focus across our industry and country regarding data centers. Xcel Energy has nearly 9,000 megawatts of opportunities in our customer pipeline before 2030. The scale of this pipeline gives us the ability to thoughtfully negotiate agreements that deliver the energy and capacity needed to important new customers in the region while protecting Xcel Energy and its customers and ensuring lasting relationships with our data center customers, ensuring that new data center load that's brought onto our system benefits all customers. It drives load growth to our increasingly decarbonized energy system, generates economic growth and vitality in our communities, and delivers on the national imperative to support a domestic data center industry. As a result of these guiding principles, we anticipate we will secure contracts with about 25% of this pipeline in the five-year forecast period. We also expect these opportunities to continue to grow, and the need extends well past the next decade. We previously signed data center agreements with Meta and QTS and completed land sales with entities, including Microsoft to support new facilities. In October, a new data center customer completed a land acquisition in our service territory, and we're in the final stages of signing service contracts with that party. Turning to the supply side of the equation, we continued progress during the quarter on our clean energy transition through multiple resource planning and RFP processes. We reached a settlement in our Upper Midwest resource plan. And as part of that settlement, 720 megawatts of company-owned natural gas CTs and battery investments were selected. In addition, the agreement reflects the need for an incremental 4,200 megawatts of wind, solar, and storage, a portion of which is included in existing RFP solicitations. The settlement is pending a decision by the Minnesota Commission, which is expected in the first quarter of 2025. In October, we made a new energy resource filing in Colorado called the Just Transition solicitation. Our projections indicate the need for up to 14,000 megawatts of new generation to meet the phase-out of our coal plants, to accommodate increasing demand from data centers and to achieve state and customer emissions goals. We anticipate a decision on that filing in fall of 2025 with RFPs to be issued in early 2026. We're working on our solicitation and SPS, which could ultimately yield more than 5,000 megawatts of renewable and firm dispatchable generation. These are due in January of next year, and we expect commission approvals in 2026. Protecting our customers from the threats of extreme weather also remains a top priority. In August, severe thunderstorms brought heavy rain, hail, and winds of over 60 miles an hour to customers in Minnesota and Wisconsin. Xcel Energy employees and contractors safely and promptly restored power to over 250,000 customers who lost service during those storms. We're thankful for the dedication of our employees and contractors that ensure that our communities continue to have safe and reliable service that they expect from Xcel Energy. In addition, we'd like to thank our crews who've worked tirelessly to provide mutual aid assistance to other utilities to support recovery and restoration efforts from the devastating hurricanes Helene and Milton. Regarding wildfire risk reduction, we continue to make progress on our accelerated wildfire mitigation efforts as well as our Colorado wildfire mitigation plan filing. In the fourth quarter, we anticipate filing our Texas resiliency plan, which will include wildfire mitigation in the Southwest. Finally, turning to a tradition that I'm very proud of, during the third quarter, nearly 2,200 volunteers from Xcel Energy in our communities took action to support nonprofit organizations during our 14th annual day of service. Volunteers dedicated almost 8,000 hours to support 125 projects for nonprofits across our eight states. We're grateful to the thousands of volunteers and nonprofits that come together year after year to put good energy into action that fuels growth, influences change, and lifts up our neighbors. With that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. Starting with our financial results, Xcel Energy had ongoing earnings of $1.25 per share for the third quarter of 2024 compared to ongoing earnings of $1.23 per share in 2023. The most significant earnings drivers for the quarter included the following: outcomes from rate cases and nonfuel riders increased earnings by $0.25 per share and higher AFUDC increased earnings by $0.04 per share. Offsetting these positive drivers were higher O&M expenses decreased earnings by $0.09 per share. Higher depreciation and amortization decreased earnings by $0.08 per share, reflecting our capital investment programs. Higher interest charges decreased earnings by $0.08 per share, driven by rising interest rates and increased debt levels to fund capital investments and other items increased earnings by $0.02 per share. Turning to sales, year-to-date weather and leap year adjusted electric sales increased 0.2%. However, third-quarter weather adjusted sales increased 1.3%, based on our forecast, we are reaffirming our full-year guidance of a 1% increase in weather-adjusted electric sales. Our new five-year plan includes 5% per year electric sales growth, of