Xcel Energy Inc.

Good day and welcome to Xcel Energy's third quarter 2022 earnings conference call. Today's conference is being recorded. After the presentation, we will open up for questions. Questions will only be taken from institutional investors. Reporters can contact media relations with inquiries and individual investors and others can reach out to investor relations. I will now hand the call over to Paul Johnston, Vice President, Treasurer and Investor Relations. Please go ahead.

Good morning and welcome to Xcel Energy's 2022 Third Quarter Earnings Call. Joining me today are Bob Frenzel, Chairman, President, and Chief Executive Officer, and Brian Van Ebel, Executive Vice President and Chief Financial Officer. In addition, we have others in the room available to answer questions if needed. This morning we will... discuss our 2022 results, share recent business and regulatory developments, update our capital and financing plans, and provide 2023 guidance. Slides that accompany today's call are available on our website. As a reminder, some of the comments made during today's call may contain forward-looking information. Significant factors that could cause results to differ from those anticipated are described in our earnings release and our SEC filings. Today we will discuss certain measures that are non-GAAP.

metrics information on the comparable gap measures and reconciliations are included in our earnings release i'll now turn the call over to bob thanks paul and good morning everyone welcome to our third quarter earnings call let's start with our financial results we had another solid quarter recording earnings of 1.18 per share for 2022 compared to 1.13 per share in 2021. Our earnings are on track, and as a result, we are narrowing our 22 earnings guidance range to $3.14 to $3.19 per share. We're also initiating 2023 earnings guidance of $3.30 to $3.40 per share, which reflects our 5% to 7% long-term EPS growth objective. Consistent with past practices, we've updated our base investment plan, which reflects $29.5 billion of capital expenditures over the next five years. This investment plan provides significant benefits to our customers, supports community vitality and resiliency, and delivers rate-based growth of 6.5%. We're very excited about our investment plans, which support continued execution of our long-term strategy and clean energy leadership. It enhances reliability and resiliency, advances our generation fleet transition, allows for the electrification of transportation, keeps customers' bills low, and delivers attractive returns for investors. And while our base plan is robust, it does not include any potential renewable generation assets that are approved in our Minnesota and Colorado resource plans or additional transmission capital that's needed to integrate new renewable generation in Colorado beyond the Power Pathway project. For these assets, we expect further regulatory clarification in the second half of 2023. which could result in incremental capital expenditures of $2 to $4 billion, which would result in rate-based growth of 7.6% at the midpoint. Our updated capital plan, which reflects the benefits of the IRA, extends the growth rate and improves the quality of rate base, reduces financing risk, improves credit metrics, and delivers substantial customer and environmental benefits. During the quarter, the Inflation Reduction Act was passed into law, which includes new and extended tax credits for wind, solar, hydrogen, storage, carbon sequestration, and nuclear. It also includes tax credit transferability. Some of the key takeaways for the IRA include substantial customer benefits and a continuation of our clean energy leadership while keeping customer bills affordable. The inclusion of the new solar production tax credit makes our company-owned projects more affordable for our customers relative to the solar ITC. The hydrogen production tax credit should improve our competitive advantage in delivering low-cost clean fuels for our combustion turbines for electric reliability and for blending into our local gas distribution systems that will help our customers lower their carbon footprints in the future. The nuclear production tax credit will provide additional customer credits depending on MISO marginal pricing, thereby lowering the cost of electricity from our existing nuclear assets. The tax credit transferability will increase liquidity and improve credit metrics. An excellent example of the IRA tax benefits is our 460 megawatt Sherco solar proposal that was recently approved by the Minnesota Commission with strong stakeholder support. This will be the largest solar facility in the Midwest in a top five installation in the United States, which will go into service in 2024 and 2025. Following the IRA passage, the levelized cost of Sureco Solar is projected to decline by over 30%, even after accounting for inflation and supply chain pressures. Due to the project qualified for both solar PTCs and community energy bonus, as we are reinvesting in the community around our retiring coal facility. This is a substantial benefit to our customers. Earlier this year, the commissions in both Minnesota and Colorado approved resource plans that will add nearly 10,000 megawatts of utility scale renewables to our systems and achieve an 85% carbon reduction by 2030. These resource plans were approved prior to the passage of the IRA. But the final recommended portfolios are expected to capture the benefits of the IRA, which will significantly reduce the levelized cost of these renewable projects for our customers. We've issued a request for proposal in Minnesota and plan to issue an RFP in Colorado later this year. After evaluation of proposals, we anticipate submitting our recommended portfolios to our respective commissions by the middle of next year and expect decisions in the second half of next year. We expect the recommended portfolios of generation assets will include a mixture of self-build, build-owned transfer projects, as well as some power purchase agreements. Our generation resource plans are consistent with our seal for fuel strategy, which provides a valuable hedge for our customers against rising commodity prices. As an example, our own wind farms are projected to generate nearly $1 billion of fuel-related customer savings in 2022 alone, and almost $3 billion since 2017. While these fuel savings were not included in our investment case, it shows the tremendous customer benefits of being an early leader in a clean energy transition. We also continue to advance our broader ESG leadership as MSCI recently upgraded Xcel Energy's rating from AA to AAA and categorized our company as leader in their nomenclature for managing the most significant ESG risks and opportunities. This is an outstanding accomplishment and reflects our continued progress, including adopting a water management goal, greater disclosure of human capital management practices, and an improved governance score. We were also named to Investor Business Daily's 100 Best ESG Companies, which is further recognition of our ESG leadership. And with that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. We had a solid quarter, recording earnings of $1.18 per share for the third quarter of 2022 compared with $1.13 per share in 2021. The most significant earnings drivers for the quarter included the following. Higher electric and natural gas margins increased earnings by $0.33 per share, primarily driven by riders and regulatory outcomes to recover our capital investments. In addition, a lower effective tax rate increased earnings by $0.02 per share, Keep in mind, production tax credits