Comstock Resources, Inc.

There may be a spot, maybe very infrequent, though, that we have to pick up a spot third frat crew, but we pretty much could cover most of that still with the rig count we got with two frat crews, which, you know, I'll just say our frat crews that we got are really good and very efficient, so that's why we're able to do that.

Got it. Thanks, guys. Thank you, Kaylee.

Thank you. Our next question comes from, Charles Meade from Johnson Rice. Please go ahead.

Good morning, Jay, Roland, Dan. I want to ask one more question about the Elijah wand. And, Dan, I think you mentioned in your prepared comments that one of the reasons that you guys were, I guess, chose this location or more confident in it is that you had some deep vertical well control there. And I'm curious, I know that there was a lot of, you know, there was historical vertical development in this area, but how many other places, will having offset vertical well control, will that be the kind of the dominant variable on picking locations when you step out, or was that just kind of a one-time thing with the Olajuwon well?

So we did, you know, when you do your first step out, obviously you want to have as much control as possible. If you don't, if you get away from the areas where you have well control, that's where we have to drill a pilot hole, you know, and log it and get that, you know, see what that section looks like. So we did kind of know generally where we wanted to drill up here, but with the vertical well control we did have, we wanted to get something fairly close to, you know, kind of know for sure what the log quality was and And that is how we picked the first one. But all the future wells, obviously, will be, you know, will spread out. And in some places, we will be drilling. We will need to drill some pilot holes. As we get further away from those control points, you know, just to control your risk, you need to drill those pilot holes and get some logs across them.

You know, Charles, to go back to the Circle M, you know, that area we have the most well control. So that's why we drilled it where we drilled it. And then we marched that 23. three miles up to the north-northeast, you know, to the Leon well, the Diornellis wells. And then to answer your question, we thought we had better well control near the Elijah one, so it's kind of a mirror image of the Circle M. We had 3D. We had well control. We didn't see a lot of static in the 3D lines, et cetera. So, you know, you have to go back and almost ask the question, why did you drill it? I mean, that was 24.4 miles. Even at the time we decided we wanted to drill it, we were probably 30 miles away from our closest producer. But the goal that we keep telling you and the world is we do trust our geological department, we trust the operations department, and we really want to de-risk this 520,000-net-acre footprint as quickly yet as prudently as possible. And we did take a chance that the Elijah 1 would be a great well. We didn't know that. But I do think that the results are transformational. We're glad we can report it. Another thing I think, Charles, is that even if you go back in February, we didn't really talk about the Elijah 1. We did some road shows. We didn't tout something. We said we're drilling a well. You almost had to go find that well. And once we could report it, then we tell you the truth about it, whether it's good, bad, or ugly. And this happened to be great. So that's how we go about it. And when we decided to do the Elizalde gas, it was probably $1.90. I mean, this was many, many, many, many, many months ago. We elected to go ahead and drill this well.

That's a helpful elaboration, Jay. And then perhaps following up on that idea of de-risking more of the position, it looks to me, I'm not looking at any kind of contours or anything, but it looks to me that if you look at the wells you've drilled and the permits that you have, it's mostly along what looks like that kind of southwest-northeast strike axis. So I'm wondering, is that in fact the case? And if it is, when or what's the right time to push it push the de-risking kind of a northwesterly up-dip direction?

