Hello, and welcome to Xcel Energy 2023 Year-end Earnings Conference Call. My name is Melissa, and I will be your coordinator for today's event. Please note, this conference is being recorded. [Operator Instructions]. Questions will only be taken from institutional investors. Reporters can contact Media Relations with inquiries, and individual investors and others can reach out to Investor Relations. I'll now turn the call over to Paul Johnson, Vice President, Treasurer and Investor Relations. Please go ahead.

Good morning, welcome to Xcel Energy's 2023 Fourth Quarter Earnings Call. Joining me today are Bob Frenzel, Chairman, President, Chief Executive Officer; and Brian Van Abel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer your questions if needed. This morning, we will review our '23 results and highlights, share recent business and regulatory updates and provide updates on our long-term growth plans. Slides 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 both anticipated are described in our earnings release and our SEC filings. Today, we'll discuss certain metrics that are non-GAAP measures. Information on the comparable GAAP measures and reconciliations are included in our earnings release. In the fourth quarter, Xcel implemented several workforce actions to streamline the organization, ensure resources are aligned with business and customer needs to ensure our long-term success. Xcel initiated a voluntary retirement program under which 400 non-bargaining employees retired. In addition, we eliminated 159 bargaining positions. As a result, we recorded a workforce reduction expense of $72 million or $0.09 per share in the fourth quarter of '23. Also in '23, we recorded a charge of $35 million or $0.05 per share related to a legal dispute between CORE and Xcel Energy regarding prior year operations at the Comanche 3 coal plant. Given the nonrecurring nature of these items, both have been excluded from ongoing earnings. As a result, our GAAP earnings were $3.21 per share, while ongoing earnings which exclude these nonrecurring charges were $3.35 per share. All further discussions in this earnings call will focus on ongoing earnings. For more information on this, please see the disclosures in our earnings release. With that, I'll turn the call over to Bob.

