Good day, and welcome to Xcel Energy's First Quarter 2021 Earnings Conference Call. Today's conference is being recorded. At this time, I would like to introduce your host for today's call, Paul Johnson, Vice President of Investor Relations. Please go ahead.

Thank you. Good morning, and welcome to Xcel Energy's 2021 First Quarter Earnings Conference Call. Joining me today are Ben Fowke, Chairman, Chief Executive Officer; Bob Frenzel, President and Chief Operating Officer; Brian Van Abel, Executive Vice President and Chief Financial Officer; and Amanda Rome, Executive Vice President and General Counsel. This morning, we will review our 2021 results and share recent business and regulatory developments. There are slides that accompany today's call available on our website. As a reminder, some of the comments 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 metrics that are non-GAAP measures, including ongoing earnings and electric and natural gas margins. Information on the compatible comparable GAAP measures and reconciliations are included in our earnings release. With that, I'll turn it over to Ben.

Well, thank you, Paul, and good morning, everyone. Today, we reported strong first quarter earnings of $0.67 per share compared with $0.56 per share last year. We're off to a good start, and we are reaffirming our 2021 guidance range. But I want to start out by thanking our employees for their outstanding work to ensure that our customers did not experience any material outages during Winter Storm Uri. I'm proud of the strong performance of our power plants and our electric and natural gas systems during that serious event. I think there are a lot of lessons learned from Uri, including the need to invest in resiliency, the increased interdependency between the gas and electric sectors, and the need to have 24/7 dispatchable generation available. So despite strong operational performance, we incurred $1 billion of incremental fuel costs during the winter storm. It's important to recognize that we followed all the policies and procedures regarding natural gas purchasing and hedging as approved by regulators in our states. We're in the process of seeking recovery for incremental fuel cost and we'll propose to defer the cost recovery over 1 year or 2 to mitigate the impact on our customers. Turning to our investment plans. In February, we filed our proposal to buy out a repowered 120-megawatt wind PPA from ALLETE for $210 million. The buyout will save our customers money while extending the life of our renewable energy resource. We also filed our proposal to build 460 megawatts of solar facilities near our retiring Sherco Coal plant for an estimated investment of $575 million. The project takes advantage of existing transmission and will bring good, high-paying local construction jobs to our economy. We requested a commission decision on both projects later this year and are confident the commission will see the customer and economic benefits. In March, we filed our resource plan in Colorado, which details our plans to reduce carbon emissions by 85% and increase renewables to 80% of our fuel mix by 2030. The plan includes the early retirement of 2 coal units at Hayden in 2027 and 2028, the conversion of Pawnee to natural gas in 2028, and the early retirement of Comanche 3 in 2040 with reduced operations beginning in 2030. Now under the plan, we will add 2,300 megawatts of wind, 1,600 megawatts of universal scale solar, 400 megawatts of storage, 1,300 megawatts of flexible resources, and 1,200 megawatts of distributed solar resources through our renewable energy programs. In addition, we are continuing to make progress on the Minnesota resource plan and expect a decision later this year. Between the Minnesota and Colorado resource plans, we anticipate adding nearly 10,000 megawatts of renewables to our system to meet our 80% carbon reduction goal by 2030. We also filed our pathway transmission expansion plan in Colorado. The proposal requests approval to build 560 miles of 345 kV transmission lines, creating a backbone that will enable 5,500 megawatts of incremental renewables and help Colorado achieve its 2030 carbon reduction goals. The estimated cost of the backbone is $1.7 billion, with an incremental investment of up to $1 billion for network upgrades, voltage support, and additional transmission line and interconnection work. We expect decisions on the Colorado pathway project later this year. Turning to the NSP system. MISO recently presented its long-range transmission planning roadmap, which identified potential scenarios for future system development based on constrained areas and options for regional transmission expansion. This conceptual roadmap highlighted an initial set of projects in the MISO footprint, which could drive $30 billion of investment, and a full rollout could result in up to $100 billion of investment. While this is very preliminary, a high-level conceptual framework, it does highlight the need for significant transmission over the next 15 years. The transmission expansion and resource plans will provide transparency into our long-term opportunities and will likely lead to robust capital investment in the second half of this decade. Now, as you know, one of my highest priorities is ensuring Xcel Energy is a positive force for racial justice and reconciliation. We are deeply committed to supporting our communities in advancing racial equity, rebuilding following civil unrest, and addressing COVID-19 impacts, which continue to disproportionately affect black communities. I'm proud that our company is engaged in a community dialogue, and we are investing in organizations that are having a real impact. We've got more work to do as a company, a community, and a country towards creating a more just society. But by working together, we can all be part of the solution. We're also proud of the recognition we're receiving for our actions. For example, Xcel Energy was named among the world's most admired companies by Fortune Magazine for the eighth consecutive year, ranking second among gas and electric companies. And we continue to be cited as a top company for LGBTQ equality, earning a perfect score in the Human Rights Campaign's 2021 Corporate Equality Index and a 'Best Place to Work for LGBTQ Equality' designation for the fifth consecutive year.