which approximately 50% is from data centers with other growth coming from the oil and gas industry and EVs. Our sales forecast only assumes contracted or high-probability data centers. We also expect that large data center load growth will continue beyond our five-year plan, and there is upside to what we have included. Year-to-date, O&M increased $58 million, primarily driven by increased generation maintenance, damage prevention, wildfire mitigation, and storm expenses. In addition, we are facing increased costs from our recent excess liability insurance renewal. As such, we are revising our full-year O&M forecast to a 3% to 4% increase relative to 2023. During the quarter, we also made progress in several rate cases. Earlier this month, the Colorado Commission completed deliberations on our natural gas rate case, which reflects an estimated rate increase of approximately $130 million which includes $15 million of incremental depreciation that was not included in our original request. The decision was based on a historic test year with an average rate base and a weighted average cost of capital of 7%, reflecting an ROE range of 9.2% to 9.5% and an equity ratio of 52% to 55%. Rates will go into effect in November. In early November, we plan to file a Minnesota Electric Rate Case, seeking a rate increase of $490 million over two years based on an ROE of 10.3% and a 52.5% equity ratio. We're also requesting interim rates of $224 million to go in effect in January of 2025. The final decision is expected in 2026. We continue to make progress in the Smokehouse Creek wildfire claims process. We've settled 86 of the 179 submitted claims, which we view as a positive and constructive outcome, 23 lawsuits have also been filed. In addition, there is no change to our estimated accrued liability of $215 million. As a reminder, we have approximately $500 million of excess liability insurance coverage for this fire. Shifting to our investment plans, we provided an updated $45 billion five-year base capital expenditure forecast, which reflects annual rate base growth of 9.4%. These investments are critical to serve growing electric demand, meet clean energy goals, and ensure system safety and reliability. We have an additional $10 billion plus pipeline of potential investment, which we view as conservative and could be significantly higher. This additional capital reflects generation from RFPs and resource plans, load growth from data centers, beneficial electrification, and additional transmission, including opportunities from MISO Tranche 2 and the Southwest Power Pool. We also refreshed our base financing plan which reflects approximately $19 billion of debt and $4.5 billion of equity. We anticipate that any incremental capital investment will be funded by approximately 40% equity and 60% debt. It's important to recognize 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. As a result, you'll notice we issued $1.1 billion of equity via our ATM program this year. This equity issuance is not part of our 2025 to 2029 financing plan and reflects our commitment to credit quality while delivering on our long-term financial objectives. Maintaining solid credit ratings and favorable access to capital markets are critical to fund the clean energy transition, deliver strong shareholder returns, and keep customer bills low. Moving to earnings, we are reaffirming our 2024 ongoing earnings guidance range of $3.50 to $3.60 per share. We are also initiating our 2025 earnings guidance range of $3.75 to $3.85 per share, which reflects 7% growth from the midpoint of 2024 guidance. Key assumptions are detailed in our earnings release. We are updating our long-term EPS growth objective to 6% to 8% with expectations to deliver earnings in the upper half of the range. The increase in the EPS growth rate reflects our significant investment pipeline and confidence in our financial outlook. We also modified our dividend growth objective to 4% to 6%, with the expectation to be at the low end of the range. A lower dividend growth rate allows us to retain additional cash flow to fund growth and lowers equity funding needs. In addition, that will lower our dividend payout ratio over time, which provides greater financial flexibility and drive power for the future. With that, I will wrap up with a quick summary. We reached a settlement in our Minnesota resource plan and filed our latest Colorado resource plan, which allow us to lead the clean energy transition, ensuring customer affordability and reliability, while driving economic growth. We continue to make progress on our wildfire mitigation plans, which reduced risk from extreme weather. We announced an updated capital investment program that provides strong, transparent rate base growth and significant customer value. We provided a balanced financing plan to fund accretive growth while maintaining a strong balance sheet and credit metrics. We are on track to meet our 2024 ongoing earnings guidance and have provided 2025 guidance consistent with our growth objectives. We revised our long-term earnings growth to the upper half of the 6% to 8% objective range and dividend growth to the low end of the 4% to 6% objective range, which is indicative of our significant capital investment pipeline. This concludes our prepared remarks. Operator, we will now take questions.

