Xcel Energy Inc.

Good day and welcome to the Xcel Energy's first quarter 2022 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 their investor relations. At this time, I would like to turn the conference over to Paul Johnson, Vice President, Treasurer and Investor Relations.

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 different 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 70 cents per share for 2022 compared with 67 cents per share in 2021. And 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 plans, achieving significant and constructive regulatory outcomes. In February, the Minnesota Commission approved our resource plan. which achieves an 85% carbon reduction in a full coal exit by 2030. Other key components include an early retirement of the King Coal Plant in 2028 and the Sherco Unit 3 in 2030, 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 two new generation tie lines associated with the retiring coal plants, as well as the associated 2,600 megawatts of renewable resources on those lines. And finally, the Commission recognized the need for approximately 800 megawatts of firm, dispatchable resources, which will go through a separate certificate of need process. As you can tell, 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 earlier this week, we reached a revised settlement on our electric resource plan. 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 1st of 2031, which we believe addresses the concerns expressed by the Commission during previous deliberations. The settlement includes approximately 4,000 megawatts of renewable additions in the conversion of our Pawnee coal plant to natural gas no later than January 1st of 2026. This resource plan is expected to reduce carbon by at least 85 percent by 2030. We believe the revised segment 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 portfolios early next year and commission decisions in the first half of 2023. We expect the recommended portfolio generation assets will include self-build, build-owned 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 and 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 constructive regulatory outcomes reflect our alignment with our commissions on our clean energy transition. It's critical as we work to deliver reliable, affordable, and sustainable energy to the states, the communities, and the customers that we serve. We also remain excited about the transmission expansion opportunities in our Midwest region. MISO's future one scenario, which reflects an estimated $30 billion of investment opportunity, is expected to be awarded in four discrete tranches. Tranche one includes roughly $10 billion of projects, and a MISO decision on that tranche is anticipated this July. Our preliminary estimates suggest a $1 to $2 billion investment opportunity for Xcel Energy within tranche one. 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 five to six billion dollars in total future one investments. And 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 our clean energy transition while keeping our 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 we recently received approval of our transportation plan in Minnesota. which outline 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 the potential for customer rebates similar to what we're implementing in Colorado. We're planning a more 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 live our company values every day, and 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're also recognized by Military Times and GI Jobs for our continued commitment to veteran hiring. And finally, I want to pause and remember that today, April 28th, is Workers Memorial Day, which for more than 50 years has been a day of remembrance for workers who've been injured or killed in the line of work. And I want to acknowledge that all the women and men of Xcel Energy, our contractor partners, and all utility workers across the country who sacrificed to provide the critical energy needs of our customers and our communities. And 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 the following. higher electric and natural gas margins 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. But keep in mind, production tax credits lower the ETR. However, PTCs are flowed back to customers through a 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 reduced 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 CNI 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 for the country. As a result, we've increased our 2022 electric sales growth assumption to 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 in 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 also 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. Now, every settlement is based on compromises, and we feel these are constructive outcomes for all parties. We also have pending rate cases in other jurisdictions. In Texas, have a black box settlement in our electric rate case which provides a rate increase of approximately 89 million dollars the agreement also accelerates the depreciation life of the tote 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 expect intervener testimony this fall followed by commission decisions in 2023. In addition, we'll look for opportunities to resettlements on both these cases after interviewing your testimony has been filed. Earlier this year, we filed a natural gas case in Colorado. The request is 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 earnings release. Please note our depreciation expense assumption has increased to reflect regulatory recovery in Colorado and New Mexico. In addition, the decrease in capital riders in the lower ETR reflect an IRS increase in the value of the PPC. 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 III 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 reach a revised settlement on the Colorado resource plan, which has the support of additional parties and accelerates retirement of Comanche III to no later than January 1st, 2031. We are reaffirming our 2022 earnings guidance, and we remain confident 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, and operator, we will now take questions.

Thank you. As a reminder, if you wish to ask a question, please press star 1 on your telephone keypad. Please ensure the mute function on your telephone is switched off to allow your signal to reach our equipment. We will now take our first question from Jeremy Tunnett from J.P. Morgan. Please go ahead.

Hi, good morning. Hey, Jeremy, how are you? Busy day for you. That's right. 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 and Any thoughts you could share or any consensus you're hearing out there with regards to resolution of the DOC's anti-circumvention investigation or just any thoughts on that topic in general at this point?

