Good day everyone. Welcome to Xcel Energy's Third Quarter 2021 Earnings Conference Call. Today's conference is being recorded. [Operator Instructions]. At this time, I would like to turn the conference over to Paul Johnson, Vice President, Treasurer and Investor Relations. Please go ahead sir.

Good morning and welcome to Xcel Energy's 2021 third quarter earnings conference call. Joining me today are Bob Frenzel, President and Chief Executive Officer; Brian Van Abel, Executive Vice President and Chief Financial Officer; Amanda Rome, Executive Vice President and General Counsel; and a few others. This morning, we will review our 2021 results, share recent business and regulatory developments, update our capital and financing plan, and provide 2022 guidance. Slides that accompany today's call are available on our website. As a reminder, some 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 in our SEC filings. Today, we will discuss certain non-GAAP measures, including ongoing earnings, electric and natural gas margins. Information on comparable GAAP measures and reconciliations are included in the earnings release. With that, I'll turn over to Bob.

Thank you, Paul and good morning everybody. Today, we reported solid third quarter earnings of $1.13 per share compared with $1.14 per share last year. And given our strong year-to-date results, we're narrowing our 2021 guidance to $2.94 to $2.98 per share. We're also initiating 2022 guidance of $3.10 to $3.20 per share, which reflects our 5% to 7% long-term EPS growth objective. Consistent with our past tradition, we've updated our base investment plan, reflecting $26 billion of capital expenditures over the next five years, which provides significant benefits to our customers and supports community vitality. This investment plan delivers rate base growth of 6.5% off of a projected 2021 year-end rate base. This plan is robust, but there are certain investment opportunities that are not included in our base plan, including potential renewable generation assets authorized in our Minnesota or Colorado resource plan proceedings and additional transmission capital that's needed to integrate new renewable generation additions in Colorado beyond the base Colorado power pathway proposal. The base plan also does not include any capital for green hydrogen production for our LDC or generation needs, which we believe could be material over the balance of the decade. We have our hydrogen pilot at the Prairie Island nuclear plant, and we're exploring five to eight additional greenfield and brownfield projects. And with favorable state backdrops in Minnesota and in Colorado, which have passed clean fuel legislation as well as a potential for a federal hydrogen production tax credit, we believe that our favorable renewable generation conditions will help us push beyond pilots and into green hydrogen production resources that can be valuable to a clean energy future. I'm very excited about our investment plan, which supports continued execution of our long-term strategy and clean energy leadership. It provides for sustainability of our local communities, enhances reliability and resiliency, advances our fleet transition, keeps customer bills low, and delivers attractive returns for our investors. We're well positioned for sustainable organic growth over the next decade, including renewable additions in our proposed Minnesota and Colorado resource plans and the transmission needed to enable those carbon-free resources. Together, our resource plans are going to add nearly 10,000 megawatts of renewables to our system and achieve an 85% carbon reduction by 2030, while keeping customer bills at or below the rate of inflation. We expect decisions on both the Minnesota and the Colorado resource plans in the first quarter of next year. The clean energy transition is also going to need substantial transmission investment. We continue to make good progress in the Colorado power pathway transmission project, which is essential for us to deliver on our Colorado energy resource plan. It will enable over 5,500 megawatts of new renewables in the state, and it's vital as we explore further western market integration over time. To-date, comments from most parties have been generally supportive, and we expect the commission decision in the first quarter of 2022. In the Midwest, MISO has experienced some minor delays, but we still expect MTEP21 to be announced in the first half of next year. We also had a strong operational quarter. Our industry-leading nuclear fleet set another record, with two units having run over 700 consecutive days prior to their refueling outages. Another highlight this quarter was the dedication of the 300-megawatt Bighorn solar facility at the EVRAZ steel mill in Pueblo, Colorado. In partnership with Lightsource BP and state and local leaders, we've enabled the largest on-site solar array in the country serving a single customer. This is a really creative solution between multiple parties to ensure the continued operation and expansion of the steel mill and its 1,100 employees. It reduces carbon emissions and creates valuable property tax base that helps sustain the local economy. We also continue to partner with our states and OEMs to electrify the transportation sector. This quarter, we implemented new programs for our Colorado customers that will help us to achieve our goal of enabling 1.5 million electric vehicles across our states by 2030. We appreciate the collaboration with so many stakeholders as we collectively work to reduce carbon emissions and enable sustainable communities. We remain well-positioned with a sound strategy, a robust five-year capital plan, and sustainable long-term growth trajectory that provides attractive returns to our investors, while keeping bills low for our customers. These plans are not dependent on changes in federal policy. However, it's our understanding that Biden administration has reached an agreement on a framework for the reconciliation package, which would include extensions for investment tax credits and production tax credits, a solar and a hydrogen production tax credit, a storage and a transmission investment tax credit and direct pay options for all tax credits. This proposed plan creates significant customer benefits by lowering the cost of our proposed resource plans and potentially accelerating our clean energy transition. Our steel for fuel program has demonstrated our geographic advantages in renewables. Proposed tax credit expenses for ITCs and PTCs, including the solar production tax credit, will make future projects even more competitive, providing additional benefit to our customers. Additionally, a direct pay option would provide greater financial flexibility, increased corporate cash flow and credit metrics, which would reduce our financing needs. A PTC for green hydrogen would also bring significant value and technology advancement and costs. It could help accelerate the time frame in which we could begin incorporating hydrogen into power generation and into our natural gas distribution operations at a cost that's more economic for our customers. While discussions continue at the federal level on the final bill, we are optimistic that this plan will be passed and will have significant benefits to our