Hello, and welcome to the Xcel Energy First Quarter 2023 Earnings Conference Call. My name is George, and I'll be your coordinator for today's event. Please note, this conference is being recorded. [Operator Instructions] I'll now hand it over to Mr. Paul Johnson, Vice President, Treasurer, and Investor Relations, to begin this conference. Please go ahead, sir.

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, like hydrogen and clean fuels to commercialize in order to realize a clean energy future. And at Xcel Energy, we are actively working to do our part for the regions and the customers that we serve. And 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 amongst 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 be a leader 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. And 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. And with recent declines in natural gas prices, we proactively lowered our gas recovery mechanism in Colorado 4x, 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. And finally, in addition to our energy efficiency programs, we are relooking at 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, multiyear 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 amongst the most admired electric and gas companies in the country. In addition, 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 will be possible without the commitment of our employees, contractors and our partners. And 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. But keep in mind, production tax credits lowered the ETR. However, PTCs 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 3 months of 2023. We continue to expect annual electric sales growth of approximately 1% in 2023, driven by C&I 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 and 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 also 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% in 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 in 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'll 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'll 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 we remain confident, we 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.

[Operator Instructions] Today's first question is coming from Julien Dumoulin-Smith of Bank of America. Julien Dumoulin-Smith: Thank you, guys, for the time. 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, good to hear your voice on a Thursday morning. So we've been -- I appreciate your question. Look, as I think about legislation in Colorado that got introduced last week, pretty late in the session. We've been very keenly aware, as I said in my prepared remarks around the impacts to our customers from the volatility in natural gas prices that occurred largely last year and the declines that we've seen this year. And we've taken a lot of steps, both on the communications side and on the price mitigation side to assist there and obviously more to do. The legislation itself as proposed, was introduced in the Senate. And with the idea that we look at both price and price volatility that we saw over the past year, really with the benefit of our customers in mind, requires the company in the PUC. And again, this is still in -- it was approved by the Senate, I believe, yesterday, and it's going to go to the house maybe today or tomorrow. But requires a company in the PUC to look at all the mechanisms that can be helpful for our customers on price and price volatility. As I think about it, I think it provides tools on both the front end and the back end of the gas procurement cycle. So think on the front end, hedging and hedging tools, thinking -- rethinking about long-term storage, physical and financial hedging and things like that on the front end of the cycle. The legislation also takes a look at the back end of the cycle in the event that there are price volatility that exceeds a forecast, then we look at mechanisms for deferrals so that it may not be felt immediately in the pocket books of our customers. And I think those mechanisms much to be determined in the regulatory process, but the legislation contemplates those mechanisms being very beneficial to mitigate the volatility that we saw over the past year. I think the third piece of the legislation looks at something we've been already working with -- proactively with the commission on, which is incentive mechanism that provides an incentive to the company to meet or beat gas price forecast and manage the volatility for our customers. Again, lots of details that have to get worked through the regulatory process. But on balance, the intention is to really protect customers from the volatility we saw over the last year with regulatory mechanisms. Julien Dumoulin-Smith: 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. Look, I think on the gas procurement side, it applied to procurement for both the electric and the gas business. More broadly speaking, it also looks at -- it asked us to do a cost causation study around gas LDC customers and how we make future long-term investments into the gas system allows for some distributed energy resources and the ability to add those to our systems maybe in a more expeditious manner. So there's some factors like that in the electric and gas, probably a little too early to say what the long-term implications on our capital forecasting are in the state, but I don't think it will be necessarily material in totality.

Yes. And Julien, I would just add, we’re scheduled to file a clean heat plant in Colorado in August, which is really – I equate that to call it a resource planning process on the electric side. So really working through with our commission and our stakeholders is how do we do decarbonize the LDC. We have legislation with targets in 2030 and then a net zero target longer term. So 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.

Our next question will be coming from Durgesh Chopra calling from Evercore ISI.

Team, thanks for the update. I just wanted to -- I was going to ask you a question on Colorado, which you just answered. But just maybe can we get an update on the tax credits transferability? You have, what, $1.8 billion in the plan that is going to come from the tax credit transferability through 2027. Maybe just update us on your efforts there? And then can you remind us, I think you've disclosed this in the past, what are you assuming in terms of 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. But specific to transferability on the guidance, we expect guidance to be issued in Q2 for transferability. And for us, we're looking for a 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. And so we're looking for documentation and the certification requirements, in terms of sale, registration requirements, so pretty basic stuff. So 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. So we're pretty confident in terms of our ability to execute on this at a good price for our customers. And so I think about this, we get guidance in Q2, I would expect us to start executing in Q3. And 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 of half of what we could sell this year. So -- and then 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 is 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. And then just -- how will you announce like as you sell these tax credits, is that just going to be in your back half of the year earnings calls? Or are there going to be depending on how sizable these are other sort of 8-K type announcements any...