lower the ETR. However, PTCs are flowed back to customers through lower electric margin and are largely earnings neutral. Offsetting these positive drivers were increased depreciation expense, which reduced earnings by $0.10 per share, reflecting our capital investment program, higher O&M expense, which decreased earnings by $0.06 per share, higher interest expense and other taxes, primarily property taxes, decreased earnings by $0.07 per share, and other items combined reduced earnings by $0.07 per share. Turning to our sales, our year-to-date weather adjusted electric sales increased by 2.2%, largely due to higher CNI sales driven by strong economic activity in our service territories. The year-to-date results are relatively consistent with our expectations of 2% sales growth for 2022, while we anticipate more modest sales growth of 1% for next year. Shifting to expense, O&M expenses increased $43 million for the third quarter. driven by investments in technology and customer programs, storm costs, vegetation management, and inflation. Like other businesses, we are facing inflationary pressures and now expect an annual O&M increase of approximately 4%. This represents a step increase due to cost pressures. However, we anticipate flat O&M in 2023. We've made progress on a number of regulatory proceedings. During the quarter, Minnesota Commission approved our URI storm settlement, including full recovery of all costs, with the exception of a $19 million disallowance. We have now resolved yearly cost recovery in all of our states, with the exception of Texas. We also have pending electric and natural gas rate cases in Minnesota. In the natural gas rate case, we reached a comprehensive settlement, which reflects a rate increase of $21 million, an ROE of 9.57%, a currently authorized equity ratio of 52.5%, a decoupling mechanism, and property tax tracker. We think this is a constructive settlement and anticipate a commission decision next year. In the Minnesota electric rate case, we recently received intervener testimony. The Department of Commerce recommended a three-year rate increase of $274 million based on an ROE of 9.25% and an equity ratio of 52.5%. In addition, The Department of Commerce recommendation reflects customer credits for the MISO capacity auction revenues and extension of the depreciable lives of the Monticello Nuclear Plant and our wind farms. We are meeting with parties to see if we can reach a constructive settlement. In October, the Colorado Commission approved a rate increase of $64 million for our natural gas case, reflecting a historic test year with a year-end rate base and $16 million of incremental depreciation expense. The Commission also approved a weighted average cost of capital of 6.7%, which will reflect as an ROE of 9.2% and an equity ratio of 53.8% based on the ranges they provided. As a result of the Colorado Commission denying the step increases, we're evaluating options of filing another rate case as the natural gas business remains a critical part of the energy infrastructure in Colorado that is valued by our customers. As far as future filings, we plan to file Colorado and New Mexico electric rate cases later this year and the Texas rate case in the first quarter of 2023. As Bob mentioned, we've issued a robust $29.5 billion five-year base capital forecast with a rate-based growth of 6.5% using 2022 as a base. The base plan reflects significant grid and resiliency investment, our Colorado Power Pathway proposal, and other transmission system investments to maintain asset health and reliability and enable renewable generation. The plan reflects a modest level of renewables, including our Sherco solar facility. It also includes natural gas peaking plants to ensure reliability as we retire coal plants, along with investments to improve the customer experience. We also anticipate potential incremental capital investment for renewables associated with the Minnesota and Colorado resource plans. Our proposed resource plans include approximately 3,500 megawatts of additions from 2024 to 2027, which would result in capital investment of $1.5 to $3 billion, assuming 50% ownership. In addition, we anticipate the need for an incremental $500 million to $1 billion of related transmission for the Colorado IRP. Combined, we could see a potential incremental investment to support the clean energy transition of $2 to $4 billion. We've updated our financing plan, which reflects a combination of cash generation, debt, and equity to fund the majority of our capital expenditures. The financing plan assumes $1.8 billion of tax credit transfers, which improves our credit metrics, maintains a strong balance sheet, and lowers the cost of renewable projects for our customers. Compared to our previous five-year plan, transferability reduced equity needs to $750 million, while we've increased capex by $3.5 billion. In addition, we anticipate that any incremental capital would be financed at roughly our current capital structure. It is important to recognize that we've always maintained a conservative financing strategy, which reflects a strong balance sheet and credit metrics, a balanced financing plan, and minimal levels of variable debt and longer maturities. This approach is critical in the current market of rising rates and will benefit our customers while maintaining our solid credit ratings and favorable access to the capital markets. Bob discussed IRA customer benefits, but I wanted to add a few more details. Tax credit transferability is projected to provide $1.8 billion of liquidity, which increases cash flow and reduces our equity needs. Our FFO to debt metrics improved by approximately 100 basis points during the forecast time period, even after adding $3.5 billion of capital in reducing equity needs. The solar PTC and tax credit transferability improved the competitiveness of our renewable bids. We project the IRA will drive approximately $500 million of customer savings from our own renewable projects over the next five years, and nuclear PTCs could drive additional savings. We anticipate that pricing will decline on solar projects by 25% to 40% and wind projects by 50% to 60% later in this decade due to new and extended tax credits along with potential adders in the IRA. Finally, we don't anticipate any material impact from AMT, as a result of makers' appreciation in existing tax credits on our balance sheet. Shifting to earnings, we've updated our 2022 guidance assumptions to reflect the latest information. We're also narrowing our 2022 earnings guidance range to $3.14 to $3.19 per share. We're also initiating our 2023 earnings guidance range of $3.30 to $3.40 per share, which is consistent with our long-term EPS growth objective of 5% to 7%. Key assumptions are detailed in our earnings release. With that, I'll wrap it up with a quick summary. IRA was passed with significant benefits for our customers and the company. The Minnesota Commission approved our Sherco solar project. We reached a constructive settlement in our Minnesota natural gas rate case. The Colorado Commission approved our natural gas rate case. We're narrowing our 2022 earnings guidance range. We announced a robust, updated capital investment program that provides strong, transparent rate-based growth in customer value. We initiated 2023 guidance consistent with our long-term earnings growth rate, and we remain confident we can continue to deliver long-term earnings and dividend growth within the upper half of our 5% to 7% objective range as we lead the clean energy transition and keep bills low for our customers. This concludes our prepared remarks. Operator, we will now take questions.

