Comstock Resources, Inc.

Good day and thank you for standing by. Welcome to the Comstock Resources second quarter 2025 earnings call. At this time all participants are in a listen-only mode. After the speaker's presentation there will be a question and answer session. To ask a question during the session you'll need to press star 1 1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question please press star 1 1 again. Please be advised that today's conference is being recorded. I'd now like to hand the conference over to Jay Allison, Chairman and CEO. Please go ahead.

Thank you. Welcome to the Comstock Resources second quarter 2025 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation entitled second quarter 2025 results. I have Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Five years ago, we made the decision to lease acreage and to drill an exploratory well in what we now call the Western Hainesville. Today, our Western Hainesville footprint has grown to nearly 525,000 net acres, and we have now drilled 29 wells with 24 of those currently producing. 10 are producing from the Hainesville Shill and 14 from the Bossier Shill. The Western Hainesville Wells vertical depths range from 14,000 feet to 19,200 feet with completed lateral lengths of 6,700 feet to 12,763 feet. Since we have put the first well online in 2022, we have made many changes to our drilling and completion design for this area. Both the Hainesville and Bossier shells in this area are rich in organic content, very thick, and have high pressure. This year we have drilled two pilot holes, taking logs and whole cores to increase our knowledge about the best ways to complete the wells in the future to maximize the EURs of the wells. As we develop our vast acreage position in the Western Hainesville, we're also building out our own midstream to support it. To that end, we just put our new gas treating plant in operations, which increased our treating capacity by 400 million cubic feet per day. In the second quarter, we turned five new Western Hainesville wells to cells. These wells include the Elijah I to the north and the Bellmire to the south, which is 30 miles away. Both of these wells appear to be some of the best we have ever, ever drilled. The second quarter wells were drilled and completed at an all-in cost of $2,647 for completed lateral foot, which is substantially less than the wells we completed in the last three years. Over the last three years, we have decided not to engage in the M&A market to build drilling inventory for the future. Instead, we have put resources into amassing the western Hainesville land position and de-risking this new place. The path we've chosen is not an easy one in a public company setting as future operating results are hard to predict, and many of our actions are aimed at creating long-term value versus creating immediate short-term results that benefit the next quarter. In order to protect our balance sheet, we pulled back from drilling wells in our legacy Hainesville area, which still accounts for over 80% of our production. We now have four rigs working in our legacy Hainesville area, which will allow us to stabilize production there as we grow the Western Hainesville. So far this year, we have turned 21 wells to cells with an average lateral length of 11,803 feet and a per well initial production rate of 25 million cubic feet per day. As Dan will go over in a few minutes, we're excited about the horseshoe wells that we're adding to our drilling program that the added rig will focus on. As Roland will cover in a few minutes, the second quarter financial results benefited from the improved natural gas price we're seeing this year versus 2024. Our natural gas and oil sales grew to $344 million and we generated 210 million of operating cash flow or 71 cents per diluted share. Our adjusted net income for the quarter was $40 million for 13 cents per share. We're also excited to announce that we're working with NextEra Energy, who leads the nation in the development of power generation, to explore the development of gas-fired power generation assets near our growing Western Hainesville area that can power potential data center customers. We believe our location, which is 100 miles from the Dallas Metroplex, is an ideal site with natural gas, water, and electrical grid infrastructure resources that could support data center development. I will now turn it over to Roland to discuss the financial results we reported yesterday. Roland?

