Good day, everyone, and welcome to Xcel Energy's Year-end 2021 Earnings Conference Call. Today's conference is being recorded. Questions will only be taken from institutional investors. Reporters can contact Media Relations with inquires and individual investors and others can reach out to Investor Relations. And now at this time, I'd like to turn the call over to Mr. Paul Johnson, Vice President, Treasurer and Investor Relations. Please go ahead, sir.

Good morning, and welcome to Xcel Energy's 2021 year-end conference call. Joining me today are Bob Frenzel, Chairman, President and Chief Executive Officer; and Brian Van Abel, Executive Vice President and Chief Financial Officer. In addition, we have others from our management team here to help answer any questions you might have. This morning, we will review our 2021 results and share recent business and regulatory developments. Slides that accompany today's call are available on our website. As a reminder, some of the comments made during today's call may contain forward-looking information significant factors that could cause results to differ from those anticipated are described in our earnings release and our SEC filings. Today, we will discuss certain metrics that are non-GAAP measures. Information on the comparable GAAP measures and reconciliations are included in our earnings release. And with that, I'll turn it over to Bob.

Thank you, Paul, and good morning, everyone. Before we walk through year-end results, I want to reflect on the devastating wildfires that tour through Boulder County, Colorado just before the New Year. It's been a long four weeks since this historic tragedy ravaged our communities and resulted in two people losing their lives and over 1,200 homes and buildings being destroyed or damaged. Our hearts and thoughts are with all members of these communities who lost their homes, suffered damage or were displaced, including 17 of our own employees and their families. I'm truly grateful for our hundreds of employees, contractors and partners who exercised incredible diligence in keeping each other and our customers safe while working around the clock to get the lights and the heat back on especially over a holiday weekend with below zero temperatures and more than a foot of fresh snow in some areas. More than 100,000 electric customers experienced a sustained outage and service was largely restored within 48 hours. Our wildfire protocols require that we turn off natural gas service to over 13,000 customers as a safety precaution. And once it was safe, our employees with mutual aid assistance went door-to-door to manually relight pilot lights, restoring service within just three days. In addition to our crews, I want to extend my heartfelt thanks to our many employees and community members who volunteered alongside emergency responders, handing out space heaters and water bottles and collecting clothing donations. I'm so proud of how our team and partners led with compassion and deliver for our customers and communities in this extreme time of need. Officials continue to investigate the cause of the fire, but they confirmed there were no down power lines in the ignition area. Our systems remain resilient even as when 100-mile per…

Thanks, Bob, and good morning, everyone. We had another strong year, booking $2.96 per share for 2021 compared with $2.79 per share in 2020. The most significant earnings drivers for the year include the following: higher electric and natural gas margins increased earnings by $0.41 per share, primarily driven by riders and regulatory outcomes to recover our capital investments. In addition, a lower effective tax rate increased earnings by $0.17 per share. Production tax credits lowered the ETR, however, PTCs are flowed back to customers through lower electric margin and are largely earnings neutral. Offsetting these positive drivers were increased depreciation expense, which reduced earnings by $0.24 per share, reflecting our capital investment program. Lower AFUDC decreased earnings by $0.10 per share, largely due to placing several large wind farms into service last year. Higher other taxes, primarily property taxes decreased earnings by $0.03 per share and other items combined to reduce earnings by $0.04 per share. Turning to sales. Weather-adjusted electric sales increased by 1.7% in 2021 as the economy recovered from the pandemic. We anticipate weather-adjusted sales growth of approximately 1% in 2022. Shifting to expenses. Our O&M spend was flat in 2021. This continues an existing trend as we kept our O&M flat since 2014, while adding significant renewables and capital investment. We expect O&M will increase 1% to 2% in 2022, driven by wind farm additions, increased spending on electric vehicle programs and other customer initiatives. Turning to regulatory. We reached an unopposed settlement in our Colorado electric case, which will provide a net rate increase of $177 million based on an ROE of 9.3%, an equity ratio of 55.7% in the 2021 test year. Every settlement is based on compromises, and we feel this is a constructive outcome for all parties. Hearings were completed last…

[Operator Instructions] We'll take our first question from the line of Insoo Kim with Goldman Sachs.

