Good day, and welcome to Xcel Energy's First Quarter 2021 Earnings Conference Call. Today's conference is being recorded. [Operator Instructions]. 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 '21 -- 2021 results and share recent business and regulatory developments. There are slides that accompany today's call are 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 our 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, 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 are a few that come to mind. 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. Well 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, 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 request 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 addition 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 conceptional 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. So with that, I'll turn it over to Brian.

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. 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 expense 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. This concludes our prepared remarks. Operator, we will now take questions.

[Operator Instructions]. And we will begin with Jeremy Tonet with 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 in 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 we -- if the extension of PTCs, the direct refundability, the normalization opt-out for solar, 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 will give you -- 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. Yes, good question. I think from a -- we talk about -- I'll talk about SPS specifically, when we talk about a little bit broader. We're in touch with our major customers in the oil patch area, and I would say they're cautiously optimistic. And we monitor some of our substations that serve those loads specifically, and they're reaching pre-pandemic levels. So that's a good sign. We're also hearing from them that there's a -- from the oil majors, that there's a big focus on electrifying rigs and pumps as they look at ways they can improve their carbon footprint. So I would say, optimistic with what we're hearing down there. Overall, I think our territories, we're starting to come out of the COVID restrictions. And we have no restrictions in the Dakotas in Wisconsin and Texas, and Minnesota and Colorado are starting to ease up. In Minnesota here, we're at about a 75% capacity for bars and restaurants. So we look at all the leading indicators in our economies. And I would say there's positive growth in signs for this year. And I think we feel pretty good about our 1% year-over-year sales growth on the electric side.

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, transmission owners, 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'd just add that -- I would just add that the throttle has always been the cost to the consumer. And as I mentioned to a question earlier, we already had an affordable plan. I mean, taking advantage of very low-cost renewables, which even with transmission build, that still is great for our customers. You make that even less expensive, more affordable with the tax policies that are -- that I think have a pretty good shot of getting passed. And that's creating a lot of headroom for our investment, while keeping our product affordable, allowing us to then focus on things like electrification, which is also going to get ramped up with -- under the Biden administration proposal. It really is, I think, very, very bullish for Xcel Energy and great for our customers. I'm really excited about it.

Bob, you were saying...

Add one more opportunity, right? And on the SPP side, while they haven't been as outspoken and probably aren't as long as the process, as Ben mentioned earlier, that region of the country is renewables rich, has the opportunity to be an energy exporter to the country, and that's going to need transmission investment. So we think the MISO studies will provide some, I'll call it, no regrets projects early. But MISO and SPP also are going to have a lot more longer-dated capital projects to enable the resource-rich regions of this country to export to either the East or the West Coast. And we have a lot of ROFRs in place. So that's the other thing. We really -- we have right of first refusals, as you probably know, in some of our key states. So excited about it. Yes.

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 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 place like MISO so that could kind of work together.

Yes, I mean, I think we had some pretty conservative numbers in our resource plans on how -- what the price point would be by 2030, and it's very affordable. Now if you have this, it becomes that much more affordable, creating the headroom to, again, make those investments in the grid that we'll be able to do and keep our product affordable, which opens up electrification opportunities in other sectors.

That's really helpful. One just follow-up. You've -- in your resource plans, you've often talked about sort of the role of energy storage versus the role of peaking generation. You've raised a lot of good points about storage has a kind of limited duration, and you really do need peaking generation to ride through extended periods where renewables output might be low, for example. But I was just curious, as you think about the evolution of cost for storage, the potential for a federal tax credit for storage, would that sort of tip the balance a little bit more towards storage, a little bit less peaking? Or how are you all thinking about sort of the trade-offs between the two technologies?

Well, I think it's one of the reasons why, for example, in the Colorado resource plan, we -- I think we called for 1,300 megawatts of flexible resources. That's in addition to identified 400 megawatts of storage. So we'll let the economics aside, if it's gas or if it's batteries. That said, there are still going to be limitations to how much you can rely on batteries for longer term durations, like Winter Storm Uri. You need more than 4-hour battery storage or even 8 hours. But to the extent that it becomes affordable, I mean, we will definitely have more batteries on our system.

Stephen, there's legislation in Colorado that's moving around innovative technology for pilot programs on dispatchable, zero-carbon assets, long duration storage, and any one of those can solve the reliability and affordability needs of our customers. Right now, we look at what's available in the market, and that's short duration storage, 4, 8 hour stuff or gas CTs, but you might find a hydrogen fired opportunity or a long-dated energy storage opportunity that comes out of work -- that we're working on with EEI and other organizations over the next decade. So we can be flexible at this point. We don't have to build that stuff today. But over time, we're betting with technology, not against it.

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 in 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 time line for recovery? It sounds like you're not asking for carrying costs on the storm Uri impacts. But maybe just time line 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 time line 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 overall 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?

Well, I mean, I think -- I don't know how much it helps, but I mean the reception, as I mentioned before, has been very favorable to the project, and it's very much tied to our ability to hit those, I think, remarkable interim goals that we're shooting for in Colorado. So Brian or Bob, I don't know if you have anything to add to that.