Hey, Jeremy. Good morning. You know, we're certainly seeing the disruptions and you saw the impacts in our earnings release and all the impacts it's had on the panel supply. Now, we're in regular contacts with developers, whether it's on BOT projects or PPAs that are in the works, or even as we think about we're going into potential RFPs in Minnesota and Colorado later this year. I don't think there's necessarily a consensus. I think there's good arguments 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. Certainly, there'll be the preliminary findings at the end of August will be the first real data point. And then we'll see how things go from there. You know, for us, you know, I think, you know, we're in a good spot. You know, solar CapEx is less than 3% of our overall five-year CapEx plan. And, you know, we have flexibility to delay our projects, the Sherco Solar project and the Western Mustang. So we really just push them later into our five-year plan. I just want to note that we are very committed to those projects, both the Sherco Solar and Western Mustang. Now, Sherco Solar is going to be the largest solar farm in Minnesota. We're pretty excited about it. We can reuse a coal transmission interconnection. It reinvests tax base into that community and also it will create good local paying union construction jobs. So we're very committed to that and look forward to working with our intervenors And our stakeholders in the Commission, as we bring forward a new plan on that, but really we just asked for some time, as you said, to work through kind of what the real supply chain impacts are here, you know I think broader or no on a broader note, I think there's really points to. The importance of getting a domestic clean energy supply chain. And hopefully with this event and some of the other global events that are happening is we can get some legislation passed in Washington, as Bob noted, right, that has a lot of incentives for clean energy manufacturing. And, you know, we're very supportive of that and then also very supportive on the tax credit side for production of wind, solar, hydrogen. I think that will be absolutely great for our customers long term. So, you know, certainly weighing in where we can on this issue.

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

Yeah, Jeremy, it's Bob. You know, we said that we've got 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 the energy replacement of that unit, and we expect that to be maybe two to three years from now.

Got it. Thank you. 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, I guess, squares versus your expectations. Have they been kind of changing over time based on what you're seeing unfolding here? And just any other thoughts, I guess, for two and three, you know, sizing up what those investment opportunities might look like for Excel?

Yeah, look, we see great opportunity and great need for transmission expansion in the upper Midwest and is one of the largest transmission owners in the country. You know, our expectations for Future 1 and Tranche 1 really haven't changed. That's still a bit of our same range, 1 to 2 in Tranche 1 and 5 to 6 over Future 1. And then if you think about longer term in the country nationally, when you look at MISO's Future 3, you know, that looks a little bit more like what would match something that has the decarbonization plans of the United States embedded into it. So we see great opportunity here. Only thing that's changed in our view was a little bit of a delay in the timing of the MISA publishing the results and then getting board approval for the plans. But our investment opportunity looks very similar.

Got it. That's all very helpful. I'll leave it there. Thanks.

We will now take our next question from Julian Dumoulin-Smith from Bank of America. Please go ahead.

Hey, good morning, Tim. Thanks for the time. Hey, good morning, Julian.

Hey, 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 and kind of near-term, you know, purchase power impacts. I imagine that that's fairly transparent. I wanted to check in on that. And then also related on C3, just any efforts to improve the reliability of the unit through the 2031 timeframe.

Sure. Happy to chat about it. 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 or $10 we talked about in the first quarter. I feel comfortable with that in that the Collector rings on the generator, which is what we needed to repair, were sourced, have been procured, and have been delivered to the United States, and 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. And look, longer term, the reliability of that unit, I think early in its life it had some asset challenges, They're largely behind us. And I think we've spent a lot of time on operational excellence in our generation fleet broadly and in Colorado in particular. And I think we should have sustained reliability in that unit for the balance of the decade.

Got it. Excellent.

And then if I can pivot here to the buy-ins, as you previously talked about, obviously some of your peers have as well. I mean, how is that going, the process, the negotiations? I mean, wind cost increases, is that an issue here for the relative economics, or is pressure on that vertical, you know, keeping the economics close to intact here? Just to kind of revisit the wind subject, especially in light of everything going on so far.

Hey, Julian, just to clarify, when you say buy-ins, you mean PPA buyout opportunities? Yeah.

Absolutely. Sorry. Indeed.

