Xcel Energy Inc (XEL) — Q3 2022 Earnings Call Transcript

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 Abel, 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 GAAP 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 5 years. This investment plan provides significant benefits to our customers, supports community vitality and resiliency and delivers rate base 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 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 billion to $4 billion, which would result in rate base 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 footprint 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 and a top 5 installation in the United States, which will go into service in 2024 and 2025. Following the IRA passage, the levelized cost of Sherco solar is projected to decline by over 30%, even after accounting for inflation and supply chain pressures. Due to the project qualifying 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-own-transfer projects as well as some power purchase agreements. Our generation resource plans are consistent with our Steel for Fuel strategy, which provides a valuable hedge for our customers against rising commodity prices. As an example, our owned 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 the 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 a leader in their nomenclature for managing the most significant ESG risks and opportunities. It 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 lowered the effective tax rate. 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 to reduce 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 C&I 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 made progress on a number of regulatory proceedings. During the quarter, the Minnesota Commission approved our Yuri storm settlement, including full recovery of all costs with the exception of a $19 million disallowance. We have now resolved Yuri 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 a natural gas rate case, we reached a comprehensive settlement which reflects a rate increase of $21 million, a 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 3-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 Monaco 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 the 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 are 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 5-year base capital forecast with a rate base 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 billion 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 foresee a potential incremental investment to support the clean energy transition of $2 billion 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 5-year plan, transferability to reduce equity needs to $750 million, while we've increased CapEx by $3.5 billion. In addition, we anticipate that any incremental capital will 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 and reducing equity needs. The solar PTC and tax credit transferability improve the competitiveness of our renewable bids. We project the IRA will drive approximately $500 million of customer savings from our owned renewable projects over the next 5 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 maker’s depreciation and 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. The IRA was passed with significant benefits for our customers in 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 our robust updated capital investment program that provides strong, transparent rate base growth and 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 those low for our customers. This concludes our prepared remarks. Operator, we will now take questions.

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 in that plan? I believe that there is some offset to rate base with transferability in the various tax impacts, but any more clarity would be helpful.

Yes, definitely, Nick, I'll address that. When we consider the IRA, it's a significant benefit for both our customers and us. Our financing plan focuses on transferability. There's an effect because most of those tax credits were recorded on our balance sheet as a deferred tax asset, which would elevate the cost of our renewable projects. By monetizing them, we decreased that tax asset on our balance sheet, lowering the overall levelized cost of energy for our wind and solar projects, benefiting our customers and enhancing our cash flow. This results in a lower rate base in isolation, but it enables us to decrease our equity requirements, boost capital expenditures, and effectively improve the quality of our rate base. We have substantial infrastructure in place and tax assets 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. And then in the electric rate case in Minnesota, if I heard you correctly, I think you're engaging parties for a possible settlement. Can you just kind of give us a sense of overall confidence level and just getting it across the finish line? And then 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?

Yes, Nick, it's Bob. Thanks for the question. Regarding the Minnesota electric case, first and foremost, we have the gas case settled, which provides a solid foundation for addressing the electric case. We're in discussions with involved parties, and I believe the hearings are scheduled for mid-December. Therefore, we should consider that timeframe as a potential deadline for settlement discussions.

Maybe sticking on 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?

Thank you for the question, David. We filed the case back in January with the commission, and we are looking at a 3-year forward gas case. We anticipate ongoing capital expenditures for the next year and the year after, and we have good visibility into the case. The commission granted us a historic test year case, which means we will likely need to return in 2023 for a new gas case.

Yes. 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?

Yes. Yes, I'll take that one. I think it absolutely does. And the way I think about it, it extends our PPA buyout opportunity for a long time, right? What we've been successful at, we bought out about $750 million 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 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 is in our 5-year plan as upside. And I think that longer term, as you think about repowering, as you mentioned repowering, we put over 3,000 gigawatts or 3,000 megawatts 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 4 wind repowerings in Minnesota right now. So I think this really extends our opportunity on the PPA buyout and our own repowering opportunities.

Yes. That's helpful color. It seems like a big opportunity. Any just visibility into timing or clarity as to when those could crystallize in terms of hitting the CapEx plan?

I think we might see some developments in Colorado similar to the bids we're observing in the solar-focused Minnesota RFP. The Colorado RFP will be all-source, and we could introduce something there later this year that Bob mentioned, which you might have a clearer view of by mid to late next year. During the resource plan and RFP processes, we want to ensure we stay aligned with other acquisitions. This timing is likely the first point of reference. Looking further ahead, there are more opportunities, but we need to identify a developer willing to negotiate at a price that benefits our customers.

Thank you for the detailed information on CapEx today. I'm curious about what additional opportunities might be on the horizon. Specifically, I'd like your thoughts on further prospects with MISO, whether that's through competition or expanding future LRT portfolios.