Just first question, maybe for Brian, touching on your O&M growth forecast comment now 1% to 2% versus 1% that you had given in the third quarter earnings. Could you elaborate a little bit more on what's driving this, whether it's more demand-driven or are we seeing some impact of cost inflation that's getting impacted here? And also how confident you think some of those other offsets that you've included in the drivers could get you to keep you on pace?

Good morning, Insoo. Yes, and if we look at our -- I'll start just with the updates on the guidance changes. And most are just updating to actuals when we look at 2020 year-end versus the guidance we gave in Q3 for 2022. And that's exactly what it is for O&M. Our O&M number in 2022 didn't change. But what happened is our O&M for the end of the year ended up lower than it was. So what you're seeing is just an update to actuals. We had lower benefits costs in Q4 of 2021 and also manage through some of the weather impacts that we saw in 2021. So, we're comfortable with our O&M guidance in 2022 that 1% to 2%, like I said, is just a function of where '21 landed.

Yes, I did see that. And I think the '21 levels were still below the 2019 level. So that makes sense. Okay. Second question, the -- it seems like in the fourth quarter, you did a pretty healthy amount of ATM equity, $350 million or so. How does that fit into your five-year plan of up to $800 million that you've laid out? And just out on the front loading, it seems of a lot of equity up frontiers, especially given we don't know what will happen with spill back better or any of the energy-related provisions, but you have said in the past that direct pay provision could meaningfully reduce your equity needs. Thanks.

Yes. Good question, Insoo. And I look at our 2022 to 2026 capital plans and financing plans is just at the five-year. And so -- but we've been transparent in terms of the incremental capital is generally financed, we call 50-50. And if you think about where we were last year, meaning our last five-year plan, '21 through '25 rolling forward, we added about $2.5 billion of capital. And so the way I think about it is, yes, we're opportunistic in issuing some equity and add that to the $800 million of equity in our plan today because DRIP was it the same in both, and it was about $1.15 billion. So if you look at the $2.5 billion of capital we added, so it's right on kind of right in line with how we talk about financing incremental capital. So hopefully, that makes sense is kind of look and plan over plan. But you're absolutely right. As we think about the potential for clean energy legislation and the opportunity that gives us that absolutely still rings true in terms of being able to significantly reduce our equity needs going forward if that does pass. And or vice versa, we could really potentially accelerate investment without the need for incremental equity. So, I think it gives us a lot of flexibility going forward if it does happen.

Next, we'll go to Julian Dumoulin-Smith with Bank of America.

Congrats on continued progress here, especially in Colorado. I just wanted to bring up this pathway project, kudos on pending a deal there. I'm just curious if you could elaborate here on how that fits into the potential upside that you guys articulated earlier, the $0.5 billion to $1 billion that potential incremental for '22 to '26. And also, if you could clarify, the settlement seems like, it's 1.7, it's what you asked for, but you also alluded to this potential further network upgrades. Is that something else that we should be looking for to come out of the settlement or what have you?

Julien, it's Bob, great to hear you this morning. Appreciate the interest in the Colorado Pathway Project. It's obviously very strategic for us, as we look to transition that state to an 87% carbon reduction and greater than 80% renewables by the end of the decade. I think if you went back and looked at the filings, what we asked for was a base plan of about $1.7 billion of capital to enable that almost 600-mile project. That $1.7 billion also had in the filings in the original filings is we call it an extension that would enable access to the best wind resources in the state. I think it was, it's conditional approval based on whether or not we have projects that show up in our RFP in that region and whether we'll build it or not. When I think about the incremental capital that we laid out, there's a couple of pieces in the pathway program that would take that $1.7 billion, somewhere higher. The first one is this $250 million extension. And then, as we've said since the outset of the Pathway project, we have to, at some point, ultimately interconnect all of the assets that get proposed to us in the RFP. And those interconnections come with additional upgrades on the transmission system to enable voltage support and stability. And those may -- depending on the ultimate locations of the projects that are picked, those could happen out in the Eastern planes of Colorado that could be more in the Metroplex. We don't know exactly where that's going to happen until the final projects are picked. And that's -- we know they'll cost some money. We just don't know what it is and where exactly it will happen. So that's where the incremental capital comes from, but we expect it to be needed.

