Xcel Energy Inc (XEL) — Q1 2022 Earnings Call Transcript

Good morning, and welcome to Xcel Energy's 2022 First Quarter Earnings Call. Joining me today are Bob Frenzel, Chairman, President, Chief Executive Officer; and Brian Van Abel, Executive Vice President and Chief Financial Officer. In addition, we have other members of the management team in the room to answer your questions if needed. This morning, we'll review our 2022 results, share recent business and regulatory developments. 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. In addition 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. With that, I'll turn the call over to Bob.

Thank you, Paul. Good morning, everybody. At Xcel, we had another strong quarter, recording earnings of $0.70 per share for 2022 compared with $0.67 per share in 2021. As a result, we're reaffirming our 2022 earnings guidance of $3.10 to $3.20 per share. During the quarter, we made strong progress on our clean energy plan, achieving significant and constructive regulatory outcomes. In February, the Minnesota Commission approved our resource plan, which achieved an 85% carbon reduction with a full coal exit by 2030. Other key components include an early retirement of the King coal plant in 2028 and Sherco Unit 3 in 2030, a 10-year extension of our Monticello nuclear facility, and the addition of approximately 6,000 megawatts of new wind and solar resources. The ownership of 2 new generation timelines associated with the retiring coal plants, as well as the associated 2,600 megawatts of renewable resources on those lines. The commission recognized the need for approximately 800 megawatts of firm dispatchable resources, which will go through a separate certificate of need process. Based on the latest MISO capacity auction results, it's critical that we add these firm dispatchable resources to ensure the reliability and affordability of the transition for our customers. Shifting to Colorado, we reached a revised settlement on our electric resource plan, and as a result, additional parties joined that settlement. The revised agreement further accelerates the retirement of our Comanche 3 coal unit to no later than January 1, 2031, which we believe addresses the concerns expressed by the commission during previous deliberations. The settlement includes approximately 4,000 megawatts of renewable additions and the conversion of our Pawnee coal plant to natural gas no later than January 1, 2026. This resource plan is expected to reduce carbon by at least 85% by 2030. We believe the revised settlement will enable the commission to rule on the resource plan in June. Together, our Minnesota and Colorado Resource Plans will add nearly 10,000 megawatts of renewables to our system and achieve an 85% carbon reduction by 2030. This is consistent with our steel-for-fuel strategy, which provides a significant hedge against rising commodity prices and is projected to generate over $1 billion of fuel-related customer savings in 2022 alone. In terms of next steps, we anticipate issuing RFPs in the second half of this year, with insight into the preferred portfolio early next year and commission decisions in the first half of 2023. We expect the recommended portfolio of generation assets to include self-build, build-own transfers, as well as some power purchase agreements. This timeline represents a modest delay in our original plans, but provides additional time for more clarity given the solar supply chain considerations. Last quarter, the Colorado Commission approved our $1.7 billion Pathway transmission project to enable access to 5,500 megawatts of new renewables in some of the richest wind and solar resources in the region. The commission also conditionally approved the 90-mile May Valley to Longhorn line extension with an additional investment opportunity of approximately $250 million. These regulatory outcomes reflect our alignment with our commissions on our clean energy transition, which is critical as we work to deliver reliable, affordable and sustainable energy to the states, communities, and customers that we serve. We also remain excited about the transmission expansion opportunities in our Midwest region. MISO's Future 1 scenario reflects an estimated $30 billion of investment opportunities expected to be awarded in four discrete tranches. Tranche 1 includes roughly $10 billion of projects, and MISO's decision on that tranche is anticipated for this July. Our preliminary estimates suggest a $1 billion to $2 billion investment opportunity for Xcel Energy within Tranche 1, and we expect to have more clarity this summer after MISO provides more detail on the recommended portfolio. Longer-term, we expect to be awarded approximately $5 billion to $6 billion in total Future 1 investments. As we've discussed previously, our capital investment plan is not dependent on changes in federal policy. However, the energy provisions included in the Build Back Better legislation would provide substantial customer benefits and help enable our clean energy transition while keeping customer bills affordable. While that legislation has stalled, there is ongoing discussion of a more modest version potentially moving forward this year. We would expect it to include new and extended tax credits for wind, solar, hydrogen, storage, nuclear, and even transmission, along with a direct pay option for those tax credits. We continue to work with our federal delegation as well as the EEI to advocate for these provisions, which we believe would benefit our customers and accelerate a clean energy transition nationally. Shifting to electric vehicles, we are executing well on our approved Colorado and New Mexico plans and recently received approval of our transportation plan in Minnesota, which outlines future program focus areas and allows for implementation of new fast chargers in our service territory in Minnesota. We're also supporting comprehensive transportation legislation in Minnesota that includes potential customer rebates similar to what we're implementing in Colorado. We're planning a substantial update around these programs this summer to coincide with potential federal funding from the IIJA, and these are important steps in helping drive electric vehicle adoption as we support the goals of our states. Given strong alignment with our states on EV goals and our progress to date, we continue to anticipate