I appreciate the question. A couple of things. Brian highlighted what we would call incremental capital that 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 in Colorado to integrate those renewables. That opportunity is $2 billion to $4 billion. At the midpoint of that, we probably have rate base growth in the mid-7s. Additional to that, early things we're starting to think about, I mean, you heard the previous caller's comments around PPA buyouts and repowerings that’s certainly in our sights. We haven't put bookends around those for the community, but 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 can make an acceleration of renewables in the SPS territory, also not in our plan would be towards the back end of the 5-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 harden our grids for climate change. But some of that will happen with the intelligence we need on the distribution grid to enable electrification and 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?

Yes, I would just add a couple more points. In our 5-year plan, we have not addressed hydrogen, whether there are opportunities in the electric sector or potential possibilities in the gas local distribution company side as we progress with our clean heat plans. In addition, we are exploring some intriguing long-duration storage projects, as well as looking into opportunities with the stand-alone investment tax credit for our storage initiatives. Therefore, I believe there are several incremental opportunities that are not included in our plan as we consider the overall advantages of the Inflation Reduction Act.

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 derisk the '23 outlook, if you could kind of give us thoughts as to how that factors into the '23 guide?

Yes. On the first part, just to make sure you're talking about sales, right?

Yes.

Yes. 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 to residential use for customer to come down kind of like we saw in Colorado this year where residential usage has come down more towards pre-pandemic levels. And I think we expect to see that in other jurisdictions while we do see continued economic growth. So you could call it conservative. We are 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, yes, I think as we went through this year, right, we're certainly subject to the inflationary pressures, and we have been flat since 2014 on O&M. So that was 8 years of being flat, and we had some inflationary pressures, had storms this year, increased 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, and higher plant costs. So as we think about it next year, and we had a good year this year, if you look at the kind of the change in the guidance from Q2 to Q3, we invested it this year right when we have good time. So that's why we think about next year in maintaining flat almost a rebaselining into this year, doubling down on our continuous improvement programs and setting ourselves 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 have contagion, Jeremy, between the electric and the gas case. I think this year was particularly sensitive given the commodity increase in the impact of winter storm Yuri on the gas case. So no, I don't think I'd sort of read through too much to the electric side. We are continuing to invest in that system for safety and reliability and continued customer growth there. So we need to make sure that we're having the right balance of healthy financial metrics for the company. So we are going to file a rate case next year.

Yes. And I just think about longer term on the gas LDC side, like our net zero plans for 2030 and 2050 and 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, 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.

Solid quarter here. Thank you time. Just I actually had 2 questions, Brian, for you. Just one, I think you mentioned this in your remarks, but the jump in CFO between the 2 plants the $1.8 billion or $2 billion is included in that CFO number, right, from the tax.

Correct.

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 5 years?

Yes, that's a great question. The market for PTCs and transferability is still being established, effective January 1, 2023. Any credits generated starting that date are eligible for transfer, and we played a key role in shaping the relevant language. We have focused on this because it is crucial for our customers to lower the overall costs of renewables and the levelized cost of energy for their projects. We have not waited for a market to be established; while we anticipate that a liquid exchange will eventually be set up, we do not expect that to happen in 2023. We are actively engaging with local companies that have significant cash tax needs to explore bilateral transactions. We see a strong local opportunity to help our customers save money, and the reception to our discussions has been very positive. We are confident in our ability to execute on this transferability. However, being conservative, we are only assuming the transfer of half of those credits in 2023. This conservative approach has implications for our financing plan, but based on our discussions over the past month, we are optimistic about executing this plan and the interest from 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?

Yes, you are. Yes.

So I just want to wind back a little bit to Nick's question on growth, right? You lowered the 2022 base year to about 38.9%, which is lower than your previously forecasted growth and then your growing rate base out a little bit faster. If I look at your old forecast, it's sort of 6.4% to 6.5% through 2025, 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 3-year rate base growth out to 2025, it's about 7.3%, before it was sort of 6.5% 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?

Yes. We believe that we can achieve EPS growth in the higher end of our guidance range of 5 to 7 percent. We are confident in our ability to reach this target, as we have consistently delivered in the upper half of our annual guidance for the past 12 years and met our guidance for 17 consecutive years. We feel positive about the plan we have set. While we traditionally adopt a conservative approach, we see significant potential for additional growth. You highlighted an important point; one of our slides illustrates where we anticipate that incremental capital will come from in the latter part of our plan. So, continued strong year-over-year growth in our rate base is the best way to view this.

Okay. And maybe as we just look forward into winter, how are you thinking about natural gas fuel expenses there? Has any of that been sort of deferred through the regulatory process? Or how are you just thinking about build pressure generally? How do we keep that with customers because natural gas prices are up a lot year-over-year?