Maybe just to clarify that...

I would say just in terms of timing and visibility in the incremental spend, like Bob said, we know what needs to happen. We just don't know the timing and type of it yet. But once we get through the RFP process later this year and have identified the actual resources and where they're going to be located, whether it's wind or solar, then we'll have a really good visibility into what the transmission upgrades will be needed and when they'll be needed, probably latter half of this five-year plan early in kind of the second five.

But maybe to clarify that further, you talked about this $1 billion to $0.5 billion to $1 billion transmission upside in the current five-year plan. It sounds like you're edging towards the higher end of that incremental piece. And then ultimately, if I can push you a little bit on this, you've alluded to this in the remarks, I mean, whether it's Colorado or the Minnesota or Colorado IRPs, when do we get a more fully baked view on your CapEx? I know you said that, that's coming in the first quarter here, but it sounds like considering the RFPs, et cetera, that may be more of an EEI or even next year at this time, kind of update to get a more fully fleshed view?

Yes. I think let me answer your first question around, well, that, call it, in the transmission settlement, the conditional approval of that extension of $250 million, that certainly is helpful when we look at that $0.5 billion to $1 billion. And that's a really -- I mean, as Bob said in his opening remarks, that's really goes to a very resource-rich wind region that would be beneficial for our customers. And really, the parties just want to make sure that we get projects appearing there, and that's why it's conditional approval. So if you assume that's already part of the $500 million to $1 billion, you could see how there's -- will be incremental opportunities that will push that number closer to the midpoint or higher. On your second question around really timing. So what's going to happen, we'll get decisions in both Minnesota and Colorado on the resource plans from the commission in Q1. And then, we'll move into the RFP phase, which is likely going to be two, three, four months beyond those decisions, and then we have to work through that process. So Colorado could move a bit quicker in terms of getting clarity around from Colorado as we think about that process. Minnesota might be a little bit later than that. But there will be opportunities as we work through it and get through the RFP phase and make filings with commission where there'll be more visibility kind of throughout the process.

All right. Next question will come from the line of Jeremy Tonet with JP Morgan.

Hi, good morning. Just wanted to kind of start off with MISO MTEP process here. And just seeing if you could share any other thoughts on the time line? And what is the potential for the process to bear fruit for the current plan? Or where could that come in, in the future?

Jeremy, it's Bob. Thanks for the question. Similar to Colorado, we're really excited about the opportunity for transmission expansion in all of our regions as it will enable additional renewable penetration that we can deliver to our customers. In particular, in MISO, we've been very active with the MISO steering committee and the MISO transmission owners. Recently, we've agreed to cost allocation mechanisms across MISO and new proposed tariffs, which we expect to deliver next month, which puts us on a schedule for MISO to release what they would say is MTEP 2021 by, I'll call it, midyear. And our expectation for MTEP21 is a subset of the projects that are included in MISO's future ones. So if you go back to the original source document, MISO released three futures of the world. We've been largely talking about future one and future three. Future one was about a $30 billion transmission expansion in the Upper Midwest or throughout MISO region. And then future three was really the other goalpost was about $100 billion investment needed to enable a significant carbon reduction across all of MISO footprint. Our expectation for future one is that as a company, we're probably likely to get about 20% of the transmission opportunities that are included in future one. We expect MTEP21 to be a subset of future one, so a smaller subset than the $30 billion worth of projects.

