Xcel Energy Inc (XEL) — Q1 2023 Earnings Call Transcript

Thank you. Good morning, and welcome to Xcel Energy's 2023 First Quarter Earnings 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 other members of the management team in the room to answer your questions if needed. This morning, we will review our '23 first quarter results and highlights and share recent business 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. With that, I'll turn it over to Bob.

Thanks, Paul, and good morning, everyone. Let's start with our first quarter results. We had another solid financial quarter, recording earnings of $0.76 per share for 2023 compared to $0.70 per share in 2022. The increase in earnings largely reflects new revenue to recover our investments in clean energy and grid systems for the benefit of our customers. Our business plan is on track for the year, and as a result, we are reaffirming our 2023 earnings guidance of $3.30 to $3.40 per share. This quarter, we continue to make progress on our industry-leading clean energy transition plans. We've received and reviewed a significant number of proposals in our pending solicitations for nearly 6,000 megawatts of new electric generation across multiple jurisdictions. We anticipate commission decisions on these various proceedings in the second half of '23 and remain confident in our ability to deliver a beneficial mix of both company-owned and third-party resources across those plans. We also continue to pursue the benefits and opportunities provided by the Infrastructure Investment and Jobs Act and the Inflation Reduction Act to accelerate the clean energy transition. We recently submitted multiple projects to the Department of Energy for funding consideration, including the multiparty Heartland and Western Interstate Hydrogen Hub and grid resilience investments in Colorado. In addition, we recently applied for DOE and venture capital grants for our long-duration energy storage proposals in Colorado and Minnesota and believe we are well-positioned to receive some or all of our requests. Our country and our company need new technologies like long-duration storage, hydrogen, and clean fuels to commercialize in order to realize a clean energy future. At Xcel Energy, we are actively working to do our part for the regions and the customers that we serve. While the promise of a clean energy future is bright, we are keenly aware of the financial challenges that some of our customers experienced this winter with a significant rise in gas prices that we saw in 2022, driven by macroeconomic and geopolitical issues. Xcel Energy is proud of our long track record of keeping customer bills among the lowest in the country and to transition to a cleaner energy future with bill increases below the rate of inflation. We believe that affordability, reliability, and sustainability can be realized concurrently through thoughtful energy policy and excellent operations. We've taken a number of steps in recent years that have saved customers money and reduced exposure to commodity volatility. In our electric business, Xcel Energy's nearly 4,500 megawatts of owned wind farms continue to lead in capacity factor performance and generated $1.1 billion of fuel-related customer benefits in 2022 and more than $3 billion since 2017. Future investments in renewable generation and clean fuels will continue to reduce our reliance on fossil fuels and add further benefits to our customers. Since 2014, we've kept our operating and maintenance expenses nearly flat and well below inflation through our continuous improvement programs, which is a benefit that accrues to our customers' bills. Our numerous energy efficiency and demand management programs have saved enough energy to avoid building approximately 25 average-sized power plants. In 2022, we disbursed a record $216 million in state and federal payment assistance funds to customers across our states, and we expect to exceed that record in 2023. Also, in partnership with Colorado Staff, Colorado Energy Office, Energy Outreach Colorado, and the Utility Consumer Advocate, we proposed to the commission to increase funding to support income-qualified customers burdened by high energy costs. We expect to provide those increased benefits to our customers throughout 2023 and beyond. With recent declines in natural gas prices, we proactively lowered our gas recovery mechanism in Colorado four times, reducing customers' gas costs by 58%. Our customers in our other states are seeing comparable benefits. In Colorado, we've been working with stakeholders on proposed legislation regarding customer affordability, rate stability, and the regulatory process. In addition to our energy efficiency programs, we are re-evaluating potential long-term solutions to reduce price volatility that could include physical and financial hedging, additional natural gas storage, long-term natural gas supply contracts, multi-year rate plans, natural gas cost deferrals, energy decoupling, and the use of renewable energy to generate clean fuels for blending in the natural gas LDC. We are confident that if implemented, these actions can help reduce natural gas volatility in the future for our customers. As I wrap up, I'm pleased to share some of the company's recent recognition. For the tenth year in a row, we've been honored as one of the world's most admired companies by Fortune Magazine. We ranked first in social responsibility and quality of management, placing second overall among the most admired electric and gas companies in the country. Additionally, for the fourth year in a row, Xcel Energy has been named one of the world's most ethical companies by Ethisphere, a global leader in defining and advancing the standards of ethical business practices. None of this would be possible without the commitment of our employees, contractors, and our partners. While we're proud of our track record and our accolades, we will never rest on our mission to provide our customers with safe, clean, reliable energy services at a competitive price. With that, I'll turn it over to Brian.