Yeah, thanks, Jay. On slide four, we covered the second quarter financial results. Our production in the second quarter averaged 1.23 PCFE per day, which is 14% lower than the second quarter of 2025. reflecting our decision to drop rigs in early 2024 and our deferral of completion activity last year into this year. With the improvement in natural gas prices, our oil and gas sales in the quarter increased 24% to $344 million in the second quarter of this year, despite the lower production. EBITDAX for the quarter was $260 million, and we generated $210 million of cash flow in the quarter. As Jay said, we reported adjusted net income of $40 million for the second quarter, or 13 cents per diluted share, compared to a loss in the second quarter of 2024. Slide five is the financial results for the first half of this year. Production averaged 1.26 BCFE per day in the first six months of the year, 15% lower than the same period in 2024. And our oil and gas sales in the first six months of this year increased 22% to $749 million. EBITDAX in the first six months was $553 million, and we generated $449 million of cash flow. For the first half of this year, our adjusted net income is $94 million, or 32 cents per diluted share, as compared to loss in the same period of 2024. Slide six breaks down our natural gas price realizations for the year and the quarter. Our quarterly NYMEX settlement price for the second quarter averaged $3.44. However, the average Henry Hub spot price in the second quarter averaged a much lower $3.16. So 32% of our gas is sold in the spot market. So the appropriate NYMEX kind of reference price for our for our activity was about $3.35 for the second quarter. Our realized gas price for the same quarter was $3.02, reflecting a 42-cent basis differential compared to the NYMEX settlement price and a 33-cent differential compared to the reference price. We were 56% hedged in the second quarter, so that improved our realized price to $3.06. and we earned a $4.4 million profit from third-party marketing activity, which improved our realized price to $3.10. Slide seven, we detail our operating costs per MCFE and our EBITDAX margin. Our operating costs per MCFE averaged 80 cents in the second quarter, three cents lower than the first quarter rate, and four cents lower than the second quarter of 2024. Our EBITDAX margin was 74, percent in the second quarter compared to 76 percent in the first quarter production and ad valorem taxes were down one cent from the first quarter rate due to lower natural gas prices and our lifting costs improved by two cents in the quarter gathering and gna costs remained unchanged in the second quarter compared to the first quarter slide eight we recap our spending on drilling and other development activity we spent 268 million dollars development activity in the second quarter. And for the first six months this year, we've now drilled 16 wells or 14.5 net wells. And those are in it that target the Hainesville Shale. And then we've also drilled another three gross wells or three net wells that target the Bossier Shale for a total of 19 wells drilled so far this year. We turned 24 or 25 0.3 net operated wells to sales, which had an average IP rate of 27 million cubic feet per day. On slide nine, we recap what our balance sheet looks like at the end of the second quarter. We ended the quarter with $475 million of borrowings outstanding under our credit facility, having paid down $35 million during the second quarter. Our borrowing base is $2 billion under the credit facility, And the elected commitment still is $1.5 billion. Our last 12-month leverage ratio has improved just to three times and will continue to improve as we get away from the 2024 results, which are weighed down by low natural gas prices. At the end of the second quarter, we had approximately $1.1 billion of liquidity. And I'll turn it over to Dan to discuss the drilling and operating results. Okay. Thanks, Roland.