Thanks, Ben. Good morning, everyone, and thanks for joining us. We had a good start to the year, booking $0.67 per share compared to $0.56 per share last year. The most significant earnings drivers for the year include the following: higher electric and natural gas margins increased earnings by $0.18 per share, primarily driven by riders and rate outcomes to recover our capital investments and increase margin from our small trading operation, reflecting higher market prices. In addition, a lower effective tax rate increased earnings by $0.06 per share. As a reminder, though, production tax credits lower the ETR. PTCs are flowed back to customers through lower electric margin and are largely earnings neutral. Offsetting these positive drivers were increased depreciation and interest expenses which reduced earnings by $0.09 per share, reflecting our capital investment program. Lower AFUDC decreased earnings by $0.02 per share, largely due to placing several larger wind farms into service last year. In addition, other items combined to decrease earnings by $0.02 per share. Turning to sales. Weather and leap year adjusted electric sales declined by 1.9% in the first quarter. Our sales forecast assumed that there was a lingering impact from COVID-19, and we expected a slight decline in Q1. However, the adverse impacts of COVID on sales were largely felt starting in the second quarter of last year. As a result, we anticipate a positive quarter-over-quarter sales comparison next quarter. And for the year, we continue to anticipate modest weather-adjusted sales growth of approximately 1%. Shifting to expenses. O&M increased slightly for the quarter. We expect annual O&M expenses to be relatively flat in 2021, reflecting incremental costs for new wind farms, offset by a decline in base O&M. Now turning to our regulatory filings. In January, we filed a New Mexico electric rate case seeking a net rate increase of $48 million after reflecting fuel savings and PTCs from the Sagamore wind farm. A commission decision and implementation of final rates are anticipated in the fourth quarter of this year. In February, we filed a Texas electric rate case seeking a net rate increase of $74 million after reflecting fuel savings and PTCs from the Sagamore wind farm. A commission decision is expected in the first quarter of 2022 with a surcharge back to March 2021. The Texas and New Mexico rate cases are driven by the Sagamore wind farm, investment in transmission and distribution due to significant growth, the loss of a wholesale customer, changes in depreciation to reflect the planned early retirement of our coal plant, a requested ROE of 10.35% and an equity ratio of 54.6%. In November 2020, we filed a request in North Dakota seeking an electric rate increase of approximately $19 million based on a requested ROE of 10.2% and an equity ratio of 52.5%. Interim rates were implemented in January and the decision is expected later this year. As far as future filings go, we anticipate filing a Colorado electric rate case this summer with rates going into effect in the first half of 2022. We are working with parties to reach settlement agreements regarding our plans for Wisconsin rate case. And finally, we also anticipate filing a Minnesota electric rate case in November, with interim rates going into effect in January of 2022. Shifting to renewables. We continue to achieve important milestones in our PPA buyout strategy. In March, we closed on the acquisition of the 99-megawatt repowered Mower wind farm. We expect Mower will provide significant customer savings in carbon reduction for our customers. We've gotten off to a great start for the year and are reaffirming our 2021 earnings guidance of $2.90 to $3 per share. We've updated our guidance assumptions, and we expect incremental interest expense due to the lag in recovery of the $1 billion of unplanned fuel costs associated with Winter Storm Uri. As we work with our commissions to recover the fuel costs, we're not seeking to recover the carrying costs from our customers, as we help to manage the overall bill impacts. We continue to expect to deliver earnings around the midpoint of the guidance range. With that, I'll wrap up with a quick summary. We continue to execute on our PPA buyout strategy with the acquisition of the Mower wind farm and filing of the elite PPA repowering buyout. We filed our solar proposal in Minnesota. We filed our Colorado resource plan and transmission expansion plan, which will provide transparency into our long-term opportunities and will likely lead to robust capital investment in the second half of the decade. We reaffirmed our guidance range and finally, we remain confident we can deliver long-term earnings and dividend growth within our 5% to 7% objective range.