customers. With that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. We had a solid third quarter, recording $1.13 per share compared with $1.14 per share last year. On a year-to-date basis, our earnings are $0.13 per share ahead of last year. The most significant earnings drivers for the quarter include the following; higher electric and natural gas margins increased earnings by $0.04 per share primarily driven by riders and regulatory outcomes to recover our capital investments. Lower O&M expenses increased earnings by $0.02 per share. And in addition, the lower effective tax rate increased earnings by $0.01 per share. As a reminder, 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 $0.03 per share reflecting our capital investment program. Lower AFUDC decreased earnings by $0.02 per share, largely due to placing several large wind farms into service last year and other items combined to reduce earnings by $0.03 per share. Turning to sales. Weather-adjusted electric sales increased by 2.4% in the third quarter, while our year-to-date electric sales increased 1.9%. Given our year-to-date results and the continued economic rebound in our states, we're updating our full year weather-adjusted electric sales growth to approximately 1.5% to 2%. Shifting to expenses. O&M expenses declined 1.9% for the quarter and increased 2.6% on a year-to-date basis. Quarterly O&M expense comparisons are noisy with the COVID impacts from last year, but overall, we expect our O&M expenses to increase approximately 1% for the year. Turning to regulatory, we reached a comprehensive settlement in Colorado, and are making strong progress on potential Texas rate case settlement. As a reminder, last quarter we reached constructive settlements in our Wisconsin, New Mexico and North Dakota rate cases. In October, we reached a comprehensive settlement with the Colorado staff in the Colorado Energy office that proposes to resolve several regulatory proceedings. Key terms include: we will fully recover all Winter Storm Uri deferred fuel costs over 24 months for electric and over 30 months from the natural gas LDC customers, with no carrying charges through a rider. Please note, the Uri Storm cost estimate for Colorado was revised to $550 million. We will refund to electric customers approximately $41 million of previously deferred revenue associated with the 2020 decoupling program. We'll forgo recovery of approximately $14 million of replacement power costs incurred due to an extended Comanche three outage during 2020. And we will not seek recovery of approximately $11 million of deferred COVID-19 bad debt expense. We are pleased that we were able to reach this comprehensive settlement, which represents compromises from all the parties and take steps to mitigate the customer impact of the Uri cost recovery. We expect a commission decision in the first half of 2022. In terms of pending rate cases, we are making progress in settlement discussions in our Texas case. As a result, the hearing schedule has been abated, and we are hopeful that we'll ultimately be able to reach a settlement agreement. We expect a decision on our Colorado electric case in March of next year with new rates effective in April. As a reminder, we're seeking a net rate increase of approximately $343 million based on an ROE of 10% and equity ratio of 55.6% in the 2022 forecast test year. The case is largely driven by capital investment. In October, we filed the Minnesota electric rate case seeking a net increase of $677 million over three years. The filing is based on a requested ROE of 10.2% and equity ratio of 52.5% in forecast test years. We requested interim rates of $288 million to be implemented in January 2022. Finally, we plan to file a Minnesota gas rate case in early November with interim rates going into effect in January of 2022. We also plan to file a stay-out option as we look to help mitigate bill impacts of Uri cost recovery for our customers. As Bob mentioned, we have issued a robust $26 billion 5-year capital forecast, which is detailed in our earnings release. Our base capital plan results in rate base growth of approximately 6.5% using 2021 as a base. The base forecast reflects significant grid investment in 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 proposed Sherco solar facility. It also includes two natural gas peaking plants to ensure reliability as we retire coal plants, along with investments to improve the customer experience. Beyond our base capital forecast, we anticipate potential incremental capital investment for renewables associated with the Minnesota and Colorado resource plans. Our proposed resource plans include approximately 2,000 megawatts of renewable additions from 2024 to 2026, which would result in incremental capital investment of $1.0 billion to $1.5 billion, assuming 50% ownership. In addition, we anticipate the need for incremental $500 million to $1 billion of related transmission for the Colorado IRP. Combined, we could see a potential incremental investment to support the clean energy transition of $1.5 billion to $2.5 billion in the latter part of this five-year forecast. We've also updated our financing plan, which reflects a combination of internal cash generation and debt issuances to fund the majority of our capital expenditures. We expect to issue $800 million of equity and $450 million of DRIP and benefits equity over the next five years. The financing plan maintains our current credit metrics and strong balance sheet, which is important for maintaining a low cost of capital for our customers. We expect the equity would likely be issued through an ATM over the five years. We anticipate that any incremental capital would be financed with approximately 50% equity and 50% debt. This incremental equity will allow us to fund accretive capital investments, which will benefit our customers while maintaining our solid credit ratings and favorable access to the capital markets. However, our equity needs could be significantly reduced if the reconciliation package is passed with the current framework. Shifting to earnings, we are initiating our 2022 earnings guidance range of $3.10 to $3.20 per share, which is consistent with our long-term EPS growth objective of 5% to 7%. Key assumptions are detailed in our earnings release. In addition, we've updated the base of our growth rate to $2.96 per share, which represents the midpoint of our revised 2021 guidance range. This represents 6.5% growth in the base between 2020 and 2021. With that, I'll wrap-up with a quick summary. We reached a comprehensive settlement in Colorado that resolved several regulatory proceedings. We are making progress towards the settlement of our Texas rate case. We narrowed our 2021 guidance range to $2.94 to $2.98 per share. We announced a robust updated capital investment program that provides strong, transparent rate base growth and customer value. We initiated 2022 earnings guidance consistent with our long-term growth objective. And finally, we remain confident we can deliver long-term earnings and dividend growth within the upper half of our 5% to 7% objective range as we continue leading the clean energy transition and keeping bills low for our customers. This concludes our prepared remarks. Operator, we will now take questions.