Thanks, Paul, and good morning, everybody. We had another successful year at Xcel Energy continuing to provide our customers with safe, clean, reliable and affordable energy while delivering an operational and financial performance. In 2023, we executed on the largest capital program in Xcel Energy history, investing approximately $6 billion to improve resiliency and enabling clean energy for our customers while delivering economic growth and vitality for our communities. Our investments in operations enabled ongoing earnings of $3.35 per share, representing the 19th consecutive year of meeting or exceeding our earnings guidance. Meeting our financial commitments is critical to maintaining a competitive cost of capital, which benefits our customers as we access the capital markets to fund our operations. In December, we received approval for our ground breaking clean energy portfolio with over 5,800 megawatts of new generation resources. This $4.8 billion of new generation investment, which when coupled with the necessary transmission represents almost an $8 billion worth of commitments in Colorado to deliver a cleaner energy economy. I'm proud of how our teams partnered with so many stakeholders to deliver on these achievements. And as I look back on the year, we accomplished so many other great outcomes. While the final values aren't in yet, our SAIDI scores improved and we believe we'll be in the top quartile of U.S. utilities for delivering reliable electricity to our customers. Across our wind fleet, we continue to deliver strong net capacity performance and exceeded our corporate availability target for the third consecutive year. We navigated a very busy regulatory calendar resolving multiple rate cases and reached a pending settlement in our Texas electric rate case. We filed our Clean Heat Plan in Colorado and our natural gas innovation plan in Minnesota, providing a framework in both of those states to achieve net zero greenhouse gas emissions for our natural gas customers. We've approved transportation electrification programs in New Mexico and in Wisconsin, along with updated transportation plans pending commission approval in both Minnesota and Colorado. We were partners in over $1.5 billion of awards by the Department of Energy to support the Heartland Hydrogen Hub, wildfire and extreme weather resiliency, Form Energy long-duration energy storage pilots, and additional transmission as part of the MISO SPPC's projects. These grants will lower the cost of these clean energy and resiliency projects for our customers. In 2023, we signed agreements for data centers with Meta in Minnesota and QTS in Colorado. Data center and AI-driven demand continued to be a low driver on our system with several gigawatts in the pipeline across our footprint. In Minnesota, we received approvals for an additional 250 megawatts of solar in our 10-megawatt 100-hour Form Energy battery pilot both at our retiring Sherco coal facility. We have active RFPs for over 2,000 megawatts of renewable resources across our operating companies, which we expect resolution on later this year. We also filed resource plans in our SPS company, which could add an additional 5,000 to 10,000 megawatts to our system by 2030. In December, we retired Unit 2 at our Sherco coal facility while continuing the trend of no personnel layoffs at our retiring coal facilities over the past 15 years. We reduced carbon emissions for the electric utility by 53% as compared to a 2005 baseline, on track with our goals for 2030 and 2050. All the while, our customer bills remain amongst the lowest in the country. Over the past 5 years, the average Xcel Energy residential, electric and natural gas bills are 28% and 14% below the national average, respectively. And over the last 10 years, we kept our annual residential electric and natural gas bill increases to 1.8% and 1.1%, respectively, well below the rate of inflation. We're actively involved in our communities as our employees, contractors and retirees provided more than $11 million and volunteered over 40,000 hours to support charitable organizations across our footprint. We initiated 18 economic development projects for our communities, which are projected to create more than $2.4 billion in capital investments and 1,400 jobs. For the seventh consecutive year, we received the top score from Human Rights Campaign Foundation's Corporate Equality Index, the nation's foremost benchmarking survey in measuring corporate policies and practices related to LGBTQ+ workplace equality. And finally, we received several other recognitions, including being named a top military employer by multiple organizations and one of the World's Most Admired Companies by Fortune Magazine. We're proud of these achievements, which reflect operational excellence and strong policy alignment, allowing Xcel Energy to provide a valuable product with significant benefits to our customers, our communities, our employees and our shareholders. With that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. For the full year 2023, we had ongoing earnings of $3.35 per share compared to $3.17 per share in 2022. The most significant earnings drivers for the year include the following: higher electric and natural gas margins increased earnings by $0.10 per share. This reflects $0.10 of unfavorable weather as compared to last year. Lower O&M expenses increased earnings by $0.06 per share which reflects the impact of cost containment actions. Lower conservation and DSM expense increased earnings by $0.06 per share, which is largely offset in lower margins. Higher other income increased earnings by $0.05 per share, primarily due to rabbi trust performance, which is largely offset in O&M expenses. Lower other taxes, primarily property taxes, increased earnings by $0.04 per share. And in addition, other items combined to increase earnings by $0.06 per share. Offsetting these positive drivers, higher interest charges, which decreased earnings by $0.14 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 $0.05 per share, reflecting our capital investment program. Turning to sales. Full year weather adjusted electric sales increased by 1%, consistent with our guidance assumptions. For 2024, we expect electric sales to increase by 2% to 3%. Shifting to expenses. O&M expenses decreased $47 million or approximately 2% for the year. This is consistent with our annual guidance and reflects management action to offset inflation and other challenges we faced during the year. During the fourth quarter, we also made constructive progress on several rate case proceedings. In December, we filed a settlement in our Texas Electric Rate Case, which reflects a rate increase of $65 million; an acceleration of the Tolk depreciation life to 2028; and the ROE of 9.55% and equity ratio of 54.5% for AFUDC purposes. The commission decision is anticipated in the first quarter of 2024. In November, Wisconsin Commission approved an electric rate increase of $1 million and a natural gas increase of $5 million based on an ROE of 9.8% and an equity ratio of 52.5%. The decision reflects adjustments for our residential affordability program, updated fuel and purchase power costs and other items, which are earnings neutral. Rates were effective January 2024. In November, we filed a Minnesota Natural Gas Rate Case requesting a $59 million rate increase based on an ROE of 10.2%, an equity ratio of 52.5% in a forward test year. In December, the commission approved our request for interim rates of $51 million, subject to refund starting this January. Final decision is expected later this year. As far as future filings, we plan to file a Colorado Natural Gas Case in the next week or so. In addition, we also anticipate filing a revised Wildfire Mitigation Plan in Colorado in the first half of 2024. Updating our progress on production tax credit transferability. We executed multiple contracts in 2023 totaling $400 million. We anticipate executing $500 million of PPC sales in 2024. Transferability reduces near-term funding needs, and most importantly, lowers the cost of our renewable energy projects for our customers. Moving to our capital forecast. We've updated our 5-year capital plan for the decision in the Colorado Resource Plan, which now reflects an investment of $39 billion. This base capital plan supports investment in renewable generation, transmission to deliver the clean energy and customer-facing investments for a reliable and resilient advanced grid. The baseline results in an annual rate base growth of approximately 9%. Not included in our base plan is approximately $5 billion for renewables and firm capacity associated with RFPs at NSP and SPS and future filings in Colorado. We've updated our base financing plan, which reflects the incremental debt and equity financing needs for these investments. Please note that the guidance assumptions in our earnings release have also been updated to reflect changes to the capital forecast for this year. As a reminder, we anticipate any incremental capital investment to be funded by approximately 40% equity. 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 metrics and favorable access to capital markets are critical to fund our clean energy transition, maintain a competitive cost of capital and keep customer bills low, especially in a higher interest rate environment. Finally, we remain committed to our long-term EPS growth objective of 5% to 7%, which we believe is conservative. We now expect to deliver earnings at or above the top end of the range in 2025 -- starting in 2025. In addition, we will rebase future annual guidance of actual results. As a result of the significant capital investment opportunities and equity funding needs, we now expect to grow the dividend at the low end of our current 5% to 7% dividend growth range with a target payout ratio of 50% to 60%. This will reduce our equity financing needs over time, lower financing risk and give us even more dry powder and financial flexibility in the future. Now I'll conclude with a brief update on the Marshall Wildfire Litigation. The statute of limitations ended in December, and as expected, we saw a significant increase in the number of claims. As of now, we are aware of 298 lawsuits with approximately 4,000 claims. In early February, there will be a hearing at which time a schedule may be determined. We believe the trial will likely begin in 2025. With that, I'll wrap up with a quick summary. We're executing on an ambitious investment plan for our customers to deliver clean, reliable energy that investment enabled Xcel Energy to deliver 2023 ongoing earnings within our guidance range for the 19th year in a row. For the 20th consecutive year, we increased our dividend to investors. We resolved multiple rate cases and filed foundational plans for our natural gas utility to reach its net zero goals. We retired our Sherco Unit 2 coal plant early and reduced carbon emissions by 53% from 2005 levels. We received approval for our groundbreaking portfolio of clean energy resources in Colorado. We updated our base 5-year capital plan to $39 billion, which reflects 9% rate base growth. We have additional capital backlog in all of our jurisdictions. We have a strong line of sight to achieving -- to achieve earnings at or above the top end of our 5% to 7% long-term EPS growth rate. And finally, our electric and natural gas customers have some of the lowest bills in the country, while continuing the safe and reliable service they expect from Xcel Energy. This concludes our prepared remarks. Operator, we will now take questions.