Well, when we started five years ago, you have a blank sheet of paper like you're in kindergarten. You've got a sheet of paper. There's nothing on it. And then all of a sudden, we look and say, well, maybe we should drill this Circle M well. Now, all that acreage that you see that we present, we didn't own any of that. And we said, okay, let's drill the Circle M. Well, as you progress, it's almost quarter by quarter, year by year, you know, we're able to buy the big position from Legacy Reserve, which had Pinnacle. Well, we didn't know if the Pinnacle plant in that 145 mile high pressure pipeline, whether it was located at the right spot. But we did know that the logs that we had showed that on the, you know, there was a boundary kind of on the east side. And we did with our hundreds of land men, you know, we did find out that that was unleashed. So you go and you aggressively, yet prudently, grab what is unleashed, and then if you can add HPP acreage, which most of that is to the west. So 80 plus percent of our acreage is HPP, but we didn't add that HPP acreage. You know, it was March of last year, we added 185,000 net acres. It was probably first quarter, we had another 62,000 net acres. So the acreage that you're seeing to the west, most of that's HPP. So we've said over and over, we've got to drill about 70 wells to hold acreage that we leased in this 520,000 net acre play. So we have focused our most part of drilling to hold acreage, and then we'll deviate over and drill some of the HPPed acreage. Now, we've had one pilot well core, and we've got a second one that we're working on right now. So as we go through 2025, 2026, we would like to have a core of our own on all four corners of the footprint and a few in the middle. And that will tell you the answer to the question that Derek asked, you know, what is the rock quality? Well, we're going to know that with the cores.

That is helpful detail. Thank you, Jay.

Sir, thank you.

Thank you. Our next question comes from Jacob Roberts from TPH and Company. Please go ahead.

Good morning. Good morning. Maybe a bit of a macro question, but if we see gas prices cooperate to the end of the decade, how many rigs do you envision the Western Hainesville being able to support over that timeframe? And maybe as a sidecar to that, Is there an internal view to take a more methodological approach to growth and target high single digits or low double digits through the end of the decade?

You know, I think if you have, you know, all of this except like 6,000 acres is undedicated. So I think you have to look at that and say, well, we're going to probably connect 15 or 20 new wells to sales. And then as Dan mentioned earlier, when Derek or maybe Callie asked the question of How many more wells are you going to drill than what Elijah won? Fortunately, we have an incredible partner in Pinnacle with Quantum. So we do control a budget for our gathering. And then the other question was asked, how about AI? How about the data centers, et cetera? I think that we'll be able to control it. We will never have to drill a well that we shouldn't be drilling. We'll never oversupply the market because, of course, you have to drill wells. I think you will see us very prudently develop this and de-risk all four corners in the middle of it with the Pinnacle Gas Services, which makes our wells far more economic. And I think that'll serve data centers. I think you're gonna see, you know, we're 100 miles away from Dallas, 100 miles away from Houston. We're where you should have a data center. And I think with BKB and the carbon capture, we're gonna be far more attractive for companies that will look to approach us, and we're already in discussions with them, to create the data center, which goes back to this power demand. I think we're going to be able to fulfill our share of the power demand. And you look and you say, well, is it real? You know, you always say, where's Waldo? Is this real? Do you really need this gas? And, you know, we looked in the world's largest electric utility company, this week, said that U.S. power demand will probably grow by 450 gigawatts. That's 71 BCF of gas, which is what? That's 75 gigawatts with gas fired. That's 12 BCF of new gas that's needed. You got Woodside's announcement, it can probably have two BCF by 2029 or 30. Current permitted LNG projects are about 17 B. So this is a great question. Where are you going to get that gas? We think that Appalachia is constrained. You'll get a B or so. I think the farming, you don't drill there for gas. This is this core area why we work really hard and fought hard to de-risk this stuff, to deliver it to you when we need to. So we're always going to protect the balance sheet, but we're going to de-risk this thing and take risk to de-risk it just like the Elijah one.

Great. I appreciate the answer. The second question, kind of circling back to Freestone and some of the comments y'all made about timing it perhaps with the midstream build out as we progress in the Q4 and the 2026. Is there anything we should be thinking about on the Elijah one in terms of flow rate versus the IP rate or if that dynamic will apply to any other wells planned for this year?

Well, so the flow rate on the Olajuwon is, I mean, we're flowing at basically the same type curves that we've got set up for all the wells back to the core. I don't think anything on the midstream side is going to constrain us on the ability to flow them how we want to flow them. We just need to be able to get the midstream in place to be able to drill these, which is why we're not spreading another well until... up there until the end of this year and really mostly into next year. The well looks as good as everything else we have. We're going to flow it the same as the other wells we have, and we don't have any constraints on the midstream side.