And we will begin with Jeremy Tonet from JPMorgan.

I was just wondering, how does your Colorado generation transition impact transmission needs overall? Given the national attention on transmission currently, what type of receptivity do you expect to this proposal? And are there similar investments you're evaluating across the rest of your footprint?

Well, yes, I mean, I think the response has been very favorable. And I think there's a recognition that if we're going to achieve, in the case of Colorado, an 85% carbon reduction with almost 80% of it coming from renewable energy, that we're going to need a strong backbone to be able to do that. And Jeremy, when you factor in the price of all that, it still comes out at an incredibly affordable price point for our customers, which, quite frankly, might be made all the more affordable with some of the policies that are coming out of the Biden Infrastructure Plan. If you think about it, if the extension of PTCs, the direct refundability, the normalization opt-out for solar, and an ITC for transmission, that promises to make our plan, which, of course, includes 10,000 megawatts of renewables, that much more affordable for our customers. And when you keep your product affordable, you create headroom for additional investments in the grid, like the transmission you're referring to. So I'm really optimistic that we've got a tremendous opportunity in front of us with transmission aided by the policies that I mentioned that will keep the price point low. And that's in all of our regions. The MISO studies are preliminary, but I think you can see that, that's an enormous investment opportunity. And hopefully, the slides we've attached for you are helpful in demonstrating where some of that build could happen.

That's very helpful. And you outlined a lot of great CapEx opportunities out there over a long period of time. And just wondering how we should think about this CapEx as you laid it out there. As it relates to your growth rates, do you see this kind of firming up the 5% to 7% over a longer time period? Or do you think that there could be upside at some point? Just wondering how this all kind of comes together in your mind.

Well, we firmly believe we can be in the upper half of that 5% to 7% range. The things I'm describing only are helpful for that. But I mean, you made a great point. When we talk about a long-term growth rate, we're not talking about 3 to 5 years; we're talking about a long time. So I'm quite confident that the opportunities we have in front of us should give you comfort that we've got transparent plans to hit that. And again, we believe that we can be in the upper range of that range, upper half, right.

Got it. That's helpful. Just one last one, if I could. If you could speak to recent sales trends across territories, particularly SPS, and how do you see reopening trends impacting sales over the balance of the year here?

Yes, Jeremy, that's a good question. Specifically regarding SPS, we are in communication with our major customers in the oil sector, and they seem to be cautiously optimistic. We are also monitoring some of our substations serving those loads, and they are returning to pre-pandemic levels, which is a positive indicator. Additionally, we are receiving feedback from oil companies about their increased focus on electrifying rigs and pumps to improve their carbon footprint. Overall, I would say the outlook is optimistic based on what we are hearing. In general, our territories are starting to recover from COVID restrictions. There are currently no restrictions in South Dakota, Wisconsin, while Minnesota and Colorado are beginning to ease their measures. In Minnesota, bars and restaurants are operating at about 75% capacity. We are examining various leading economic indicators and are seeing positive growth signs for this year. We feel confident about achieving a 1% year-over-year sales growth in the electric sector.

We will now hear from Stephen Byrd with Morgan Stanley.

So thinking more on transmission, just building on some of the prior questions. Just you laid out in MISO some potential additional growth. And I was just curious if you could just talk a little bit about the sort of the process steps in MISO from here. How will this develop over time? How might this impact your thinking and your CapEx over time?

Stephen, it's Bob here. Good to hear from you. Look, with MISO and their MTEP21 plan, we expect all transmission owners to work through the process at MISO over the course of 2021. Ultimately, with a goal of by the end of the year, coming out with a series of recommended projects all over the territory. Obviously, being one of the largest TOs in MISO, we'd expect a lot of those projects to be in our service territory areas, particularly since those are the high-density renewable areas in the territories as well. So that goes forward. Those projects are generally long-dated items, and we don't have capital for new major transmission lines in MISO in our 5-year forecast. But when Ben talks about the elongation of our growth and the investment that this industry needs to make the clean energy transition, we see that as the back half of the decade that's going to perpetuate the growth profile that we shared earlier.

Stephen, I want to emphasize that the main constraint has always been the cost to the consumer. As I mentioned earlier, we already have an affordable plan that capitalizes on low-cost renewable energy. Even with the expenses for transmission, it remains beneficial for our customers. This can become even more affordable thanks to tax policies that have a good chance of being enacted, creating more opportunities for our investments while keeping our offerings accessible. This enables us to concentrate on advancements like electrification, which will also see an increase under the Biden administration's proposal. Overall, I believe this is very promising for Xcel Energy and advantageous for our customers, and I am genuinely excited about it.