Thank you. If you would like to ask a question, please press star 1 on your telephone keypad. We will take our first question from Nicola Campanella with Credit Suisse.

Hey, good morning, everyone. Can you hear me?

Sure. Hey, good morning, Nick.

Hey, morning, morning. So I guess I'll just start it off. I mean, you're raising CapEx. You decreased equity needs. The CAGR is still the same. Can you just give us a sense of kind of what the offsets are? you know, in that plan, you know, I believe that, you know, there are some offsets to rate base with transferability and the various tax impacts, but any more clarity would be helpful.

Yeah, absolutely. They can all handle that one. Yeah. I mean, when we look at the IRA, huge win for our customers and us in really, and if you think about our financing plan, it's around transferability and there was an offset because a majority of those tax credits were on our balance sheet as a deferred tax asset. which would increase the cost of our renewable projects. So by being able to monetize them, we reduce that tax asset on our balance sheet, lower the overall LCOE for our wind projects and solar projects to our customers, and improve our cash flow. So you do have lower rate base from that in a vacuum, but it allows us to reduce our equity needs, increase capex, and have basically a higher quality rate base as we think about it. I'd much rather have steel in the ground than a tax asset on our balance sheet.

And Nick, just as a clarification, those tax credits are not currently on our balance sheet, but they would have been on our balance sheet without tax credit transferability in the future.

Got it. That's helpful. That's helpful. And then in the electric rate case in Minnesota, if I heard you correctly, you know, I think you're engaging parties for a possible settlement. Can you just kind of give us a sense of, you know, overall confidence level and just getting across the finish line and then you know, is there a drop-dead kind of date that you need to get this done by if you were to? Like, is there a hearing date we should have in mind?

Thanks. Yeah, Nick. Hey, it's Bob. Good morning, and thanks for the question. You know, look, I think on the Minnesota electric case, first and foremost, we've got the gas case behind us, and that sets a good framework for some of the items in the electric case. We're engaged with parties. I think rebuttal testimony is due in the middle, or the hearings are in the middle of December, so I think we should target that as a deadline for settlement opportunities. All right, thanks so much. We'll see you in a few weeks.

See you.

We will now take the next question from David Arcado with Morgan Stanley.

Hi, thanks so much for taking my question. Maybe sticking to the regulatory arena, wondering on the Colorado gas rate case, when might be the next time you go in? just in the wake of this recent decision. Hey, David, it's Bob.

Good morning. Thanks for the question. You know, we filed the case back in January with the commission, and we're looking for a three-year forward gas case. We have expected capital expenditures continuing next year and the year after. We had real visibility into the case grant. Sorry, the commission granted us a historic test year case means we likely need to go back in sometime in 2023 for a new gas case.

Yep, got it. Makes sense. And then the other thing I wanted to check on was, what's your latest thinking about the prospects for PPA buyouts and repowering opportunities in the wake of the IRA? Does that become a bigger opportunity for you to look at now?

