Good day and welcome to the TXNM Energy Third Quarter 2024 Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Lisa Goodman of Investor Relations. Please go ahead.

Thank you, Wyatt, and thank you, everyone, for joining us this morning for the TXNM Energy third quarter 2024 earnings call. Please note that the presentation for this conference call and other supporting documents are available on our website at txnmenergy.com. Joining me today are TXNM Energy Chairman and CEO, Pat Vincent-Collawn; President and Chief Operating Officer, Don Tarry; and Senior Vice President and Chief Financial Officer, Lisa Eden. Before I turn the call over to Pat, I need to remind you that some of the information provided this morning should be considered forward-looking statements pursuant to the Private Securities Litigation Reform Act of 1995. We caution you that all of the forward-looking statements are based upon current expectations and estimates and that TXNM Energy assumes no obligation to update this information. For a detailed discussion of factors affecting TXNM Energy results, please refer to our current and future annual reports on Form 10-K, quarterly reports on Form 10-Q, as well as reports on Form 8-K filed with the SEC. With that, I will turn the call over to Pat.

Thank you, Lisa. Good morning, everyone, and thank you for joining us for the Halloween edition of our quarterly earnings call, also known as the third quarter call. We had a great Halloween during the Monster Mash, and we snagged all of the Reese Peanut Butter Cups from our neighbors last night. So we are all ready to treat you to our results and updates. I’ll start on Slide 4. Ongoing earnings for the third quarter are $1.43 per share, reflecting some warmer weather and timing impacts. Based on our year-to-date results, we are narrowing our guidance range for the year to $2.70 to $2.75 per share. We continue to target 6% to 7% earnings growth through 2028. Lisa will provide more detail on the numbers and our expectations for the remainder of the year. Don will provide an update on each of our utilities and highlight the customer-focused investments in both New Mexico and Texas that allow us to build a cleaner, more resilient grid. At PNM, our recently approved grid modernization plan will give customers the day-to-day need to have more control over their monthly energy bill. In addition, we have been awarded funding from the DOE to complement these plans with a virtual power plant project. Don will talk more about this also. This DOE award was in addition to funding from the DOE on a joint research and development project that includes New Mexico State and the National Renewable Energy Lab. It will use AI-powered technology to improve reliability and resiliency of the grid with variable renewable resources. At TNMP, our system resiliency plan is designed to improve the response of our systems to extreme weather events, a direct benefit to the customers we serve. Don, I’ll turn things over to you for utility updates.