And Jeremy, it's probably important to point out, too, that we don't have any material MISO transmission in our first five-year forecast.

Got it. That's very helpful. Thank you for that. And then, maybe just pivoting over to Minnesota and the yearly proceeding there, I was wondering if you might be able to provide any comments or thoughts there? And does this provide any indications or takeaways related to the Minnesota rate case?

Yes, it's Bob. I'm not certain I would put a lot of linkage between those two proceedings. As I think about Yuri in the Minnesota case, I think about so the unprecedented event that happened last February. And it's not unexpected to have parties question, the investments that we made to enable our system reliability at the time. In Minnesota, in particular, working through that regulatory proceeding, we filed what I would say is extensive testimony and -- just last week, we filed rebuttal testimony. We obviously disagree with the positions of the OAG and the department on the disallowances they proposed. And look, we'll continue to work with the commission through the proceeding. But I wouldn't put a lot of linkage between a Yuri proceeding and the Minnesota electric or gas cases.

Got it. Understood. Just a last one for me here. You might be able to provide more color on the process for converting Pawnee to natural gas by 2026. And what the potential cost for conversions could be and over what time frame should we expect this to occur?

Yes, I expect that conversion cost to be relatively small. And that's really one of the reasons why we propose to convert Pawnee versus Comanche just because the conversion costs are that. And right in 2026, I expect the conversions really to be in the back half of this five-year forecast. So that's really -- assuming we get approval for it, we think it is certainly the right path to ensure that we have system reliability with converting the pony to gas and having that. But in terms of conversion, it is not significant.

[Operator Instructions] We'll next go to Durgesh Chopra with Evercore ISI.

Hey, good morning, team. Thanks for taking my question. Bob, maybe just to kick things off, I have two questions. First, just on the macro, I appreciate the commentary on bill, back better. Sorry if I missed it, but you didn't touch on AMT. I'm just wondering if -- I know industry sort of leaders in the last few weeks, last few months as sort of lobbied against it. Is that something that you think perhaps comes out in the process of negotiations or what are your latest thoughts there?

Durgesh, good morning, and thanks for the question. Let's -- I think it really depends is what is the size -- assuming something can get done and there seems to be pretty good support for the clean energy provisions. But the question is then what is the pay for and what's the size of the clean energy provisions, right? You've heard around this number of a $500-plus billion climate provision package being put forth. There also seems to be pretty good support for the Medicare/prescription drug change, which is a revenue raiser of about $300 billion. So I really think I haven't from -- certainly from what we have heard is AMT is not off the table. I think it all depends on what size of the package they can get support from. I mean for us, certainly, if the climate provisions were passed and like Bob said in his opening remarks, we strongly support those clean energy provisions. They are great for our customers in terms of driving this clean transition, meaning able to do it more affordably. But if AMT wasn't included in that, that is just better for us as we talk about the overall impacts of the clean energy provisions plus AMT -- but if we actually just didn't have AMT, that improves our cash flow metrics probably by about 15 basis points, so relatively minor. But I think to your question, is more to come as we think about how this could play out and really how they look paying for the overall smaller package.

Dugresh, I'd just add one more thing to what Brian said is. One, I think we've concluded that the AMP in and of itself isn't all that impactful for Xcel Energy as it allows the use of existing renewable credits to fund it. I think the other thing that we would look to, though, as an industry in mitigating the AMP is really the fact that, on one hand, the federal government is giving you a lot of tax credits to incentivize development of renewable assets. And then on the other hand, if you have an AMT funding requirements, you're almost notifying some of the incentives that come with those tax credits. So where I think the discussion would go with lawmakers is can we use tax credits funded in the clean energy provisions to offset the AMT provisions. And ultimately, if you think about AMT and our industry, it's paid for by our customers. And so it's just -- it's an increase in tax to our existing customers. And I think that would be an area that we would negotiate with lawmakers as well. So it's still included in what we see as provisions in the build, back, better plan, but all subject to negotiation.