Our first question comes from Julien Dumoulin-Smith from Bank of America. Julien Dumoulin-Smith: Congratulations on a variety of different metrics here. But you guys had already been tracking above the midpoint of your 5% to 7% and given the -- the rate base going up say, 1.5% even with kind of incremental dilution, how do you think about that adding up, right? I mean I'm going to put it back to you a little bit, like how do you think about doing the math there, if you will? And just setting expectations. Obviously, every year might be slightly different here.

I like the phrase doing the math. I think I might have heard that before. Look, we're really excited about our investment profile over the next 5 years, across our 8 states, multiple asset categories, clean generation, transmission, advanced grid, electric vehicles, everything in support of our customers. Obviously, the EPS growth rate follows the rate base growth with some amount of dilution for financing costs at the parent level. The new updated capital plan is accretive. We expect during this 5-year period to be at or above the top end of our 5% to 7% range. But we think 5% to 7% is still a good long-term growth rate for the company, and that's our guidance right now.

Yes. And Julien, I'd just add that we do expect -- that's a conservative growth rate. And as I noted in my remarks, going forward, we will rebase off of actual earnings. So important things to note in our script. And overall, as Bob said, we're really excited about it. We're excited about our opportunities and our steel for fuel and the clean energy transition. And I think we're one of the fastest transitioning utilities in the country. And our electric bills are 28% below the national average. So I think we're in a great place for our investors and our customers. Julien Dumoulin-Smith: Yes. I appreciate being able to rebase of the actuals. That's certainly a sign of strength, as you say. Now maybe just to come back to the timing of equity here. How do you think about that vis-a-vis the updated plan and updated needs? And perhaps just to clarify this, just for the time being, at least this year, no change in that 5% to 7% at least for the current plan here?

Yes. Julien, yes, no change and our guidance assumptions for this year is still $3.50 to $3.60. Now there is an increase in CapEx if you look kind of plan over plan this year. But that was really back-end loaded as we work through some of the regulatory approval processes. From an equity perspective, look, we have -- we've said we've been -- we've talked about doing at least $500 million annually through our ATM and expect that ratable over the 5 years. And then we do have some drip. The amount above the $1.5 billion above that, we'll be opportunistic, and we'll look at it. But I think it kind of follows with how our incremental CapEx follows. Julien Dumoulin-Smith: Got it. Excellent. And then on Minnesota commissioner you've experienced, what's your relationship and maybe a little bit of a brief comment here on where we stand in Minnesota, if you will.

