Xcel Energy, Inc. (NASDAQ:XEL) Q3 2022 Results Conference Call October 27, 2022 10:00 AM ET
Company Participants
Paul Johnson – VP, IR & Treasurer
Bob Frenzel – President, CEO & Chairman
Brian Van Abel – EVP, CFO & Principal Accounting Officer
Conference Call Participants
Nicholas Campanella – Credit Suisse
David Arcaro – Morgan Stanley
Jeremy Tonet – JPMorgan
Durgesh Chopra – Evercore
Ross Flower – UBS
Steve Fleishman – Wolf Research
Sophie Karp – KeyBanc
Julian Dumoulin-Smith – Bank of America
Ryan Levine – Citigroup
Travis Miller – Morningstar
Operator
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.
Paul Johnson
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.
Bob Frenzel
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, keep 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 is 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 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-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 leader in their nomenclature for managing the most significant ESG risks and opportunities. It’s 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.
Brian Van Abel
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 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 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, 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. And in a 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 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 can see 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, transfer ability 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 makers’ 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. 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.
Question-and-Answer Session
Operator
[Operator Instructions] We will take our first question from Nicholas Campanella with Credit Suisse.
Nicholas Campanella
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.
Brian Van Abel
Yes. Absolutely, Nick, and I’ll handle that one. Yes. I mean when we look at the IRA, huge win for our customers and us. And really — and when we think about our financing plan, it’s around transferability. And there is 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 reduced 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. Much of the steel in the ground and the tax assets on our balance sheet.
Paul Johnson
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.
Nicholas Campanella
Got it. That’s helpful. 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?
Bob Frenzel
Yes, Nike, it’s Bob. Thanks for the question. 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 as to 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.
Operator
We will now take the next question from David Arcaro with Morgan Stanley.
David Arcaro
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?
Bob Frenzel
David, it’s Bob. Thanks for the question. We filed the case back in January with the commission, and we’re looking for a 3-year forward gas case. We have expected capital expenditures continuing next year and the year after, and we have real visibility into the case — 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.
David Arcaro
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?
Brian Van Abel
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 PP and repowering it and qualifying for new set — new strip of tax credits on the wind side.
So pre IRA, the buyout opportunities were stepping down as your tax credit 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 is 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.
David Arcaro
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?
Brian Van Abel
I think what we could potentially see in the Colorado, like we talked about potentially seeing bids in the RFP and the Minnesota RFP is focused on solar. The Colorado 1 will be an all-source RFP so we could potentially see something in that RFP that we’ll launch later this year that Bob mentioned, will — you’ll get visibility in call it, mid to later next year, could be the first time. Because when we were middle of kind of the resource plan and RFP processes, we want to follow those and make sure we align with the other acquisitions. So that’s probably 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 at a price that’s beneficial for our customers.
Operator
We will now take the next question from Jeremy Tonet with JPMorgan.
Brian Van Abel
Jeremy, nice headline.
Jeremy Tonet
Just with life in the fastlane, just wondering — thank you for all the details today on CapEx, but what could be incremental maybe on the horizon here, if I dare kind of asked what more could come in over time? And specifically, thoughts on additional MISO opportunities, whether that’s competitive or upsizing future LRT portfolios?
Bob Frenzel
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, things — 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 sites. 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.
Brian Van Abel
Yes, I would just add a couple more to that. One is in our 5-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 stand-alone ITC on store — for our storage we’re looking at opportunities there. So I think there’s a good number of, call it, incremental opportunities that aren’t captured in our plan as we think through the overall benefits of the IRA.
Jeremy Tonet
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?
Brian Van Abel
Yes. On the first part, just to make sure you’re talking about sales, right?
Jeremy Tonet
Yes.
Brian Van Abel
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 resi UPC 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, 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 the change in the guidance from Q2 to Q3, we invested it this year, right, and 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 our continuous improvement programs and setting ourselves up for next year.
Jeremy Tonet
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?
Bob Frenzel
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.
Brian Van Abel
Yes. And I just think about longer term on the gas LDC side, like our net 0 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 plant 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.
Bob Frenzel
And just to put a time line on that, you should see a clean heat plan filing from the company sometime in the second half of next year.
Jeremy Tonet
Got it. That all makes a lot of sense. Just checking.
Operator
And we will now take the next question from Durgesh Chopra with Evercore.
Durgesh Chopra
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.
Brian Van Abel
Correct.
Durgesh Chopra
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?
Brian Van Abel
Yes, 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 1 — so any credit generated starting January 1, 2023, so starting next year is eligible to be transferred. And 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 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 that — so it takes a little bit of while less 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.
Durgesh Chopra
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?
Brian Van Abel
Yes, you are. Yes.
Operator
We will now take the next question from Ross Flower with UBS.
Ross Fowler
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 base out a little bit faster. If I look at your old forecast, it’s sort of 6.4% to 6.5% 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 3-year rate base growth out to 25%, 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?
Brian Van Abel
Yes. So I think, Ross, the way we think about it is really 5 to 7, 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. We’ve delivered in the upper half of our guidance for the past 12 years when you look at our annual earnings guidance and delivering on our guidance for 17 straight years. So we feel good about the plan we put in place. Yes, it’s — we have generally been 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 1 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 2 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 base growth.