Thanks, Bob, and good morning, everyone. We had another solid quarter, reporting earnings of $0.76 per share for the first quarter of 2023 compared with $0.70 per share in 2022. The most significant earnings drivers for the quarter included the following: higher electric and natural gas revenues increased earnings by $0.24 per share, reflecting new revenue to recover investments in our electric and natural gas systems and clean energy infrastructure. A lower effective tax rate increased earnings by $0.02 per share. However, keep in mind, production tax credits lowered the effective tax rate. Nevertheless, the production tax credits are flowed back to customers through lower electric margin and are largely earnings-neutral. In addition, other items combined to increase earnings by $0.01 per share. Offsetting these positive drivers were increased depreciation expense, which reduced earnings by $0.08 per share, reflecting our capital investment program; higher O&M expense, which decreased earnings by $0.06 per share; and higher interest expense and other taxes which decreased earnings by $0.07 per share. Turning to sales, weather-adjusted electric sales increased by 0.6% for the first three months of 2023. We continue to expect annual electric sales growth of approximately 1% in 2023, driven by commercial and industrial sales, while we expect residential sales to be down slightly for the year. O&M expenses increased $48 million for the first quarter. The increase was primarily due to timing differences associated with regulatory recovery mechanisms, generation outages, emergent work, inflationary pressures, and investments in electric vehicle programs and other customer products. We continue to expect O&M to decrease approximately 2% in 2023 compared with last year. We've made progress on a number of regulatory proceedings. The commission recently approved our settlement in the Minnesota natural gas rate case, which reflects a rate increase of $21 million, an ROE of 9.57%, an equity ratio of 52.5%, and the decoupling mechanism and property tax tracker. In the Minnesota electric case, we received a constructive ALJ recommendation including a 9.87% ROE and a 52.5% equity ratio. We anticipate a commission decision in June and final rates implemented in the fall. During the quarter, we filed a Texas electric rate case seeking a rate increase of $158 million based on an ROE of 10.65%, an equity ratio of 54.6% in the historic test year, and the early retirement of the Tolk coal plant. We anticipate a commission decision and implementation of final rates in the first quarter of 2024. Our electric rate case in Colorado is early in the process. Intervenor recommendations are due in May, and we will see if there’s a potential to reach a settlement with parties. A commission decision and implementation of final rates are expected in the fall. In our New Mexico electric rate case, intervenors filed an initial testimony. The staff recommended a forward test year with a rate increase of $37 million based on an ROE of 9.35% and an equity ratio of 54.7%. Other intervenors recommended equity ratios in the range of 45% to 54.7% and ROEs between 8.7% to 9.6%. We anticipate a decision later in the year. Finally, later this month, we will file a rate case in Wisconsin, seeking an electric rate increase of approximately $40 million and a natural gas rate increase of approximately $9 million based on a 10.25% ROE, a 52.5% equity ratio and a 2024 future test year. We expect the commission to decide on the case before year-end with new rates in effect in January. Details on these cases are included in our earnings release. We are reaffirming our 2023 earnings guidance range of $3.30 to $3.40 per share, which is consistent with our long-term EPS growth objective of 5% to 7%. We've updated our key assumptions to reflect the latest information, which are detailed in our earnings release. With that, I'll wrap up with a quick summary. Our customers continue to have some of the lowest bills in the country. We remain committed to keeping long-term bill growth below the rate of inflation while leading the clean energy transition and reducing customer exposure to volatility in fossil fuel prices. We continue to achieve constructive regulatory outcomes across our operating companies with progress across multiple rate cases. We have received a significant number of generation bids in response to our RFPs with additional RFPs forthcoming. We are reaffirming our 2023 earnings guidance and remain confident that we will 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. This concludes our prepared remarks. Operator, we will now take questions.