Excellent. Appreciate the time. Thank you. Great questions.

Thank you. Our next question comes from Carlos Escalente. from Wolf Research. Please go ahead.

Hey, good morning, gentlemen. Thank you for taking my question. Good morning.

Good morning. So considering that 2025 is an HBP-driven program, so to speak, if I jump forward to 2026, what is y'all's underlying assumption for that year's program in terms of capital allocation in between HBP exclusive wells versus delineator slash appraisal wells. I think that to conclude the question, it would be tremendously helpful to understand and parse out the general geography of where these HBP wells are and their underlying impact to the perception of those well results as we move through the next 24 months.

Yeah, I mean, we still want to focus on when we drill a well in the western Hainesville into holding acreage. And remember, we have that 70 wells or so to hold this acreage that we leased versus the acreage we acquired that's held by the shallow production. So that will always be a big priority over anything else. Yeah, that and the proximity and availability of midstream and acreage are for the next – 25, 26, they'll both be similar. Those will be the main drivers to where they drill these wells.

Yeah. Thank you, Roland. I maybe should have clarified that I was asking specifically about the western Haynesville.

That is the western Haynesville, right? Yeah. Legacy Haynesville, we don't have any acreage to drill the hole, so that's very price-driven and And the takeaway is there are areas that the takeaway is more difficult in the Legacy Hainesville. There are different costs to the transport in the Legacy Hainesville, so we take that into account. But generally, we fill in the Legacy Hainesville locations. And since we haven't been that active there, we're actually able to go back into some of our higher performing areas, you know, with our with the rig we just added and drill and the Legacy Hainesville around that since we've created a lot of space about letting production kind of fall in that area. Yeah.

Thank you, Roland. Appreciate it. My second question is turning to the macro real quick and perhaps, you know, using one of the prior questions as a segue. Are you, would you be concerned at all if, Permitting around the Permian, even though you rightly point out, Jay, those wells are drilled for the oil, but unfortunately have a ton of associated gas. Simply, they don't have the necessary takeaway capacity to the necessary demand center. So would you all be concerned, or what do you view that Permian gas, if there was an outlay for that gas from additional permitting at the government level that would take more of that molecule towards the Gulf Coast or the general demand area. Is that something that you're thinking about or concerned about at all?

I think that's all expected, you know, as far as the – I mean, obviously the Permian gas supply has to grow in order to fuel the big demand pool that's, you know, coming from LNG and other power generation. So, yeah, that's going to be a big contributor. So it's, you know – We do think that the weak oil prices today kind of, you know, stall a lot of the interest in drilling those wells since they are drilled mainly for oil prices.

Yeah, we do expect that growth.

Thank you, gentlemen. Thank you.

Our next question comes from Phillips Junston from Capital One. Please go ahead.

Hey, thanks and congrats. I wanted to ask you about the quarterly shape of your tills and just assess your confidence in achieving the large ramp up in production in the second half of the year that your midpoint of the guidance implies. It looks like you brought on 11 tills in Q1 and are planning 12 to 14 or so in the second quarter. So combined for the first half, that's about half the 46 wells or so. for the year. So the till cadence seems fairly rateable by quarter. I'm just trying to reconcile that with the fairly flat production level in the first half, and then sort of the large ramp up in the second half. Is that mainly a function of the timing of when those 12 to 14 tills occur here in the second quarter, or is it sort of a larger mix of Western Hainesville tills in the second half, or some sort of a combination of those factors?

It's a combination of the both. I mean, the problem that till related production models have is there's no way for people outside to know the timing of when those are brought on. And so the tills in the second quarter look to be more second half weighted. That's why the production's really, you're starting to see the production, the sequential production growth return in both the third and the fourth quarter. And then if you, it's just a function of the types of wells that we're drilling and that we are completing at which time. The third and fourth quarters, like you said, will be a similar amount of total tills as the first half, but the profile will look pretty similar to the first and second, where the third will be a lower number of tills and the fourth will be a higher number of tills.