significant long-term investment opportunities and load growth from electric vehicles. We've made significant progress this quarter, and I’m proud of the way our teams delivered those results. Our regulatory settlements and outcomes reflect our diligent efforts to listen, engage, and collaborate with our many stakeholders, not just through regulatory processes, but also through our sustainability priorities and our core values. We have a history of strong storm restoration, and earlier this month had another opportunity to showcase our operational excellence when we experienced two feet of snow in North Dakota. Our teams were prepared and restored power to customers quickly despite battling frigid conditions. Our system resilience and storm preparedness are great examples of our continued discipline and proactive planning, strong execution, and our employees' commitment to customer service. We strive to deliver our company values every day. As a result, we were again named as one of the World's Most Ethical Companies by Ethisphere and the World's Most Admired Companies by Fortune. We were also recognized by Military Times and GI Jobs for our continued commitment to veteran hiring. Finally, I want to pause and remember that today, April 28, is Workers' Memorial Day, which for more than 50 years has been a day of remembrance for workers who have been injured or killed in the line of work. I want to acknowledge all the women and men of Xcel Energy, our contractor partners, and all utility workers across the country who sacrifice to provide for the critical energy needs of our customers and our communities. With that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. We had another solid quarter, recording earnings of $0.70 per share for the first quarter of 2022, compared with $0.67 per share in 2021. The most significant earnings drivers for the quarter included higher electric and natural gas margins, which increased earnings by $0.12 per share, primarily driven by riders and regulatory outcomes to recover our capital investments. In addition, a lower effective tax rate increased earnings by $0.05 per share. However, production tax credits lowered the ETR, but 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 $0.06 per share, reflecting our capital investment program; higher O&M expense, which decreased earnings by $0.02 per share; higher interest expense and other taxes, primarily property taxes, decreased earnings by $0.02 per share; and other items combined to reduce earnings by $0.04 per share. Turning to sales, weather-adjusted electric sales increased by 3.9% for the first quarter of 2022, largely due to higher C&I sales driven by improved economic activity as COVID impacts lessen. Our unemployment rate is 60 basis points below the national average, and our economies are growing faster than the average of the country. As a result, we've increased our 2022 electric sales growth assumption of 1% to 2%. Our O&M expenses increased $18 million for the first quarter, primarily driven by higher insurance costs and additional investments in technology and our customer programs. We now project an annual O&M increase of approximately 1%. While Bob touched on the resource plan and transmission regulatory approvals this past quarter, we made strong progress on various rate cases. In March, the Colorado Commission approved our electric rate case settlement, which will provide a net rate increase of $177 million based on an ROE of 9.3% and an equity ratio of 55.7%. New rates were effective in April. In February, the New Mexico Commission approved our electric rate case settlement, which will provide a net rate increase of $62 million and includes an ROE of 9.35% and an equity ratio of 54.7% for determining the revenue requirements for our wind projects. Rates were effective at the end of February. Every settlement is based on compromises, and we feel these are constructive outcomes for all parties. We also have pending rate cases in all jurisdictions. In Texas, we have a Blackbox settlement in our electric rate case, which provides a rate increase of approximately $89 million. The agreement also accelerates the depreciation life of the Tolk coal plant to 2034. The commission decision is anticipated later this year. We also have pending electric and natural gas rate cases in Minnesota and are early in the process. We're in the discovery phase and expecting intervenor testimony this fall, followed by commission decisions in 2023. Additionally, we will look for opportunities to resettle on both these cases after intervenor testimony has been filed. Earlier this year, we filed a natural gas case in Colorado, the request driven by significant capital investment to support continued customer growth, safety, reliability, and resiliency. We anticipate a commission decision later this year, and final rates to be implemented in November 2022. Details on these cases and schedules are included in our earnings release. Shifting to earnings, we've updated our 2022 guidance assumptions to reflect our latest information. Details are included in our earnings release. Please note, our depreciation expense assumption has increased to reflect regulatory recovery in Colorado and New Mexico. Additionally, the decreasing capital riders in the lower ETR reflect an IRS increase in the value of the PTC. These assumption changes are largely earnings neutral. Finally, the combination of increased sales growth, favorable weather, and lower O&M costs are expected to mitigate the headwind associated with replacement power costs related to Comanche 3 and increased interest expense due to rising rates. As a result, we are 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. The Minnesota Commission approved our resource plan. The Colorado Commission approved our electric rate case settlement and Pathway transmission project. We reached a revised settlement on the Colorado Resource Plan, which has the support of additional parties and accelerated the retirement of Comanche 3 to no later than January 1, 2031. We are reaffirming our 2022 earnings guidance. We remain confident that we can continue to deliver long-term earnings and dividend growth within the upper half of our 5% to 7% objective range as we lead the clean energy transition and keep bills low for our customers. This concludes our prepared remarks. Operator, we will now take questions.