Thank you very much. Our first question is from Nicholas Campanella with Barclays. Please go ahead.

Hey, good morning. Thanks for taking my questions.

Good morning, Nick.

Good morning. So, I just wanted to ask, you talked in your prepared remarks, you had a customer make a large land acquisition. Where was that exactly? Was that in Minnesota, or could you provide more details on that? And then is that included in this 5% kind of consolidated load growth outlook long term for the company, or is that pressure higher? And then how do we think about rate design there? I know that's a lot in one. Thanks.

Hey Nick. Good morning. Undisclosed customer, but yes, it was in Minnesota. And that's one of the, call it, as we think about high-probability loads. We've been, as you can imagine, in active discussions with them and significant progress on services agreement. So, great to see the continued progress we have on the data center front. And so I mean, we’re getting into as part of the negotiations, you get into rate design and in terms of pricing, but I think, it's important as Bob laid out the guiding principles and how we think about it and ensuring that all of our customers benefit from these large loads that come on, sort of help drive economic growth for our state, but also benefits all of our customers. I think it's just something I'm not sure if people caught it, but there was a planning session at the Minnesota Commission on Tuesday that included the data centers, IBEW, Department of Commerce, us, and other significant stakeholders, talking about how do we support and move faster on the data center front. And so, we're pretty excited about those conversations. It's not really constructive and look forward to working with our commission on these opportunities.

And Nick, just to answer, I think, probably part two of a three-part question was, is it included in our forecast? So we’ve got about a quarter of that 9,000 megawatts included in our five-year sales forecast. This land acquisition would be one of the projects that would be a part of that forecast. Obviously, we think that this is a trend that’s likely to continue in our regions for a lot of reasons, and we have real confidence in our ability to meet that forecast as well as to continue to see sales growth transition into our regions over time.

Hey, that’s great. I appreciate that. And maybe a one-part question. But on the financing, I know you’ve priced the $1.1 billion, are you done for the year? Would you derisk the five-year plan at this point? And what’s the right mechanisms to do that in your mind? Thanks.

Yes, Nick, thanks for the question. Yes, as you can see, we did about $1 billion of ATM issuance in Q3. So certainly, a very strong quarter for us. And that does fulfill our equity needs for the year. That's our plan for the year. Now it doesn't mean that we can't be opportunistic if we think through the end of the year, we like something. Actually, we don't need to do anything through the end of the year. Second part of your question, look, we view an ATM, and we've always talked about this, it's an efficient mechanism to get our equity issuances one. But it doesn't mean we won't look at all other products and options on the table as we move forward.

Thank you so much.

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

Hi. Good morning.

Good morning.

Can you hear me okay?

We can hear you.

Great. So, just wanted to reconcile the CapEx increase with the equity, because I think, CapEx went up about $6 billion of equity and we went up $0.5 billion. So, it’s kind of a lot less than that 40%-60%. So, is that because you prefunded some with this $1 billion, is that because cash flows just getting better, or just how should we think about that?

Yes. Hey Steve, a couple of things, and thanks for the question. One, you're right. Generally, we guide investors to a 40%-60% mix. Part of that is we do get a little bit of benefit as we lower the dividend growth rate that I talked about that helps a little bit in the five-year, but also gives us more dry powder longer term. But it’s really about kind of the cash flow and the timing of the capital. And if you look at how we design it, when we put together that slide around the credit metrics, our credit metrics are very stable. Generally, still going forward, we expect that 40%-60% mix, but we were able to be a little bit flexible here and not have as much equity as we needed as we roll forward our five-year.

Okay, great. That’s helpful. And then totally separate question, just knock on wood, we’re getting, hopefully, near the end of wildfire season, if it ever ends, and we haven’t seen anything happen. So maybe you could just talk to Bob, maybe just talk to the actions that you’ve taken on wildfire mitigation, how you feel they’re working, what else you might do? And just – and then related, could you just clarify the insurance amount? And are you including deferral of that in your guidance? Or are you assuming you have to expense it in 2025? Or yes, that would be helpful.

Yes, great questions. Appreciate it. I’ve said before, I’m very proud of the activities and the accomplishments that the company has executed to protect our customers and our communities since the March timeframe. I think we’ve really built a lot of muscle around our wildfire protection mechanisms. First and foremost is operating the system with safety, so our capabilities in both enhanced power line safety settings and our abilities to execute PSPS is first and foremost in our minds of what helps protect our customers and communities in that process. I think we built a lot of muscle and capability there. Over time, we know that we have to harden the system and segment the system, and we take a lot of lessons learned from our peers in California and what they’ve done in terms of situational awareness, the ability to see whether coming sooner, the ability to alert their customers faster and more confidently in their ability to segment the system, so that the impacts of EPSS or PSPS are mitigated or muted in that process. We’ve been working on the intelligence side of that. We’ve installed AI cameras. We’re starting to look at weather stations and starting to incorporate other data feeds in this timeframe. Again, huge benefits from being a fast follower here to what other people have plowed ground on and the learnings that they’ve had over a decade of dealing with this kind of risk. On the regulatory side, obviously, we’re moving forward with our wildfire plan in Colorado and a system resiliency plan in Texas. All of those will help us to accelerate pole inspections, accelerate replacements of anything that we see out there, more aggressive vegetation management. I think we’ve done a lot to protect the system in the short-term. As we go forward, our actions are going to be very much focused on how we mitigate the impacts on our customers over the long-term and making sure that we have a resilient and safe system into the future.