Yeah, I'll take that one. I think it absolutely does. And the way I think about it, it's extends our ppa bout opportunity for a long time right what we've been successful at we've bought out about 750 million dollars of ppas over the past number of years and we were successful because we brought forward a win for our customers a win for us right we were able to buy out a ppa put steel in the ground and save our customers money and we did that by buying out the ppa and repowering it and qualifying for a new new set new strip of tax credits on the wind side so Pre-IRA, the buyout opportunities were stepping down as your tax credits stepped down. Now, since we have a 10-year-plus runway of PTCs, and also we'll look at evaluating solar buyout opportunities, if you can repower on a solar PTC farm. So I think there's a much longer runway for buyout opportunities, and none of that is our capital forecast in our five-year plan as upside. And I think longer term, as you think about repowerings, you mentioned repowerings, is that we put over 3 000 gigawatts or 3 000 megawatts of of wind in service between 18 and 21 and we'll look at potentially repowering those in 2028 2029 2030 and save our customers money like we're doing with our four week wind repowerings in minnesota right now so i think this really extends our opportunity on the ppa buyout and our own repowering opportunities thanks yeah that's helpful color seems like a big opportunity any um

Any just visibility into timing or clarity as to when those could crystallize in terms of hitting the CapEx plan?

You know, I think what we could potentially see in the Colorado, like we talked about potentially seeing bids in the RFP, and the Minnesota RFP was focused on solar. The Colorado one will be an all-source RFP, so we could potentially see something in that RFP that will launch later this year that Bob mentioned. You'll get visibility and call it. Jay Frykberg, M.D.: : mid to later of next year, could be the first time is because when we were middle of kind of a resource plan and rp processes processes, we want to follow those and make sure we align with the other acquisition so that's probably. Jay Frykberg, M.D.: : The first time i'd look at it longer term it's much more opportunistic right you got to find a developer that is willing to transact in a prop at a price that's beneficial for our customers. Jay Frykberg, M.D.: : yep got it okay great thanks so much.

We will now take the next question from Jeremy Tonnes with JP Morgan.

Hi, good morning.

Hey, Jeremy, how are you? Nice headline.

Thanks for that. Just with life in the fast lane, just wondering, you know, thank you for all the details today on CapEx, but what could be incremental maybe on the horizon here, if I dare kind of ask what more could come in over time? You know, and specifically any thoughts on additional MISO opportunities, whether that's competitive or upsizing future LRTP portfolios?

Yeah, hey, appreciate the question. A couple things. You know, Brian highlighted what we would call incremental capital we've been talking about for the better part of the year. And this is the competitively bid generation in both Minnesota and Colorado, as well as the incremental transmission that we would need on the Power Pathway. uh in colorado to integrate those renewables that opportunity is two to four billion dollars um you know at the midpoint of that uh we probably have rate based growth uh in the mid sevens um additional to that things early things we're starting to think about i mean you heard the previous caller's comments around tpa buyouts and repowerings that's certainly in our sites we haven't put bookends around those uh for the community but uh we certainly will Secondly, as we think about generation in our southwestern service territory, I think with the IRA, we see economics in solar and wind down there that could make an acceleration of renewables in the SPS territory, also not in our plan. It would be towards the back end of the five-year plan, maybe in the middle of the 10-year plan. We're still evaluating our resiliency expenditures. We feel very solid about what we're doing to, you know, harden our grids for climate change. But some of that will happen with the intelligence we need on a distribution grid to enable electrification transportation and the potential beneficial electrification of gas. Those are the big buckets that I think we need to be continuing to think about. Brian, do you have anything to add to that?

Yeah, I would just add a couple more to that. One is, you know, in our five-year plan, we have nothing on hydrogen. whether if there's an opportunity on the electric side or potential looking opportunities on the gas LDC side as we work through our clean heat plans. Then also storage. We're working on some interesting long-duration storage projects and also with the standalone ITC for our storage. We're looking at opportunities there. So I think there's a good number of incremental opportunities that aren't captured in our plan as we think through the overall benefits of the IRA.

Got it. That's great to hear. And I just wanted to go into 23, guide a little bit more there. I think there's 1% growth next year instead of 2% this year. Just wondering, is this primarily post-COVID normalization or some, I guess, conservatism here? And just thoughts, I guess, on achieving flat O&M in 2023, including, I guess, work that you've done this year to de-risk the 23 outlook, if you could Kind of give us thoughts as to how that factors into the 23 guide.

Yeah, and the first part, just make sure you're talking about sales, right?

Yes.

Yeah, so I think the way you framed it up, it's a little bit of both, right? It's a little post-COVID normalization. We expect residential use for a customer to come down, kind of like we saw in Colorado this year, where UPC has come down more towards pre-pandemic levels, and I think we expect to see that in other jurisdictions, too, while we do see continued economic growth. So you could call it conservative. We were certainly conservative with our sales forecast this year. Going into the year, we thought we were going to be flat, and we've been up 2% and have seen strong economic activity. On the O&M side, yeah, I think as we went through this year, right, we're certainly subject to the inflationary pressures, and we've been flat since 2014 on O&M. So that was eight years of being flat, and we had some inflationary pressures, had storms this year. increase investments in our customer platforms. And also we're running our coal plants much more given the change between gas prices and coal. So higher chemical costs, higher plant costs. So as we think about it next year, and we had a good year this year, if you look at kind of their change in our guidance from Q2 to Q3, we invested this year, right? And when we have good times. So that's why we think about next year in maintaining flat, almost a re-baselining to this year. doubling down on continuous improvement programs and setting yourselves up for next year.