Yes. No, we've got a long-standing relationship. The new commissioner comes out of the department, and we've been working with him very proactively over years. So we expect a continued strong relationship with the Minnesota Commission.

Our next question is from Jeremy Tonet with JPMorgan.

It's actually Rich Sunderland on for Jeremy. Can you hear me?

Yes, we can.

Great. Just picking at the last point on equity. I appreciate opportunistic in terms of timing. Can you speak a little bit more in terms of format of how you might address that I guess, the gap from the ATM to the total needs. Anything on the table at this point or any guardrails to that?

No, the way we'll -- a pretty plain vanilla way we finance our company. So kind of the base case to be is a block issue. And something you can obviously look at doing a forwards or something. We look at mandatory converts, but our base case is just doing blocks above the level that we feel comfortable with on the ATM.

Understood. Very helpful. And then looking at a high level in terms of the O&M outlook and then parsing that relative to the workforce reduction announcements. Could you speak a little bit more to the savings there over the near to medium term? How that factors into your overall O&M trajectory and how you're thinking about that O&M outlook, I guess, over the long term as well relative to the work you've accomplished over the past few years.

Yes. Let me hit the workforce reduction question first, and I'll transition to the longer-term O&M outlook for us. I think from a workforce reduction perspective, us like everyone else faced some significant cost challenges and pressures over the past few years. And so we -- as Paul said, we undertook that to streamline the organization and ensure some of our resources are aligned where our customer needs are and our growth opportunities. So as Paul said, approximately 400 employees are through that voluntary retirement program and another 150 positions were eliminated so that we look forward that generates approximately 2% O&M savings on a run rate basis. But we will look to reinvest some of that, as I said, into the growth areas of the company as we look to support our customer needs. But overall, sets us up into '24 that is included and incorporated into our 2024 guidance. As I think about 2024, our guidances were up 1% to 2% relative to '23, but it's really flat to '22 when you look what happened in 2023. Now longer term, you asked about kind of what our longer-term expectations are, we've been managing our O&M with a laser focus on operational efficiency. I think if you look at our IR deck from Q4, we're 1 of 3 utilities that have O&M flat or down since 2015 on the electric operations side. So something we're really proud of. And while we look longer term, we have some tailwinds of coal plant shutdowns. We expect we'll be shutting down a coal plant roughly a coal unit roughly a year. We spend a lot of time on technology in looking at how we can leverage technology in our operations in the corporate areas. And then I think most importantly, we haven't talked about this that much as we launched something that we call One Xcel Energy Way which is our continuous improvement engine. We deployed it last year, so we're in the year 2 of it. Really focused on the lean principles and being a transformation engine that is looking at waste reduction and waste elimination. And so that's something we're putting a lot of effort and focus on it and that team reports directly to me, so I'm very involved in it. So we think longer term, our goal is to absorb inflation, absorb the, call it, areas we need to invest in from a growth perspective and maintain O&M roughly flat and ensure that we can keep our customer bills low for the long term. So we're pretty excited about it. Obviously, it's not easy but something we spend a lot of time on. So I appreciate the question.

Our next question is from Durgesh Chopra with Evercore ISI.

Bob, congrats, a solid quarter here to you as well Brian and the rest of the team. Just I thought the dividend growth trajectory change was interesting. You're now saying low end of the 5% to 7% because you have high growth rate. Maybe just talk through your thinking there. You were kind of growing faster, so that gives you more flexibility on the financing side. Just a little bit more color there would be helpful.

Yes. Absolutely. So as we look at it, given our significant growth in our base plan, we just added $5 billion of capital to it and that -- the fact that we're guiding to the top end or above our conservative 5% to 7% EPS growth, we thought it was prudent and the right decision to lower our dividend growth, still within our dividend growth guidance of 5% to 7%. But as we think over the long term that helped us reduce the equity we needed for this $5 billion of capital. But even longer term, when you look at the compounding impact of a lower dividend with significantly high capital needs it feels like a prudent decision, gives us longer-term financial flexibility and dry powder and reduces financing risks over the long term. So we feel really good about it. We feel really good that we have a very good total shareholder return proposition for investors, and we'll continue -- we expect to deliver here [indiscernible]

Got it. And Brian, just as you -- there's obviously a ton of CapEx opportunity, you outlined $5 billion additional CapEx. Do you expect -- is that 5% the floor? Or could you -- could the dividend growth be further lowered in case you have -- you're adding more capital to the plan?

Durgesh, I think we'll assess it every time if we have a significant chunk of capital, update our plans as we do regularly, we obviously evaluate all parts of our total shareholder return.