Thank you, Pat, and good morning, everyone. I’ll start on Slide 6 with TNMP. TNMP continues to set new system peak records, including another one yesterday, its sixth new peak of the year. It is 16% higher than last year’s peak and reflects a 13% annual growth rate since 2020. The amount of interconnection requests received this year is nearly double the levels we were seeing in 2020, signaling continued growth in our service territory and into the future. We are expecting a 2% to 3% growth in our traditional volumetric and demand-based rate classes in 2024, and we are seeing this across each of our areas we serve. Residential customer counts have steadily increased for many years, and the interconnection requests for housing units in our service territory are trending stronger than the statewide numbers as we continue to see folks moving into our communities outside of the larger cities. We also see continued requests for larger accounts, which require longer lead times to serve, providing confidence in our growth assumptions, and production from oil and gas load in West Texas remained strong. Data centers have also had an impact in our service territory, now totaling over 400 megawatts. These customers typically start off as distribution customers, paying demand-based rates, and eventually move to transmission customer class, paying rates through our TCOS filing that recover transmission investments made into our system. ERCOT’s growth expectations for the market have been a topic of conversation all year for both traditional customers and new customers like data centers. Legislation passed in Texas last year now requires planning studies to consider load beyond the contracts already in process, and studies recently completed for West Texas more than doubled the forecast load for the region compared to the studies from just a few years ago. We have been building our system to support this growth and using semiannual TCOS and DCRF rate mechanisms to recover our invested capital. Our regulatory highlight for the third quarter is the successful resolution of our second set of filings on both the transmission and distribution sides, adding to the successful resolution in the first half of the year. Turning to Slide 7, we have a few key updates on the horizon at TNMP. We filed our System Resiliency Plan in August and are moving along the procedural schedule with a decision expected no later than February of 2025. The plan includes $600 million of capital investments that would be recovered primarily through our existing semiannual DCRF filings. For West Texas planning, ERCOT has laid out its proposal to the Texas Commission for local projects totaling the $4 billion estimate previously made for the region. TNMP is proposed as a suggested owner or co-owner for a number of these projects involving both new and existing infrastructure. We do believe there may be some additional projects TNMP was not selected for that we should also take part in, and we will follow the commission process for resolution on these projects. We expect to see a total of $600 million to $900 million of projects beginning in 2027. We will be required to file for regulatory approvals for each of these projects. The recovery for these investments will be allowed through our existing semiannual TCOS filing. There is no update this quarter on the pending rules for mobile generation which were proposed earlier this year for comment. We will continue to monitor the proposed rules and we will consider whether to file for any resources in 2025. Now let’s move on to PNM on Slide 8. We’ve had a couple of noteworthy announcements recently. Our grid modernization plan was approved earlier this month, including metering infrastructure. Once in place, customers will be able to use real-time information to manage their energy usage and will also be more efficient and effective in managing our system. Also, the Department of Energy announced that it has selected PNM’s virtual power plant project for funding through the GRIP program. This project is designed to integrate smart grid technology, distribution-sided batteries, and other distributed energy resources. The anticipated project outcome will enhance grid stability and benefits for customers. We are continuing our journey to carbon-free and recently added another 450 megawatts of solar and storage to our system. We have a lot of advantages in New Mexico when it comes to clean energy. We have an abundance of solar and wind potential, and when joined with battery storage capacity, it allows us to reliably meet our customers' energy needs. We’ve also had a number of positive regulatory highlights this year at PNM. Earlier this year, the New Mexico Commission approved our application for new resources in 2026. In October, our grid modernization application was approved. And there have been a number of constructive workshops on several topics, including our regional markets and the other benefits this could bring to customers. I will talk more about this when we turn to Slide 9 to cover the key items on the horizon for PNM. In the coming weeks, we plan to file an application at PNM for new resources to be in service in 2028. We originally issued an RFP for projects that were able to come online in either 2026, 2027, or 2028. This is the second and last application stemming from this RFP. We’re not going to get ahead of our filing and talk about the details, but we are committed to putting forth resources that ensure grid reliability and resilience and movements towards our energy transition. We continue to believe that a balanced mix of utility-owned and third-party developed generation is the best course of action for our customers. We will provide more information when the filing is submitted. As we look forward, we will be issuing our next RFP in the fourth quarter for resources to come online between 2029 and 2032. In addition to meeting increased demand, this RFP will cover the years where we need to bring on new generation to facilitate our exit from the Four Corners coal plant in 2031. This will complete PNM’s exit from coal as we look towards the next step in our energy transition. As I mentioned earlier, regional markets hold the key to maximizing benefits to customers. When our intermittent resources are producing more energy than we can use, other regional utilities can purchase this excess. Similarly, when other resources in the West are available at a lower cost, we can lock in those benefits for our customers. Our commission is expected to issue a policy statement today, supporting participation in the regional market with a focus on customer benefits. We expect to make a decision on which market we will join before the end of the year. To realize the value of New Mexico's renewable potential, we need to develop and implement transmission plans to complement the plans for generation resources. PNM is moving forward by publishing a 20-year transmission planning study later this year. This study will lay out a roadmap to achieve the emission limits in carbon-free energy mandates set forth by the Energy Transition Act and set the stage for New Mexico to be able to contribute to the Western regional planning efforts. It will also provide a more comprehensive framework to integrate our generation, transmission, and distribution businesses. We expect to share more about the result of this study when complete later this year. Lastly, let me provide an update on our 2025 rate review filing. The procedural schedule calls for testimony from staff and interveners filing a settlement by November 26. We are in discussions with parties about the issues in this case. If a settlement is not reached, rebuttal testimonies are due January 17, and hearings are set to occur late February and early March with a final decision in the case by early July. With that, I’ll turn it over to Lisa for a more detailed look at the numbers.