On slide 10 here is just an overview of our latest acreage footprint in the Hainesville-Bossier in East Texas and North Louisiana. We now have 1,105,000 gross and 826,741 net acres that are prospective for commercial development of the Hainesville-Bossier shales. Over on the left is our western Hainesville western Hainesville acreage footprint, which we have grown to nearly 525,000 net acres. And over on the right are 302,000 net acres in our legacy Hainesville area. We have 23, 24 wells currently producing on our western Hainesville acreage, which is virtually undeveloped compared to our legacy Hainesville area. With the high pay thickness and pressures we encounter in the Western Hainesville, we expect the Western Hainesville will yield significantly more resource potential per section than our legacy Hainesville. On slide 11 outlines our new development plan utilizing the horseshoe lateral concept. The horseshoe well design concept combines two separate and adjacent shorter laterals into a longer single lateral which results in a much more efficient use of capital. We realized 35% savings in our drilling costs when drilling a 10K lateral horseshoe wells compared to a 5,000 foot sectional lateral well. Our drilling inventory in the legacy Hainesville now includes 149 horseshoe locations. We completed our first horseshoe well last year, the Sebastian 11 number five. It had a 9,382 foot lateral and we had an IP rate of 31 million cubic feet per day. To date, this year, we've drilled two additional horseshoe wells. So in 2025, we plan to drill a total of nine horseshoe wells, and we will drill 10 horseshoe wells in 2026. On slide 12 is our updated drilling inventory at the end of the second quarter. Our total operated inventory consists of 1,538 gross locations and 1,222 net locations. which equates to a working interest of approximately 80%. Our non-operated inventory has 1,125 gross locations and 137 net locations, and this represents an average 12% working interest. The drilling inventory is split between the Hainesville and Bossier. Our drilling inventory is comprised of short laterals less than 5,000. Our medium laterals are between 5 and 8,500 foot. long laterals between 8,500 foot and 10,000 foot and our extra long laterals over 10,000 foot. Our gross operated inventory, we have 42 short laterals, 318 medium laterals, 573 long laterals and 605 extra long laterals. The gross operated inventory is evenly split with 50% in the Hainesville and 50% in the Bossier. Over 75% of the gross operating inventory consists of laterals greater than 8,500 feet. Our drilling inventory includes the 149 horseshoe locations, which are also split half and half between the Hainesville and the Bossier. The average lateral length in the inventory is now up to 9,686 feet. This is up 85 feet from the end of the first quarter. So, this inventory provides us with over 30 years of future drilling locations based on our current activity level. On slide 13, as a chart outlining the average lateral length drilled, this is based on the wells that we have drilled to TD. The average lateral lengths are shown separately for our legacy Hainesville area and our western Hainesville area. In the second quarter, we drilled eight wells to total depth in the legacy Hainesville and these had an average lateral length of 11,705 feet. The individual laterals ranged from 7,782 feet up to 15,190 feet. Our record long laterals on our legacy Hainesville acreage still stands at 17,409 feet. In the second quarter, we drilled four wells to total depth in the western Hainesville. and these wells had an average lateral length of 7,933 feet. The individual lengths ranged from 6,708 feet up to 8,836 feet. Our longest lateral drill to date in the Western Hainesville still stands at 12,763 feet. To date, we've drilled 122 wells with laterals longer than 10,000 feet, and we've drilled 47 wells with laterals longer than 14,000 feet. Slide 14 outlines the wells that were turned to cells on our legacy Hainesville acreage this year. So far for the year, we've turned 21 wells to cells on our legacy Hainesville acreage. The individual IPs for these wells range from 16 million a day up to 37 million a day, and our average IP was 25 million a day. The average lateral length for these wells was 11,803 feet and the individual lateral springs from 9,252 feet up to 17,409 feet. And four of our eight rigs that we have currently running are drilling on our legacy Hainesville acreage. Slide 15 outlines the five wells that have been turned to cells on our western Hainesville acreage this year. We discussed the 24-mile step-out well, the Olajuwon No. 1H, during our last quarter's conference call. Since we last reported earnings, we've turned four additional wells to sales. These four wells had an average driver length of 11,044 feet and an average initial production rate of 35 million cubic feet a day. And four of our eight rigs are currently drilling on our western Hainesville acreage. Slide 16 highlights the average drilling days and our average footage drilled per day in the legacy Hainesville area. In the second quarter, we drilled eight wells to total depth in the legacy Hainesville, and we averaged 28 days to total depth. This is two days slower than the prior quarter. In the second quarter, we averaged 921 feet per day on our legacy Hainesville. This is a 10% decrease versus the first quarter. of 2025 and a 7% decrease versus our 2024 full-year average of 987 feet drilled per day. Now the additional drilling days and the lower daily footage that we had drilled in the second quarter compared to the first quarter were really the result of two wells in our East Texas area that experienced some drilling difficulties associated with some highly over-pressured SWD zones. The best well drilled today on our legacy Hainesville acreage averaged 1,461 feet per day, and we drilled that well to TD in 14 days. Slide 17 highlights our drilling progress in the western Hainesville. During the second quarter, we drilled four wells to total depth in the western Hainesville. This now gives us a total of 29 wells that we drilled the total depth through the end of the second quarter. Since we split our initial well in the fourth quarter of 21, we have seen significant improvement in our drilling times. Our first three wells drilled in 2022 averaged 95 days to reach TD. Our average drilling time dropped to 70 days in 2023 and dropped again to 59 days for the full, for the 2024 full year average. In the second quarter, we averaged 58 drilling days for the four wells that we drilled the total depth. This is a decrease of one day compared to the 2024 full-year average, but reflects an increase of three days compared to the first quarter. And the increase in the drilling days compared to the first quarter can really be attributed to two things. The first one being one of our wells in the second quarter had to be sidetracked up in the vertical due to a downhole motor that we had come apart And secondly, all four of the wells drilled in the second quarter were over 1,500 feet deeper vertically than the wells we drilled in the first quarter. The additional drilling days in the second quarter is also a reflection of the lower footage drilled per day. Our fastest well drill to date in the Western Hainesville still stands at 37 days, and that well had a 12,045 foot lateral. Slide 18 is a summary of our DMC costs through the second quarter for our benchmark long lateral wells that are located in our legacy Hainesville area. These costs reflect all our legacy area wells that had laterals greater than 8,500 feet. The drilling costs are based on when the wells reached TD, and our completion costs that we show here are based on when the wells returned to sales. So during the second quarter, we drilled seven of our benchmark long lateral wells to total depth. The second quarter drilling cost averaged $696 a foot, which is a 33% increase compared to the first quarter. Like I mentioned earlier on our second quarter drilling efficiency, we incurred some additional drilling costs on a couple of our East Texas wells in the second quarter. due to drilling difficulties that were associated with the localized, highly overpressured SWD zones. During the second quarter, we also turned eight wells to sales on our legacy Hainesville acreage. The second quarter completion cost came in at $724 a foot. This represents a 15% decrease compared to the first quarter. And the lower completion costs in the second quarter were partially driven by lower frac costs that we had associated with lower fuel costs. And so we did have more of our fracs in the second quarter that utilized a higher percentage of natural gas for fuel. We also experienced much better efficiency drilling out frac plugs in the second quarter. We currently have the four rigs running on the legacy Hainesville acreage, and as we look ahead, we believe our D&C cost will remain relatively flat to slightly lower for the remainder of the year. Slide 19 is a summary of our D&C cost through the second quarter for all the wells drilled in the western Hainesville, on the western Hainesville acreage. During the second quarter, we drilled four wells to total depth. These had an average lateral length of 7,933 feet. The second quarter drilling cost averaged $1,875 a foot, which represents a 36% increase compared to the first quarter. The dominant driver for the higher drilling cost in the second quarter was the shorter laterals. Our average lateral length in the second quarter was 7,933 feet. And this compares to an average lateral length of 10,728 feet for the wells we TD'd in the first quarter. We do plan on targeting much longer laterals in the western Hainesville as we go forward. Also, one of our four wells drilled during the second quarter had to be sidetracked in the vertical downhole due to a motor that came apart. During the second quarter, we also turned six wells to sales on our western Hainesville acreage that had an average lateral length of 10,445 feet. We did not turn any wells to sales in the first quarter. The second quarter completion cost averaged $1,305 a foot. This is a 1% decrease compared to the fourth quarter of 2024. Our frack crews have continued to execute with very good efficiency. And during the second quarter, all but one of our six wells that we turned to sales were fracked using a blended fuel of natural gas and diesel. We do currently have four of our rigs running in the Western Hainesville. We also have two full-time dedicated fracked fleets, and both of these fleets do have the ability to run off a blend of natural gas and diesel. So now I'll turn the call back over to Jay.