That's fair. Okay. And then just one last one for me is just thank you for the color on Marshall Fire, the additional complaints and other things. Maybe just what are the key steps for us to watch there? And when could we expect updates?

It's Bob. Thanks for the support as always. With the fire, I think the next sort of milestone I'd say is we have a sort of a trial planning period of meeting first week of February. Given the change in cases and plaintiffs that schedule got moved back a little bit to give new claimants more time. We'll get a better trial calendar. As Brian said, we expect a trial some time in '25. Look, we -- after that, we go into discovery, there's not much to do past that. So we'll update everybody when we know more, but there's not much to say other than the facts remain the same on the case and roll the calendar probably to early next month.

Our next question is from Steve Fleishman with Wolfe Research.

Yes. So I just wanted to clarify, all your growth rate commentary is that based on the base plan? The updated base plan?

Yes, Steve, the updated $39 billion plan. Yes.

Okay. And on the -- could you just talk to the PIMs in Colorado and just how you're feeling about being able to manage any -- I guess it could be good or bad, but just any risk exposure from that?

Yes. Certainly, Steve, and for the folks that haven't been close to that proceeding. We really have 2 PIMs, which the commission asked to propose a couple of PIMs. So we have a cost to construct and think of that just as a capital, what's our budget for the project has been. And we've operated under those types of things for a long time, whether in Minnesota, Texas, New Mexico, we've had those in Colorado. So we propose a PIM. The commission modified it a little bit, so it's a plus or minus 5% deadband and then customers sharing -- savings and sharing was a penalty or incentive above the 5%. Overall, we're comfortable with managing within that PIM. We feel like we put forward good budgets for our projects and knew going in that we would be held to what we proposed given that was a competitive process. So we feel comfortable about that. On the operational PIM, again, it's -- the commission modified it slightly but generally adopted what we proposed. That's an overall -- think of it as LCOE PIM on a 3-year rolling average with a plus or minus 5% deadband. And the first 5% to 10% above, it's 80% of the costs or savings you have for customers, the company bears 20%. So if you look at it, we view that's very manageable and appreciative that the commission adopted the PIMs that we -- our structure that PIMs are put forward. So we look forward to working through the CPCNs with commission and then we have the Just Transition plan coming up, which is additional opportunities as we think about transitioning our generation fleet in Colorado.

Okay. Great. And then lastly, just some Washington question. The, I guess, time line, if any, on the nuclear PTC. Your thoughts on the proposed hydrogen rules and what that means for your project. And if you want to take up any thoughts on election risk to IRA.

Steve, it's Bob. The last one seems like a lot of fun to talk about, but I'll probably pass on that fastball. On Washington, in particular, the hydrogen production tax credit, we were very active, we've been very stalwart in our position that we believe that clean fuels and clean molecules are going to be needed as part of a broader, cleaner energy economy. We felt that hydrogen was probably the most attractive molecule that we could produce in a clean and green way. We are really proud to be considered for a Hydrogen Hub and in our Upper Midwest proposal, The Heartland Hub. But I got to tell you, the 45V tax credit draft guidance out of the treasury was disappointing. It doesn't feel as if we're trying to support a hydrogen economy in the United States. It's going to make it more expensive for our customers, harder to develop an electrolyzer industry on an industrial basis in the country and will slow or stall clean fuel deployment in the United States. We expect to make comments within the comment period. We expect EEI to make comments. We expect other customers to make comments. So I think the treasury is going to have a lot to balance here, strict additionality and hourly matching if it's going to make it more challenging to produce hydrogen at a cost-competitive basis with other fuels. So that's kind of where we are on hydrogen. And I think you asked about nuclear, our math -- go ahead, Brian.

Yes, I can just chime in on nuclear. So we expect guidance here in Q2 is our current thinking. Obviously, the guidance we're looking for is how do you calculate the gross receipts, meaning how do you calculate the value. We've got advocated for the use of LMPs, obviously, given that we're in an RTO. Certainly, if you look at our earnings guidance, we have not incorporated that into our ETR. But when we look at kind of the forward curve, we would expect north of $100 million benefit for our customers. So something that we're -- that we provided our comments and hopeful that treasury comes out and favor us because it's a great benefit for our customers. So looking for that Q2. Just a follow-up on Bob's comments on hydrogen. I mean disappointing, the analysis I've seen is green hydrogen now structurally more expensive than blue hydrogen for the next decade and significantly more expensive than gray hydrogen. And so it will depress the development of the green hydrogen market. And so hopeful to get some changes to the final rules.