Hey Steve, I’ll handle that second part of the question around just insurance deferrals. We completed our insurance renewable this month, premiums are significantly higher as we kind of alluded to in Q2. We saw premiums triple on us capacity did shrink some. So we do have – we have a regulatory deferral docket in front of the Colorado Commission where they have a sudden expedited schedule to get decision by the end of the year. We’re in discussions with our peer utilities and staff in Texas around the industry issue around increasing excess liability premium. So we do include constructive regulatory outcomes in our 2025 guidance, and that is included getting recovery of our deferrals and constructive cost recovery around our wildfire mitigation plan is an overall part of our constructive regulatory outcomes for 2025.

Okay. Thank you.

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

Hey, good morning. Thanks for taking the questions and for the updates. Maybe just start on the new capital plan, I guess how should we think about the kind of $6 billion capital increase relative to the 40 basis points increase in the rate base CAGR. Is that just a function of base effects rolling forward the plan in other years? Or anything else that we should be keeping in mind there?

No, Carly, you’re exactly right. It’s just a function of rolling forward and having a bigger base as we roll forward to the next five years. So that’s all it is a function of nothing else going on.

Got it. Okay. Great. And then maybe to follow up, just on the 5% new load growth forecast, you mentioned in the slides that being sort of back-end loaded due to the timing of data center load coming in. So is there any other granularity you can provide in terms of sort of when you expect to see that more significant inflection in load and any sense of the magnitude there?

Yes, Carly, I think if you look at our 2025 guidance, our sales guidance is 3% for 2025 and expect it to go up there to 5% to 8% in the years after that and really peaking in 2020 as we see it and that’s really driven by, like I said, kind of a combination, which is what we view as a great to have the diversity. Half of that sales growth of the 5% is coming from data centers. But we also have significant growth in the oil and gas region in SPS out of the Permian Basin, and we’re starting to see the effects of beneficial electrification around EVs and other BE in Colorado that helps drive kind of the other part of that growth. So I think we see kind of more kind of middle to back end weighted, but also having this diversity in growth is helpful in the overall plan.

Great. Thanks so much for the color.

Thank you. Our next question is from Jeremy Tonet with JPMorgan. Please go ahead.

Hi, good morning.

Hey, good morning, Jeremy.

And Happy Halloween. Thank you for all the details that you provided on the call today. Just want to come back to kind of high-level thought process here. Historically, you’ve stuck to the conservative 5% to 7% EPS CAGR with the plus more recently, but noted that there are all these array of new opportunities that you talked about. And so just wanted to get, I guess, your thought process on moving it to 6% to 8% CAGR at this point. And it sounds like you’re still at the high end there. So I just wanted to kind of walk through that a little bit more if possible.

Yes. Hey, Jeremy, good morning. I think about it in two ways is one, if you just look at our base plan, the majority of that capital is investing in our wires business, right? We’re focused on that kind of safety and resiliency in our wires business, and that base plan drives 9% – 9.4% rate base growth. But then it’s all about the additional steel underground related to the projects we need to deliver on retiring our coal plants, as Bob talked about, and executing on 5%-plus electric growth. We view that as a tremendous opportunity. We’ve talked – Bob talked about our resource plans in flight. When you add all those up, there’s between 15,000 and nearly 30,000 megawatts of generation we need to add to our system to serve our customers over the call through 2030. So a huge opportunity. I think the other part is we’ve demonstrated through the RFP process recently, that can be extremely competitive in these generation procurement processes that we have a top-tier internal regulated development team that can bring projects that are very competitively priced. So we expect to build a now, and I would say, at least $10 billion of those pipeline of projects. That’s why we’re sitting here very confident about not only the next five years, but longer-term executing at an upper half of the range and potentially going above it.

Got it. That’s very helpful there. So with that last comment potentially going above it, I thought it might be too early to ask there, but I just wanted to dive in a little bit more. I think you talked about three buckets that feed into the incremental CapEx opportunity. Can you weigh out I guess, over the next 12 months what some of the milestones could be and kind of what would it take to move more of that into plan?