Thank you, Don, and good morning, everyone. I’ll start on Slide 11 with a recap of third quarter results. Earnings per share were $1.43 compared to $1.54 in the prior year. Earnings benefited from the recovery of capital investments through TCOS and DCRF mechanisms at TNMP. The implementation of new retail rates of PNM in January and income from our PNM decommissioning trust. Low growth at PNM and TNMP was more than offset by the impact of milder temperatures compared to last year, reducing earnings on a net basis. Lower transmission margins at PNM also reduced earnings along with depreciation, property tax, and interest expenses associated with new investments. Lastly, the dilution impact from shares issued in December of last year lowered our earnings on a per share basis. Now turning to Slide 12. I’ll cover our guidance assumptions for the rest of the year. We’ve gotten through the majority of our annual earnings, and we are comfortable narrowing our guidance to a range of $2.70 and $2.75. We have been above expectations in some drivers, including PNM low growth and weather, while we have seen decreases from other drivers, mainly PNM transmission margins and corporate interest expense. We have raised $100 million of equity through the third quarter by way of our ATM. These are forward sales that we plan to settle in December of this year. Earlier in the year, we issued a junior subordinated convertible bond to replace $550 million of corporate term loans, the debt-for-debt exchange balances our income statement with our balance sheet by achieving a lower interest rate while also receiving equity credit from the rating agencies. On Slide 13, we have updated our capital plan to incorporate the additional $150 million of investments included in TNMP’s system resiliency plan for a total of $600 million. These capital plans already include PNM’s recently approved grid modernization plan with investments of $344 million, $291 million of these investments are planned through 2028 with the remaining amount in 2029. Adding the full amount of TNMP’s system resiliency plan has increased our rate-based growth slightly to 10.7% on a consolidated basis for 2024 through 2028. Don described a number of other opportunities that we have on the horizon and will need to prioritize based on the impacts and benefits to our customers and our systems along with our balance sheet. As each of those opportunities become more defined, we will integrate them into our plans and projections. On Slide 14, we have also incorporated TNMP’s resiliency investments into our earnings power, and we remain comfortable with our targeted 6% to 7% growth in EPS through 2028. We continue to plan for an average of $100 million of equity per year to fund planned capital investments through 2028. We have assumed we’d finance the additional $150 million of TNMP investments with approximately 45% equity or $70 million from 2025 through 2027. For any incremental capital stemming from the opportunities on the horizon, we continue to assume that the holding company issues equity for 40% to 50% of the total spend to maintain our consolidated credit metrics. We continue to execute on our plans for this year and feel confident in our targets. With that, I’ll turn it back over to Pat.

Thank you, Lisa. We are pleased with the positive regulatory outcomes we’ve seen this year and the opportunities we have on the horizon at both PNM and TNMP. Before I open it up for questions, I want to thank the TNMP lineman who packed up and went to provide mutual assistance after Hurricane Helene. I know their work was appreciated by those impacted by the hurricane, and we appreciated it here as well. Wyatt, let’s open it up for questions.

I’ll now begin the question-and-answer session. And our first question comes from Nicholas Campanella with Barclays. Please go ahead.

Hey, good morning. CapEx trick or treat?

Well, it’s a treat. It’s a treat.

Definitely a treat. I should clarify that, so…

Okay.

Hey, so, it’s good to see the $600 million to $900 million of ERCOT projects and just thinking about where that the size of that capital relative to even your current rate base there, where it’s projected to be in 2027, and just seems very material. And I acknowledge in the prepared remarks you kind of talked about having to prioritize capital within the plan as well as the balance sheet. So just how should we kind of think about this $600 million to $900 million? Would that replace current CapEx in your projections as it stands today, or is it truly incremental? Just maybe you can kind of give us a little bit there.

Yes, absolutely. And good morning, Nick. And look forward to seeing you in about 9 or 10 days at EEI. We would look to see that $600 million to $900 million being incremental starting in about the 2026, 2027 timeframe and going through 2030 based on the ERCOT schedule.

Incremental. Okay. Thank you. And then on the New Mexico rate case, I understand that you could potentially see a path where parties file testimony or potentially you get a settlement filed here. Just putting some parameters around that, are you willing to file a partial settlement? Is this to really take all the issues off the table? Just – what could we kind of potentially see here as we get into November? Thanks.

No, absolutely, Nick. In this rate case, we’ve kind of taken a different approach, and we began discussions with all intervening parties before we actually filed the case. And it’s a traditional kind of T&D case; a lot of those legacy issues are behind us now. And we’ve continued those discussions even through this week about a potential settlement. And we’re still hopeful that there will be a settlement. So I think all avenues are open at this point, whether it’s been a partial settlement or a full settlement as we continue to work with the intervening parties.

All right. I’ll get back in the queue. See you in the week here. Thanks.

Thanks.

Thanks, Nick.

Our next question comes from Julien Dumoulin-Smith with Jefferies. Please go ahead.