Okay, perfect. Thanks, Ron.

When they come on during the quarter.

Yeah, okay. Appreciate that. And then obviously it's pretty early days regarding the BKV agreement. I'm sure a lot of details need to be hammered out and there's, you know, tax credits to consider and whatnot. But looking out in the future, Would you guys expect any incremental costs incurred by Comstock or any sort of net capital outlays funded by Comstock?

No. Our partnership is basically they will get the tax credits, and they will make the capital outlays, and then we'll participate by receiving. They'll purchase the CO2 from us. There will be a reduction in our operating costs, net-net. But, yeah, we don't see any big capital investment by Comstock.

Excellent. Thanks, Roland.

Thanks, Phil.

Thank you. Our next question comes from Greta Drefk from Goldman Sachs. Please go ahead.

Good morning, and thank you for taking my questions. My first one is on your lateral links. You've seen pretty consistently continued improvements across operations, particularly in the legacy Hainesville area. How much further upside do you see the laterals on a sustainable basis, and how would you characterize the applicability of these lateral lengths, you realize, in 1Q25 going forward this year and into next?

So, in the legacy Hainesville, yeah, we're, you know, we've gotten actually pretty long where we're at today. I don't see us getting a whole lot longer than this on average. I mean, we were at, what, just under 13,000 feet for Q1. You know, we're our longest one, 17,000. We still have several 15,000, you know, 14, 15,000 critters in our inventory. But, you know, when you just look at the mix of what we're going to be drilling as we go forward on the schedule, you know, we're just getting pretty flat up there around that 12 to 13,000 foot average length. So I don't think you're going to see us continually like keep climbing higher than that.

The positive is though we, We'll not have to drill a lot of the very short laterals for reasons because of the U-turn and horseshoe wells are now kind of replacing those. So where we had those scattered in the drilling programs and even last year in the first part of the year, we had short laterals. Our averages should be a little bit better because we won't have the really short ones to weigh it down.

Right. And most of the horsey whales we'll be drilling, they're going to be, you know, they're 9,500 feet. And we've got a few of them going to be a little bit longer than that. But, you know, as far as just the average, I think, is what you were asking about going in the future. I think we're, you know, probably getting close to a plateau point.

Got it. I appreciate that color there. And then my second question is just on DNC costs. Do you think that there could be some meaningful pricing concessions on rigs or crews as we head towards 2026? Just given the broader, more macro uncertainty, especially potentially also the implications from the oil macro more idiosyncratically.

Yeah, I think that's a really good question, and I think the answer is yes. If you would ask that question on the last call, obviously we're more optimistic we'll see some price concessions just with what we're seeing with the – oil strip and where the activity may be headed in the Permian. And I think we'll see that across the board on all services, rigs, frack crews. I mean, obviously we got some of our rigs are turned up, but I think we'll see it on a lot of the smaller services beyond rigs and frack crews, I think where you'll probably get a more meaningful percentage drop. and uh you know vendor calls are there and also hopefully on our bite prices you know depending on what happens with the tariffs got it appreciate thank you thank you thank you our next question comes from noel parks from toy brothers investment research please go ahead uh hi good morning uh just have a couple

It looks like a pretty exciting quarter in terms of a large one well and everything going on. I guess I did want to ask about maybe just overall. It used to be that before the shale era, rock that was too tight was off the table. And I'm just wondering, do you see there being plays now where formerly the thinking was, well, it's too deep and too hot, that now could be available sort of to make a second wave in shale, given what you've demonstrated you've been able to do in areas that pretty much everyone dismissed as just not workable?

