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spk02: 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 inquiries, 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.
spk07: 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'll discuss certain metrics that are non-GAAP measures. Information on the comparable GAAP measures and reconciliations are included in our earnings release. With that, I'll turn it over to Bob.
spk04: Thank you, Paul, and good morning, everyone. Before we walk through year-end results, I want to reflect on the devastating wildfires that tore 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 exercise 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 required 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 delivered for our customers and communities in this extreme time of need. Officials continue to investigate the cause of the fire. They've confirmed there were no downed power lines in the ignition area. Our systems remained resilient even as 100 mile per hour winds propelled the fires due to our previously approved wildfire mitigation plan and our continued focus on operational excellence. As we always do, our team rallied to the call, guided by our four values, connected, committed, trustworthy, and safe. Moving on to our 2021 results, we had another very successful year continuing to execute on our strategy while delivering strong financial and operational performance. First and foremost, throughout the pandemic, we continued to provide safe, reliable service to our customers and support to our employees and our communities. Financially, we delivered EPS of $2.96, representing 17th consecutive year of meeting or exceeding our earnings guidance. We raised our annual dividend for the 18th straight year, increasing it by 11 cents per share. We reached constructive rate case settlements in Colorado, Texas, New Mexico, Wisconsin, North Dakota, and Michigan. We also reached constructive settlements in several additional regulatory proceedings in Colorado, including URI storm cost recovery, our resource plan, and the pathway transmission project. We anticipate commission decisions on these settlements by the end of the first quarter. Our nuclear fleet remains the top performing fleet in the country, achieved a capacity factor of over 92% last year. We also installed over 300,000 smart meters as part of our advanced grid program and plan to install more than 1 million in 2022. Continue to lead the country in carbon reduction. In 2021, our estimated carbon emissions were approximately 50% below 2005 levels. and we remain on track to achieve 80% carbon reduction by 2030. As planned, we completed four wind farms with 800 megawatts of capacity, which provides significant environmental benefits and cost savings for our customers. We also accelerated our timeline for transitioning out of coal and now expect to be coal-free by the end of 2034. 2021, we extended our clean energy leadership to our natural gas business, committing to reduce greenhouse gas emissions by 25% by 2030 and deliver net zero natural gas service by 2050 for scope one, two, and three emissions. We continue to execute on our electric vehicle vision, implementing 12 new programs for our customers, receiving approval for our New Mexico plan, and preparing for increased levels of electric vehicle adoption across our eight states. We're also recognized for our continued ESG leadership, named among the world's most ethical companies, the best veteran employers, and for disability inclusion in the workplace. And finally, we introduced a compensation-based diversity metric and earned a perfect score on the Corporate Equality Index for the sixth consecutive year. I'm proud to lead a team that can deliver on financial, operational, environmental, customer, and diversity goals simultaneously. Looking ahead, we're well positioned for sustainable organic growth over the next decade, including affordable, renewable additions in our proposed Minnesota and Colorado resource plans, the transmission needed to enable those carbon-free resources, and responsible transitions as we retire our coal plants. Together, our resource plans will add nearly 10,000 megawatts of renewables to our system and achieve an 85% carbon reduction by 2030. In December, we reached a settlement in our Colorado resource plan that will accelerate the retirement of our Comanche III coal unit to 2034 and advance our Pawnee plant conversion to natural gas to 2026. while maintaining plans to add approximately 4,000 megawatts of renewables and reduce carbon 87% by 2030. We also reached a settlement in our $1.7 billion pathway transmission project in Colorado. The pathway will provide 560 miles of double-circuit 345 kV lines to enable 5,500 megawatts of new renewables in the state. The settlement includes a certificate of need, rider recovery, and a potential for a 90-mile line extension with an additional investment of $250 million to enable access to some of the richest wind resources in the region. We expect decisions on both the Minnesota and the Colorado resource plans and the pathway transmission project in the first quarter of the year. As we've previously discussed, Our capital investment plan is not dependent on changes in federal policy. However, the energy provisions that were included in the Build Back Better legislation would provide substantial customer benefits and help enable the clean energy transition. While that legislation has stalled, there is some discussion that a more modest version could potentially move forward this year. This could include new and extended tax credits for wind, solar, hydrogen, storage, nuclear, and transmission, along with a direct pay option for the tax credits. Continue to advocate for these provisions, which would be beneficial for our customers. And as President Biden has suggested, there may be congressional support for energy and climate bill with a more modest price tag than the original Build Back Better bill. With that, I'll turn it over to Brian.