Got it. That's all very helpful. One last one, if I could, if you might be able to speak on the Colorado gas step increase denial there. Do you see this as a signal from the commission to continue regularly filing rate cases? And are there any takeaways on the electric side?

I wouldn't, I wouldn't have contagion Jeremy, between the electric and the gas case. I think this year was, was particularly sensitive given the commodity increase in the impacts of winter storm URI on the gas case. Um, so no, I don't think I'd, I'd sort of read through too much to the electric side. Um, you know, we are continuing to invest in that system for safety and reliability and continued customer growth there. So, you know, we need to make sure that we're having a right balance of, of healthy financial metrics for the company. So we are going to file a rate case next year.

Yeah, and I just think about longer term on the gas LDC side. Like our net zero plans for 2030 and 2050 on the LDC side are aligned with the climate science. They're aligned with the state goals. And we're looking forward to working through the clean heat plan in Colorado. Really, you know, I think about resource planning on the gas side. And I think that will help us align with the commission and our stakeholders on how we achieve these carbon reduction targets on the LDC side because it is a critical asset for us and our customers really see demand and interest in it.

And just to put a timeline on that, you should see a clean heat plan filing from the company sometime in the second half of next year.

Got it. That all makes a lot of sense. Just checking. Thank you. Great. Thanks.

And we will now take the next question from Durgesh Chopra with Evercore.

Hey, good morning, guys. Solid quarter here. Thanks for your time. I actually had two questions, Brian, for you. Just one, I think you mentioned this in your remarks, but the jump in CFO between the two plans, The $1.8 or $2 billion is included in that CFO number, right? From the tax transfer? Okay. Then maybe just because it's a newer concept, how does that actually work? Is there a market for it? And how should we think about you monetizing those taxes? I heard Paul say that that's for newer assets, if I'm not wrong. So maybe just any color that you could give us there, which will sort of help us profile the cash flows through the five years.

Yeah, absolutely. And it's a great question because the market for PTCs and transferability doesn't exist because it's being stood up and it's effective. So any credit generated starting January 1 of 2023, so starting next year, is eligible to be transferred. And You know, we were instrumental in the language that was included. We worked very closely on that. So we've been very focused on this because it's so important for our customers to driving down the overall cost for renewables and the LCOE of projects. And for us, we've spent a lot of time. We're not waiting for a market to get set up right longer term. I think a liquid exchange ultimately gets set up, but we don't expect that in 2023. We've been going out ourselves, talking to local companies, that have a significant cash tax appetite to look at bilateral transactions. And I think there's a really good local angle here where we can save our customers money. We've had very good reception in the discussions we've had. And so we feel very confident in being able to execute on this transferability. But even just being conservative, we've only assumed we transfer half of those credits in 2023, just in conservative nature. And so it takes a little bit of a while to set up in our financing plan. But from all the discussions we've had over the past month, we feel very bullish about being able to do this in the interest there from the other corporates.

Got it. Sounds like the process is already underway. And just to be clear, these are tax credits in excess of what you wouldn't be able to offset your taxes currently. Am I thinking about that correctly, Brian? Yep, you are. Yep. Okay. Thanks so much, Brian. Ever so helpful. Thank you so much. Yeah, thank you.

We will now take the next question from Ross Fowler with UBS.

Morning, Barb. Morning, Brian. Excuse me. How are you? Hey, great, Ross. Thanks.

So I just want to wind back a little bit to Nick's question on growth, right? You lowered the 22 base year to about 38.9, which is lower than your previously forecasted growth, and then your growing rate face out a little bit faster. If I look at your old forecast, it's sort of 6.4 to 6.5 percent through 25. And now it's kind of 7.1 to 7.4, depending on the year, through 25. And I know you mentioned transferability sort of brings that back a little bit. But now if I look at sort of your three-year rate base growth out to 25, it's about 7.3 percent. And before it was sort of 6.5 percent or just under that. So it would seem to me that you're really pushing the high end of your EPS growth guidance here, or am I not thinking about that correctly? And then I guess the second part of that question is the growth tails off a little bit in 26 and 27. Is that where you see most of that $2 billion to $4 billion in CapEx upside potential coming in?

Yeah, so I think, you know, Ross, the way we think about it is really, you know, five to seven, but we publicly target the upper half of that guidance range for EPS growth. And when we look at it, we feel very confident in delivering there. You know, we've delivered in the upper half of our guidance for the past 12 years. When you look at annual earnings guidance and delivering our guidance for 17 straight years. So we feel good about the plan we put in place. Yes, it's, we have, generally be known to put a conservative plan in place. And we have a lot of incremental upside. And I think you hit the nail on the head. If you look at one of our slides, we show where we think that incremental capital is going to be in the back half of the plan or the back two years of the plan. So I think that's the way to think about it as we kind of have that continued year-over-year strong rate-based growth.