Yes, Ross, it's Bob. We are certainly sensitive to the commodity impact on our natural gas customers in their bills this winter. We've been very active in energy efficiency programs. We've been very active in 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 empathetic. We're doing everything we can to mitigate the impacts. We have extended the cost of the winter storm Yuri costs in various jurisdictions anywhere from 2 to 5 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.

I'll add that, Bob, you mentioned the LDC side. Let's discuss the electric side, where we are approximately 85% electric. Our investments in Steel for Fuel have positioned us well, acting as a hedge against increasing gas commodity costs, which is exactly what we're experiencing. This year, we're set to deliver over $1 billion in fuel-related benefits to our customers through our owned wind farms, which we approved when gas prices were in the $2 to $3 range. This highlights the economic advantages of our wind investments for our customers now. We are confident about our position in the electric sector and also note that we have the third lowest bills among investor-owned utilities in the country, providing us with a solid starting point. As Bob mentioned, we are very mindful of the impact on customer bills, and I am dedicated to finding ways to alleviate and manage those costs for our customers.

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?

I believe it's important to find a balance between funds from operations to debt and the holding company debt as a percentage of total debt. Currently, Moody's has set a threshold at around 25% for us. We plan to discuss what the ideal threshold should be. It's encouraging to note our funds from operations to debt has improved significantly by over 100 basis points compared to before the Inflation Reduction Act. However, we consider both metrics together because maintaining strong credit quality is crucial, not just at the holding company level but also across our operating companies, as it ultimately benefits our customers.

Okay. To clarify your comment about the $2 billion to $4 billion incremental capital, you mentioned that you would be able to finance it with the current capital structure. Could you explain what that means? Does it imply that you would finance it in a manner consistent with your current capital structure regarding new debt and new equity?

It is consistent with the consolidated capital structure.

Yes.

There would be more equity needed to fund that.

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

I appreciate a strong balance sheet, and having 18% is unusual these days. It's certainly better to be in a strong position than not.

Yes, we mentioned that the IRA is beneficial for us and our customers. We're pleased to discuss it in more detail during this earnings call. Last time, we only had about 12 hours during the Q2 earnings call to address it, so we're glad to dedicate more time to it now.

Okay. I have another question regarding the data you provided on IRA savings for solar and wind costs. For example, Sherco shows 30% lower figures. I want to clarify the starting point for these numbers. Given the significant inflationary pressures over the past 18 months, when you mention these savings, are you basing them on figures before those pressures, or is the baseline reflecting the current situation that includes the inflation already experienced? I just want to ensure I understand the basis for these savings.

Absolutely. I'll start with Sherco Solar. That includes our initial filing and the revised filing that reflects higher capital costs due to supply chain pressures. This encompasses all those pressures, as well as the shift from pre-IRA to post-IRA, including the actual capital costs and the impact of panel pricing.

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

The revised filing, so the revised filing, pre-IRA, post IRA. And then on the generics, assume capital cost is the same, assume today's capital cost or inflated capital costs, right? So assume CapEx is the same. And a solar farm that would have qualified for a 10% ITC versus now you get a PTC for us, which is as a regulated utility, would choose the PTC. And then the range is based on NCFs if you qualify for any, call it, adders or bonuses, so just community energy.

So those are savings, yes.

Right. When that assumes say, a 2027 wind farm that would have qualified for 0 tax cut to 0 PTCs versus now 100% PTCs at the escalated value as you assume over time. So that's really where our customers are going to see when we add those several thousand megawatts or 5-plus thousand megawatts in that back half of the decade.

I was wondering if you could discuss the collaboration with Bloom Energy on the zero-emission electrolyzer, which is intended to produce hydrogen for nuclear plants. Could you provide any updates on the milestones related to this project? Additionally, could you explain why it is beneficial to implement this process at a nuclear plant, which operates as a base load, rather than at a wind facility, which may experience more variability?

Sophie, it's Bob. Thanks for the question. We received a high-temperature electrification pilot project from the Department of Energy related to our Prairie Island nuclear plant. The main idea is that as we increase the amount of wind or renewable energy on our system, we find our nuclear plants, especially during transitional months, starting to cycle up and down. We have processes and approvals in place for that, but wouldn't it be better to keep the plant running at full power without cycling? That's where the concept of using an electrolyzer connected to the nuclear plant comes in. By taking the steam produced, we can keep the reactor at full power while not operating the generator at full capacity. Instead, we use the extra steam for steam reformation on the electrolyzer, raising the temperature to produce hydrogen. This approach allows us to maintain reactor stability by keeping the nuclear plant at full power while allowing the generation plant to adjust its load. Regarding your mention of the manufacturers, we have selected a manufacturer for the electrolyzer, which I believe you referred to.