spk05: 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 41 cents per share, primarily driven by riders and regulatory outcomes to recover our capital investments. In addition, a lower effective tax rate increased earnings by 17 cents per share. Production tax credits lower 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 24 cents per share, reflecting our capital investment program. Lower APDC decreased earnings by 10 cents per share, largely due to placing several large wind farms into service last year. Higher other taxes, primarily property taxes, decreased earnings by 3 cents per share and 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've 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% and 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 week, and we expect a commission decision in March. We also reached a black box settlement principle in our Texas electric case, which provides a rate increase of approximately $89 million. THE AGREEMENT ALSO ACCELERATES THE DEPRECIATION LIFE OF THE TOTE POLE PLANTS TO 2034. THE COMMISSION DECISION IS ANTICIPATED LATER THIS YEAR. MOVING TO MINNESOTA, IN DECEMBER, THE COMMISSION APPROVED INTERIM RATES OF $247 MILLION FOR ELECTRIC CUSTOMERS AND $25 MILLION FOR NATURAL GAS CUSTOMERS. THE COMMISSION GRANTED INTERIM RATES AS REQUESTED FOR OUR NATURAL GAS OPERATIONS, BUT LOWERED OUR ELECTRIC REQUEST BY $41 MILLION DUE TO THE LINGERING IMPACTS OF THE PANDEMIC ON RESIDENTIAL CUSTOMERS. They made similar adjustments for CenterPoint and Minnesota Power. Schedules for both cases are included in earnings release and we expect commission decisions in mid-2023. Earlier this week, we filed a natural gas case in Colorado seeking a net rate increase of $107 million in 2022 with incremental step increases of $40 million in 2023 and $41 million in 2024. The request is driven by significant capital investments for customer growth, safety, reliability, and resiliency, and is based on a 10.25% ROE and equity ratio of 55.6% in the 2022 current test year. Our average Colorado residential customer's natural gas bill was 24% below the national average in 2020, among the lowest in the country. We anticipate a commission decision later this year and final rates to be implemented in November 2022. Shifting to earnings, we've updated our 2022 guidance assumptions largely to reflect 2021 actual results. Details are included in our earnings release. In addition, we're reaffirming our 2022 earnings guidance range of $3.10 to $3.20 per share, which is consistent with our long-term 5% to 7% EPS growth objective. With that, I'll wrap up with a quick summary. We delivered 2021 earnings guidance within our guidance range, the 17th consecutive year and increased our dividend for the 18th consecutive year. We continue to execute on a steel for fuel strategy by adding 800 megawatts of wind to our system. We remain on track to achieve 80% carbon reduction by 2030 and plan to be coal free by 2034. We reach constructive rate case settlements in Colorado, Texas, New Mexico, Wisconsin, North Dakota and Michigan. We also reached constructive settlements in several additional regulatory proceedings in Colorado, including storm URI cost recovery, our resource plan, and the pathway transmission project. We've kept our O&M expenses flat since 2014. We reaffirmed our 2022 earnings guidance, and we remain confident we can deliver long-term earnings and dividend growth within the upper half of our 5% to 7% objective range to continue leading the clean energy transition and keeping bills low for our customers. This concludes our prepared remarks. Operator, we will now take questions.
spk02: Thank you, sir. If you'd like to ask a question at this time, please signal by pressing star 1 on your telephone keypad. Please make sure that your mute function is turned off to allow your signal to reach our equipment. Once again, that is star 1 if you'd like to ask a question. We'll take our first question from the line of Insoo Kim with Goldman Sachs.
spk11: Yeah, thank you. Hope everyone's well. 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 do you think some of those other offsets that you've included in the drivers could get you to?
spk05: to keep you on pace. Hey, good morning. And Sue. Yeah. And if we look at our, I'll, I'll start just with the updates on the guidance changes. And most are just updating to actuals. Uh, 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. Now we have lower benefits costs in Q4 of 2021 and also managed through some of the weather impacts that we saw in 2021. So we're comfortable with our O&M guidance in 2022. And that 1% to 2%, like I said, is just a function of where 21 landed.
spk11: Yeah, I did see that. And I think the 21 levels are still below the 2019 level. That makes sense. Okay. The second question, 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 the up to $800 million that you've laid out? And just thoughts on the front-loading, it seems, of a lot of equity up front here, especially given – You know, we don't know what will happen with spillback better or any of the energy-related provisions, but, you know, you have said in the past that direct pay provision could meaningfully reduce your equity needs.
