Greetings, and welcome to the Texas Pacific Land Corporation Fourth Quarter 2024 Earnings Call. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Shawn Amini with Investor Relations. Thank you. You may begin.

Thank you for joining us today for Texas Pacific Land Corporation's Fourth Quarter 2024 Earnings Conference Call. Yesterday afternoon, the company released its financial results and filed its Form 10-K with the Securities and Exchange Commission, which is available on the Investors section of the company's website at www.texaspacific.com. As a reminder, remarks made on today's conference call may include forward-looking statements. Forward-looking statements are subject to risks and uncertainties that may cause actual results to differ materially from those discussed today. We do not undertake any obligation to update our forward-looking statements in light of new information or future events. For a more detailed discussion of the factors that may affect the company's results, please refer to our earnings release for this quarter and to our recent SEC filings. During this call, we will also be discussing certain non-GAAP financial measures. More information and reconciliations about these non-GAAP financial measures are contained in our earnings release and SEC filings. Please also note, we may at times refer to our company by its stock ticker, TPL. This morning's conference call is hosted by TPL's Chief Executive Officer, Ty Glover; and TPL's Chief Financial Officer, Chris Steddum. Management will make some prepared comments, after which we will open the call for questions. Now I will turn the call over to Ty.

Good morning, everyone, and thank you for joining us today. Fourth quarter closed a remarkable year as TPL set records across nearly every key operating driver despite sideways crude oil and natural gas prices. Year-over-year 2024 oil and gas royalty production volumes increased 14%, water sales volumes increased 31% and produced water royalty volumes increased 37%, with all three of those performance indicators representing corporate records. Our strategic investments in people, technology and infrastructure are paying major dividends as our surface and water revenues were collectively up 23% year-over-year. In addition, last year, we acquired over $400 million of high-quality Permian mineral, royalty, water and surface assets, providing TPL with additional growth levers. The cumulative impact of all these successes culminated in record shareholder return of capital in 2024 with a combined $376 million returned via dividends and buybacks. It was very simply a great year. I'd like to focus my prepared comments today on three topics: First, a debrief on the Permian during 2024 and an outlook for this year; second, a description of our latest efforts towards next-generation opportunities; and lastly, an update on our produced water desalination and beneficial reuse endeavors. Starting with the Permian. Despite a steady decline in rigs throughout 2024, Permian oil and gas production exited last year at record highs. According to Baker Hughes, Permian horizontal rigs peaked at around 345 in the first half of 2023, which then declined to about 300 entering 2024 and exited the year around 290. However, as the industry has demonstrated time and again, operators continue to find efficiencies through innovations such as longer laterals and multi-formation coal development. Based on preliminary industry data on a full year basis, despite the average rig count in the Permian being down about 8% from 2023, the number of spudded…

Thanks, I. For full year 2024, we generated record free cash flow of approximately $461 million, which represents an 11% year-over-year increase. Full year performance benefited from higher daily oil and gas royalty production, which increased 14% year-over-year, higher water sales daily volumes, which increased 31% and higher produced water royalty daily volumes, which increased 37%. Of the approximately 26,800 barrels of oil equivalent per day for full year 2024 royalty production, acquisitions that closed last August and October contributed approximately 1,100 barrels of oil equivalent per day. Consolidated results were partially offset by lower realized oil and natural gas prices, which declined year-over-year by 2% and 48%, respectively. Consolidated revenues during the fourth quarter of 2024 were approximately $186 million. Consolidated adjusted EBITDA was $161 million and adjusted EBITDA margin was 87%. Diluted earnings per share was $5.14. Fourth quarter 2024 royalty production of approximately 29,100 barrels of oil equivalent per day represents an 11% increase compared to the same period last year and a 3% increase sequentially as activity remains robust in our Loving County, Central Midland Basin and Northern Reeves County subregions. Quarterly produced water royalty volumes grew 8% sequentially and 44% year-over-year to approximately 4 million barrels per day, benefiting from our new volumes into our out-of-basin pore space in Andrews County that we acquired in 2023. Sourced water sales volumes of 737,000 barrels per day grew 2% sequentially and 42% year-over-year with demand for treated water especially strong during the quarter. As of quarter end, we had 6.4 net permitted wells, 13.2 net DUCs and 3.0 net completed but not producing wells. That amounts to 22.6 net line-of-sight inventory. We believe this level of near-term inventory can support near- and medium-term production growth above overall Permian production growth. Permit and spud activity have been especially…

[Operator Instructions] Our first question comes from Derrick Whitfield with Texas Capital.

Ty and Chris, congrats on your progress during 2024. Also certainly, thanks for the update on water and some of the next-gen opportunities you guys are discussing. Maybe starting there and referencing Page 33 of your presentation. Could you further elaborate on the potential desal synergies with behind-the-meter power generation and data centers? And how advanced your discussions are on this opportunity?

Yes, sure. Robert, do you want to take that one?