Hi, good morning.

Hey, Jeremy. How are you? Busy day for you.

That's right. Thanks. I just want to start off on the solar supply chain. You noted in the release some timing changes there. And just wondering if you could speak to your conversations with developers in the supply chain. Any thoughts you could share or any consensus you're hearing out there with regards to the resolution of the DOC's anti-circumvention investigation? Or just any thoughts on that topic in general at this point?

Hey, Jeremy, good morning. We are certainly seeing the disruptions and given you saw the impacts in our earnings release and all the impacts it's had on the panel supply. We are in regular contact with developers, whether it's on BOT projects or PPAs that are going to work. As we consider the potential RFPs in Minnesota and Colorado later this year, I don't think there's necessarily a consensus. I think there is a good argument for it not to be affirmed in terms of a tariff, but we'll wait and see where the Department of Commerce rules on it. The preliminary finding at the end of August will be the first real data point, and then we'll see how things go from there. I believe we're in a good spot. Solar CapEx is less than 3% of our overall five-year CapEx plan, and we have the flexibility to delay our projects, namely the Sherco Solar Project in the Western Mustang. I want to note that we are very committed to those projects, both the Sherco Solar and Western Mustang. Sherco Solar will be the largest solar farm in Minnesota, and we're excited about it. We can reuse a coal transmission interconnection, reinvest in the tax base in that community, and also create good local paying union construction jobs. We are committed to that and look forward to working with our intervenors and our stakeholders and the commission as we bring forward a new plan on that. But we just ask for some time, as you said, to work through the real supply chain impacts here. I think broader, or on a broader note, this really points to the importance of getting a domestic clean energy supply chain. Hopefully, with this event and some global events unfolding, we can get some legislation passed in Washington, as Bob noted, which includes a lot of incentives for clean energy manufacturing. We are supportive of that and also very supportive of the tax credit side for the production of wind, solar, hydrogen. This will be absolutely great for our customers long-term. So we certainly weigh in where we can on this issue.

Got it. That's very helpful there. And then maybe just pivoting towards Colorado in the IRP revised settlement filed in April. With the implications for the 2031 Comanche Unit 3 retirement there, just wondering how you think about potential generation replacement options going forward at this point? Or just any other details on that you could provide?