spk05: Thanks. Yeah, no, good question, Insu. And I look at our 2022 to 2026 capital plans and financing plans is just at the five-year. And so, but, you know, we've been transparent in terms of of the incremental capital is generally financed, what 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, yeah, we were opportunistic in issuing some equity in Q4 and add that to the $800 million of equity in our plan today, because DRIP was in the the same in both, and it was about $1.15 billion. So if you look at the $2.5 billion of capital we added, it's kind of right in line with how we talk about financing incremental capital. So hopefully that makes sense. I know it's kind of looking plan over plan, but you have to really 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. 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. Got it. Thank you so much.
spk02: Next we'll go to Julian DeMullen-Smith with Bank of America.
spk01: Hey, good morning, team. Thank you for the time again, and congrats on continuing progress here, especially in Colorado. I just wanted to bring up this pathway project. Kudos on penning 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 half a billion to one that's the 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 this settlement or what have you?
spk04: Hey, Julian. 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 also had in the filings, in the original filings, 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 plains of Colorado. They could be more in the metroplex. We don't know exactly where that's going to happen until the final projects are picked, and 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. I think just to clarify that, I would say just in terms of
spk05: timing and visibility in the incremental spend. Like Bob said, we know it 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, you know, latter half of this five-year plan early in kind of the second five.
spk01: But maybe to clarify that further, you know, you talk about this half billion to 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 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, You know, 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.
spk05: Yeah, 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. half a billion to a billion. And that's a really, I mean, as Bob said in his opening remarks, that 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 to a billion, you could see how there's, you know, it will be incremental opportunities that will push that number closer to the midpoint or higher. um 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 Q4 from Colorado as we think about that process. Minnesota might be a little bit later than that, but there'll 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.
spk01: Got it. All right. Look for some crumbs. I got it. Thank you guys very much. I appreciate it. Cheers. Good luck.
spk02: All right. Next question will come from the line of Jeremy Tanay with JP Morgan.
spk08: Hi. Good morning. Hey, Jeremy.
spk05: Good morning.
spk08: I just wanted to kind of start off with MISO MTEP process here and just seeing if you could share any other thoughts on the timeline and what is the potential for the process to bear fruit for the current plan or where could that come in in the future?
spk04: Hey, Jeremy, it's Bob. Thanks for the question. You know, 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, You know, 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 mid-year. And our expectation for M-TEP 21 is a subset of the projects that are included in MISO's Future 1. So if you go back to the original source document, MISO released three futures of the world. We've been largely talking about Future 1 and Future 3. Future 1 was about a $30 billion transmission expansion in the upper Midwest or throughout MISO region. And then Future 3 was really the other goalpost was about a $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 MTEP 21 to be a subset of future one, so a smaller subset than the $30 billion worth of projects.
spk07: 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.
spk08: Got it. That's very helpful. Thank you for that. And then maybe just pivoting over to Minnesota in the URI proceeding there, I was wondering if you might be able to provide any comments or thoughts there. Does this provide any indications or takeaways related to the Minnesota rate case?
spk04: Yeah, it's Bob. I'm not certain I would put a lot of linkage between those two proceedings. You know, as I think about URI and the Minnesota case, I think about sort of the unprecedented event that happened last February. And it's not unexpected to have parties, you know, question the investments that we made to enable our system reliability at the time. You know, and 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 URI proceeding and the Minnesota electric or gas cases.
spk08: Got it understood. Just the 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?
spk05: Yeah, 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, so expect the conversions really to be in the back half of this five-year forecast. So that's really, you know, assuming we get approval for it, we think it is certainly the right path to ensure that we have system reliability with converting the Pawnee to gas and having that. But in terms of conversion, it is not significant.
spk08: Got it. That's helpful. I'll leave it there. Thanks.
spk02: Once again, everyone, star one if you'd like to ask a question. We'll next go to Durgas Chopra with Ivercore ISI.
spk10: 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, appreciate the commentary on Build 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 have 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?
spk05: Hey, Durjesh. Good morning, and thanks for the question. You know, let's see. I think it really depends is 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-slash-prescription drug. change, which is a revenue raiser of about $300 billion. So I really think, you know, certainly from what we have heard is AMT is not off the table. I think it all depends on what size of the packages 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 energy transition, meaning it'll 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.
spk04: And as you, Gresh, I'd just add one more thing to what Brian said is, one, I think we've concluded that the AMT 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 AMT is 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 requirement, you're almost nullifying 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 in our industry, it's paid for by our customers. And so it's just 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.