Our next question is from Anthony Crowdell with Mizuho.

Just hopefully 2 quick ones if I could follow up on Steve and Julien's math class question. When you think of the 5% to 7%, you're at or above the high end, and that's all in the base capital. What would cause you to get to 6% growth?

Well, I mean, at or above the high end implies that we're above 6% growth right now. But I take it your question, what would cause us to go to 6% to 8%, if I can interpret it. Like we evaluate it we feel 5% to 7% is the right long-term growth rate. It's conservative and rebasing off of actuals and signaling that we're going to be at the top end or above is the right place to be long term.

Great. And then I think you mentioned you're filing a Colorado Wildfire mitigation plan later this year, I believe. Just could you give us a look into that? I mean, is that also a potential for additional capital -- CapEx and then -- or any changes in operation you're thinking once you make that filing?

Yes. Anthony, it's Bob. Good to hear you this morning, and thanks for the questions. We're operating under an existing wildfire mitigation program in Colorado right now. And I'd say that, that plan includes asset hardening and replacement. It's got pilots for various technology solutions and risk modeling embedded within that. I think the updated plan that we're anticipating for Colorado would be a continuation of a lot of those existing programs and maybe moving from more pilot to more scale -- or scale deployment of everything from coatings on poles to covered conductor analysis and deployment to enhanced recloser settings and recloser installations across the business, potential for incremental undergrounding in various areas and probably some operational opportunities around enhanced power line settings and PSPs mechanisms. Still working on finals. So I don't think it's going to be a material driver in terms of our capital deployment, but I do think it will be an enhancement to our risk reduction in our Colorado company.

And Bob, just lastly, do you -- does that plan have to get approved or just accepted, just a procedure that goes on in Colorado on a wildfire mitigation plan?

Yes. It goes through a regular way of proceeding with intervenor testimony and our testimony [indiscernible] approval by the PUC.

Our next question is from Carly Davenport with Goldman Sachs.

Just two quick ones for me on some of the resource plan opportunities that you've highlighted. So first, on Colorado, obviously, strong results on that plan in 2023. How should we think about just the next milestones to watch in Colorado, whether that's around the CPCN process for the transmission or the Just Transition filing? And then just second on SPS. We saw the load growth come in close to 5% overall in '23. So just in that context, can you talk a little bit about the SPS opportunity around the future RFP there to sort of accommodate that level of potential growth going forward?

Yes, absolutely, Carly. Related to Colorado, we'll begin -- so the marker will begin to file CPCNs for all of our projects in transmission starting in likely late February. And then you'll just see them kind of filter in probably over Q2. And then those will be regular way CPCNs, I think probably 8- to 9-month type approval processes on each of those filings. So those are the next markers at least on the projects coming out of the Colorado Resource Plan that was just approved. And then we're working on filing our Just Transition Plan in June and that was originally focused on the replacement of the Comanche 3 assets with a little bit of the commission approving No Regrets Portfolio in this December. I think there's opportunity to bring the incremental resources. We do think we need additional resources that we propose and even the commission acknowledges that there may be an opportunity or they believe that we may need those resources. So that will be all part of the Just Transition Plan filing. And again that follows a typical Colorado time line in terms of 9 months or so to work through that proceeding. So it would - pushes that into 2025. But overall, excited those are kind of looking at '28 to [ '29 ], '30 type clean generation opportunities and how do we transition our fleet in Colorado as it will be completely out of coal by the end of 2030 in Colorado. On SPS, really great low growth opportunities in SPS. And you noted our sales growth there in 2023, we expect to continue to see significant sales growth in that region. I think that is really the driver of our SPS resource plan. We provided a range from 5,000 megawatts up to 10,000 megawatts. That 10,000 megawatts is really working with our large customers on their electrification forecast. So I think it's a significant opportunity. We do not have that anywhere in our capital plans. So we will make -- we will work through that filing and the New Mexico Commission will -- they don't officially approve it, but they accept the resource plan, and then we'll look to launch the RFP in the summer time. And then we'll get our results later in 2024 and likely start working on selection early in 2025. So pretty excited about that plan, excited about supporting the benefits of electrification down in SPS and making sure that we can serve our customers. So overall, like I said, really great steel for fuel low growth -- steel for fuel opportunities in serving the low growth in our territories.

Carly, it's Bob. I just add on to what Brian said is probably remiss if we didn't comment on the Minnesota and the Wisconsin RFPs that are in the SPS RP that's in flight right now, which represents 2,000 megawatts of new clean energy in the Upper Midwest and in the Southwest. We expect resolution of those, as I said in my prepared remarks, this year, and they're included in our incremental capital opportunities in our investor deck.