Yes. So let’s hit the first ones that are more near-term. MISO tranche 2.1, which we should get a decision by the end of the year. Then we’ll need to go through the regulatory approval processes. But that’s roughly about $2 billion of transmission opportunities. We got the SPP, ITP that was just approved by the Board this month. That’s another about $2 billion of projects that we expect to be awarded to us because of reliability-driven projects, meaning that the need is within a few years. So those are kind of the transmission buckets. The SPS, RFP is another big bucket, 5,000 to 10,000 megawatts. We’ll get bids in, in January. The first look investors will probably get is roughly probably Q2 of next year when we file our preferred portfolio of New Mexico. So that will at least get some insight into that with approvals going into 2026 for that. The Minnesota resource plan, we should get a Q1 decision out of our commission on the overall resource plan, which includes, as Bob mentioned, 720 megawatts of storage and CTs in there, along with some additional RFPs we’re working through. Finally, related to Colorado, we just filed the Colorado resource plan, which we’re pretty excited about with upwards of 14,000 megawatts in that we’ll work through that resource plan, call it, within a year, and then we’ll file RFPs. So that will be a little bit longer dated on all the opportunities. But you’ll continue to see execution opportunities throughout the next 12 months to 24 months for us.

Jeremy, just to add on to Brian’s comments, I’m really excited. We’re starting to see this energy transition we’ve been talking about and working on for the past five years, really start to accelerate as we start to get to the periods where we’re proactively removing our coal plants from the system and replacing them with cleaner and, in some cases, lower-cost generation resources. Brian is right, the development team that we’ve built in-house, starting with our 2017 steel for fuel plan has been an incredible asset for the company. I’d be remiss if I didn’t talk about our transmission capabilities. Obviously, we have a lot of transmission to build in the company and across the country. We’ve been the leading provider of new line miles of transmission over the last 15 years as a company. With all the projects we mentioned here, whether it’s the Colorado Power pathway, whether it’s LRTP2.0, 2.1 billion the ITP process in the Southwest. We’ve got a terrific transmission development construction team here that are helping us execute on a very strategic asset for the company and the country.

Got it. Exciting times ahead. Thank you for that.

Thank you. Our next question is from Julien Dumoulin-Smith from Jefferies. Please go ahead.

Hey, good morning, team. Keep going, I’m super impressed, so thank you. Look, I wanted to follow up on the 6% to 8%. And obviously, the timing here is obviously coincident with an accelerating backdrop on sales growth here. But what does that say about confidence in wildfire outcomes in your mind? Is there anything implicit in the read into this? I mean, again, somewhat of an unknowable, but I’m just curious if there’s anything that you see in a litany of recent developments on that front as well here, if you can.

Look, I'd suggest – sorry, Julien, it's Bob. Thanks for the question. First of all, as I think about wildfire current proceedings as well as litigation and long-term outcomes in our states. I feel confident in our wildfire position, both from my comments earlier on what we're doing to protect the customers and the community going forward. Our position is unchanged as it pertains to our litigation matters, both in the Southwest and in Colorado regarding Marshall and Smokehouse Creek, long-term, I think we're doing the right things in the system to harden it and protect our customers. There's obviously some investment that's needed there. I would suggest that obviously 6% to 8% is an ongoing earnings number. If we had an unexpected outcome in any of the proceedings, we'd have to accommodate that. But our position has been – we didn't work – we didn't act negligently in our systems in the Smokehouse Creek. Our accruals are consistent quarter-over-quarter and within our limits of our insurance and we look forward to working through those proceedings and really getting behind us and starting to partner with our communities as we move forward in time with our resiliency plans.

Okay. All right. Fair enough, Bob. And actually, just going back to Steve's question for earlier and for the record, I get Jeremy all the time. Just on what we said, you mentioned EPSS and PSPS. I mean these are obviously terms we know well from California. I mean, given – you talked about being a fast follow, how quickly can some of this be implemented, right, in terms of achieving meaningful derisking of the system here? I mean what kind of time frame are you looking at? I mean it seems like some fairly readily implemented kind of solutions.

So look, I think quickly, and I mean that in a – the – we have the capability to do the PSPS today. We have the capability to do EPSS today as we think – and every single day, we do a wildfire risk assessment on the conditions across our system across all eight states and make decisions on how we position the system, how we set up breakers and how we set up controls. I think probably the difference between where we sit and where some of our peers in California said is the granularity with which we can do that. Our protection may come at an entire feeder level, which might be a 10-mile long stretch of distribution line. Our goal in the future is to be able to segment that distribution line into much more manageable, maybe one-mile chunks instead of one 10-mile chunk, so that we can be more targeted with the protections and more protective of customers. So I think as the final analysis is we have great sort of bulk protection systems. We need to get – I would say, we're working with a sledgehammer today. We need a scalpel in the future, and that takes investments over time. But I think from a true protection mechanism, we've got a lot of the capabilities that we need. It's just a little bit blunter than we'd like.