Yes. Jeremy, it's Bob. We stated that we have about 4,000 megawatts of new renewables as part of this resource plan. As it pertains specifically to Comanche 3 replacement, we're going to need a separate regulatory proceeding to address the capacity replacement and energy replacement of that unit, and we expect that to be in maybe two to three years.

Got it. And then maybe just a quick last one on MISO, the $1 billion to $2 billion of CapEx for Tranche 1 that you identified today. Just wondering how that squares with your expectations? Have they been changing over time based on what you're seeing unfolding here? Any other thoughts for two and three sizing up what those investment opportunities might look like for Xcel?

Yes. Look, we see great opportunity and a great need for transmission expansion in the upper Midwest, and as one of the largest transmission owners in the country, our expectations for Future 1 and Tranche 1 really haven't changed. That's still in the same range of $1 billion to $2 billion in Tranche 1, and $5 billion to $6 billion over Future 1. If you think about longer-term in the country nationally, MISO's Future 3 looks a little more like it would match something that has the decarbonization plans of the United States embedded into it. We see great opportunity here. The only thing that's changed in our view was a little bit of a delay in the timing of the MISO publishing the results and getting Board approval for the plans. But our investment opportunity looks very similar.

Got it, that is all very helpful. I will leave it there. Thanks.

Good morning, team. Thanks for the time.

Hey, good morning, Julien.

So perhaps just the nuance here on Comanche 3, just if you can speak to it, just the extent to which the plant is out in kind of near-term purchase power impact. I imagine that that's fairly transparent. I just want to check in on that. And then also, related to C3, just any efforts to improve the reliability of the unit through the 2031 time frame?

Sure. Happy to chat about it. Look, Unit 3 went down in January. In our fourth quarter call, we indicated that it was likely going to be a two-month repair. After inspection and discovery, it looks more like a four-month repair and our cost looks more like $25 million as opposed to the $9 million or $10 million we talked about in the first quarter. I feel comfortable with that in that the collector rings on the generator were sourced, have been procured, and have been delivered to the United States. We're starting reassembly as early as this week. So our June timeframe, I feel pretty comfortable about. We did have higher purchase power costs to replace that unit, and that's reflective of the $25 million estimate that we put out there. Looking at longer-term, the reliability of that unit, I think early in its life it had some asset challenges, but they're largely behind us. I think we've spent a lot of time on operational excellence in our generation fleet broadly, and in Colorado in particular. We should have sustained reliability in that unit for the balance of the decade.

Got it. Excellent. And then just if I can pivot here in terms of the buy-ins as you previously talked about. Obviously, some of your peers have as well. I mean, how is that going, the process negotiations been? Wind cost increases, is that an issue here for the relative economics? Or is pressure on that vertical keeping the economics close to intact just to kind of revisit the wind subject, especially in light of everything?

Julien, just to clarify, when you say buy-ins, do you mean PPA buyout opportunities?

Absolutely. Sorry. Indeed.

Yes, different nomenclature used by different companies. The way we've talked about it recently is we still see a good opportunity. But the next opportunity comes through the RFPs that we'll issue after we resolve Minnesota's ERP, and we're waiting on the Colorado commission to approve our revised ERP settlement. That's the process for us in the near term in terms of seeing some potential PPA buyout opportunities that will get bid into an RFP. I think, so as I think about it longer-term, with where gas prices are today and the upward step change in long-term gas forecast, that will provide us more opportunity on wind. Even if you see higher capital costs for wind pushed up by inflation or on the solar side, that comparison against gas being the marginal fuel, the offset fuel will make the renewable strategy and buyout opportunities more valuable for our customers. We have to demonstrate customer benefit. The other data point to watch is an extension of the long-term PTCs, just provides a longer run rate for us to look at buying something else and repowering them because we've been very successful at our recent buyouts that have been buyout and repower. So that's a little bit of commentary. When you think about inflationary costs on renewables relative to how we look at it for customer benefit, and what fuels you offset, they will still hunt.

Right. Certainly, I'm just curious on the timing. It sounds like that's not necessarily as relatively pressing as something to the RFPs. That's what you've...