Thank you. [Operator Instructions] And we'll take our first question from Jeremy Tonet with JPMorgan. Please go ahead.

Hi, good morning.

Hey Jeremy

Good morning Jeremy.

Thanks. I just want to start off on the load side, if I could. What types of customers drove the C&I growth there? And how did residential perform relative to your expectations heading into the quarter? Just trying to see how you think these respective classes would be trending into 2022, particularly with retained residential load.

Yes, so I think residential has been stickier than the, call it, forecasted going into this year. And we expected to give back some of the, call it, the residential gains that we saw last year, but it's been sticky. If you look at a year-to-date basis, residential is up 1.8%. So, I think that's -- that was one of the big drivers of our updated guidance for the year. And a lot of that is in Colorado, if you look at where Colorado has been. We also see strong customer growth on the residential side across all of our service territories. Residential permits or building permits are significantly up. On the C&I side, I think it's -- we're really seeing good rebound in -- across all C&I sectors in our opcos. But really, the Permian Basin is coming back. We focus a lot on what's happening with our oil and gas customers in SPS. And we look at some substations that directly serve those loads, and that load is up 25% even relative to pre-pandemic levels. And so we're hearing our -- those customers are disciplined, but continue to drill. And also, they're looking at electrification. They're feeling ESG pressure and that is a big focus on electrifying drill rigs, pumps, compressors, certainly good load growth for us. So, I think we're pleasantly surprised with the strength of our sales and confident that it will continue into next year.