Thank you, guys, for the time. I appreciate it. Look, I wanted to talk about the proposed legislation and just efforts in Colorado to address the affordability, obviously, a lot of different comments out there. Can you set a little bit of your thoughts out there as to what the key tools and mechanisms and avenues that exist out there? And then ultimately, how to address some of the recovery issues and some of the perception issues?

Yes, Julien, it's great to hear from you this Thursday morning. Thank you for your question. Regarding the legislation introduced in Colorado last week, which came in late in the session, we are very aware of how the volatility in natural gas prices affected our customers last year and the price declines we've seen this year. We have taken several steps, both in communication and price mitigation, to support our customers, and there is still more work to be done. The Senate introduced the legislation with the goal of addressing both price and price volatility for the benefit of our customers. It was approved by the Senate recently and is expected to go to the House soon. This legislation requires our company and the Public Utilities Commission to explore all mechanisms that could help our customers with pricing and volatility. I believe it offers tools for both the beginning and end of the gas procurement process. At the beginning, it includes hedging tools and options for long-term storage. At the end of the cycle, it addresses cases of unexpected price volatility by allowing for deferral mechanisms to prevent immediate impacts on our customers' budgets. While many details still need to be worked out through the regulatory process, the legislation aims to mitigate the price fluctuations experienced over the last year. Additionally, it encompasses incentive mechanisms we have been discussing with the commission, which aim to encourage the company to meet or surpass gas price forecasts while managing volatility for our customers. Overall, the intention is to protect our customers from the volatility we witnessed last year through regulatory measures.

I hear you on that front. And then ultimately, as you think about this, mean just on the electric business, I mean, does this change anything in terms of procurement? Obviously, that could feed into some of those conversations. And then related on the gas side, any initial thoughts as to what this could mean from a financial perspective, maybe too early.

Yes. I think the gas procurement discussion pertains to both our electric and gas operations. More generally, it involves conducting a cost causation study regarding gas local distribution customers and considers how we can make long-term investments in the gas system. This includes the possibility of integrating distributed energy resources into our systems more efficiently. There are several factors to consider in both the electric and gas sectors. It's likely too early to determine the long-term effects on our capital forecasting in the state, but I don’t anticipate it will be significantly impactful overall.

Yes. And Julien, I would just add, we’re scheduled to file a clean heat plant in Colorado in August, which I equate to a resource planning process on the electric side. So really working through with our commission and our stakeholders is how do we decarbonize the LDC. We have legislation with targets in 2030 and then a net zero target longer term. We're looking forward to working with all our stakeholders about how we decarbonize our LDC, and I think that’s a real opportunity as we put plans in place for a longer term.

Team, thank you for the update. I had a question about Colorado, which you already addressed. Could you provide an update on the tax credits transferability? You mentioned that $1.8 billion in the plan will come from tax credit transferability through 2027. Can you share your progress on that? Also, can you remind us of the expected funds from that activity this year?

Durgesh, thanks for the question. Something we're very focused on, not only transferability guidance but guidance for the other aspects of the IRA. Specific to transferability on the guidance, we expect guidance to be issued in Q2 for transferability. For us, we're looking for fairly straightforward guidance, right? We would call it clean, no pun intended, a clean seller of these tax credits here from wind farms that have already been in service. We're looking for documentation and certification requirements in terms of sale registration requirements, so pretty basic stuff. That's really what we're looking for out of the guidance from the IRS. The other aspect is we've talked to about 20 counterparties already, and there is a significant amount of interest in the purchases of our tax credits, not only this year but for a longer term. We're pretty confident in terms of our ability to execute on this at a good price for our customers. I think about this, we get guidance in Q2. I would expect us to start executing in Q3. This year, we took a pretty conservative approach. We really expected to sell about $200 million of tax credits in our financing plan. That's about half of what we could sell this year. We'd assume we sell the remainder of it in the year after. But that's kind of our view on transferability and I think it's a great mechanism as we think about the longer-term cost of renewable projects and how we can be the most tax efficient with those tax credits.