Okay. Thanks, Brian. Maybe as we just look forward into winter, how are you thinking about, you know, natural gas fuel expenses there? You know, has any of that been sort of deferred through the regulatory process? Or how are you just thinking about bill pressure generally? How do you keep that with customers? Because, you know, natural gas prices are up a lot year over year.

Yeah, Ross, Bob, we are certainly sensitive to the commodity impact on our natural gas customers and their bills this winter. We've been very active in energy efficiency programs. We've been very active on the federal and the state levels on identifying and trying to secure significant portions of LIHEAP funding and then working with our customers directly to find and enable those customers that may not even know they're LIHEAP eligible to benefit from some of the mechanisms that we have at the state and at the federal level to mitigate impacts on our customers. We start with some of the lowest rates in the country in our Colorado gas company, but we recognize and are empathetic to everything is up from a starting point for customers who are feeling it at the pump, they're feeling it in rent, and they're feeling it at the grocery store. So we're, we're empathetic. We're doing everything we can to mitigate the impacts. We have extended the cost of the winter storm URI costs in various jurisdictions, anywhere from, you know, two to five years. So we have mitigated regulatory outcomes on that gas piece, but very active with our customers and communications as we go into the winter time.

And I'll just add, Bob, you talked on the LDC side. We can touch on the electric side, right? We're 85% roughly electric. And we've really set ourselves up well with our steel for fuel investments, right? We've always viewed those as being a hedge against rising gas commodity costs. And that's exactly what we see. Now we're going to provide our customers over a billion dollars in fuel-related benefits or avoidance this year alone with our own wind farms. And we got those approved back when their gas was $2 to $3 million. in the $2 to $3 range. So think about how economic those wind investments are for our customers now. So on the electric side, we feel good about where we are. And also on the electric side, we have the third lowest bills of any investor-owned utility in the country. So we're at a really good starting point too. And so obviously, what Bob said, we're very conscientious of customer bill impacts and spend a lot of time focusing on how we can mitigate and manage those for our customers.

Yeah, very good work on the electric side, Brian. I appreciate the answer. Thank you.

We will now take the next question from Steve Fleischman with Walt Research.

Yeah, hi, good morning. So the 18% FFO to debt that you now see, I mean, that's obviously a great number, very strong.

Is that kind of your target now for FFO to debt going forward, or how should we think about that?

Steve, The way I think about it is a little bit of balance between FFO to debt and then the holding company debt to total debt. And that metric right now for Moody's has us at about a 25% threshold on that. And certainly we can have conversations about what that right threshold is. But great to see our FFO to debt with strong improvement, 100 plus basis points relative to pre-IRA. But we look at both of those in combination because it really is important to maintain that strong credit quality, not only at the holding company, but also the to work with our commissions, ensure we have strong credit quality at all the operating companies, too, because that really is in the best interest of the customer.

Okay. And just to clarify the comment that you made about the $2 to $4 billion incremental capital, I think you said you'd be able to finance it with the current capital structure. Could you just better clarify what that means? Does that mean you would finance it kind of consistently with the way your current capital structure is in terms of new debt and new equity?

Yep. Consistent with the consolidated capital structure. Yep.

So there would be more equity needed then to fund that.

Yeah, but caveat that with all depending on the timing of that capital, right? If it's more backdated, you maybe have more flexibility. So that's just sitting here today, but it really depends on the timing. We'll evaluate it once we get more visibility on magnitude and timing of that capital.

Okay. Okay, yeah, because it just – I mean, I love strong balance sheets. Just 18% is kind of off the charts these days, so it's – But it's also obviously better to be strong than not.

Yeah, we said the IRA was good for us and good for our customers. So we're glad to be able to speak about it in more depth on this earnings call. We only had about 12 hours last Q2 earnings call to talk about it and digest the text. So happy to spend more time on it now.

Okay. And then another question, just on all the data that you gave on the IRA savings, for the cost of solar and wind. So like Sureco 30% lower and some of the data. I want to just make sure I understand the starting point there because there have been a lot of inflationary pressures for like the last 18 months. And so when you're saying these savings, are you going back to before that? Are you going to kind of where you'd be now you know, as a baseline, including those inflationary cost pressures that had already occurred. I just want to make sure I understand the baseline for that.

Absolutely. So I'll start with Sherco Solar. That includes from our very initial filing to the revised filing with higher capital costs to address the supply chain pressures. So that includes all those pressures and then pre-IRA to post-IRA. So that's that kind of actual capital costs, including pressures on the overall, call it panel pricing, with everything that happens.

So the 30% goes back to the initial filing or to the revised?