Got it. And just on residential for next year, do you expect more kind of a give back? Or have we kind of hit a new normal as far as kind of partial work from home, what have you?

I think we expect a slow give back. I think there'll be an amount of stickiness long term that will be there as you think about return to work, and I'll give you our example. We have a telecommuting policy for our employees when they come back to work. so they'll be able to work from home on a part-time basis. And I think we'll see that stickiness for a long time, but I do think it will start to come down from last year and this year a little bit.

Got it, that's helpful. Certainly, the Northern Delaware there and New Mexico, really a lot of activity, good to see it coming through for you there. And then I just want to pivot, I guess, it's a bit early for MISO's MTEP process. But just wondering what your current thoughts are, what you might be able to say as far as the first wave of projects that could come out there. Could you frame your expectations of the timing of the release, the volume of the investments expected, potential start/completion of project announced.

Hey Jeremy, it's Bob. I agree that the analysis and the output of MTEP21 has been probably slower than we expected. We do expect a series of MTEPs over the next number of years that will continue to highlight the need for transmission expansion in the upper Midwest. My expectations for 2021 are reasonable maybe modest. I think we'll see more in 2022 and 2023. I think the time line for construction is probably at the very tail of this five-year plan, but probably more in the back half of the decade for these projects. It's going to take a while to get through once you file the proceeding. It's going to take a while to get through permitting and things like that, and then actual construction. So, probably outside of our five-year forecast, but really in the five to 10 years after that.

Got it. Just one last one, if I could. For the incremental CapEx, how do you expect line of sight to develop here as the IRP process continues? Could the opportunity be fully defined in 2022? Or do you expect it to take more time?

Yes, I expect 2022 for it to really shape up. Call it a year from now, we should have a real good clarity. Q1 of next year, we expect the Phase 1s of those resource plans in both Minnesota and in Colorado to be approved by their commissions and -- with a substantial amount of renewable opportunity and growth in each of our jurisdictions, as I highlighted in my prepared remarks. We'll go through Phase two processes through Q2 and Q3 of next year, and we expect to be back here next year having some pretty good clarity on the outcomes.

And for clarification, Phase two is the request for proposal to determine how much is PPA versus BOTs and ownership.

That’s very helpful. That’s it for me. Thanks.

Thank you.

And we'll take our next question from Insoo Kim with Goldman Sachs. Please go ahead.

Thank you. My first question, and apologies if I missed it, is on the Minnesota side of things for Uri cost recovery process. Where are we in that process? And similar to what you got on the Colorado side, do you think that there is a potential for a constructive settlement there?

Yes. So, Insoo, this is Brian. So, in terms of Uri in Minnesota, the commission has approved recovery of the cost over 27 months, subject to a prudency review. There is some disputed amounts. If you remember, the Department of Commerce disputed about $20 million of our costs and the OAG disputed about $34 million of our costs. So, we'll work through that proceeding. We'd expect to see intervenor testimony late December and then a commission decision mid-next year. Now, we feel like we've acted prudently and filed commission-approved hedging policies. And we feel good about working through the process of the commission and expect to reach a constructive outcome.

Got it. And a second question just a little bit longer term, maybe for Bob. You're seeing a lot of other utilities in their generation transformation plan, putting out time line for coal retirement from the 2030s and even 2040 period to the late 2020s and whatnot. I know in your Colorado and Minnesota jurisdictions, you have the IRPs that have been filed that are -- that call for acceleration and have robust plans in place. But just how much further acceleration opportunity do you think is possible, given the current regulatory frameworks that are in place? And maybe from a financial and reliability perspective as well, and what other helper items do you think are needed to that could further support acceleration?