Bob, you were saying...

There is another opportunity, especially on the SPP side. Although they haven't communicated as much and the process may take longer, as Ben pointed out, that area is rich in renewable resources and has the potential to become an energy exporter. This will require investment in transmission. We believe the MISO studies will identify some early projects that are beneficial. However, MISO and SPP will also have numerous long-term capital projects needed to facilitate the export of resources from these regions to both the East and West Coasts. Additionally, we have several right of first refusals in our key states, which is another positive aspect. Overall, we are very optimistic about this.

So adding these together, I guess, if the combination of it, you get federal support in the form of an extension of tax credits for wind and solar, maybe a new storage tax credit. That really helps reduce the cost in the second half of the decade anyway because you already have kind of a visibility on those tax credits in the first half, and that lines up with potentially, for example, more transmission spending in a place like MISO so that could kind of work together.

I think we were quite conservative in our resource plans regarding what the price point would be by 2030, and it's very affordable. With this, it becomes even more affordable, allowing us to make investments in the grid while keeping our product affordable, which in turn opens up electrification opportunities in other sectors.

That's really helpful. Just one follow-up. In your resource plans, you've often discussed the role of energy storage compared to peaking generation. You've highlighted that storage has a limited duration, and peaking generation is necessary for prolonged periods of low renewable output. I'm curious, as you consider the evolving costs of storage and the possibility of a federal tax credit for it, would that shift the balance more towards storage and away from peaking generation? How are you approaching the trade-offs between these two technologies?

I believe one of the reasons we projected 1,300 megawatts of flexible resources in the Colorado resource plan is to supplement the identified 400 megawatts of storage. While we can set aside the economics, whether it's gas or batteries, there are still limitations to how much we can depend on batteries for extended durations, such as during Winter Storm Uri. We need more than 4-hour or even 8-hour battery storage. However, if it becomes affordable, we will certainly incorporate more batteries into our system.

Stephen, there is legislation in Colorado promoting innovative technology for pilot programs focused on dispatchable, zero-carbon assets and long-duration storage, which can address our customers' reliability and affordability needs. Currently, we are looking at what's available in the market, such as short-duration storage that lasts 4 to 8 hours or gas combustion turbines. However, there might be potential in hydrogen-fired opportunities or long-term energy storage options that we are exploring through collaborations with EEI and other organizations over the next decade. Therefore, we have the flexibility to wait; we don't need to implement these solutions immediately. Over time, we are optimistic about technology developments.

Now we'll take a question from Durgesh Chopra with Evercore ISI.

I just wanted to clarify one thing, Brian. On the 2021 guidance slide, the lower depreciation expense, I think you explained it well, but just so I have it correct. So essentially you're deferring the depreciation expense on the balance sheet. And that's what's driving the expense lower and you're going to get recovery of it over the longer term? Is that what's going on?

Yes, Durgesh, it really is just the timing. Previously, we thought we'd get the Texas rate case order by the end of this year, so you'd recognize the revenue and the expense with it. Now given that procedural schedule is in Q1 next year, so we just defer that expense for this year because we have a laid-back date to March. So earnings neutral, but just a change in our expenses there.

Got it. Okay. And then maybe just can you comment on the timeline for recovery? It sounds like you're not asking for carrying costs on the storm Uri impacts. But maybe just the timeline for recovery of those dollars. I mean, you've got, I believe, authorization in one of your opcos, but just what to look for there in terms of timeline and recovery?

Yes. So yes, you're right. In Wisconsin, it's over a 9-month period. But generally, what we've proposed in Minnesota and Colorado is over 2 years and really looking to help mitigate the bill impacts on our customers. So I think of that over the next couple of years, we'll work through the proceedings here in the summer. And we're also not asking our customers to recover those carrying costs because they're really trying to help mitigate the bill impacts. And we have a slide in there where it's over two years, it's anywhere from $2 to $10. So really looking at how we can help our customers here.

Got it. So you said a decision on sort of the Colorado, Minnesota is during summer?

It should be, yes, yes, later this summer.

Moving on to a question from Travis Miller with Morningstar.

Back to the Colorado pathway, I saw earlier this week that it was put on, I don't know what I think about as the anointed list of nationwide top transmission projects. I don't know what other words you can call it. But yes, how does that change kind of how you discuss this with regulators, the probability of getting the project approved? And then even beyond that, the probability of getting that incremental investment being on that list?