Got it. How will you announce the sale of these tax credits? Will that information be shared in your earnings calls later in the year, or will you have other announcements depending on how significant these sales are?

No, I think we just included it in our quarterly earnings calls. Obviously, there may be – depending on the counterparty, they may want to make some announcement about it if they’re thinking about how they’re supporting the clean energy transition by other counterparties may not want to. But the expectation would be in our quarterly earnings calls.

I was wondering if you could comment a little bit on what you're seeing in the RFPs that you've got outstanding right now, how Xcel is competing. If you're seeing cost increases or decreases just in terms of inflationary pressures or if some of these project proposals are coming in at more attractive prices?

David, thanks for the question. We’re still working through the RFP processes, and I can comment on Colorado because we made a what we call a 30-day filing in Colorado that talked about the median prices that we've seen, incredible amount of interest in the projects and in the bid process. On the wind side, the median price was about $22 from an LCOE perspective. If we didn't have IRA and didn't have any tax credits, that would probably be closer to $50. A really great opportunity from a customer savings perspective with the IRA in what we're seeing. Now that's slightly above the RFP that we did five years ago, as you can see some inflationary pressures on CapEx. On the solar side, the median price is about $33. Now I'm giving you a median price; we have not disclosed the project portfolio that will happen in August when we make our filing and with our recommended portfolio to the commission. Overall, I think our project portfolio will come in well below those median prices that we've stated. We feel pretty good with the number of bids we put in from a self-build perspective. We've been at the scheme for a long time from the wind side. And now we've proven with Circle solar and the price point we've delivered Circle solar that we can be very competitive. Overall, we're excited about getting these RFPs. I talked about Colorado because that's the one that we've at least shared some information. Minnesota expects a filing from us here in May on the Minnesota RFP. And then on the SPS, RFP, expect a filing in Q3. We'll give everyone kind of full transparency and visibility into the opportunities later in this year. Overall, we're pretty excited and looking forward to executing on some of these wind and solar and storage projects for the benefit of our customers.

Okay. Got it. Great. And then could you also give any more color just related to the water leak at the Monticello plant? What was the cost of the repair? Curious if you see any broader or more significant issues that popped up just in inspecting it. What's the status of the plant now and when it would be coming back online?

David, it’s Bob. Thanks for the question. As we think about the water leak at Monticello, the repair costs were not significant. As we said in our releases, we have contained the leak, repaired the pipe, and are in the process of removing the water from the aquifer below the plant. There was no risk to people or planet in the process. We’re about halfway – close to halfway through that water removal; expect to finish it probably by the end of this year or early next. So not a material increase on the cost side. It’s really about pumping water out of the plants. The plant planned to shut down for refueling. We do refueling at Monticello every two years. I expect they probably have two more weeks before they finish loading fuel and restarting the plant, but it is ready to go.

Just want to pivot to Minnesota a little bit, if I could. I didn't know if you could share any other thoughts with regards to remaining priorities out of Minnesota electric ALJ recommendation there. Are there any particular points to address in the final stages of this rate case from your perspective?

Sure, I appreciate the question. The process is ongoing. Since we last met, we received the ALJ's recommendations at the end of March. We didn't get everything we requested in the ALJ filing, but that's not unusual in litigation. We'll file some exceptions and address points the ALJ suggested we consider in future proceedings or bring to the commission. I don't think these exceptions are very significant. We haven't had a general rate case since 2016 for electric services. We believe the ALJ's recommendations were well-considered from all perspectives. We expect the commission to review the ALJ's recommendations alongside the mitigation strategies we implemented to lessen the impact on customers after our extended outage. We plan to discuss this likely in early June and anticipate a decision by the end of the second quarter.

Got it. And then just kind of pivoting towards MISO. Just as far as tranche 2 is concerned, what are you hearing there? Are there any updated thoughts from your side on what kind of current timing expectations for initial thoughts on CapEx potential there?