Yes, that's a great question. And look, we've been a leader in coal plant transitions over the last decade. And we expect, over the next decade, to close the majority of the coal plants on our systems across the country. We'll be out of coal in the Upper Midwest by the end of this decade. We're -- we have plans and approved plans to close a coal plant almost every single year this decade, which we've done a great job of transitioning to communities and the employees as part of that program. Our philosophy has been long runways, Insoo, making sure that we take care of the communities, the property tax base. We get a chance to do economic development and bring businesses back to those communities that have supported us and those assets for decades. So, with the proposal on the table for production tax credits that are part of the reconciliation bill, I think you're going to see with a 10-year window, we've got a long runway to manage this transition. And I think for the company, we are going to potentially accelerate areas that might have been a bit behind, as best we can. But these resource plans are very much in the works. And so we expect to work through these resource plans, and we file about every three years. So, come 2024, so we'd have another bite at the apple to think about the remaining assets on our fleet in those transitions. I think at the core, though, we need to identify that next generation of generation. We were the first company to announce we'd be carbon-free by 2050. I think what we need is another type of emissions-free generation. And I think the infrastructure bill triples DOE funding for research and development. I think that's critical for the industry to progress past where we expect to be, which is about an 80%, 85% carbon reduction by the end of the decade.

That makes sense. Thank you so much.

And we'll take our next question from Julien Dumoulin-Smith with Bank of America. Please go ahead. Julien Dumoulin-Smith: Hey good morning team. Thanks for the time. Perhaps just a pickup on the reconciliation

Hey Julien. Julien Dumoulin-Smith: Hey good morning. Maybe just a pickup on the reconciliation point. I wanted to follow-up on this. Just how are you thinking about the potential for expanding repowering here, depending on the various combinations on PTCs here? I mean, it seems like your position might be particularly enviable when it comes to leveraging an expanded PTC. Could you elaborate a little bit more specifically on some of the opportunities that could emerge there? I mean, I know we've been talking about repowering in various forms here for a bit.

Yes. Look, repowering is a great opportunity for us. We've been leaders in wind for 15 years. So, we've got some assets that have moved past their PTC dates, and we've got a lot of wind on our system already. We have four repowerings underway already that were approved as part of the R&R plan here in Minnesota. And I think that this bill again, which lacks a lot of definition and clarity but would provide people who've owned wind for a long time to repower those assets. So, we haven't delved into the details on our side on our legacy assets and what this would open up for repowering, but I think the opportunity could be pretty substantial.

Yes. And I think if you -- Julien, this is Brian. You heard me talk before. If you look at our PPA buyout strategy as particularly the ones who have been successful have been on the wind side where we bought them out and repowered them. So, I think a long-term extension of wind PTCs, even solar PTCs, new solar PTCs longer term, open up that PPA buyout opportunity or kind of just extend the runway for that longer term, right? We're obviously opportunistic, and you got to make it work for the customers and show a customer benefit and make it work from a financial perspective. But I think that's a longer-term opportunity that this reconciliation package in a 10-year extension of credit springs. Julien Dumoulin-Smith: Got it, excellent. And then I mean at risk of staying on the subject of reconciliation here, can you elaborate is there anything else that you all are looking at particularly closely and scrutinizing in terms of potential angles for you all specifically here? I mean, I know we talked about transmission a little bit ago, perhaps maybe elsewhere. What else are you seeing in that reconciliation bill that could really move the needle beyond the PTC in front of us?

Yes. Look, I think the bill lacks a lot of clarity. And our understanding even towards the goal line, we were putting in $100 billion or so of government infrastructure proposals that lack a lot of clarity from our side. But I see real opportunity in hydrogen, as I mentioned in the prepared remarks, storage and transmission with potential development, and obviously with the potential for a nuclear production tax credit, you're talking about significant opportunities on the customer bill side as our plants run through the next decades we've applied for in the Minnesota resource plan. So, opportunities are out there. We really honestly, without a lot of clarity on the bills, lack some definition, but that's the stuff we're going to be working on through the course of the next couple of months, and then we'll have more clarity as we get more insight into the bill text. Julien Dumoulin-Smith: Yes. No, I appreciate your prepared remarks. But it sounds like -- just to clarify that, on the nuclear front, it sounds like you could potentially tap into that depending exactly on how it's framed here for your regulated assets.

That's correct, yes. Julien Dumoulin-Smith: Excellent, good to hear. All right. Well, I'll pass it on. Thank you guys very much.

Thanks Julien.

And we'll take our next question from Steve Fleishman with Wolfe Research. Please go ahead.

Hey good morning. So, just I think, Brian, you said in your remarks that your equity needs could be lower if reconciliation passes. Could you explain that more?