Yeah. Yeah. Different nomenclature, different companies. You know, the way we've talked about it recently, like we, we still see a good opportunity, but I think for us, the next opportunity comes to the RFPs that we're issuing after we resolved it, you know, in Minnesota, we resolved the ERP and we're waiting on the Colorado commission to, to, approve our revised erp settlement so i think that's the process for us near term in terms of seeing some potential ppa about opportunities as it'll get bid into an rfp and we have a nice process set up so we have to work outside of that i think so as i think about a longer term with where gas prices are today in call the upward step change in long-term gas forecasts is i think it provides 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 kind of the marginal fuel, the offset fuel, will make the renewable strategy and bio opportunities more valuable for our customers. And we have to demonstrate customer benefit. And then the other data point to watch, and we've spoken about it before, is an extension of a long-term extension of PTCs just provides a longer runway for us to look at buying something out and repowering them because we've been very successful at our recent buyouts that have been a buyout and repower. So that's a little bit of commentary before, but I think when you think about inflationary costs on renewables relative to how we look at it for customer benefit and what the fuels you're offset is, I think they'll still haunt.

Right, certainly. I'm just curious on the timing. It sounds like that's not necessarily as relatively pressing as some of these other RFPs. That's what you've watched first.

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

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

We're going to take our next question from Dagesh Chopra from Evercore. Please go ahead.

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

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

Got it. Is that cash flow accretive? I mean, is it higher rates? Yes. Okay. So this would be cash flow positive modesty, I guess.

Yep. Okay. Thank you.

We will now take our next question from Travis Miller from Morningstar. Please go ahead.

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 on... Could you see a shift toward winds in the near term, especially these RFPs? Would you anticipate maybe seeing a little solar pullback, at least, again, in the near term? A little more winds, and are there supply chain issues that might prevent that on the wind side?

You know, Travis, it'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 that preliminary finding um for the the tariff investigation and so i think that will help but these are longer term right we're looking to source uh renewable projects you know 25 and beyond so i think now it's a fair question and you certainly could see some shift from solar wind maybe in the near term but you know, ultimately the way we look at it long-term, we are adding a lot. We do need a lot of solar and we need that resource diversity from wind and solar. And so it's not just purely a cost perspective. It's what is called the capacity accreditation for solar. So there's a little bit more nuance going into it, even if you do see some changes in overall capital costs.

Yeah. So Travis, Bob, just to add on to what Brian said, When you think about our renewable mix right now, we're about 11 gigs of wind and 2 gigs 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 what our starting point is. You asked a good question about nationally. Could you see a shift towards wind in lieu of solar energy? I think it's going to be company dependent, but you do raise a nice thoughtful point around the wind supply chain looks a little bit more certain right now than the solar supply chain. But again, we expect the DOC outcome sometime in August, and we're hopeful to not have a significant tariff there for the benefit of our customers. And in the meantime, just the fact that we've got, you know, still working hard on federal legislation for tax credits, recognizing that with inflationary pressures on both, all these will be mitigants for a clean energy transition across the country.

Oh, great. Thanks so much. 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? Is this a year away, two years away, months away?

You know, so Travis, you know, we expect, you know, approval in, call it the summer timeframe, MISO July timeframe. And then certainly we would need to go through a certificate of need process with our commissions. But right now we don't have any of that MISO capital that in call it tranche one in our five-year plan. So could you start to see it in the 2020, 5-26 time frames, certainly potentially, and we'll give you more visibility into that as we get some ourselves with the approval of MISA and then we start the regulatory proceedings at the state level.

Okay, great. Thanks.

We will now take our next question from Nicholas Campala from Credit Suisse. Please go ahead.

Hey, everyone. Thanks for squeezing me in here and taking my question. Our pleasure, Nick. Yeah, thank you. I heard your prepared remarks on just the MISO capacity print. Can you just kind of update us on how Excel is exposed to these higher capacity prices on the supply side here? Just kind of saw some of your MISO peers put out some releases on some seemingly high bill impacts, and I know it's very specific to how your own vertically integrated portfolio is positioned. just how should we kind of think about the impact of supply costs for Excel customers? Thank you.

Yeah, Nick, good morning and good question. You know, clearly it's hit some headlines here in April as a result of that planning auction, and I would say it was unexpected by parties, right? You had the capacity payment last year, right, was $5 per megawatt per day, and it hit the cost of new entry here. And ultimately, MISA was short when you look at the numbers. You know, I think it really highlights the importance of dispatchable generation in making this transition reliably and methodically. And I think you saw that in our commission decision with our resource plan is they saw the need for us to add dispatchable generation as we shut down our coal units. And so, but for us in this auction specifically, we're long. And so it's a benefit to us and ultimately will be a benefit to our customers. And the way we look at it is it'll flow through in our Minnesota rate case and help us mitigate our electric rate case and hopefully facilitate a settlement. So overall, we're in a good position with capacity auction and it's important and just a credit to how we think about this transition and ensure that we have the capacity to serve our customers.