Excellent. All right, guys. Congrats, again. Nicely done.

Thank you. Our next question comes from Durgesh Chopra with Evercore ISI. Please go ahead.

Hey team, good morning. Thank you for taking my questions. Just maybe on the – good to see the equity out of the way for this year, strong quarter, Brian, like you mentioned. Maybe just how should we think about the timing of the $4.5 billion that is in the plan? Is that ratable over basically the same amount over a year annually or back-end loaded? Just any color there?

Yes. Hey, good morning, Durgesh. Yes, I mean I think you've heard us before, we don't necessarily comment on – or give guidance on the timing of our equity, but here's the way to think about it is if you look at the shape of our annual CapEx over the next five years, that's a good way to assume it kind of follows that shape as our annual CapEx is larger in the first few years. So that’s how I'd think about it.

That's helpful. Thank you, Brian. And something that is near and dear to you, the transferability. Maybe just help out what portion of the CFO in the plan is transferability, how are you doing there versus your annual target for 2024?

Yes, we've executed all of our credit sales for 2024, working on 2025 significant demand. It's kind of in and out, right, in terms of giving the customer what the offset in revenue and then we used to pick it up on the tax line. So from a cash flow perspective in and out, we've had many discussions about this, I think we lost as leaders in this in terms of the opportunity. Also working with the large buyers of this. It's helpful to have – we have 17 Fortune 500 companies in our backyard here that we know extremely well. We’re not only looking at 2025, but also longer-term deals and getting the pricing we expected. Overall, we expect we'll be monetizing $700-plus million of credits annually going forward and the markets there, and it's been a great tool to have.

Thanks, Brian. How much do you do this year? Can you just remind us quickly?

Roughly $400 million to $500 million.

Thanks so much. Congrats.

Thank you. Our next question comes from Ross Fowler from Bank of America. Please go ahead.

Good morning, Ross.

Good morning. So just a couple of things. Maybe winding back to the Marshall Fire a little bit. We saw the judge's order on September 30 on the 25 trial. So obviously, now we're talking a different level of multiplier from that, and we sort of bucketed it in two pieces from what I can tell. So is there any reduction or settlement of claims related to that? Or how do we think about the calendar from here given that, that order is out?

Okay. Ross, it's Bob. Let me try to address what I think your question is. First of all, in Marshall, let's start with, we don't think we acted negligently. We know that the fire was started on the 12 tribes property; the first ignition occurred there. We don't believe we acted negligently in the operation of our system, and we dispute the Sheriff’s Report that we called the second ignition. Notwithstanding, the litigation persists and the structure of the trial was architected in the judge's orders about a month ago. The way they've constructed it is the first trial will determine liability and the issue did Xcel Energy's equipment start a second ignition as part of the process of the overall fire. We'll use a second trial, if necessary, to determine damages, and then each individual claimant will have to prove up their own damages. We’re not going to have a sort of blanket claim or a blanket number applied to any challenges. We think that the trial structure was constructive from the judge's perspective. That's what happened in September. I'm not certain if I answered your question or not.

Yes. And I think the other part is just that in terms of – I think you're asking a little bit about the multiplier effect where the actual jury would have to hear each award damages and can have a multiplier across all plaintiffs. So helpful. I'll come in that regard.

And then next calendar steps, what should we look for as the next sort of thing to watch for here in the process?

So we're in diligence right now, heavy diligence; the trial set for next September for a couple of weeks. So I think we've got a while before there are any real milestones in the trial going forward.

Okay. And then you go through in the slides today on Slide 11. You're well below the national average in most jurisdictions on bills. So maybe contextualize, there's a lot of increase in CapEx here and really good rate base growth. Have you sort of laid out what that increase would be the customer builds over the course of the forecast?

Yes. Look, I think that we sit in a really good starting position, as you mentioned, and it's for a host of reasons, obviously. And as we move forward through time, we actually think the bill impacts are relatively benign as well. We sit in a region that is incredibly advantaged for renewables. This opportunity to invest in clean generation and maybe even fractions of the cost that other parts of the country see is really what helps us keep bills low for our customers. A couple of other mechanisms. Obviously, we've been very prudent in managing our operating expenses over a decade and that helps keep bills well below the average. We have very proactive and productive energy efficiency and demand management programs, which help our customers manage the size of their energy usage and the access to lower-cost energy helps along the way. The best thing we've done is we filed in our Colorado just transition solicitation proceeding, we filed a 20-year plan in Colorado that incorporates all the investment that's expected in Colorado over that period and yielded a customer bill increase of about 2.2% over that long duration. There will be ups and downs from that number, and it won't be linear along the way, but we think it's relatively manageable. We’re always looking for ways to mitigate even those types of increases through, again, very aggressive cost management. Our 1X LNG Way program I mentioned in my remarks has delivered real benefits and avoided costs to our operating expense line and to our fuel line.