Yes absolutely, Steve. I said that could significantly be reduced if the current framework passes. Now it's still a little light on details in terms of what gets passed. But you see we have $1.2 billion of equity in our plan, and you could see that cut significantly down, right? The direct pay opportunity reduces, call it, the tax inefficiency and provides probably, call it, 75 to 100 basis points of improved cash flow. And so we look at that and what we can do from a financing perspective. It gives us a lot of opportunity to reduce those equity needs. So, we're pretty excited about the overall plan, really good from customers. And we look at that long-term tax credit extension and what that can do for our customers.

Okay. And then I know this is also -- sorry, same topic. I know it's early, but the -- it looks like they've added the provision of a minimum corporate tax of 15% on larger companies like yours. And I think renewables credits are excluded from that, which is good, but I don't know if there might be other issues related to that for you. So, could you talk a little bit about how to think about that provision? And I think bonus went away with the Trump changes, but just thoughts on that issue and whether that could be a pressure?

Yes. So, it's a new regime, and we spent the last -- yesterday looking through the legislative tax and assessing that. And we think it's, for us, very manageable in terms of -- really it's -- the way it's qualified is a book alternative minimum tax, so different than the old AMT that existed. But overall, we feel comfortable with how it work and we can manage through it. And so when we look at the overall package, we view it as very positive for us. So, -- but again, like I said, it's a new regime and details will continue to come out, but that's our initial read on it.

Great, that's very helpful. Last question, just high level, you obviously have the two big rate cases, Minnesota, Colorado. You've had a lot of success in regulatory for a while now. I guess the one thing that might be different today is just there are a lot of upward rate pressures. Those are decent-sized rate filings. There's fuel costs are rising and Uri and things like that. Just could you talk about does this make that different this time?

Steve, it's Bob and thanks for the question. One of the key tenets of our strategy is affordability for our customers. You hear how resource planning will drive over the long-term, continued transitions in renewables that will drive customer bills relatively lower. We always work for ways to mitigate the customer impacts. These cases are largely capital cases under approved capital investment plans. And we have deferred -- at least in the Minnesota side, for over six years, we haven't had a case. And we've offered ways to mitigate some of the impacts of this case in particular. If you remember, we deferred cases throughout the pandemic and feel like we've been very judicious in watching our O&M expenses and trying to continue the investment plans that drive a clean energy transition, but ultimately end up in investing in capital that will ultimately need to get recovered. So, our plans, we've offered mitigation on interim rates. We think that the bill increases are manageable. I think under the proposal, we'd be down at about $1.25 a month for residential customers, so I think very manageable in total bill impacts. And so other areas we improve, we work hard on, if you think about our steel for fuel program and the success of adding wind in the Upper Midwest that -- we talked about this at the outset, but that addition of those megawatts has provided a natural gas hedge. We think we saved our customers over $300 million per year by having wind blowing instead of procuring natural gas on the margin. So, a very successful steel for fuel program, which doesn't necessarily show up, but it's mitigated bills over the last years and certainly with this uptick in natural gas pricing.

Great. Thank you so much.

And we'll take our next question from Durgesh Chopra with Evercore ISI. Please go ahead.

Hey good morning. Thank you for taking my question.

Good morning.

You've answered, I guess, all the questions I had. Maybe just elaborate a little bit on the last point you made about natural gas prices? Obviously, you've had a ton of discussions with investors on that front. So perhaps your hedges, your gas assets how are they placed, impact on customer bills, anything that you can share with us?

Yes. So, really -- Bob's point was really around our own wind investments providing significant fuel reductions. And if we look at what the cost would have been had we not had those wind farms, it would have been a $300 million higher impact to our customers on a year-to-date basis this year. So that's really what Bob's point is. I think the broader question is around kind of how these higher commodity costs potentially impact our customers. And when we think about it on the electric side. I think we're really well positioned, right? Bob already made the point about our wind strategy, our steel for fuel strategy. But also look, right, natural gas is a relatively small portion of the overall customer bills on the electric side. And we also have length. And you look at in NSP and SPS, this is something that doesn't quite come through clearly, but we've had light this year and we can sell into the market. And we've provided over $300 million in market sales that we credit back to our customers and help offset some of those higher commodity costs. So, I think we're really well-positioned on the electric side and don't see a significant impact on our customers. On the LDC side, certainly, there's less you can do there, given that commodity costs are a higher portion of our customers' bill. But the -- on the -- going into the winter, right, we have physical storage. We have financial products. And so I think we're -- when we look at it for -- take Colorado for example, I think our forecast for an impact, the average impact on the residential customer bill is about $15 per month for this winter. So, we think it's manageable, but we obviously look for every opportunity we can to help mitigate these customer bill impacts.