I believe the reception has been very positive for the project, and it closely relates to our ability to achieve the significant interim goals we have set for Colorado. Brian or Bob, do you have anything to add?

No. I think the initial response to the filing was positive. We anticipate that the filing will progress alongside our resource plan, which, as Ben mentioned, targets over 4,000 to 5,000 megawatts of renewable energy in Colorado. When we submitted that plan, we had the support of transmission owners in Colorado who were excited about the opportunity, not only for us to achieve our goals but also to assist the state in reaching its goals along with other energy providers by enabling access to the transmission for their renewable objectives. For now, we plan to build and own that pathway. Our expectation is that other transmission owners are supportive, but they have currently opted not to take part in the construction, ownership, and operation of that asset. This situation could evolve over time, but that is our current approach.

Okay. Just to clarify about the additional investment. So the plan would be $1.7 billion, is that what you filed for? And is there potentially another $1 billion, or is that extra billion included in the $1.7 billion?

Yes. The way I think about it, Travis, is I'll call it the base double loop 345 circuit on the Eastern Plains of Colorado is about $1.7 billion. There's an additional extension on that loop that would drop it down into the southeastern most part of Colorado. That's another couple of hundred million dollars, $300 million. And then once we get the resource plan approved, and we know where assets are going to get firmly located, then we need to come back and look at how much voltage support we might need for those assets, where they're going to be specifically located, and that comes with incremental capital costs. But again, as Ben said, you take the renewables, you take the pathway, and it's probably an $8 billion initiative in Colorado, all going to keep our bills at or below the rate of inflation in Colorado. Really exciting to be able to transition that state to an 85% carbon reduction and 80% renewable penetration at that low cost.

Okay. Great. And if I could sneak one more in there on the project. What are your thoughts on suggestions about investment tax credits for certain high-priority transmission projects or federal-backed loans? What are your thoughts in terms of that support?

Yes. I believe Ben summarized it well earlier in the discussion. We have a plan that is both affordable and reliable for our customers. Any incentives associated with that plan enhance its affordability and allow us to explore other avenues to either develop our own portfolio or advance initiatives like electric vehicles in the states, all while keeping energy bills low for our customers. Overall, we find this to be beneficial. However, we believe we can achieve this at a very affordable price regardless of outside factors, and it does not rely on federal legislation being approved.

Now we'll take a question from Julien Dumoulin-Smith with Bank of America.

I'll make it quick and just to rehash this transmission point, I just want to just make sure we hear you clearly on this. With respect to the MISO process, what's your level of confidence on this looking more like MVP of the last decade versus being this future 1 proposal being the start of a fairly protracted effort to get these discrete projects underway? Obviously, these have been fairly contentious at times. So I just want to understand your sense of confidence around sort of a near-term reflection in processes of these projects.

I think it's going to take some time, and while we might eventually be in an RTO, we can definitely move faster when we're not in that process. The need for this is strong, and it will be accomplished. It's important to consider that we have a right of first refusal in Minnesota, which is beneficial. We also have a proven history of building transmission at a competitive cost. I'm not sure if I've fully addressed your question, so I'll see if Brian and Bob have any additional thoughts to add.

Julien, it's Bob. I approach it in segments. There are likely some straightforward initiatives that will emerge from MTEP21. I anticipate more transmission expansion planning through MISO that will tackle some of the more challenging aspects you mentioned. The MVP projects were a specific moment and aligned perfectly. There are definitely projects that MISO and the transmission owners in MISO acknowledge as urgent. I expect those to emerge from MTEP21, and I'm optimistic that, in collaboration with MISO, we will see progress on those by the end of the year. When it comes to the larger figures, like $30 billion or $100 billion, those initiatives might take longer and could be more contentious. However, as Ben mentioned, it is crucial for us to achieve the state's and the company's objectives, and I believe we will make it happen.

All right. Excellent. And guys, one further follow-up, if I can. It might be somewhat evident, but the decision to file in Colorado here, do you want to walk through that a little bit? I'll leave it open-ended. And especially on earning your ROE.

Yes, Julien. I mean, we look at a couple of things, right? We had originally filed for an AGIS rider and a wildfire rider. We still have our deferral on AGIS CPCN costs, and we have a deferral on our wildfire investments. But really, we're putting those on our balance sheet. You don't want those deferrals to get too large. So that's one piece of it. But also we have some regulatory lag in the Colorado electric jurisdiction. And so as we look at it and look at that and look at kind of how the economies are really coming out of COVID and in terms of the strength we're starting to see there that I think it's really the time to file. And I add to that, we talk about our advanced meter investments that we're making in Colorado, and we're really ramping that up this year of deploying about 400,000 meters, is the first large deployment. And again, it's about getting that cash in the door versus deferral on it and putting it on our balance sheet and kind of kicking the can down the road.