Hey, good morning, team. Happy Halloween, indeed. Thanks for all the treat. Maybe too excited, I don’t know. Anyway, just following up on what someone was saying there real quickly, if I can. On the $600 million to $900 million there, real quickly here. You talked about potentially getting involved in some additional projects. Is that what’s contemplated when you talk about the upper end of that range there? Or is there an upside to the upside on that, if you will?

Outside of the upside, Julien. I would look at it between the $600 million and $900 million. The upside would be if they chose a different path. And I think we’ve listed out with the 3.5 kV path; it looked like based on just how ERCOT’s allocated the projects another $900 million. If they do the 565 kV path, then right now, we have zero allocated to us out of that. So I kind of think about it like that.

But just to clarify that, you have zero allocated to that. Your contention is that you merit some amount of that, if I understand your comments correctly.

On the 765 kV?

Yes.

I would assume that the commission would follow kind of the same path, and we would have to look at it to see right now. What the commission has done is, as you can – as you probably know, is there’s transmission providers that can dispute, and then they kind of go into a process there. And so we would have to look at it based on that import path if that import path was selected.

Got it. All right. So it does sound like there’s really some moving pieces there. All right. Excellent. Thank you. And then related here, just going back to the financing plan real quickly. I mean, you’ve made allusion to this, maybe not necessarily conventional equity in all context here. Obviously, you’re increasing your assumptions here today about equity. How do you think about refinancing and potentially upsizing your use of other forms of equity content here within the plan? Again, should we expect on incremental updates when you reflect that $900 million or $600 million, wherever that comes out to be, a traditional equity piece? Or would you think about layering in additional equity content, if you will?

Julien, as those opportunities become more defined and certain, we will integrate them into our plans and projections. And our base assumption is 40% to 50% equity. But as you know, we will always look to the market to see how we can best optimize that financing to get the best shareholder value.

Got it. All right. Excellent. And then just on the regulatory front, again, just re-asking a little bit of what Nick said as well, just on the rate case process here in the potential settlement. Just any nuance or any pieces of this that you could really look to get resolved here, maybe asking that a little bit more directly.

Yes. No, Julien, I think we’re in discussions, and I don’t want to jump in front of that. But we’ve had really good discussions with intervenors all along the way. And again, it’s a traditional kind of T&D type rate case at this point.

All right. Fair enough. I know there are a couple of different pieces there. So well, look. Nicely done, guys. Congrats, Pat, on the additional appointment here, and we’ll see you guys soon. right, all the best.

Thanks. Look forward to seeing you at EEI. Thanks, Julien.

And our next question comes from Michael Lonegan with Evercore ISI. Please go ahead...

Hi, good morning. Thanks for taking my question.

Good morning.

Good morning. On the West Texas transmission and Permian reliability study, you highlighted the additional $900 million under the 345-kV scenario. If I’m not mistaken, the traditional path is the 345-kV. So what would you say the chances are of that traditional pathway that could include that higher investment? And then also, do you know that schedule and timeline to address the remaining unresolved ownership?

On the pathway, you are correct that 345-kV was one of the past. I’m not going to get in front of the commission on what path they would select, import path. So I think we will wait to see on that topic.

Okay. Great. Thank you. And then secondly, a lot of growth in Texas, obviously, you haven’t filed a rate case there since, I think, 2018. What is your expectation for when you will file there again? Obviously, you have some constructive cost recovery there with the TCOS and DCRF mechanism?

Yes, you’re 100% right. It’s been six years since we filed a rate case there. We’ve gotten two extensions – we are always looking at the rate recovery and whether we file one or not. There have been some changes in the business between our transmission and our distribution there. So we’re exploring that as a potential in 2025.

Great. Thanks for taking my questions.

Thank you. See you at EEI.

The next question comes from Ryan Levine with Citi. Please go ahead.

Good morning and happy Halloween.

Same to you, Ryan.

Maybe in terms of PNM low growth, the customer count is relatively flat for this year versus previous years, but yet your retail load is expected to accelerate for the fourth quarter with some industrial growth. Can you elaborate around what types of customers are and what you’re seeing in the market?

Yes. No, absolutely. And Ryan, good morning. We’ve had some industrial load that we’ve talked about ramping up for probably the last 12 or 18 months, and COVID kind of slowed that down. We’re actually seeing that ramp, and it’s been ramping the last half of the year. So that’s what’s kind of closing the gamut there that we would expect to be within the 2% to 3% guidance range.