Thank you, Dan. Thank you, Roland. If you would, please refer to slide 20 where we summarize our outlook for 2025. In 2025, we remain primarily focused on building our great asset in the western Hainesville that will position us to benefit from the longer-term growth in natural gas demand. We currently have four operated rigs drilling in the western Hainesville and continue to delineate the new plates. We expect to drill 19 or 18.9 net wells and turn 13 net wells to sales in Western Hainesville this year. We'll continue to build out our Western Hainesville midstream assets to keep up with the growing production from the area. Our new Marquette gas treating plant started operations this month, which more than doubled our gas trading capacity. In the legacy Hainesville, we're currently running four rigs to build production back up for 2026. We expect to drill 32 or 24 net wells and turn 32 or 26.8 net wells to sales in the legacy Hainesville this year. Given the tremendous interest in acquiring properties in the Hainesville, we currently plan to divest certain non-core properties during 2025, which will allow us to accelerate deleveraging of our balance sheet. We continue to have the industry's lowest producing cost structure and expect drilling efficiencies to continue to work toward driving down drilling and completion costs in 2025 in both the western and legacy Hainesville areas. With strong financial liquidity, as Roland reported, totaling almost $1.1 billion. We now have a few slides that show some guidance for the rest of the year, so please reach out to Ron if you want to discuss those slides. All right, Liz, we can go and open up to Q&A.

