Good day everyone. Welcome to Xcel Energy's Third Quarter 2021 Earnings Conference Call. Today's conference is being recorded. 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 the 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 among multiple parties to ensure the continued operation and expansion of the steel mill and its 1,100 employees. It reduces carbon emissions and creates a 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 the 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 timeframe 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 effective tax rate. However, PTCs are flowed back to customers through lower electric margin and are largely earnings neutral. Offsetting these positive drivers were increased depreciation expense, which reduced earnings by $0.03 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. 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.

I believe the residential segment has been more stable than we initially predicted at the beginning of the year. We anticipated some decline in the residential gains from last year, but it has remained steady. Year-to-date, the residential area has increased by 1.8%, which has significantly influenced our revised guidance for the year. Much of this growth is concentrated in Colorado, where we are also witnessing strong customer growth in residential across all our service areas. Residential building permits have increased substantially. On the commercial and industrial side, we are observing a solid rebound across all sectors in our operations. The Permian Basin is particularly showing signs of recovery. We pay close attention to the activities of our oil and gas customers in SPS, and we’ve noted that the load in certain substations serving those customers is up by 25% compared to pre-pandemic levels. While our clients are exercising discipline, they continue to drill and are also exploring electrification solutions. They are under pressure to meet ESG standards, which is driving a focus on electrifying drill rigs, pumps, and compressors, contributing to good load growth for us. Overall, we are pleasantly surprised by the robustness of our sales and are confident that this momentum will carry 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 timeline 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 ten 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 to be a significant year. In about a year, we should have clear insights. In the first quarter of next year, we anticipate the Phase 1 plans for both Minnesota and Colorado to gain approval from their respective commissions, accompanied by considerable renewable opportunities and growth in each area, as I mentioned in my prepared comments. We will proceed with Phase two processes during the second and third quarters of next year, and I believe we'll return next year with a much clearer understanding of the results.

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 are 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. I have a second question that may be more long-term, perhaps for Bob. Many other utilities are laying out timelines for coal retirement, moving from the 2030s and 2040s to the late 2020s in their generation transformation plans. In your Colorado and Minnesota jurisdictions, I know you have filed Integrated Resource Plans that call for acceleration and have strong plans. How much more acceleration do you believe is achievable given the existing regulatory frameworks? Additionally, could you address this from a financial and reliability standpoint, and what additional factors do you think might help support further acceleration?

Yes, that's an important point. We have been at the forefront of transitioning coal plants over the past ten years, and we plan to close most of the coal plants in our systems nationwide over the next decade. By the end of this decade, we will eliminate coal in the Upper Midwest. We have plans, which are already approved, to shut down a coal plant nearly every year during this decade. We have been effective in transitioning and supporting the communities and employees involved in this process. Our approach has focused on long-term strategies, ensuring we support the communities, maintain the property tax base, and facilitate economic development to attract businesses back to these areas that have relied on us and these assets for many years. With the production tax credit proposal included in the reconciliation bill, we are looking at a lengthy ten-year period that allows us to effectively manage this transition. We may look to expedite efforts in areas that may not be as advanced. These resource plans are actively being developed, and we typically file these plans every three years, with the next opportunity in 2024 to reassess our remaining assets and their transitions. Ultimately, we need to focus on the next generation of clean energy. We were the first to commit to becoming carbon-free by 2050, and we are seeking another type of emissions-free power source. The infrastructure bill significantly increases funding for research and development, which is essential for the industry to move beyond our goals of an 80% to 85% reduction in carbon emissions 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.

Hey good morning team. Thanks for the time. Perhaps just a pickup on the reconciliation.

Hey Julien.

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, Julien, this is Brian. As I've mentioned before, our PPA buyout strategy has seen success primarily in wind, where we have bought and repowered projects. I believe a long-term extension of wind and solar PTCs would create new opportunities for PPA buyouts and extend the potential for these projects. We remain opportunistic and need to ensure that these initiatives benefit customers while being financially viable. Overall, this reconciliation package and a 10-year extension of credit could present significant long-term opportunities.

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.

Yes. I appreciate your prepared remarks. To clarify, regarding nuclear, it seems you could potentially leverage that depending on how it's structured for your regulated assets.

That's correct, yes.

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. 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. I understand this is a continuation of the same topic. It's early, but it appears that a minimum corporate tax of 15% has been introduced for larger companies like yours. While it's positive that renewables credits are excluded from this, I am uncertain if there may be additional concerns related to this for you. Could you provide some insights into how to approach this provision? I believe the bonus was eliminated with the changes made during the Trump administration, but I would appreciate your thoughts on this matter and whether it could pose a challenge.

Yes. It's a new system, and we spent yesterday reviewing the legislative tax changes. We find it quite manageable since it introduces a book alternative minimum tax, which is different from the previous AMT. Overall, we are comfortable with its implementation and confident that we can navigate through it. When we evaluate the entire package, we see it as very favorable for us. However, as I mentioned, it's a new system, and more details will emerge, but that’s our initial assessment.