The revised filing. Okay. The revised filing is pre-IRA, post-IRA. And then on the generics, assume capital cost is the same. Assume today's capital costs are an inflated capital cost, right? So assume CapEx is the same. And a solar farm that would qualify for a 10% ITC versus now you get a PTC for us, which is a regulated utility, we'll choose the PTC. And then the range is based on NCFs and if you qualify for any adders or bonuses, so it's just community energy. So those are saving, yeah. Got it. And then wind, right, wind that assumes, say, a 2027 wind farm that would have qualified for zero tax credits, zero PTCs versus now 100% PTCs at the escalated value as you assume over time. So that's really what our customers are going to see when we add those several thousand megawatts or five plus thousand megawatts in that back half of the decade.

Okay. That's great. Thanks. Thanks for that.

Our next question comes from Sophie Karp with KeyBank.

Hi. Good morning. Thank you for taking my questions. I was curious if you could talk a little bit about the cooperation with Bloom Energy on the zero-emission electrolyzer, I guess, that produces hydrogen in front of your nuclear plants. Just curious if you could give any color on the milestones there. And also, can you describe why it makes sense to have this type of process at the nuclear plant, which is a baseload plant and presumably could dispatch into the grid at all times? as opposed to a wind facility that may have more variability. Thank you.

Hey, Sophie, it's Bob. Thanks for the question. Look, we were a recipient of a high-temperature gas, high-temperature electrification pilot from the Department of Energy related to our Prairie Island nuclear plant. And the concept is, and I think you hit on really the big point, is As we increase wind or renewable or zero-cost energy on our system, we see our nuclear plants, particularly in the shoulder months, starting to cycle up and down. And we have processes and procedures and approvals to do that. But your point is, wouldn't you rather keep the plant at 100% power and not cycle it? And that's exactly what the concept of an electrolyzer off the back of a nuclear plant does, is you take the steam... You let the reactor run at 100% power, but you don't run the generator at 100%. Use that excess steam to do steam reformation on the electrolyzer, raise the temperature, and create hydrogen that way. So you do it when the plant would otherwise be cycling. It allows you reactor stability by keeping the nuclear plant at 100% power while keeping the generation plant load following on the electric side. And your comment on the manufacturers, we chose a manufacturer for the electrolyzer, and I think that was your comment.

Okay.

Yeah, and Sophie, I'll just add to it. You know, we're working through the development of it. It should be online probably later in 2023. And as we think we're – this is a really interesting – aspect of potentially how we could use our nuclear plants and create pink hydrogen you know we're working with a consortium in our states around the hydrogen hub announcement and applying for a doe grant and and so this is part of a broader opportunity as we think we work with with our states both in minnesota in the upper midwest and also in colorado and the surrounding states on another hydrogen hub i guess just does it make a difference if uh it's uh the

nuclear plants that you avoid cycling versus just hooking it up to a wind farm. I guess from the operational standpoint, maybe it makes sense. But the marginal cost of a wind generation is zero, right? Marginal cost of a nuclear plant is not zero. So economically, does that make a difference? Or since they're on the same grade, it doesn't. Like, how should we think about this?

And so this is one of the unique aspects of this is high temperature steam electrolysis. So we're taking waste steam off the nuclear plant to heat the water, which makes the electrolysis process 30% more efficient.

Okay, got it. Thank you. That's all for me.

Yeah, thanks, Sophie.

We will now take the next question from Julian Dumoulin-Smith with Bank of America.

Hey, good morning, team. Thanks for the time. Appreciate it. Listen, I want to just pick up real quickly around the $2 to $4 billion real quickly with respect to the upside capex. How do you think about that materializing from just a timeline perspective? I know you flagged the back half of the year, but can you talk about some of the dynamics here in the near term that would result in that upside in the back half? IE is a lot predicated on the Colorado RFP processes here. How do you think about that manifesting itself here in just in terms of procurement processes? And related to that, what about upside to this 50% renewable assumption that we've used in the past? You allude to it in your script remarks on that front. Seems like there could be some latitude, whether it's had to repowerings or greenfield opportunity.

Yeah. Hey, Julian. Let me tell you the first one. Yeah, really two things. processes. One is the Minnesota RFP is already in flight. We launched it in later in Q3. And so that one's a little bit of ahead of Colorado. So likely see a decision out of Minnesota in middle of 23 on the Minnesota, but that's a smaller RFP than Colorado. Colorado is the bigger RFP in terms of megawatts of renewables. And we'll look to launch that here later this year and then likely file the application with the Colorado Commission and call it mid to late Q3 is probably when you get some visibility into that and the decision hopefully by the end of next year on the Colorado Commission. So a little bit phased between Minnesota and Colorado. On your question about the 50% assumption, we take a conservative assumption and I think, you know, Given the opportunity and the benefit that Iyer has around the solar PPC and transferability, we expect to be extremely cost competitive and potentially have an opportunity to own more than 50%. And that's certainly our goal because we think it is long-term beneficial for our customers of ownership, right? I mean, the PPAs that were struck a few years ago aren't passing this benefit of transferability back to our customers. as we are with our own wind farms, and we think about repowering our own wind farms longer term, it's more opportunity and benefit for our customers. So we think long-term ownership of these renewable assets is really good for our customers, and we're going to strive to own as much as we possibly can.