Thanks. The $15. Did you 1-5 dollar per month, right?

1-5, yes, not 5-0.

Yes. So what would that be percentage-wise?

It's about 20% over the -- in the winter months.

Got it. Thank you so much.

And we'll take our next question from Sophie Karp with KeyBanc. Please go ahead.

Hi, good morning and thank you for taking my question. Maybe a couple of housekeeping items, if I may. You guys are showing some equity needs in your financing plan for 2026. Can you give us some color on what shape and form those might come in as? And what should we expect in terms of timing?

Yes, I think we show -- we get about $450 million of equity through our dividend reinvestment benefits program. So, that's -- and then the other piece, we say $800 million, that's likely we do it through an at-the-market program, just through an ATM. We have flexibility over that five-year timeframe as we look at our capital needs.

Sophie, if you're -- if you want for modeling purpose, you could kind of assume something ratable assuming -- again, assuming that the -- that could be significantly reduced through a direct pay program that could potentially be approved by the government by year end.

Got it. And then just overall, the CapEx is going higher, right? And so how should we think about the rate base growth in this scenario? And I can appreciate there's lots of puts and takes here with uncertainties with what the Washington is going to do. But in general, how should we think about that and the corresponding kind of regulatory lag and earnings growth with this new forecast? And if you guys are not prepared to talk about this now, like when do you think you will roll out those numbers?

Yes. No, I think we're pretty excited about our new capital plan. I think we -- as Bob mentioned, it drives a lot of benefit for our customers. And it's -- based off of our kind of 2021 rate basis, it will afford us a 6.5% rate base growth for our five-year plan. And then if you look at that, call it, potential incremental capital that we need on the transmission system and some renewables that could come out of the resource plans, that could push north of 7%, to about 7.3% if we executed on that. And a lot of this, right, depending on the type of capital, it could be recovered through riders if it's transmission or renewables or built into our multiyear plan in Colorado. So, we're comfortable with the overall capital plan and have kind of plans in place to address the regulatory recovery of it.

And Sophie, if you look at the slides we do detailed rate base growth by year. So, if you want to see that, you can check that out.

Got it. Thank you. And lastly, if I may, on Colorado. So, a pretty good outcome I guess with the settlement there on the fuel cost recovery. Should we think about potentially that opening the door on the settlement in the rate case you have there or is it too early to say?

Well, I think you're hitting on one of the key points of the settlement. I mean we put four proceedings behind us as part of the settlement so that we could get to the more strategic conversation, Sophie. The power pathway and the resource plan are certainly right in front of us and ripe for fourth quarter conversations. And then as you mentioned, longer term the electric rate case in Colorado could also be in there. So, yes, I think what it says is we've got pathways to settlement in Colorado, we can reach constructive outcomes, we wanted to clear the underbrush a bit and get to the bigger and more strategic issues.

Thank you. I appreciate the comments. I'll jump back into the queue.

And we'll take our next question from Travis Miller with Morningstar. Please go ahead. Please go ahead.

Good morning. Thank you.

Hey Travis.

Hey Travis.

I wanted to kind of build on the customer affordability and rate-making a little bit. If you look holistically across all the regulatory rate-making proposals and such that you have out there, and we put kind of buckets around those components of the allowed ROE or cost of capital, another bucket being operating cost recovery, another bucket being CapEx, where are you seeing the most pushback in terms of keeping customer bill affordable on that?