Sure. I think when you look at all the ingredients that are required for a data center and the growth of data centers, not just in the Permian, but across Texas. Power constraints are being felt everywhere. When you say that and when you look at the synergies and the ingredients that it takes and what the Permian has, it truly is a transformational opportunity to do it. The behind-the-grid generation to see data centers come to West Texas, it's going to take behind-the-grid generation. And then when you look at the synergies of waste heat capture off of that generation for use in desal pretty tremendous. And then also just the water component, the water component of the look at the synergies we've got too much water in the Permian and in form of produced water, and then the demand that these data centers need and tying all three of those together is truly a tremendous opportunity.

Great. And that makes complete sense. And then maybe staying with you, Robert, just on the desal opportunities. Is the goal still 75% volume reclamation, 75% analyte removal at a cost of 75%. And I guess further now with the benefit of another year of assessment and your progress with Phase 2, how confident are you guys in achieving that $0.75 per barrel treatment cost with a commercial scale facility?

With all treatment, scale take to get to that point, I'll take it kind of each 75% as you go. We're on track on the first two. The 75% -- volume reduction was 75%. We're trending toward that. And again, mentioned in the call, the testing we're doing right now in North Carolina. When you look at the 75% cost outside of just scale to get there. And we see that scale and that economy to scale that required even our traditional treatment used for hydraulic fracturing. The bulk of that $0.75 for any desal technology comes from the energy consumption that's required. And you try to base that at first in a kilowatt per hour, assuming that you're going to tie into the line power. And again, it goes even more toward the benefits of going to the nat gas generation, being able to get that kilowatt per hour cost down via gas and infield gas being the generation piece, the 75% is 100% achievable. But we're trending toward all three.

That's great. And perhaps for Ty, Chris, I mean, in the press release, you guys mentioned a compelling opportunity to consolidate enormous, yet fragmented market for oil and gas royalties, surface and water assets. Where are you seeing the greatest opportunities today between royalties and surface?

Yes. I mean, honestly, the deal pipeline looks really good. The landscape for '25 looks very good. And we've been looking at quite a few opportunities, both on the surface and mineral side. So it seems like there are more opportunities for both on the landscape for '25 than we've seen in the past. And I think we're going to get the chance to look at a lot of really high-quality opportunities. And there seem to be some larger, higher-quality packages starting to come available. So we are very excited about the landscape as far as acquisitions and across surface, mineral and the water space as well.

Terrific. And perhaps thinking about things from a macro perspective with the recent change in administration, could the Trump administration make any federal changes in policy, which could open up greater amounts of pore space in New Mexico that would be attractive for the industry given the depth of SWD wells in New Mexico in general?

Maybe repeat the last half of that question, Derrick, sorry.

Sure. So could the Trump administration make any changes in federal policy, which could open up greater amounts of pore space into Mexico and federal lands that would be attractive to an industry given the depths of SWD wells in Mexico in general?

I mean, I guess it's possible. I'm not aware of anything coming down the pipeline that is going to help New Mexico from a regulatory standpoint as far as disposals, Robert, I don't know if you are. Do you have an update there?

No. No, I don't. And that would be, again, not aware of anything that would be a piece we haven't seen to date. But I would say even beyond any regulatory changes, it's just the need for an alternative in water that's outside of disposal is going to come just from a functional standpoint even beyond the regulatory standpoint, but I'm not aware of anything.

I think those changes would likely be more state level than Fed level.

And correct me if I'm wrong, but I think the wells, generally speaking, on the Mexico side, aside from the regulatory link maybe that would require or more length that would require from a timing process. Those are about 50% more expensive in general, as I understand. Is that in the right ZIP code?

I assume you're referring to the deeper disposal?

That's correct.

The deeper disposal is, I would say, even greater than 50%, but you've seen a pullback in New Mexico. You saw a pullback on the shallow disposal 7, 8 years ago. You saw a pullback more recent in the last 2 to 3 years that has really seen the overall disposal capacity in New Mexico decline. But the deeper disposals are significantly more expensive. And due to various seismic and cost and really that payback on the deep disposal when you see a reduction in volume given the capital cost to put one in, you've seen a significant reduction on both sides of the border in deep disposal.

And as my final question for you guys. I'm just kind of thinking about your 2025 trajectory, referencing your line of sight inventory and recent commentary from the industry. How are you thinking about the turn-in-line quarterly run rate, if you will, for oil and gas royalties?

Derrick, if you look at the current line of sight inventory and you just kind of take your DUCs and your recently completed 13 and kind of 3, you put those together, you're in like 16. I think the 3 recently completed nearly 100% of those or practically 100% of those are going to come online during the course of the year. On the DUCs, the timing of those, it's usually 90% or higher that get turned on in the course of the year. And you might even have like 5% or 10% of the permits that also kind of make the full cycle trip in less than a year. So if history is a guide, if people continue activity levels that we've seen historically, that might lead you to believe that somewhere in the 14 to 15 net wells would get turned in line during 2025. And all 3 of the completed and 11 or 12 of the DUCs and maybe less than one net permit or something like that. But -- and that would be very robust. I mean that would probably exceed past years as far as like quarterly run rate. So the potential is definitely there for a very robust amount of wells coming online. It's really just going to come down to oil prices and activity levels. But as far as the inventory available, very, very strong right now.

Thank you. At this time, this does conclude today's teleconference. We thank you for your participation. You may disconnect your lines at this time, and have a great day.