Ross Fowler
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?
Bob Frenzel
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.
Brian Van Abel
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 $1 billion in fuel-related benefits or avoidance this year alone with our owned wind farms and we got those approved back when their gas is $2 to $3 — 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 I spent a lot of time focusing on how we can mitigate and manage those for our customers.
Operator
We will now take the next question from Steve Fleishman with Wolf Research.
Steve Fleishman
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?
Brian Van Abel
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 going to have a conversation about what that right threshold is. But — great to see our FFO to debt with strong improvement of 100-plus basis points relative to pre IRA. So — but we look at both of those in combination because it really is important to have — maintain that strong credit quality, not only at the holding company, but also to work with our commissions ensure we have strong credit quality at all the operating companies too, because it really is in the best interest of the customer.
Steve Fleishman
Okay. And just to clarify the comment that you made about the $2 billion 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 consistent with the way your current capital structure is in terms of new debt and new equity or is it —
Brian Van Abel
It is consistent with the consolidated capital structure.
Bob Frenzel
Yes.
Steve Fleishman
So there would be more equity needed then to fund that if you —
Brian Van Abel
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.
Steve Fleishman
Okay. Okay. Yes, because it just — I mean I love strong balance sheet, just 18% is kind of off the charts these days. So it’s — but it’s also obviously better to be strong than not.
Brian Van Abel
Yes. 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 in [digested tax], so happy to spend more time on it now.
Steve Fleishman
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 Sherco 30% lower and some of the data. Just 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 seeing these savings, are you going back to before that? Are you going to kind of where you’d be now, is the baseline including those inflationary cost pressures that had already occurred? I just want to make sure I understand the baseline for that — for these.
Brian Van Abel
Absolutely. So Sherco — I’ll start with Sherco Solar. That includes from our initial — very initial filing to the revised filing with higher capital costs to address the supply chain pressure. So that is — 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 —
Steve Fleishman
So the 30% — so the 30% goes back to the initial filing or to the revised.
Brian Van Abel
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 an 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.
Steve Fleishman
So those are savings, yes.
Brian Van Abel
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.
Steve Fleishman
Okay. That’s great.
Operator
Our next question comes from Sophie Karp with KeyBanc.
Sophie Karp
I was curious if you could talk a little bit about this — the collaboration with Bloom Energy on the zero-emission electrolyzer, I guess, produce hydrogen and try 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 base load plan and presumably could dispatch into the grade at all times as opposed to a wind facility that may have more variability.
Bob Frenzel
Sophie, it’s Bob. Thanks for the question. Look, we were a recipient of a high-temperature gas — or 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 0 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. As 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 that 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.
Brian Van Abel
Yes. And Sophie, I’ll just add to it. We’re working through the development of it, it should be online probably later in 2023. And as we think we — this is a really interesting aspect of potentially how we could use our nuclear plants and create pink hydrogen. We’re working with a consortium in our states around the hydrogen hub announcement and applying for a DOE grant. And so this is part of a broader opportunity as we think we work with our states, both in Minnesota and the Upper Midwest and also in Colorado and the surrounding states on another hydrogen hub.
Sophie Karp
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?
Brian Van Abel
And so this is 1 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 it 30% — the electrolysis process 30% more efficient.
Operator
We will now take the next question from Julian Dumoulin-Smith with Bank of America.
Julien Dumoulin-Smith
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.
Brian Van Abel
Yes. Julien, let me hit on the first one. Yes, really two processes. One is the Minnesota RFP is already in flight. We launched it in — later in Q3. And so that was 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 in, 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 given the opportunity and the benefit that the IR has around the solar PTC 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 tell as much as we possibly can.
Julien Dumoulin-Smith
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 time line 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.
Brian Van Abel
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.
Bob Frenzel
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.
Julien Dumoulin-Smith
Got it. More of a holistic update, say, late next year, maybe by 4Q.
Bob Frenzel
Across — all of the above.
Operator
And we will now take the next question from Ryan Levine with Citigroup.
Ryan Levine
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?
Bob Frenzel
Sure. This is Bob. Look, we’re working on 2 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 1 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, 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, so Wyoming, Utah and New Mexico and Colorado on a similar concept out West. And again, a significant — we and our Colorado companies at the center of those conversations, again, on electricity, 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 characterized them fully in terms of the hub concept. The DOE has talked about the hubs being sort of $8 billion, 4 to 5 of them. So you could think about them being $1 million 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 billion to $4 billion of investments 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 multibillion-dollar opportunity largely centered in the back half of the decade.
Ryan Levine
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?
Bob Frenzel
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.
Operator
And we will now take the next question from Travis Miller with Morningstar.
Travis Miller
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?
Bob Frenzel
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.
Travis Miller
Okay. Great. I appreciate all the rest of the details on the call.
Operator
And there are no further questions. So I will turn the call back to Brian Van Abel, CFO, for closing remarks.
Brian Van Abel
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.
Operator
Thank you for joining today’s call. You may now disconnect.
Be the first to comment