Yes. No, I think it's more about when there's a process upcoming like an RFP, it makes sense for us to follow that and have that process already laid out versus doing a separate one-off regulatory approval.

Got it. Okay, excellent. I will leave it there. Thank you, guys.

Hey, good morning team. Thank you for taking my questions. Brian, just one quick one for me. Looking at the 2020 earnings guidance reaffirmation and changes, the depreciation expense increase that is, I know it says regulatory recovery here. Is that a change in depreciation expense that came from whatever studies that you were able to get? What does that actually represent?

It's really the implementation of new rates with the rate cases in Colorado and New Mexico. That will be offset by the revenue with it. So it's really earnings neutral and just the implementation of new rates coming out of the rate case.

Got it. Is that cash flow accretive? I mean, is it higher rates? Are these new...

Yes.

Okay. So this would be cash flow positive modestly, I guess?

Yes.

Good morning. Thank you.

Hey, Travis.

There's been a lot of talk obviously about solar and supply chain. I'm wondering, you touched on this a little bit, but I wanted some more comments. Could you see a shift toward wind in the near term, especially the RFPs? Would you anticipate maybe seeing a little solar pullback, at least again, in the near term, a little more wind? And are there supply chain issues that might prevent that on the wind side?

Travis, that's a good question. One of the reasons why, at least in Minnesota, we've slowed down the RFP is to see if we can get some visibility into the preliminary finding for the tariff investigation. I think that will help. These are longer-term projects, though; we're looking to source renewable projects for 2025 and beyond. I think it’s a fair question, and you certainly could see some shift from solar to wind in the near term. Ultimately, the way we look at it, we need a lot of solar and wind for resource diversity from both sources. It’s not just purely a cost perspective, it's about capacity accreditation for solar. There’s a little more nuance going into it, even if you see some changes in overall capital costs.

Yes. So Travis, this is Bob. Just to add on to what Brian said, when you think about our renewable mix right now, we're about 11 gigawatts of wind and 2 gigawatts of solar, if you count community and rooftop in that number. As we look forward, the 10,000 megawatts that we're likely to add over the next decade is probably 60-40 wind solar. But that's for us, and it's indicative of our needs and our starting point. You asked a good question about nationally if you could see a shift towards wind in lieu of solar. I think it's going to be company dependent, but you do raise a thoughtful point around the wind supply chain looks a little more certain right now than the solar supply chain. Again, we expect the DOC outcome sometime in August, and we're hopeful to not have a significant tariff there for our customers. In the meantime, we're still working hard on federal legislation regarding tax credits. We recognize that with inflationary pressures on both, all these will mitigate the clean energy transition across the country.

Great. I appreciate all that detail. And then just one other quick thing: when might we see some of these transmission projects and proposals start flowing through your CapEx plan? Just a year away, two years away, are you months away?

So Travis, we expect approval in July from MISO. Then, we need to go through a certificate of need process with our commissions. Right now, we don't have any of that MISO capital in our five-year plan. Could you start to see it in the '25-'26 timeframe? Certainly, possibly. We'll give you more visibility into that as we get more clarity ourselves with the approval from MISO and then we start the regulatory proceedings at the state level.

Okay, great. Thanks.

Hey everyone. Thanks for squeezing me in here and taking my questions.

It's a pleasure, Nick.

Yes, thank you. I heard your prepared remarks on just the MISO capacity print. Can you just update us on how Xcel is exposed to these higher capacity prices on the supply side here? Just saw some of your MISO peers put out some releases on higher bill impacts. I know it's specific to how your own vertically integrated portfolio is positioned. How should we think about the impact of supply costs for Xcel customers?