And just one more thing to add. We'll be filing a resource plan in Minnesota on February 1, which is a continuation of the transition of our generation fleet as we shut down our coal plants in Minnesota by 2030. And pretty excited about just all the opportunities across our service territories.

Our next question is from Sophie Karp with KeyBanc.

So I noticed that you showed the Colorado, I guess, earned ROE like sub 8%, if I'm reading this correctly. Just given how much capital you're going to be investing in the state, do you see a path to improve that? And what is that?

Yes. Sophie, thanks for the question. Certainly, in Colorado, we've had a pretty significant gap between our authorized versus earned ROE. As we think of all the capital that we're deploying on the clean energy transition that will flow through timely recovery from a rider perspective. Also all the transmission that we need to invest to be able to deliver that clean energy to our customers will flow through the TCA. So the incremental capital should get more timely recovery. I mean it's important as we think about longer term to ensure that we have a financially healthy utility because it allows us to have a competitive cost of capital, which in the long term is that -- most beneficial to our customers as it delivers the lowest cost of customers -- lowest cost to our customers. So something that we're certainly aware of and working on, our stakeholders and policymakers around ensuring that we are aligned with the clean energy policy in Colorado and how we can ensure that we keep that alignment and improve it over time.

So the problem, so to speak there was just a timing lag with capital, which you expect to improve with more contemporaneous mechanisms. Am I getting this right?

Yes. And as we mentioned, yes, it is the regulatory lag, the capital lag. We had a historic test year in Colorado gas. And as we mentioned in my opening remarks, we'll be filing a Colorado Natural Gas Case here in the next week or so. And so we'll be working through that.

Okay. All right. And my other question was your volume growth overall for the company was something like 1% or above in '23 and you're basing your guidance on 2% to 3% growth in '24. So I'm wondering where do you expect to see this acceleration and what's the underlying assumption there?

So as we think about it, yes, our guidance here is 2% to 3% in 2024. The biggest driver continues to be in SPS and the electrification and growth we're hearing from our customers, obviously, we work very closely with our large industrial customers down there, so I have a good sense of what their low growth forecasts are in 2024 and even beyond. We're starting to see some large C&I growth in Colorado with the data center coming online and a couple of other large customers coming online. So really driven by C&I load growth in 2024. We do continue to have customer -- residential customer growth of roughly 1%, so that contribute some. But overall, it's driven by our C&I growth, particularly in SPS.

Our next question is from David Arcaro with Morgan Stanley.

I had a quick question just on tax credit transfers. Let's see -- are you changing kind of the anticipated level over the course of the plan given the increased CapEx here? And did that contribute? I saw that the cash flow from ops increased versus the prior slide deck. I'm wondering if that was part of it.

David, so we incorporate the transferability into the cash from operations. But for us, transferability isn't really cash flow driver when we look plan over plans. We've incorporated all the transfer tax credits in the previous plan, the transfer tax credits in this new plan. Certainly, cash flow from ops increased by about $1.5 billion when you look at it from the $34 billion to $39 billion plan. Really, the projects -- there's a net income that drives our book depreciation and some deferred taxes, it's a combination of all 3. Some of these projects do go in service in the middle and so they are good cash flowing assets as we think about it. And so that's why you see that there. From a transferability perspective, now we do include that now in our 5-year forecast. I think prior, I talked about -- we were somewhere around $2.5 billion of transferability. Now we're approaching about $3 billion of transfer tax credits over the 5 years,. Roughly $500 million this year, growing to about $700 million at the end of the 5-year forecast. So we see the demand and have -- actually have much more demand than our supply.

Our next question is from Travis Miller with Morningstar.

I'm disappointed, we don't get to hear your election thoughts. But aside from that, wonder if you could talk a little bit more after you've added this capital and the impact that's going to have, obviously, on financing needs and the impact on the dividend growth, how do you go into these next set of RFPs and any kind of other capital investment opportunities. Does that change your thinking in terms of pursuing some of those projects?