Yes. Thanks for the question, Jeremy. I think we're thinking about it right now. Obviously, this is a little bit of a moving target with MISO, but we're thinking an announcement in the first part of next year. That said, it has the potential to shift as we've seen. We expect the next tranche or tranche 2 to be as big at least as tranche 4, potentially bigger. And as we think about it, we'd expect a similar share as we received in tranche 1. That’s where our thoughts are today, but obviously, working with MISO and the stakeholders as we move through the process.

Got it. That's helpful. Last one for me. Just didn't know if you might be able to elaborate a little bit more on the hydrogen hub now that the applications are in, just any incremental thoughts you could share with us would be great.

It's Bob. Thanks for the question. As we consider the future of hydrogen, it's clear that the country needs effective solutions for decarbonization across various sectors. Hydrogen seems to be the most adaptable clean energy source we've examined. The Department of Energy is backing this through the hydrogen hub programs and the Infrastructure Investment and Jobs Act. We're looking forward to the application process and expect decisions by the end of the year, after which we will pursue further proposals. We have two projects, one in the Rocky Mountain region and one in the upper Midwest, both involving consortia from multiple states. Our goal is to establish a system that connects producers and users of clean hydrogen, which could potentially be used for creating fertilizers in agriculture or for process heating. Additionally, we aim to explore how it can be blended into the distribution system and co-fired in existing natural gas plants. We're enthusiastic about the versatility of hydrogen and appreciate the efforts of Congress and the Department of Energy. We look forward to advancing our applications this year.

Yes. And I’ll just add a little bit more color on the process. Overall, there are about 80 concept papers that were submitted, and DOE encouraged 33 concept papers, and all three of ours were encouraged. Ultimately, as Bob said, we’ve moved forward with two because both were in the Rocky Mountain region. But we feel good about our, call it, multi-application hydrogen hubs and multi-state hubs. Looking forward to seeing this process play out, and as Bob said, awards at the end of the year, and then it’s a stage process going forward after that.

Just a quick follow-up on the RFP process. Could you remind us if you're also bidding into those? What do you expect your win rates to be, if any?

Yes, thanks for the follow-up question. We have submitted our own self-build projects in all three of the RFPs: Minnesota, Colorado, and SPS. These projects include solar, wind, and storage, depending on the RFP specifics. Minnesota was exclusively focused on solar. Over the past 18 to 24 months, we have been working on these self-build projects. With a significant renewable build-out expected in our territories over the next decade, we believe our self-build projects could be selected. We also have a strong partnership with Vestas in Colorado, taking advantage of their facility there. The geographical advantages we have include local manufacturing of wind turbine blades, and we are capitalizing on the interconnection of our retiring coal plants. We are targeting 50% ownership and believe we are well-positioned to remain cost-competitive. We would also like to demonstrate to our regulators that we could achieve more than 50% ownership because we have strong projects that will deliver substantial benefits to our customers. Looking ahead, I see this as the beginning of a new era in energy transition. Few utilities can make this clean energy transition at our price point due to the solar and wind resources we have readily available. We believe this gives us a significant competitive edge in delivering 80% to 85% clean energy by 2030 at or below inflation. We are eager to continue progressing with these RFPs and to conduct more in our jurisdictions. We look forward to providing updates to everyone on this call and our stakeholders as we move forward.

Perfect. And then as a follow-up, maybe on the O&M. I see that the O&M has been a drag about like $0.06 maybe in the first quarter. Just wondering if that was impacted maybe by the Monticello outage and repairs to a larger degree? And how do you see the shape of the O&M through the rest of the year?

Yes. Thanks for the question. No, Monticello maybe a couple of million dollars from a repair cost perspective, so pretty immaterial relative to the quarter. As we think about it, last year, if you look at our pattern of O&M last year, it was significantly higher in the latter part of the year. Part of that is due to some regulatory deferrals that were in place of Q1 last year that unwound as we got rates in Texas. We also had good weather last year, so we invested in our system later in the year. We still feel good with our year-end guidance and will continue to work on that. That being said, we are facing inflationary pressures and it's something that we're very focused on internally to keep those O&M expenses down as I think it's important from a customer build perspective long-term. Overall, we feel good with where we are and expect to deliver on our year-end numbers as we've done for 18 years.