That's real helpful. And then just one cleanup question on the MISO transmission CapEx upside. Is it still for any kind of capital upside that's not in the plan today? Should we still be thinking 50% equity funding there?

Yeah, that's fair. I mean, the one caveat that we've spoken of before is, no, we get federal legislation passed that does help us from a financing perspective, improves our credit metrics. But if we don't get that, then that's a good way to think about how we finance incremental capital.

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

Absolutely. Looking forward to it.

We will now take our next question from Ryan Levine from Citi. Please go ahead.

Good morning. If the Colorado Resource Plan tilts away from solar, how could this impact incremental capex connected to the Colorado pathway? I assume that there is some language in your presentation.

I was hoping to clarify it.

So Ryan, I think you're talking about the potential incremental capital that we need for the Colorado power pathway that we have. No, we haven't called upside, but we haven't identified yet around voltage support system stability. You know, I think it really depends. It's a tough one to answer because it depends on exactly where these projects are or end up being located. And so I think it's a little bit too early to say if we shift some more to wind than solar, because it is so location-dependent, asset-dependent in how we think about it. So we certainly, the broader point is we absolutely believe we need that capital. It's just more of where it's going to be located, right? We've talked about it. A lot of it's, you know, the thing of the – 345 that we're building is a freeway, and these are the on-ramps and off-ramps, and so we'll need it. But it's a fair question. We just don't – there needs to be a little bit more visibility into what the actual portfolio could look like. And, you know, a marginal shift between wind and solar probably doesn't change that number much.

And 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 to determine, you know, how many megawatts of solar, how many megawatts of wind are ultimately chosen.

Okay. And then one just broader question, given some of the moving timelines, given supply chain challenges and some of the 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. If you saw on both of our resource plans, We have continuing need for firm dispatchable resources in the Upper Midwest. We got a separate certificate process to build back firm capacity in the Upper Midwest. Similarly in the Colorado Resource Plan proposal. So we recognize the need for reliability. Now you'll see that we moved in the Upper Midwest, for example, from a combined cycle to combustion turbines. You know, we do think that with the geographic advantage in the place that we sit in the country, we do have high capacity factors for wind and coincident on peak solar. So we do think that the assets that need to come back are largely combustion turbines. We're prepared and have offered in all of our jurisdictions to be able to co-fire those with green hydrogen when and if that becomes available. And so we're looking at the very low capacity factors but a real need for system reliability. You know, as I think about CTs broadly, it's a bit of an insurance policy. We need them for the very rare times when the sun doesn't shine and the wind doesn't blow and the batteries aren't available. But it's a great insurance policy to have.

And Ryan, just to add on to that, I absolutely agree with everything Bob said in terms of 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 they're seeing. So we'll evaluate alternative opportunities to ensure we have reliability in the system. Appreciate the color. Thank you.

We will now take our next question from David Peters from Wolf Research. Please go ahead.

Hey, good morning, everyone. Just curious to maybe get an update on some of the regulatory items in Minnesota near term. I think you have the URI gas recovery case where an ALGA report is due soon. I know initially you were pretty far off with some of the intervener positions, but wasn't sure if conversations have developed since then to where you could maybe resolve that. And then just related, any commentary on the Ray case, if any? I know it's still early there.

Yeah, Dave. And, you know, on URI, you know, we are awaiting that ALJ decision. We should get it at the end of May, about the 25th. And we're still fairly far apart with the Office of Attorney General and Department of Commerce. I mean, if you read our testimony and our comments, we strongly disagree with their assertions. And we believe we acted prudently. in according to the Commission approved hedging procedures, really for the best interest of our customers. So we'll await that ALJ recommendation, and then once you get the ALJ recommendation, it should likely be in August with the Commission decision on that. On the rate cases, it's still early in the proceeding. There's a couple other rate cases in front of us that they have been serially working through. So we haven't received a lot of discovery yet in the electric or gas case. So not a whole lot to update you on. But certainly as we get through the year, like I said, we talked about the MISO capacity auction being help mitigating the impacts. We've seen really good sales growth in Minnesota and our economy is strong here in Minnesota. So it's good things to see that, you know, hopefully as we get later in the year and can start to talk about settlement opportunities with interviews, we can reach a pretty constructive outcome for all of our parties.

Great. Thank you.

I would now like to turn the call back to Brian Van Abel, CFO, for any additional or closing remarks.

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

Thank you. That will conclude today's conference call. Thank you for your participation. Ladies and gentlemen, you may now disconnect.