No. Look, I think the initial reception to the filing was well received. We expect that filing to proceed alongside our resource plan, which as Ben mentioned, calls for more than 4,000 or 5,000 megawatts of renewables in the state of Colorado. And when we filed that plan, we had transmission owners in the state of Colorado alongside of us, very supportive, very excited about the opportunity, not only for us to hit our goals, but we're going to help state hit its goals with other energy providers in the state, being able to access the transmission for their renewable goals. At this point, I think going to be -- we're going to build and own that pathway right now. It's our expectation that our owners are -- the other transmission owners are supportive. But at this point, I think they've declined to participate in the construction and ownership and operation of that asset. That could change over time. But right now, that's how we expect to move forward.

Okay. Just real quick one clarification on that additional investment. So the plan would be $1.7 billion, is that -- again, just remind me that's what you've filed for and then there could be another $1 billion or does the extra $1 billion included in that $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, 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. Look, I think Ben captured it early in the conversation, but we've got a plan that's very affordable and reliable for our customers. Any incentives that come with that plan, make it more affordable and more -- and the opportunity to then look at other opportunities to accelerate either our own portfolio or potentially accelerate stuff like electric vehicles in the states and keeping customers' energy bills lower. So I think on balance, it's helpful. But we think we can do it at a very affordable price with or without it. And it's not contingent on legislation passing at the federal level.

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

Well, I mean, I'll let Brian and Bob comment, Julien, but I mean, it's going to take time. I mean, that's part of -- that's -- in Colorado, that's the advantage of -- we ultimately might be in an RTO, but you can definitely move quicker when you're not in an RTO process. So I recognize it's going to take time, but the need is compelling, and it will get done. And how it gets built and how it's allocated. I think it's important to keep in mind that we do have a right of first refusal in Minnesota. And I think that's very helpful. And I think we've got a demonstrated track record of building transmission at a very good cost. So I don't know if I'm answering your question fully. So I don't know if Brian and Bob have any additional commentary they'd like to share.

Julien, it's Bob. I think about it in tranches. There's probably some no regret stuff that come out of MTEP21. I think we'll probably see more transmission expansion planning through MISO that will get to maybe some of the harder stuff as you're mentioning. So the MVP projects were a point in time and lined up very well. I think that there's some projects that MISO and the transmission owners in MISO recognize or needed sooner rather than later. And I think that's the stuff you'll see come out of MTEP21. And I am hopeful in working with the MISO that we'll see those by the end of the year. I think there's more -- when they talk about the large numbers, $30 billion, $100 billion, that stuff could take a little longer, might be a little bit more contentious. But as Ben said, absolutely positively need this to meet state's goals and company's goals, and I think it will happen. Julien Dumoulin-Smith: 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. Julien Dumoulin-Smith: 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 would expect we'd close that gap, right? This -- I mean, we'll file this case here this summer, but we won't get an outcome until next year. So you will see some regulatory lag in Colorado this year and improvement next year as we get those rates into effect.

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 think of it more kind of in the -- a little bit more back-end loaded. You'd have a little bit of spend as we go through the recovery -- we go through the proceeding, get an approval late this year. And so you start to spend next year, but really the ramp-up is in the back half of our 5-year forecast.

Great. So like the last two years, is most -- it would be the lion's share?

Yes. That's a fair way to think about it.

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?

Ryan, yes, good question. I think, I take a step back and say, we've delivered. If we look at what we've delivered or have pending approval is about $750 million of CapEx related to PPA buyouts. And that's -- and we've if you look at the amount of customer savings, it's comparable to that. So it's been a great strategy for our customers and a great strategy for us. And now you've heard me talk about, we'll continue to stay in contact with our counterparties and still think up to $500 million to $1 billion of PPA buyout opportunities are absolutely possible. And I think about what we could see coming out of the potential infrastructure plan with a longer-term extension of credits, now I look at what we've been. The 2 wind farm PPA buyouts that we have approved in Minnesota, they were PPA buyouts with the repowering, and that repowering with an additional 10 years of PTCs helps us deliver affordable projects and customer savings. And so I think that absolutely presents an opportunity over the longer-term if we get a long-term extension of credit. So we'll continue to look for the opportunities and we'll transact when we find an opportunity where it works for our customers and works for 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 got 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 impact to some of the service territories if some of those broader federal mandates were to be rolled out?

Well, I think it's very supportive of the goal we have for getting EVs on the road and everything that comes with that. And one of the things that we all know is that the range anxieties that consumers have, justifiably so, would certainly be diminished if you had 500,000 charging stations out there as proposed under the plan. So it's only going to be helpful, and EVs are great load for us, and they benefit all customers. And really, I think we're pioneering subscription rates and other things that encourage, not required, but encourage customers to charge off peak. And I think that minimizes the -- we'll have infrastructure needs, but that will minimize it again for the benefit of all customers, keeping prices low. And I just think the economics associated with the electrification of transport are pretty compelling. And this is only going to help accelerate that. So it's very positive.

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, the way we think about it, right, we have -- our stated goal for Xcel is 1.5 million EVs in our service territory by 2030. And that's about 20% penetration of EVs. And with that, we have $500 million of capital in our current 5-year forecast. And I would say we have some industry-leading EV programs with what we're accomplishing in Colorado and Minnesota and really helping our states reduce carbon emissions in the transport sector. Then we kind of pivot to the back half of that forecast. So it's another about $1.5 billion in terms of estimates. And that's for that 20% penetration. And if the federal incentives help drive that penetration faster, you can kind of ratably, I would say, scale that up. So we view it as a really good opportunity here longer-term as we pivot and help take out the carbon emissions from the transport sector with how clean our fleet is.

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.