spk10: Got it. Thank you for that, Collar. And then just one quick clarification, if I may. on the MISO process, you know, you, you mentioned mid 2022, I think, you know, we've sort of seen some dates around May. Did that move or are we still expecting some sort of CapEx announcements, project announcements in May?
spk04: Well, I think May is probably the target. I might've been hedging a bit by saying it could slip into June, but you know, I think it's, we're talking about maybe a month tops and I'm not saying it's going to slip. I just, I was hedging my own comments.
spk10: Understood. Thanks so much, guys. I appreciate the time today.
spk02: All right. Next question will come from Steven Bird with Morgan Stanley.
spk09: Oh, hi. It's Dave Arcaro on for Steven. Thanks so much for taking my question. Hey, I was wondering, you know, 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?
spk04: Hey, Steve, thanks for the question. Obviously, a tragedy in Colorado in the Marshall Fire, and with everything like that, we learn from it. We've been focused as a company on climate-driven resiliency for a long time, and we filed 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 tragedies and you know, improve the risk for the customers for sure. The Commission's open to proceeding, and we're going to actively participate with them on exploring your exact question on, you know, things that are in the approved wildfire plan and things we might want to consider in the future. But we're early stages in that.
spk09: Understood. Thanks for that, Collar. And then was curious on sales growth in the quarter, saw whether 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.
spk05: Yeah, I think I got to look at it over the balance of the year of 2021. If 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 CNI 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. uh so as i think about 2022 that was our expectation even going into 2022 continued cni strength you know our our economies are our service territories have stronger forecasted gsp than the national gdp we have forecasting strong job growth so i feel good on the cni 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, you know, stronger C&I sales offsetting some of the residential decline.
spk07: The other point to make up too is that, you know, 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 and 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.
spk09: Got it. Okay. I appreciate that. Thanks so much.
spk02: All right. Next we'll go to Paul Fremont with Mizuho.
spk00: 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?
spk05: Hey, Paul, good morning. 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 that last year was related to the last five-year plan, and I'll explain it a little bit, is when we rolled 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 plans together. So I think we're comfortable there for us. Like I said, credit quality and credit strength is important at Accel 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, you know, certainly, like I said, if something happens on the clean energy provision steadily, we'll revisit those as that gives us a lot more flexibility in terms of financing.
spk07: Yeah, 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.
spk00: 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?
spk05: I don't think I wouldn't characterize it as any less focus. You know, 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 is we're in two, you know, in 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, you know, it'd be, I think our commissions, given that we have those RFPs coming up, that that's the preference they had if, you know, sitting here today, if we had any projects spring forward, they'd prefer to see them in those RFPs. But again, We always focus on it, and I've always talked about it as being opportunistic, and it'll 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.
spk04: You know, Paul, we've been successful on the strategy. I think we've deployed more than a half a billion dollars in capital in this strategy, and I think there's another – half a billion to a 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 in Colorado over the next year or so.
spk00: 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?
spk05: 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 in pickup, 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 seven-tenths 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.
spk00: Great, that's it. Thank you very much.
spk02: Alright, the next question will be from Travis Miller with Morningstar.
spk06: Good morning everyone, thank you. Travis, good morning. Good morning. You answer my question on the Colorado wildfires. Just one quick follow up to that. Have you heard or been involved in discussions that can they give more momentum to the whole clean energy? transition, even climate change and such, following the wildfires? Is that accelerated or enhanced some of the clean energy discussion?
spk04: Hey, 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 It's 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.
spk06: Okay, great. And then second question, staying in Colorado there. See, earned ROEs for the year were in a low 8% range. Once you get that electric rate case in there in the first quarter, early second quarter, Does that jump up? Does that get you to 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 9 plus percent?
spk05: Hey, Travis, you know, 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, 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 mid-year 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, at least in 2022. Okay.
spk06: And is it the historical test year that just makes a big difference on the basis points or so?
spk05: I mean, I haven't done that math, but, you know, the historical test year, particularly when you're investing a significant amount of capital into the system, helping drive this clean energy transition, and that historical test year does put some pressure on your earned ROEs.
spk06: Sure. Okay. Makes sense. Thanks so much. That's all I had.
spk02: 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.
spk05: Thank you all for participating in our earnings call this morning. Please contact our investor relations team with any follow-up questions.
spk02: And that does conclude today's conference. We thank everyone again for their participation.
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