No, I think we just included 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 thinking about they’re supporting the clean energy transition by other counterparties may not want to. So – but the expectation would be in our quarterly earnings calls.

We'll now take questions from David Arcaro from Morgan Stanley.

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. And if you're seeing cost increase or decrease 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. So 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. And if you think about that, that's -- if we didn't have IRA and we didn't have any tax credits that would probably be closer to $50. So 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 5 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. But overall, you think our project portfolio will come in well below those median prices that we've stated. So overall, I think we set ourselves up well 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. So I think, 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 expect a filing from us here in May on the Minnesota RFP. And then on the SPS, RFP, expect a filing in Q3. So we'll give everyone kind of full transparency and visibility into the opportunities later in this year. But I would say, overall, we're pretty excited and excited to execute 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. And then 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. We – as we said in our releases, we have contained the leak, repaired the pipe 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 end of this year, early next. So not a material increase in the cost side. It’s really about pumping water out of the plants. The plants planned to shut down for refueling. We do refueling at Monticello every 2 years. And I expect they probably have 2 more weeks before they finish loading fuel and restarting the plant, but it is ready to go.

We'll now take questions from Jeremy Tonet of JPMorgan.

Just want to pivot to Minnesota a little bit, if I could. And 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. No, look, I appreciate the question. The process really continues. Since we last got together, we filed our -- the ALJ filed their recommendations at the end of March. We certainly didn't get all that we asked for in the ALJ filing, but as litigation goes, that's not atypical for the process. We'll file some exceptions and some things that the ALJ recommended we take up in a future proceeding or have the commission take up, I wouldn't say it's terribly material on the exception side. We haven't had a general rate case since 2016, prosecuted in the state on the electric side. And so we think that the recommendation from the ALJ was pretty thoughtful for all sides of the argument. And expect the commission to look at the ALJ's recommendation as well as some of the mitigation mechanisms that we put in place as a company to mitigate the impact to customers for having been out for a long time. We shall take it up in probably early June, and we expect the 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, what kind of -- what are 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. And 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. But like I said, that has the potential to shift as we've seen. And we're expecting kind of the next tranche or tranche 2 to be as big at lease as tranche 4, potentially bigger. And as we think about it, we'd expect a similar share as we received in tranche 1. So 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. We -- look, I think as we think about the future and the future of hydrogen, I think the country really needs as we think about decarbonization across the economy, why we need a clean molecule for some of those harder to decarbonize sectors and hydrogen appears to be the most versatile of the clean energy molecules that we've been looking at. Certainly, the Department of Energy supports that through the hydrogen hub programs and in the IIJA. So we're excited about the application process. We expect decisions by end of year, where then we would go into future proposals around the proceedings. So we have two, one in the Rocky Mountain region, one in the upper Midwest region, both are consortiums with our multiple states and both involve the goal of creating what I think about as an ecosystem of both producers and users of a clean molecule like hydrogen and whether that can then be converted into fertilizer for ag, process heat -- burning for process heat and from our perspective, blending into the distribution system and co-firing in our existing natural gas plants. So we're excited around the versatility that the molecule provides. We appreciate what Congress and DOE are doing, and we look forward to progressing our applications at the DOE this year.

Yes. And I’ll just add a little bit of more color on the process. I think overall, there is about 80 concept papers that were submitted, and DOE encouraged 33 concept papers and all 3 of ours were encouraged. Ultimately, as Bob said, we’ve moved forward with 2 because 2 were in the Rocky Mountain region. But we feel good about our, call it, multi-application hydrogen hubs and multistate hubs. So 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.

We'll now take question from Sophie Karp calling from KeyBanc.