Yeah, I think we've obviously, I think, made some big inroads, and I think a lot of people are looking at what we're doing and what we've been able to achieve, you know, with the depths and the temperatures. I don't think there would have been a lot of takers on trying to, you know, have a commercial development with these conditions just not too long ago. And I think, you know, with the price environment where it's headed over the next two years and the LNG demand,

You know I can certainly see some you know people looking a little bit deeper than what they would have just a year ago Right right and when you were talking about also the the great improvement you had in in just the drilling time on the Western Hainesville and You listed you know using more pads and uh the the drill pipe and uh but you also mentioned specifically casing design improvements and uh use of bottom hole assemblies uh so i just wonder if you could just talk a little bit more about you know some details on on the influence of those well there you know we've uh so we one thing i always kind of just you know preach around here is obviously consistency we've had some great results you know we obviously keep

We just want to be very repeatable and predictable to be able to deliver that. Some of that comes with time and practice. Practice. As you keep drilling wells, you keep getting better. The insulated drill pipe is basically shaved days off of drilling the lateral. Obviously, where we're deep and got a lot of high temperatures, our motors and MWD tools on bottom. Obviously, things don't perform well when you put a lot of heat on them, so the insulated drill pipe cools those temperatures down a little bit. It makes our motors and our tools just last longer. You don't have to make as many trips when you're drilling the lateral, so that's how you shave off days there. Casing designs, we've just basically been able to streamline, downsize our sizes a little bit, and we've just got a lot better at picking where our casing points are so bottom hole assemblies just as we've drilled more wells and got more data on how the motors are performing which motors perform better and basically how to you know tweak the designs on the motors for the temperature we've just delivered better runs with that you know we looked at geology 30 years ago and said we thought the rocks were there

And then when the Joneses came in, he said, you know, I'd like to drill this circle in well. I said, okay. So you have to progress, progress, progress day to day to day, just like our relationship with you. And you have to handicap people and say, you know, Tui does this, Comstock does that, et cetera, et cetera. And then you have to perform. You have to perform and you have to get in the game. And then once you get in the game, you've got to say, well, is that seismic real? Are those logs real? Is that core real? Can you really – how do you frack these wells? And look at the performance. You know, our in-house reservoir group, they have to look at, you know, how hard do you draw these wells down? But it is a – this is a team sport of Comstock. You've got to have a big backer saying, I want to own something big. And you've got to have some breaks where you get this HPPed acreage. You've got to know how much you have to spend in order to hold all that acreage. Like Roland said, we're going to drill our 70 wells. Then you've got to have some people join the team for financing, like Quantum. And then you have to get the gathering. And then you've got all this stuff. And then once you get a little bit comfortable in one area, you've got to jump out 24 miles somewhere else Because it is a very hard fought road. I don't think anybody when gas was at a 30-year low, except for COVID, was eager to jump in and drill the wells that we were drilling, which are some of the hardest in the world, when we drilled them last year. Nobody. We pushed the reset button on how to add inventory. We pursued exploration. That's what we did.

Great. Thanks a lot.

Thank you. This concludes the question and answer session. I will now turn it back over to Jay Allison for final remarks.

All right. Again, I want to thank all of you that are still here listening. You know, we respect your time. I want you to know that all 255 people here at Comstock, we relish and we're thankful for the incredible opportunity to unlock a what we see is this tremendous wealth. We love the chance that everybody's given us. It was almost seven and a half years ago when Jerry Jones and his family started supporting and investing in the company. And ultimately, you know, they own Seedy Warms in the company, but they asked three questions at that time. This is seven and a half years ago. You know, what does your drilling inventory look like? If you drill a well, can you turn it to sales immediately? And if LNG really materializes, can you use that natural gas as feedstock gas? Well, those same three questions is what we ask ourselves today over and over and over for this whole conference call. We've really, really come a long way in the seven and a half years. But we want to thank you that are our equity owners, financial backers, and all the service companies we depend upon to create this value chain. Thank you.

Thank you for your participation in today's conference. This does conclude the program you may now disconnect.