In terms of that trend, is that expected to continue to accelerate into next year? And are there certain industries that you’re more levered to?

Yes, Ryan, we do – we’ve had a lot of emphasis in the space on economic development. And so our industrial piece of the business is growing here in New Mexico. And so we continue to see growth going into 2025 as well.

And Ryan, it’s in a variety of industries, a lot of our clean energy industries, but it’s spread out. It’s not concentrated in any one customer industry.

Okay. And then maybe one follow-up in terms of the financing plan, given there’s a bias upside to some of the spending. Is it fair to assume that you would lean more heavily on the equity plan in earlier time periods than later time periods given that bias in your CapEx outlook? And is there – I think year-to-date, you’ve already achieved your ATM program for this year. Is there still an opportunity to execute on further ATM issuance in the remaining two months of the year?

So Ryan, we laid out on the earnings power a lot of detail regarding our financing plan as we see these incremental opportunities become more defined, and we will, of course, include them in our plans and projections. But our base assumption is the 40% to 50% of equity issuance for any upside on the CapEx side.

Okay. And then last question for me. Just in terms of the DPP – DOE funding, is there a way to quantify the financial benefit to the company of receiving the Department of Energy financing plan?

I think I would quantify it as customer benefit because it’s really allowing us to integrate our systems to better serve our customers. So I wouldn’t think of it as financial bottom-line impact, but again, the focus is on the customer.

Thanks for taking my questions.

Thanks, Ryan. See you soon.

And the next question comes from Andrew Weisel with Scotia Howard Weil. Please go ahead.

Thank you. Good morning, everybody.

Good morning.

I’ve got two fine-tuning follow-up questions and then one high-level one for you. So first, following up on the last one about load growth. I noticed that your forecast for 2024 came down a little bit for both states. Anything to point to there? And what’s the outlook for 2025 and beyond?

So on 2024, Don mentioned the industrial customers have been ramping up. It has been a little slower than we expected. And so as a result, we adjusted the ranges there. But we really do feel very positive about load growth in both states. Texas is, as you can see, the demand base load growth is very strong this year, and we continue to see that in the coming years. And like we said before, lots of economic development efforts here in New Mexico. And so we are getting additional load, particularly on the industrial side.

Okay. Great. And I see the data center, I think that’s a new disclosure 2.5% year-to-date. Any thoughts on how big that outlook might be for 2024 or beyond?

That’s where we’re at today, and we haven’t forecasted it. That’s a mix of those that are on our transmission system as well as on our distribution system.

Okay. Great. We’ll stay tuned. Next question, just to clarify on the equity. I know you talked very clearly about the high-level plan with specifically the $70 million related to the Texas System Resiliency Plan. Would that be financed through an ATM? And would it be spread over those three years or more front noted in 2025?

Yes. So we have spread them over the three years, 2025 through 2027, and really any additional equity will match as we spend the capital. And for us, we always look to optimize our financing plans. So it really depends on the market conditions, and we will just see what kind of vehicles we use then.

Okay. Fair enough. Then lastly, my high-level question is when we think about upside to CapEx here, you talked obviously about the Texas system resiliencies now in the plan, the West Texas transmission you’re starting to get more visibility on then you’ve talked about things like New Mexico resource plan, et cetera. My question is more broadly, do you think that there is a limit on how much upside there could be to CapEx? Is there a cap beyond regulatory approvals, whether that’s related to the balance sheet, your labor force, customer affordability, or just general corporate bandwidth?

One of the screens – thanks, Andrew – one of the screens we always go through is customer impacts in our service territory. So – and that’s one of the screens that we look at as we kind of allocate capital both in New Mexico and Texas. So I would say that’s probably the ultimate screen. And that depends on a lot of factors, as you can imagine, what load growth is doing, what the policies of the states are, and they all kind of go into the mix as we kind of look at it.

All right. Very good. Thanks so much everybody.

Thank you.

Thank you.

That concludes our question-and-answer session. I would like to turn the conference back over to Pat Vincent-Collawn, Chair and CEO, for any closing remarks.

Thank you, Wyatt, and thank you all for joining us this morning. I look forward to seeing all of you at the EEI Financial Conference, where we will provide more color on our capital investment opportunities. Stay safe.

The conference has now concluded. Thank you for attending today’s presentation. You may now disconnect.