Got it. Thank you for that color. And then just one quick clarification, if I may. On the MISO process, you mentioned mid-2022. I think we've sort of seen some bids around May. Did that move or are we still expecting some sort of CapEx announcement, project announcements in May?

Well, I think May is probably the target. I might have been hedging a bit by saying it could slip into June, but I think it's -- we're talking about maybe a month to -- and I'm not saying it's going to slip. I just -- I was hedging my own comments.

All right. Next question will come from Stephen Byrd with Morgan Stanley.

It's Dave Arcaro on for Stephen. Thanks so much for taking my question. I was wondering in Colorado, have your views of fire risk changed in light of the catastrophic fires we saw? And wondering if there are adjustments that you might make or consider to your wildfire mitigation plans in the state?

Hey, Steve, thanks for the question. Obviously, a tragedy in Colorado and the Marshall Fire and with everything like that, we learned from it. We've been focused as a company on climate-driven resiliency for a long time, and we followed in Colorado, our wildfire mitigation program back in 2019, and we're executing under that program. I'm sure there's always ways that we can learn from these strategies and improve the risk for the customers for sure. The commissions open a proceeding and we're going to actively participate with them on exploring your exact question on things that are in the approved wildfire plan and things we might want to consider in the future, but that -- we're early stages in that.

Understood. Thanks for that color. And then I was curious on sales growth in the quarter, saw weather normal resi sales down a decent amount. I was just wondering if you might be able to comment around that and just comfort level with the 2022 sales growth outlook where you sit today?

Yes. I think I kind of look at it over the balance of the year of 2021. If you recall, going into the year, we thought sales growth was going to be about 1%. We ended up -- ended at 1.7% on a weather-normalized basis. And really, our C&I forecast was pretty close. What was higher than expected was on the residential side. And what we saw is that residential stickiness through most of 2021. So I think you saw some of that give back in Q4, a little bit of that weakness when you look over the Q-over-Q numbers. So as I think about 2022, that was our expectation even going into 2020 to continued C&I strength. Our economies, our service territories have stronger forecasted GSP than the national GDP. We have forecasting strong job growth. So I feel good on the C&I side. And we do expect those residential numbers to decline a little bit as you go to return to more a little bit more, call it, return to normal. So, we do feel comfortable with where we're sitting for 2022 on the overall basis with stronger C&I sales offsetting some of the residential decline.

The other point to make, too, is that we did have some pretty extreme weather in the fourth quarter. And while we feel comfortable with our weather normalization process, when the weather extremes get kind of more extreme, it makes it a little bit more difficult to determine the weather versus the sales impact. So, there could be a little bit of noise there.

All right. Next, we'll go to Paul Fremont with Mizuho.

Great. I just wanted to sort of look at the additional equity issuance. And is it fair to sort of infer that with that additional equity issuance that you would at least be somewhat into the incremental CapEx spend that you guys have identified on a go-forward basis?

Paul, I think if you're talking about the ATM that we did in Q4, the way I think about it is the plan -- the '22 to '26 plan that we have in front of us is the equity needed for that plan. And really, the equity last year was related to that last five-year plan, and I'll explain it a little bit. Is when we rolled the forward five-year plans, we added $2.5 billion of capital. And for us, credit quality and balance sheet strength is important. And we've always talked about funding incremental capital with about 50% equity. And if you kind of look at what we did at the end of Q4 plus that $800 million gets you just under 50% equity funding when we look at kind of the two plants together. So I think we're comfortable there for us. Like I said, credit quality and credit strength is important at Xcel and our operating companies. It's important to have access to capital. And so when you look at our current five-year plan going forward, right, that equity financings hold true. And certainly, like I said, if something happens on the clean energy provision, federally, we'll revisit those as that gives us a lot more flexibility in terms of financing.

Paul, it's important to recognize what we did in 2021 was always part of our '21 plan. So it's not any change to what we had envisioned going forward.