Tavis, it's Bob. Thanks for the question. We really want to own and operate the infrastructure that serves our customers. I think this is a core skill set of the company. We think we're competitive. We think we can do a price competitively for our customers. I think we've proven that over the last 5 or 6 years and delivering value to our customers from our clean energy investments. I think -- it wasn't in our original pro forma estimates, but I think our total over the last 5 years is close to $5 billion worth of tax credits and avoided fuel costs from installing wind into our system for the benefit of our customers, which was never included in our forecast when we put those wind farms in. So there's real customer benefit for us owning and passing that stuff through to our customers. As we look to the future, obviously, we want to own and operate the infrastructure. It's important in the regulatory mechanisms, as you said, making sure that we get timely recovery of the new investment assets, is really important for us as we think about installing new generation into our areas. But I think our position would be that we continue to want to own and operate generation assets, recognizing that there are going to be likely competitive processes, and we have to prove value to our customers and we've been good at that. And I think our plan would be to continue to target ownership of some amounts of those generation assets.

Yes. And Travis just to add that -- Bob's absolutely right, we have to demonstrate that we're competitive with our commissions and we have been, and we expect to continue to be so going forward. And so we can continue to deliver low-cost electricity to our customers. But I think just from a purely financial standpoint, we've been very open about -- we will fund accretive capital growth, and we'll fund that with a balanced mix of equity and debt and cash flow from operations. So overall, we're very comfortable with it and I think we're in a great to be both to deliver for our customers and our shareholders for the longer term.

Okay. Great. That makes sense. And then one other different subject. Assuming you get the Tolk accelerated depreciation approval in Texas, are there any remaining steps, either regulatory, other procedural steps necessary to hit that 2030 goal of closing your entire coal fleet?

No. No. That was the last one outstanding. So we're pretty excited about it assuming we get PUCT approval of the settlement. That's the last one.

Okay. No transmission operator agreement necessary and anything like that?

No.

Our next question is from [ Ryan Breno ] with Citi.

A couple of quick questions. In terms of the Marshall fire, I appreciate the clarifications and updates. Is there any opportunity for settlement there outside of the formal court process?

Ryan, look, it's still very early in the process. But as we've said from the beginning, we strongly disagree with the conclusion of the sheriff's report, and we intend to viciously defend ourselves sitting here today.

Okay. And given the balance sheet, operator challenges and needs to raise capital over the coming years. Are there any M&A opportunities in terms of asset sales that you'd contemplate to derisk your funding plans?

Yes. First, I guess I'd disagree with the balance sheet challenges. I think we have one of the stronger balance sheets in the industry. So I don't necessarily agree with that characterization. But now from an M&A standpoint, now we're comfortable with where we sit in the assets we own. Obviously, we're aware of everything that is going on in the industry.

Our next question is from Paul Fremont with Ladenburg.

Just a quick question on the Marshall fire. Is there any update on the dollar amount of the claims at this point?

Paul, it's Bob. Thanks for the question. No, no update. I mean the insurance commissioner said that the property damage was in excess of $2 billion. But as far as the total amount of suits, they haven't claimed any liability in the suits or from the plaintiffs.

Our last question is from Paul Patterson with Glenrock Associates.

Just one of my questions have been asked. But on the -- to follow up on Steve Fleishman's question on the PIMs. It seemed like meeting the order and stuff that there was a greater -- that they basically anticipated looking at additional PIMs and sort of we're intrigued with sort of PBR in general. And I was wondering just sort of how you -- I know it's early to say, and it depends obviously what the PIMs are. But given that they seem to be sort of more performance-based PBR directionally driven. How you think you're positioned to deal with that? And do you see perhaps not only sticks but also carats, is there a potential, perhaps, that you could do well under PBR, if you follow me?

Paul, you were breaking up a little bit, but let me see if I understand the question. Given the recent PIMs in Colorado, how do you feel broadly about performance-based ratemaking and things like that. Look, I think that it's natural. And as Brian indicated earlier, that we've had capital cost caps on various projects broadly throughout the portfolio. I think the setup PIMs that we worked through with interveners and stakeholders and the commission as part of the CEP in Colorado, I think the process was productive. We have an opportunity to propose. I think they appreciated our proposal. I don't think it's a material move in a certain direction. I think it's probably appropriate and on a project basis probably less so for an entity-wide basis. So I don't see a lot -- I don't read a lot into where we've been with Colorado or with other jurisdictions in terms of incentive mechanisms around capital deployment.

Yes, Paul, in the written orders, certainly there's a discussion. We'll work with the staff as we work on the Just Transition plan in terms of looking at well-designed PIMs. And there's also a PIM around potential kind of the emissions achievement. So we look forward to working with staff on that as we move through time.

Thank you very much. I'd like to hand it back over to CFO, Brian Van Abel for any closing remarks.

Well, thank you all for participating in our earnings call this morning. Please contact our Investor Relations team with any follow-up questions. Have a great day.

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