Yes. I'd just add, I think that's something we're really proud of. You mentioned Slide 11, but the slide before that around all residential share of wallet is something we're really proud of. Our bills on inflation-adjusted are lower than they were a decade ago. If you look at our two biggest jurisdictions, Colorado's second lowest of the country in share of wallet, Minnesota is fifth lowest in the country in share of wallet. We're starting from a really good place too, as we think about the significant investment cycle. I appreciate the question on that.

Thanks, Brian. Thanks, Bob. Great update today.

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

Hi. Good morning, everyone. Congrats on a great update around here. A couple of questions for me. You guys have a couple of settlements in front of the Minnesota Commission. One is the resource plan gas rate case. Any reason to think that some items in those two maybe controversial and caused some delay in the settlement approval?

Hey, Sophie, good morning. Let me take first one Minnesota gas case, unanimous settlement, I think, is very straightforward. ALJ recommended approval of our settlement this month. We expect the commission decision in Q1, so certainly optimistic that it will be approved. On the resource plan, I think, again, those settlements with the major stakeholders interveners in that document. It really demonstrates our work with our stakeholders going forward, a settlement that not only addresses the resource plan into really an expeditious manner, which is great to see, but also resolves one of our RFPs outstanding. Overall, I think we're pretty excited about the work in partnership with our stakeholders and the resource plan and hopeful the Minnesota Commission, which would be a Q1 event, too.

Great. Great. Great. Thank you. And then on kind of like an wildfires, I know industry has been talking for a while about legislative solutions to that. I'm just kind of curious if you have any insight into which states where you operate or other states maybe in the West may take that up and come like session? Is there any kind of data points on that right now?

Sophie, it's Bob. From a regulatory perspective, obviously, we think Colorado will take up, and we expect a decision in our wildfire proceeding in August of this year – we, sorry, August of next year. Our resiliency plan in Texas, the commission has been working through those dockets very efficiently. We expect outcomes in Texas next year as well. On the legislative front, I think that's probably a longer burn candle, making sure we look at the legislation in all the states. I think it's topical for certainly all the Western states as we move through time. I'm not certain, I'd suggest there's a lot of outcomes that we expect in 2025, but a lot of dialogue around how do we protect customers and communities in those states.

Yes. I'll just add, a lot of focus on education with our stakeholders and our legislature's partner in Colorado, and we're also working with our peer utilities in Texas on that front in terms of talking to stakeholders on Texas. It's also one of EEI's primary topics and issues that they're looking to address. So very topical for our industry, and we'll continue to work with our states to see if there's longer-term solutions.

Thank you. Appreciate the color.

Thank you. Our next question comes from Travis Miller with Morningstar. Please go ahead.

Good morning. Thank you.

Hey Travis.

I know this is no longer the hot topic, but green hydrogen, I wondering if you had any update on where you all stand. I know that was a big initiative for you at least several quarters ago. Does it show up in pluses or minuses show up in the new investment plan, hydrogen hubs, any updates just generally on the green hydrogen initiatives?

Yes. Thanks for the question. You're right. It's sort of been a bit on the back burner for the company and probably for the country as well. We're still seeing progress made in Europe around hydrogen. I saw a big energy pipeline complex get approved in Germany. This has been a big priority for the DOE, and I've been on record saying that the country needs a cleaner molecule. Hydrogen is probably the most flexible one that we've seen. Whether it's used in its pure form as green hydrogen or it's combined with CO2 to make something more like a clean fuel, like green methane. I think that we're going to need a molecule like that in the country for industrial processes. It has slowed down in its initiatives. We were a recipient of a hydrogen grant with the DOE and that work continues, albeit fairly slowly. We're still really waiting on regulations coming out of treasury final regulations on 45Q that would be on the production tax credit for hydrogen. A little bit back burner for us. I still think it’s a promising technology. As you look at the increase in growth that we’re seeing across the country in terms of electricity, firming up wind and solar is going to need to happen. It’s likely to happen with gas and batteries in the short term. Over the longer term, maybe a combustion turbine fired on a cleaner fuel is the path forward. We’re seeing acceleration in nuclear R&D. You might see some acceleration in green hydrogen, R&D, and advancements in the cost curve because I think the need is going to be higher as we move forward in time.