Yeah, and maybe let me just clarify a little bit. On your retirement side, are you thinking that that's pretty strictly going to be done through the RFP process here? And the timeline and opportunity set sort of dictated to that, or is there more of an opportunistic ability to approach customers on a one-off basis? I think you're implying the former.

Yeah, when you say repowerings, so I think about our own repowerings in the kind of the latter part of this decade, and that would not be in this RFP. That's a couple years out type of opportunity to bring forth with our commissions in terms of we can do something that can save our customers money. So I would say that's outside of the RFP process.

But, you know, I come back to the PPA buyout concept, and, you know, we think that RFPs and preferred plans as part of our resource plans are an opportunity to bring some of the PPA buyout forward. And we have talked about that. So we have a history of doing it outside of an RFP process, as well as that being an emphasis and a driver for it. So I would expect that some of this stuff to come to fruition over the next, you know, nine months, 12 months, as we work through the process with our commissioners and with the RFP results.

Got it. More of a holistic update, say late next year, maybe by 4Q. across all of the above.

Sounds good. Take care. Good luck.

Thanks, Julian.

A couple weeks.

And we will now take the next question from Ryan Levine with Citigroup.

Good morning. I just wanted to follow up on the Hydrogen Hub comments. To the extent that Hydrogen Hub is developed in your neighborhood or in your backyard, Can you talk to the materiality for your business outlook in light of the IRA and your opportunities both on the gas and the electric side? Sure.

Hey, this is Bob. Look, we're working on two applications for Hydrogen Hub. These proposals came out of the Infrastructure and Jobs Act that was passed around this time last year. The DOE is now in receptivity mode to receiving proposals. We've got one in the upper Midwest, largely targeted around North Dakota, South Dakota, Minnesota, and Wisconsin. And we've got both the states and MOUs partnerships, as well as a lot of the energy providers in those states working collaboratively to identify all the facets of what a hydrogen hub could look like. And I'll just give you the example in the upper Midwest. You know, we're looking at Fertilizer production, we're looking at LDC gas, we're looking at gas for electric CTs, we're looking at hydrogen production off the back of our nuclear facilities, all encapsulated into a system that allows for transportation and storage and consumption of hydrogen that's produced from clean energy. Similarly, in the western states, so in Colorado, we're working with a consortium of states, Wyoming, Utah, and New Mexico and Colorado, on a similar concept uh out west um and again a significant um we in our colorado companies at the center of those conversations again on electricity uh hydrogen for electricity hydrogen for our ldc system hydrogen for agriculture hydrogen for transportation so we talk about investment opportunities i don't think we've we've characterized them um fully in terms of the hub concept. The DOE's talked about the hubs being sort of $8 billion, four to five of them. So you could think about them being $1 to $2 billion each. And each of those are requested to have sort of matching investments from private industry to match the public funds. And we've also characterized what a hydrogen production that would match just 5% of our LDC is somewhere between $2 to $4 billion of investment between the renewables it takes to generate it, as well as the electrolyzer, the balance of plant, and the storage and transportation. So significant investments to create hydrogen for the benefit of our customers and to enable our clean energy transition. So I'd say it's a multi-billion dollar opportunity, largely centered in the back half of the decade.

Thanks. Just to be clear, you have some disclosure in Minnesota around hydrogen-ready combined or CTs. Is there any of that spending that's already in your plan, or is this all incremental?

As part of the Minnesota resource plan, we have reliability assets, combustion turbines that we've committed to making hydrogen capable. That would be included in our plan, but that's just the CT side, but none of the production of hydrogen is included in our plan.

Appreciate the cover. Thank you.

And we will now take the next question from Travis Miller with Morningstar.

Morning. Thank you. You just answered my exact question on the hydrogen hub, so I won't repeat it. But I appreciate all the detail there. I'll just throw in one more in terms of the election. Any key issues? that you're looking at or key changes potentially in any of the state-level policies or legislatures?

Hey, Travis, it's Bob. Good morning. Thanks for the inquiry on hydrogen. Glad we could answer your question. On the election, I think we're about 10 days away. Lots of activity on the televisions, lots of signs, lots of mailers, lots of emails and texts. We're obviously interested in outcomes, but I think as a company we've been very successful working with all administrations. You know, our policies of energy transition, protecting our customers, enabling a good experience, and having clean energy for all is really important. And I think we can work with any of our elected officials. We've got great relationships with those sitting officers today. And we look forward to continuing those into the future. But I don't see anything that's going to dramatically change our plans, our investment philosophy, and our 10-year trajectory that we laid out today.

Okay. Great. I appreciate all the rest of the details on the call. Great. Thanks, Travis.

And there are no further questions, so I will turn the call back to Brian Van Abel, CFO, for closing remarks.

yeah thank you all for participating in earnings call this morning we look forward to seeing everyone in a few weeks and please contact our investor relations team with any follow-up questions thank you for joining today's call you may now disconnect