Okay. And then -- in the past, I guess, you guys have talked about contract buyouts. There seems to be sort of less focus on that. But can you give us any update on contract buyout opportunities? Or do you see any within that '22 to '26 period?

I don't think -- I wouldn't characterize it as any less focus. The corporate development team reports directly to me, and we're in constant discussions with developers. I think a little bit is what you see as we're in a resource plans in our two major jurisdictions, and working through those proceedings and then we have RFPs coming up, and that could be an avenue for developers to bid in potential opportunities within those RFPs. And I think it'd be -- I think our commissions, given that we have those RFPs coming up, that's the preference they had if sitting here today, if we had any projects to bring forward, they'd prefer to see them in those RFPs. But we always focus on it. I've talked -- and I've always talked about it as being opportunistic. And it will be opportunistic because it has to work for our customers. We won't bring forward an opportunity to our commissions if it doesn't save our customers' money.

Paul, we've been successful in the strategy. I think we've deployed more than $0.5 billion in capital in this strategy. And I think there's another $0.5 billion to $1 billion more opportunities for us, but they are, as Brian said, very opportunistic and likely to see some of that as we go through the resource planning processes and Colorado over the next year or so.

Great. And then my last question. When you talk about sales growth of 1% this year, on a normalized basis beyond this year, would you -- what would be sort of an expectation, a more normalized expectation for the outer years?

I think longer term, it's beyond this year as we continue to recover, and our sales are still below where we were pre-COVID levels. I think longer term, it's relatively flat with the exception is EV adoption as that starts to increase and pick up, we'll start to see some sales growth. We see our EV goal of 20% of EVs in our service territory by 2030, adding about 7/10th of a percent over a decade. So, I think it's relatively flat until we start to see some more EV penetration in larger numbers over the longer term.

Your next question will be from Travis Miller with Morningstar.

Good morning everyone. Thank you. You answered my question on the Colorado wildfires. Just one quick follow-up to that. Have you heard or been involved in discussions that kind of give more momentum to the whole clean energy transition, I mean, climate change and such following the wildfires? Is that accelerated or enhanced some of the clean energy discussion?

Travis, it's Bob. Look, I think our stakeholders in Colorado, including the Company itself, have been very aggressively pushing a clean energy transition. In fact, our goals in Colorado have us reducing our carbon footprint by 87% by the end of the decade on the electric side. And just in November, we committed on the natural gas side to reduce emissions on the natural gas business by the end of the decade and then be net zero by mid-century in the gas business. So I think the conversations in Colorado continue on that front with that as the backdrop. I've seen articles in the paper that talk about climate change and things like that. But I think the path we're on is absolutely aligned with the policyholders and stakeholders in Colorado. So, there may be increased discussion, but I think the trajectory that we're on is the right one.

Sure. Okay. Great. And then second question same in Colorado, there see earned ROEs for the year we're in a low 8% range. Once you get that electric rate case in there, call it, in the first quarter, early second quarter, does that jump up? Does that get you to of a 9% type range closer to the allowed? Or is there something in Colorado, the rate structures, et cetera, where it's just very, very difficult for you to get to the nine-plus percent?

Travis, I don't see significant improvement into 2022. One is no rates won't be effective until April on the electric side. You did see us file a gas case here very recently. And we're still -- we do face regulatory lag there with the test year on the electric side really being kind of a midyear '21. So we'll continue to work with our stakeholders and the commissions on that side, but I don't see the ROE improving significantly in 2022.

Okay. And is it the historical test year that just makes a big difference, 100 basis points or so?

I mean I haven't done that math, but the historical test year, particularly when you're investing significant amount of capital into the system, helping drive this clean energy transition in that historical test year does put some pressure on your earned ROEs.

All right, it looks like there are no further questions at this time. So, I'd like to turn it back over to Mr. Brian Van Abel for any additional or closing remarks.

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

And that does conclude today's conference. We thank everyone again for their participation.