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

Sophie. Yes, thanks for the follow-up question. We do -- so the way we see this playing out is we have absolutely submitted our own self-bid -- self-build projects in all 3 of the RFPs, Minnesota, Colorado and SPS. And those range from solar to wind and storage and combinations of each of those and depends on the RFP. Minnesota was only a solar RFP. But we've spent probably the last 18 to 24 months, working on our self-build projects. As we know, we have a massive renewable build-out over the next decade in our territories. So -- not only do we see potentially our own self-build projects being selected, we have a good partnership with Vestas in the Colorado with their Colorado facility. And so we have some geographical advantages with having wind turbine -- wind blades being manufactured there, and we have a lot of opportunities around. We're using the interconnection of our retiring coal plants. So we feel really good. Now, publicly, we talk about targeting 50% ownership. Obviously, we think we'll be very cost competitive and would love to demonstrate to our commissions that we could do more than 50% ownership because we think we have really good projects that will show a lot of benefit to our customers. And I think this is just -- as I think about this, let me give you a little view of longer-term. I really think this is a start of steel for fuel 2.0 as we think about it. And I don't think there are many utilities can do this clean energy transition at the price point that we can because of the solar and wind resources in our backyard. And we think that's a true competitive advantage over the longer term as being able to deliver 80% to 85% clean energy in 2030 at or below inflation. So we're excited to continue to work on these RFPs. And following these RFPs, we'll do multiple more RFPs in our jurisdictions. So I'm looking forward to giving you and everyone on this call and our stakeholders further updates as we work through the process.

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 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 -- 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 than unwound as we got rates in Texas. And then we also had good weather last year, so we invested in our system later in the year. So as we think about it, we're still good with our year-end guidance, and we'll continue to work on that. Now that being said, we are facing inflationary pressures and it's something that we're very focused on internally is keeping those O&M expenses down as I think is important from a customer build perspective long term. But overall, we feel good with where we are and expect to deliver on our year-end numbers as we've done for 18 years.

Next, we'll go to [Mr. Greg Orell] of UBS.

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. Now there may be other parties that are involved in tax equity partnerships or ITC, but we're looking at transferring PTCs, as I said, we're very clean from a transferability perspective. So it's more like okay, what are the registration requirements and then just our counterparties want to see the guidance too, so they know what they need to do. So nothing of our 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 we give that guidance.

The next question is coming from Ryan Levine calling from Citigroup.

On New Mexico, can you give some color as to what you're seeing in that regulatory process and compared to how the processes were with the prior commission? And 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 it in New Mexico, a wide range of intervenor testimony. I think 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. I think one of the key aspects is we filed the forward test year. And I think there's support from a forward test year construct perspective, which is different from historical standards. So absolutely, 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 and reach a balanced and constructive outcome from a settlement perspective. If you look at the schedule we have -- hearings are June 20. And so that would be kind of from now until June 20, and it's actually a stipulation period in their native, in terms of looking at settlement opportunities. But we've been -- we've reached a settlement in our last couple of rate cases in New Mexico and certainly look forward to working with the parties on it 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 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...

No. From a timeline perspective, no, I do not. In terms of it getting pushed out.

I mean, Ryan, the schedule has already moved out a month. So 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?

So I think overall, in SPS, if you looked at our sales is very strong sales on – particularly on the C&I side, right? We had 7% plus C&I sales quarter – year-over-year for the quarter. Resi sales were up about 3%. Now that was higher than expectations on the residential side. Commercial side was pretty much in line with what we expected. So really strong growth, and more of that growth is weighted towards New Mexico than Texas with what we’re seeing in the oil patch region in the Delaware Basin. Now rigs are up about 10% year-over-year from the rig count in the 2 counties we serve, Eddy and Lee. And then we’re also seeing a lot of electrification requests as the large oil and gas customers have their own carbon reduction targets hitting and they’re obviously working with the state of New Mexico is how they can improve their overall carbon footprint. So really good growth there, and we’re doing everything we can and working with our customers to make sure that we can support them with the distribution and transmission investments that we need to make.

Our next question is coming from Mr. Paul Patterson calling from Glenrock Associates.

Can you hear me?

Yes, Paul.

So just back to the Colorado bill, I apologize if I wasn't -- if I just didn't get this but are you guys -- I mean the bill is moving pretty quickly. Are you guys -- I mean, with the amendments that were done on Tuesday, are you guys okay with it at this point? Or do you look for additional changes in it? I apologize if you guys actually addressed this earlier.

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

Okay. Great. And then given some of your management experience in California, and their sort of more novel idea of the commission -- the company's proposal to bill -- at least a part of the bill associated with income. I'm just wondering if that's something that you guys have thought about in any of your jurisdictions. But particularly Colorado given the experience in California. And just if you have sort of any feedback or any thoughts you might have about that.

Yes. Thanks, Paul. I think you’re talking about stratification of residential customers from an income perspective. I think 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. And that process, I think, has worked pretty well. I don’t see us proposing any changes to customer stratification at this point.

As we have no further questions, at this time, I'll turn the call back over to Mr. Brian Van Abel for any additional closing remarks. Thank you.

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

Thank you very much. Ladies and gentlemen, that will conclude today's conference. Thanks for your attendance. You may now disconnect. Have a good day. Goodbye.