Yes. And Sophie, I'll just add to it. We're working through the development of it, which should be online probably later in 2023. We see this as a really interesting aspect of how we might utilize our nuclear plants to create pink hydrogen. We're collaborating with a consortium in our states regarding the hydrogen hub announcement and applying for a DOE grant. This aligns with a broader opportunity as we engage with our states, both in Minnesota and the Upper Midwest, as well as in Colorado and the neighboring states on another hydrogen hub.

I guess does it make a difference if it's the nuclear plant that you avoid cycling versus just hooking it up to a wind farm, I guess, from an operational standpoint, maybe it makes sense. But the marginal cost of the wind generation is 0, right, marginal cost of a nuclear plant is not 0. So economically, does that make a difference? Or since it's on the same grade, it doesn't, like how should we think about this?

One of the unique aspects of this process is high-temperature steam electrolysis. We are using waste steam from the nuclear plant to heat the water, which increases the electrolysis process's efficiency by 30%.

Appreciate it. Listen, I want to just pick up real quickly around the $2 billion to $4 billion real quickly with respect to the upside CapEx. How do you think about that materializing just on a high-level 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, i.e., is a lot of predicated on the Colorado RFP process this year? How do you think about that, you're manifesting itself here in just in terms of procurement processes? And related to that, what about the upside to this 50% renewable assumption that we've used in the past? You alluded to it in your script remarks on that front. It seems like there could be some latitude whether to have the repowerings or greenfield opportunity.

Yes, Julien, let me address the first point. There are two processes to consider. The Minnesota RFP is already underway; we launched it later in Q3. Since it started earlier than the Colorado process, we expect to see a decision on Minnesota by mid-2023, although it is a smaller RFP compared to Colorado. Colorado represents a larger RFP in terms of renewable megawatts, and we plan to launch it later this year. We anticipate filing the application with the Colorado Commission around mid to late Q3, which should provide some visibility, with a hopeful decision by the end of next year. There is a slight phasing between Minnesota and Colorado. Regarding the 50% assumption, we adopt a conservative stance. Given the opportunities and benefits that the investment has concerning the solar PTC and transferability, we anticipate being highly competitive on costs and possibly owning more than 50%. That is definitely our goal, as we believe long-term ownership is advantageous for our customers. The power purchase agreements made a few years ago do not pass the transferability benefits back to our customers as effectively as our own wind farms do. When we think about repowering our own wind farms in the long term, we see more opportunities and benefits for our customers. Therefore, we believe that long-term ownership of these renewable assets is very beneficial for our customers, and we will strive to maximize ownership as much as we can.

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

Yes. 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 of 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 I would come back to the PPA buyout concept. And we think that RFPs and preferred plans as part of our resource plans are an opportunity to bring some of the PPA buyout toward, 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 9 months to 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 Q4.

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?

This is Bob. We're currently working on two applications for a hydrogen hub in response to the Infrastructure and Jobs Act from last year. The Department of Energy is now open to receiving proposals. One of our applications is focused on the Upper Midwest, particularly North Dakota, South Dakota, Minnesota, and Wisconsin, and we are collaborating with the states, organizations, and energy providers there to explore the various aspects of what a hydrogen hub could entail. Specifically, in the Upper Midwest, we are looking at fertilizer production, local distribution company gas, gas for electric combustion turbines, and hydrogen production from our nuclear facilities, all integrated into a system for the transportation, storage, and consumption of hydrogen produced from clean energy. In the Western states, particularly Colorado, we are collaborating with a group of states including Wyoming, Utah, New Mexico, and Colorado on a similar initiative. In these discussions, we are focusing on hydrogen for electricity, our local distribution company system, agriculture, and transportation. When considering investment opportunities, we have not entirely defined them within the hub concept yet. The DOE has indicated that these hubs could require around $8 billion, with about four to five of them planned, which means each hub could range from $1 billion to $2 billion. These projects would also need matching investments from the private sector alongside public funding. We estimate that hydrogen production sufficient to cover just 5% of our local distribution company would involve investments of between $2 billion to $4 billion, covering the renewable energy sources needed for generation, electrolyzers, balance of plant, and storage and transportation systems. This represents a significant investment to produce hydrogen that would benefit our customers and facilitate our transition to clean energy. Overall, I see it as a multibillion-dollar opportunity primarily emerging in the latter part of the decade.

And just to be clear, you have some disclosure in Minnesota around hydrogen-ready combined 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.

You just answered my exact question on the hydrogen hub, so I won't repeat it. I appreciate all the detail there. Just 1 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?

Travis, it's Bob. Thanks for the inquiry on hydrogen. Glad we can answer your question. On the election, I think we're about 10 days away, lots of activity on the television, lots of signs, lots of mailers, lots of e-mails and texts. We're obviously interested in outcomes. But I think as a company, we've been very successful working with all administrations. 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.

Yes. Thank you all for participating in our 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.