I think ROE has always been, call it, an area of dispute in the rate case, right? So, I think that -- I don't think that's unique to us. I think that's pretty common across other utilities. That's one of the big levers that they look at in determining what the appropriate ROE is. Now, we feel pretty good that from where we stand, our ROEs that have been authorized over the past few years have been below the national average. So, when we think about ROE risk there, we think of more potential upside and getting closer to the national average, right, as we know we're leading the clean energy transition, helping our states lead with their policy goals. So, I think there's an opportunity there for us on the ROE side. Now, for us, I think we're pretty proud about our O&M story. Now, if you go all the way back to 2014 and look at where we are today, we're basically flat from an O&M perspective. So, we saved -- if you just apply the 2% inflation growth in that number, maybe several hundred millions of dollars that we've avoided and saved our customers annually. So, I think -- overall, I think we have a really clean story. Our cases are primarily capital-driven, investing in the needs of the system. So, I think overall -- obviously, you have sometimes just lumpy if you hadn't filed a case in six years, and it comes a big headline number. But we look forward to working with our parties and the commissions on working through these rate cases and really delivering a great product in the end.

Hey Travis, it's Bob. Just one more thing to add on to what Brian said, which I completely agree with. We've got -- and I mentioned this earlier, we've got such a favorable renewables regime where we sit that we've been able to both mitigate commodity increases, whether that's coal or natural gas over time, deliver on our steel for fuel premise and drive the fuel component of customer bills down and provide sort of a mitigant in terms of volatility. And that provides real value both on the residential side. But when you talk to our industrial customers, stability and predictability is what they really want as they're making investments in their own business. And by being able to have a favorable regime for that, we can deliver renewables at significantly more beneficial cost than a lot of the country. And that's helped mitigate our total bills for all of our customer classes.

Okay, great. I really appreciate it and you had answered all my other questions.

And we'll take our next question from Paul Patterson with Glenrock Associates. Please go ahead.

Hey, good morning.

Hey Paul.

Good morning.

Just really quick clarification question on, I guess it's Jeremy. The just on a high level, that 1% sales growth -- and I realize that it's been shifting around and what have you. Of course, we've had COVID. But just going forward at 2022, just from my understanding, would you say that 1% is kind of what you see as being now a new normal number? Not so much between the classes of customers, just a general projection in 2023, et cetera. Do you think that that's sort of your new run rate in terms of sales growth?

I think it might be looking beyond 2022. I think 2022, we're still starting to see still a little bit of a rebound from the depths of COVID. So, I don't know if that's a full 1%, probably between 0% and 1% on a longer five-year forecast. I think that's -- there's upside opportunities. I'll hedge when I give that number. There's upside opportunities, right, from electric vehicles. And we're just getting into the discussion of beneficial electrification. So, I think longer term, there's a lot of opportunities on the electric sales side. But I think for this front 5, you're probably talking in the 0% to 1% after 2022.

Okay, that's great. And then in terms of inflation, no change in that since we talked about it last quarter, so I don't want to go over it again. But unless there has been a change in your outlook, has there been any change or any new thoughts about it?

No, but I mean I'm sure you read the same headlines as we all do with the near-term inflationary pressures. But no real changes from our commentary in Q2 as we think about it longer term.

Got you. Thank you.

And we'll take our next question from Ashar Khan with Verition. Please go ahead.

Hi, good morning. If I heard correctly in response to Steve's question you said that if this reconciliation bill passes and the direct payout provision, that you can eliminate most of your equity needs of $1.1 billion that you have in the plan. Is that accurate? I just want to reconcile.

No, I said we could significantly reduce our equity needs.

Significantly. Okay, significantly is more than 50%?

I think significantly is significantly. And we do -- we really have to see the details of this plan, right? It's a framework, and the details are light. So, once we get through all the nuts and bolts of it, we'll come back. Assuming it gets passed, which we are optimistic that it gets passed, we'll come back with the full details on it.

Okay, okay. So, but then if that significantly happens hopefully, then that should imply a higher growth rate because we have less dilution. Is that -- would that be a reasonable assumption, one leading to the other?

There are some puts and takes. You could see a little bit lower rate base growth depending on the details of it. So, there's puts and takes, but I think overall, we're positive about where the reconciliation package stands, both for our customers and for us as a company.

As -- okay, as shareholders. Okay. Thank you.

It appears there are no further questions. at this time. I'd like to turn the conference to CFO, Brian Van Abel for any additional or closing remarks.

Yes, thank you all for participating in our earnings call this morning. With any questions, please contact our Investor Relations team.

This concludes today's call. Thank you for your participation. You may now disconnect.