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. Thank you for the question. A key part of our strategy is ensuring affordability for our customers. We believe that effective resource planning will lead to long-term shifts toward renewables, resulting in lower bills for customers. We constantly seek ways to reduce the financial impact on our customers. The cases we are dealing with mostly fall within approved capital investment plans. For more than six years on the Minnesota side, we have not raised rates, and we've provided solutions to lessen the impact of the current case specifically. During the pandemic, we deferred cases and have carefully monitored our operating and maintenance expenses while continuing to invest in plans that support a clean energy transition, which ultimately requires capital investment that we will need to recover. We have proposed measures for mitigating interim rates and believe that the bill increases we are looking at are manageable. Under our proposal, residential customers would see an increase of about $1.25 a month, which we consider manageable in terms of overall bill impact. Additionally, we have made improvements in other areas, such as our steel for fuel program and the successful expansion of wind energy in the Upper Midwest. This addition of wind capacity has provided a natural gas hedge, saving our customers over $300 million per year by relying on wind rather than purchasing natural gas as needed. Our steel for fuel program has been very successful, helping to mitigate bills over the past few years, especially in light of rising natural gas prices.

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.

Hey 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, the impact on customer bills, anything that you can share with us?

Yes. Bob's point was about our wind investments leading to significant fuel reductions. Without those wind farms, our customers would have faced an additional $300 million in costs so far this year. Bob's main idea is that while higher commodity costs are a concern, we’re in a strong position, especially on the electric side. Our wind strategy and steel for fuel approach are beneficial. Additionally, natural gas makes up a small part of our overall electric bills. We have excess capacity, particularly with NSP and SPS, which allows us to sell additional energy in the market, generating over $300 million in market sales that we credit back to our customers to help offset increased commodity costs. Overall, we're well-positioned on the electric side and anticipate minimal impact on our customers. On the LDC side, there's less flexibility since commodity costs are a larger part of our customers' bills. As we head into winter, we have physical storage and financial products to help manage costs. For example, in Colorado, we estimate an average increase of about $15 per month on residential customer bills this winter. While we believe this is manageable, we continuously seek ways to reduce these bill impacts for our customers.

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 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, we project approximately $450 million in equity from our dividend reinvestment program. Additionally, we anticipate $800 million, likely through an at-the-market program. We have flexibility over this five-year period as we evaluate our capital requirements.

Sophie, for modeling purposes, you could assume something ratable, again assuming that it could be significantly reduced through a direct pay program that may potentially be approved by the government by the end of the year.

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 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, we are quite enthusiastic about our new capital plan. As Bob mentioned, it provides significant benefits for our customers. Based on our 2021 rate basis, it will enable a 6.5% growth in our rate base for our five-year plan. Additionally, considering the potential extra capital needed for our transmission system and some renewable projects that may arise from the resource plans, we could see growth exceeding 7%, reaching about 7.3% if implemented. Much of this depends on the type of capital, and it could be recovered through riders if it's related to transmission or renewables, or incorporated into our multiyear plan in Colorado. Overall, we are confident in the capital plan and have strategies ready to manage its regulatory recovery.

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.

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 believe that Return on Equity has always been a contentious topic in the rate case. This is not something unique to us; it's quite common among other utilities. It is a significant factor in determining the appropriate ROE. We feel confident that our authorized ROEs over the last few years have been below the national average. Therefore, we see more potential for improvement and a movement closer to the national average, as we are leading the clean energy transition and assisting our states in achieving their policy objectives. This presents an opportunity for us regarding ROE. We take pride in our operational and maintenance performance. Looking back to 2014, our O&M expenses have remained relatively flat. If we consider a 2% inflation growth on those expenses, we've managed to save hundreds of millions of dollars annually for our customers. Overall, we believe we have a strong narrative. Our cases mainly revolve around capital investment to meet system needs. Although there can be significant fluctuations, especially after not filing a case for several years, we are eager to collaborate with our stakeholders and regulatory bodies on these rate cases to ultimately provide a great outcome.

Hey Travis, it's Bob. I want to add to what Brian said, which I completely agree with. We have a very favorable renewables environment, which has allowed us to manage commodity increases, such as coal and natural gas, over time. This has enabled us to fulfill our steel for fuel promise, reduce the fuel portion of customer bills, and provide stability against volatility. This is valuable for both residential customers and, importantly, industrial customers who prioritize stability and predictability as they make investments in their businesses. With a favorable renewables regime, we can offer renewable energy at a much lower cost than many areas of the country, helping to reduce the total bills for all 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.

I have a quick clarification question for Jeremy. Regarding the 1% sales growth, I understand it has been fluctuating. Considering the impact of COVID, looking ahead to 2022, do you believe that 1% is what you now see as a new normal figure? This is more about a general projection for 2023 than the differences among customer classes. Do you think this is your new run rate for sales growth?

I believe we should look beyond 2022. In 2022, we are still experiencing a slight rebound from the effects of COVID. Therefore, I'm not sure if we can consider it a full 1%, likely falling between 0% and 1% in a longer five-year outlook. However, there are opportunities for growth, particularly with electric vehicles, and we are just beginning to explore beneficial electrification. Long-term, there are numerous opportunities in electric sales, but for the immediate future, we are probably looking at a range of 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 believe significantly means significantly. We need to review the specifics of this plan. It's a framework and lacks detailed information. Once we go through all the specifics, we will provide more information. Assuming it is approved, which we are hopeful it will be, we will share the complete details.

If that significantly happens, it should imply a higher growth rate due to less dilution. Would that be a reasonable assumption, connecting one 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 shareholders, 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.