Just a clarification around the transferability. Is it sort of the legal basis that you're looking for? Getting the clarification enables you to move forward? Or is there something that you're looking for in terms of the content?

Not at all in terms of the content. I would call it we're looking for more administrative guidance. There may be other parties that are involved in tax equity partnerships or ITC, but we're looking at transferring production tax credits. As I said, we're very clean from a transferability perspective. It's more like, okay, what are the registration requirements? Our counterparties want to see the guidance too, so they know what they need to do. Nothing of concern beyond just getting those administrative requirements out, and that's why we're waiting, and we'll be ready to pull the trigger when that guidance comes through.

On New Mexico, can you give some color as to what you're seeing in that regulatory process compared to how the processes were with the prior commission? Is there any potential for settlement or change to the Q4 guidance given the ramp-up of the new commission staff?

Ryan, thanks for the question. As we think about New Mexico, there's a wide range of intervenor testimony. Some of that from large industrials is call it par for the course. Look at the staff testimony; we think it's a good starting point. The staff testimony supports a forward test year, which is different from historical standards. We just got the testimony in last Friday, have digested it, and then we'll see if there is an opportunity to work with the parties to reach a balanced and constructive outcome from a settlement perspective. If you look at the schedule we have, hearings are on June 20. There is a stipulation period for looking at settlement opportunities. We've reached a settlement in our last couple of rate cases in New Mexico and certainly look forward to working with the parties to get a balanced outcome for our customers. The second part of your question was around guidance. This goes into effect late in the year, so there's a relatively small impact on 2023 guidance.

Okay. But is the fourth quarter '23 decision, do you think that there's any risk to that timeline, from a regulatory timeline perspective?

Ryan, the schedule has already moved out a month. We think it's fine the way it is.

Okay. And then on New Mexico, what are you seeing for weather-normalized load for that region?

Overall, in SPS, if you looked at our sales, there are very strong sales, particularly on the C&I side, right? We had 7% plus C&I sales year-over-year for the quarter. Residential sales were up about 3%. That was higher than expectations on the residential side. Commercial side was pretty much in line with what we expected. Strong growth, and more of that is weighted towards New Mexico than Texas with what we’re seeing in the oil patch region in the Delaware Basin. Rigs are up about 10% year-over-year from the rig count in the two counties we serve: Eddy and Lee. We’re seeing a lot of electrification requests as large oil and gas customers have their own carbon reduction targets hit and they’re working with the state of New Mexico on how they can improve their overall carbon footprint. Overall, good growth, and we’re doing everything we can to work with our customers to ensure that we can support them with the distribution and transmission investments that we need to make.

Can you hear me?

Yes, Paul.

Regarding the Colorado bill, I apologize if I missed this earlier, but is the bill progressing at a satisfactory pace for you? Are you looking for any further modifications, or do you feel comfortable with it as it stands?

Paul, it's Bob. I didn't comment earlier, but no new concerns there. The bill as it passed the Senate and the amendments that were provided make the bill workable from our perspective. We continue to watch it as it moves through the House process. As it stands right now, I think it's something that we can work with. We believe it still leaves a lot at the commission for decision-making, and we would very much work with the CPUC and staff to implement some of that legislation through the regulatory process.

Okay. Great. Given your management experience in California and their unique approach to billing based on income, I’m curious if you’ve considered this in any of your jurisdictions, especially in Colorado, given the insights from California. Do you have any feedback or thoughts on that?

Thanks, Paul. I think you’re talking about stratification of residential customers from an income perspective. At this point, what we do in that regard is we direct a lot of assistance through regulatory state and federal agency programs to mitigate the income-qualified customers' burden. That process has worked pretty well. I don’t see us proposing any changes to customer stratification at this point.

Thanks, everyone, for participating in our earnings call this morning. Please contact our Investor Relations team with any follow-up questions.