And nothing is included in our capital forecast for hydrogen?

Nothing.

Did I hear you, is that right?

Correct.

Okay. Okay. And then you kind of answered my question, but the resource plans, then it's too early to expect any kind of green hydrogen.

Yes, that's correct.

Okay. Okay. That's all I have. Thanks so much.

Thanks.

Our next question is from Paul Patterson from Glenrock Associates. Please go ahead.

Hey good morning.

Hey Paul.

Just back to the, I guess, Ross's question on the rate trajectory, I guess. You guys think you mentioned 2.2% in Colorado. Is that over the next few years? That sounds like a long-term thing. I'm just wondering just – I know you guys have a difference in expectation in terms of sales growth and what have you. I would assume that would offset a lot of this over the next few years. Is that kind of the area we should be thinking about just rough obviously, it's going to vary. But is that kind of roughly what we should be expecting around your service territories in the next three years or so just in that neighborhood?

Hey Paul, this is Brian. What Bob was mentioning was in our Colorado resource plan; we filed a longer-term rate trajectory that encompasses all of our expected investments over. It was a five-, 10-, 15- and 20-year period Bob was mentioning the 20-year numbers where you had a 2.2% rate growth over that time period, so right in line with inflation. That included rate base growth of 9%, so significant investment. Retail sales growth of roughly 5% for the time frame helped to offset that, which is really a point is those large loads can help provide customer headroom and bill headroom for all of their customers. So a good piece of analysis that we included in our Colorado resource plan. I think over the next five years, look it's going to vary by jurisdiction. Over the next five years, we're roughly seeing about a 3% bill impact which we think is very manageable longer-term opportunity as we showed in the Colorado resource plan to have the large – to have kind of customer bill headroom created from the significant growth we're seeing across different industries.

Okay. And then just on Slide 9 and the sort of the potential there on data centers. Just could you just remind me what that means? These customer requests and I guess sort of the cadence that we might see in terms of, I mean, just there's a huge delta between the two. Just if you could, I'm sorry, if you could just sort of elaborate a little bit more on that, what that...

Sure. That's – when you think of that as our pipeline of requests that we've actually taken in our – from our economic development team. But then it's – then how we get down to the high probability lowered is what Bob talked a little bit about is through publicly announced projects, we signed agreements whether they've acquired land or purchased from us and we're close to signing maybe in the next 12 months. So that's kind of how we bring that down to that 2.6% growth that we include on that slide. What this also demonstrates is if a high-probability load doesn't come to a first on, there's a significant pipeline behind it. Not only do we think that's conservative, but we also see this growth extending beyond 2029. We just give you a five-year sales growth number, and we expect that to continue to build in our opportunity where we're focused on is continuing to help serve these data center customers in the long-term.

Awesome. That's the sort of the very specific company answer. I think what you're seeing, though, is obviously big demand across the country. We know there's double counting in a lot of people's inbound requests as these large loads come looking for transmission and generation service, but it highlights a different need, which is we as a country, we as an industry need to be accelerating our ability to develop both transmission and generation to serve the load that we think is on the come. On the face of it, it's a meaningful load. It's a little more concentrated. If you can provide it across the entire country, it seems manageable as you get into very specific load pockets, it comes with a lot of need and a lot of speed that's needed. We think about a pace and a scale of both investments to meet this need as a company and as a country and partnerships with our stakeholders and local communities, regulators, and legislators coming together to make sure that we can solve this opportunity for the country as we see it. As you mentioned, a rising tide lifts all ships. If we have a higher load factor on our system, that brings the per unit cost down for everybody. Today, if the country has a load factor in the 40% to 50% with high load factor customers like these with EVs charging at night with other high intensive energy loads, I think that is an opportunity for us to mitigate cost increases across the entire country as we transition both our transmission and generation footprint for the next generation. I'm excited about it. I really am. It's an opportunity that we're going to have to step into very quickly and in partnership with a lot of people and some new people at the table, but I'm excited about all of it.

Awesome. Appreciate it. Thank you.

Thank you very much. As we have no further questions in the queue, I would like to turn it back over to CFO, Brian Van Abel, for any closing remarks.

Yes. Thank you all for participating in our earnings call this morning. Please contact our Investor Relations team with any follow-up questions.

Thank you very much. That concludes today's conference. You may now disconnect.