Yes, Nick, good question. Clearly, it's hit some headlines here in April as a result of that planning auction. I would say it was unexpected by parties; you had the capacity payment last year at about $5 per megawatt per day, but it hit the cost of new entry here. MISO was short when you look at the numbers. This highlights the importance of dispatchable generation in making this transition reliably and methodically. You can see that in our commission decision with our resource plan recognizing the need for dispatchable generation as we shut down our coal units. For us, in this auction specifically, we’re long. It’s a benefit to us and will ultimately be a benefit to our customers. In the way we see it, it flows through in our Minnesota rate case and helps mitigate our electric rate case. Hopefully, facilitate a settlement. So overall, it’s good news; we’re in a good position with the capacity auction. It’s a credit to how we think about this transition and ensure that we have the capacity to serve our customers.

That's really helpful. And then just one cleanup question on the MISO transmission CapEx upside. Is it still fair to think about any capital upside that's not in the plan today, should we think of 50% equity funding there?

Yes. That's fair. The one caveat we've spoken about before is that if we get federal legislation passed, it helps from a financing perspective and improves our credit metrics. But if we don't get that, then your assumption about financing incremental capital at 50% equity is accurate.

Thank you. See you in New York in a little bit. Have a good one.

Absolutely, looking forward to it.

Good morning. If the Colorado Resource Plan fell away from solar, how could this impact incremental CapEx connected to the Colorado Pathway? There is some language in your presentation, I was hoping to clarify.

So Ryan, I think you're talking about the potential incremental capital that we need for the Colorado Power Pathway. We have that upside, but we haven't identified it yet around voltage support system stability. It really depends on exactly where these projects end up being located. It’s too early to say if we shift from solar to wind what the impact would be because it’s very location and asset dependent. A broader point is we absolutely believe we need that capital, but it's just a little too early to tell.

To be clear, Ryan, we've not made any change in our view of solar versus wind. It's really going to come through the RFP process, which will determine how many megawatts of solar or wind are ultimately chosen.

Okay, and then one broader question given some of the moving timelines with supply chain challenges and solar policies from the government. How broadly are you feeling about reliability within your service territory and needs for incremental capacity to help serve your customers?

It's a great question. I appreciate it, Ryan. This is Bob. On both of our resource plans, we continue to have a need for firm dispatchable resources. In the upper Midwest, we have a separate certificate process to build back firm capacity in the upper Midwest, similarly in the Colorado resource plan proposal. We recognize the need for reliability. We moved in the upper Midwest, for example, from a combined cycle to combustion turbines. Given the geographic advantage of where we are in the country, we have high capacity factors for wind and coincident on-peak solar. We think the assets that need to come back are largely combustion turbines. We're prepared to co-fire those with green hydrogen when and if that becomes available. We're looking at very low capacity factors but a real need for system reliability. Early on, CTs are a bit of an insurance policy; we need them for the rare times when the sun doesn't shine, the wind doesn't blow, and the batteries aren't available. It's a great insurance policy to have.

Just to add on to that, I absolutely agree with what Bob said in terms of the longer term. In the short term, certainly, we expected some solar-plus-storage projects to come online in Colorado, and we're negotiating with the developers there about the impacts we're seeing. We'll evaluate alternative opportunities to ensure we have reliability in the system.

Appreciate the color. Thank you.

Hey, good morning everyone. Just maybe curious to get an update on some of the regulatory items in Minnesota near term. I think you have the Uri gas recovery case where an ALJ report is due soon. Initially, you were pretty far off with some of the intervenor positions, but I'm not sure if conversations have developed since then to where you can maybe resolve that? Just related, any commentary on the rate case, if any, I know it's early.

Yes, Dave. We're awaiting that ALJ decision; we should get it at the end of May about the 25th. We're still fairly far apart with the Office of the Attorney General and Department of Commerce. If you read our testimony and comments, we strongly disagree with their assertions. We believe we acted prudently according to the commission-approved hedging procedures for the best interest of our customers. We'll await that ALJ recommendation. Once that comes, we'll likely see the commission decision in August. Rate cases are still early in the proceeding. There are other cases in front of us that have been serially working through. We haven't had a lot of discovery yet in the electric or gas case, so not a whole lot to update you on. We've seen good sales growth in Minnesota, and our economy is strong here; that's a positive sign. As we get through the year, we hope to talk about settlement opportunities with intervenors and reach a constructive outcome for all parties.

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