All right. Great. But I'll put it this way, you expect to be able to earn relatively close to your authorized into the future, wherever that may land?

I expect that we will close that gap. We'll file this case this summer, but we won't see an outcome until next year. So there will be some regulatory delays in Colorado this year, with improvements expected next year as we implement those rates.

Moving on to a question from Paul Fremont with Mizuho.

Congratulations, number one. Number two, if I look at Colorado pathway, how would you allocate the $700 million of investment? Would it be fairly even for the period '21 through '25? Is it back-end loaded? I just want to get a sense of when that $700 million would hit.

Yes, Paul, I see it as being a bit more back-end loaded. There will be some spending as we navigate through the recovery and seek approval late this year. You'll start to see spending next year, but the significant ramp-up will occur in the latter half of our five-year forecast.

Next question is from Ryan Levine, Citi.

I was hoping to just follow-up on some of the comments on the PPA buyouts. Curious how those potential future transactions have been progressing and what the pace is? And in the context of the Biden infrastructure plan and the Biden bill, if any of the tax provisions there could accelerate or decelerate some of the opportunities for PPA ties?

Yes, that's a great question. If we take a step back, we've made significant progress. Currently, we have around $750 million of capital expenditures linked to PPA buyouts either delivered or awaiting approval. The savings for our customers align closely with this amount, proving to be an effective strategy for both our clients and us. As I’ve mentioned before, we still see the potential for $500 million to $1 billion in PPA buyout opportunities. Additionally, considering the potential infrastructure plan and a longer-term extension of credits, the two wind farm PPA buyouts we've secured in Minnesota, which include repowering, will also allow us to deliver cost-effective projects and savings for customers due to the additional 10 years of incentives. This positions us well for future opportunities if we secure a long-term credit extension. We will continue to seek out these opportunities and will engage in transactions that benefit both our customers and our shareholders.

Ryan, it's Bob. I'll just say that as we move through the resource planning process in both Colorado and Minnesota, those are other opportunities that present themselves during those proceedings. And so as Brian said, we still have a goal to execute on this strategy, and we think there's opportunity.

And then on a similar vein in the context of some of the EV incentives or federal build-out, curious your thoughts on how that could impact your business and the impact to some of the service territories if some of those broader federal mandates were to be rolled out?

I believe this strongly supports our goal of increasing the number of electric vehicles on the road and all that comes with it. One key factor is that consumer range anxiety, which is understandable, would certainly decrease if we had 500,000 charging stations as proposed in the plan. This will be beneficial, as electric vehicles serve as an excellent load for us and benefit all customers. We are also leading the way in offering subscription rates and other measures that encourage customers to charge during off-peak times, which will help reduce our infrastructure needs, ultimately benefiting all customers by keeping costs low. The economics of electrifying transportation are quite compelling, and this will only serve to accelerate progress. Overall, it's a very positive development.

Is there any numbers you can put around the potential CapEx around additional infrastructure that Xcel may have to deploy to support the federal EV programs, if they were to be passed?

Yes, Ryan, we aim to have 1.5 million electric vehicles in our service area by 2030, which represents about 20% market penetration. We are planning to allocate $500 million in capital in our current five-year forecast. Our EV programs in Colorado and Minnesota are among the best in the industry, and they are effectively helping our states reduce carbon emissions in transportation. Looking at the latter part of our forecast, we estimate an additional investment of about $1.5 billion to achieve that 20% penetration. If federal incentives accelerate this penetration, we can scale our efforts accordingly. We see this as a significant long-term opportunity to reduce carbon emissions in transportation, especially given the cleanliness of our fleet.

All contributed to keeping the prices low too. I mean, because, again, EVs, even if you don't own one, somebody that does helps with our programs, all customers will benefit from that, and that tends to increase the denominator and keep costs low, which, again, that's the virtuous cycle allows us to make other investments.

Ladies and gentlemen, this will conclude your question-and-answer session. I will turn the call back to Brian Van Abel, CFO, for closing remarks.

Thank you all for participating in our earnings call this morning. Please contact our Investor Relations team with any follow-up questions.

And ladies and gentlemen, this does conclude your conference for today. We do thank you for your participation, and you may now disconnect.