As a reminder, if you'd like to ask a question at this time, please press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 again. Our first question comes from a line of Carlos Escalante with Wolf Research.

Hey, good morning, team. Thank you for taking my question. I guess I'll start out by asking a question on the western Haynesville, particularly on the step out to the northwest, which you point out in your map. This well seems to be a relative step out from your current PDP, and it seems to us like it's another positive confirmation of initial reservoir pressure and therefore productivity. Now, it also looks like through state data that it might be a shallower well, and so I think we should expect some cooler bottom hole temperatures when you're drilling those wells. All that to say is, to say if you can perhaps walk us through what your key takeaways and learnings from drilling on that specific area have been. and obviously what it means for your underlying capital welfare cost trend.

Well, and Dan, that's the Elijah one to the north, and you drop down to the Bellmire, and then to the left is the Jennings and then the Milne.

Yeah, that'd be correct. And I think, Carlos, I think the well you're, when you say to the northwest, I think that's, if I'm just looking at the map here, that's probably our Jennings well. We drilled a two-well pad up there. And that well was shallower, definitely on the shallower part of the acreage versus some of these other ones we drill. And, you know, Jay mentioned it earlier, you know, in his opening remarks, you know, just the TBD depth ranges. And so that particular well is the 14,000 foot bookend to those, you know, he gave you 14,000 to 19,200. That's the 14,000 foot TBD well. uh significantly you know it's also our record fastest well that we drilled at 37 days to td so it does make a big difference on where you're drilling on the acreage on you know the number of drilling days and also the cost that that well was uh also our cheapest you know cheapest fastest uh significantly cheaper really so you know we've got a pretty good range here of depths temperatures drilling costs you know across the acreage. So, yeah, just kind of point that out.

We had to tube up some of the wells that were deeper, hotter. So, Dan, you may talk about not having to tube some of these wells up.

So, we have, just due to the pressures on the initial wells we drilled, of course, were extremely high pressures. Everything that we flow up in the core, we just flow the wells up the casing. We tube them up at a later date. We didn't do that down here just because of the extremely high shut-in pressures, flowing pressures. We didn't want to be flowing at those kind of pressures up the production casing. But when you get up in this area where these Jennings wells are, because they are shallower and we do have a little bit less pressure, we're comfortable flowing those up the casing. We did run tubing in those, but In the future, wells above, you know, we kind of are looking at a cutoff in depth. Those are definitely above it. We'll flow those wells or the wells in that depth range up the casing in the future, and that'll drop our cost probably at least another $150 a foot. So I think had we not run tubing in that well, I think we'd have been looking at a sub $2,000 per foot well cost.

Well, I think another comment on the Elijah 1, you know, we completed it a little different than we did the other wells. But we came down to the Bellmire, which is 30 miles away, really about 33 miles away from the Elijah 1. And we completed it the same way that we completed the Elijah 1. And both of those, as we reported, they're some of the two best wells you've ever drilled. We did tweak the completions. And I think that's the whole focus on the program is We think we've captured our 525,000 net acres. We've captured our reserve pool. Now what we're doing, which is what your question is, every 90 days we're reporting on how we're tweaking this to de-risk it to create this tremendous value for what? For the natural gas that's needed for LNG data, industrial demand, et cetera. And then the MIM well is a little different well. You may want to talk about that, Dan.

Yeah, the men well was also one that we tweaked. And when Jay says we tweaked the completions, we just tightened up our stage spacing a little bit, which just gives us a little bit more intensity. Basically, we're fracking in just over shorter distance. The men well was also in a well in our shallower acreage, kind of similar to the Jennings. The production looks fantastic on it. It's only been on for probably couple of months now, but you know, low D and C costs, good results. We've had the Elijah one, the Bellmeyer, and the MEN are really the three that we've probably tweaked the most on the completions with the tighter stage spacing.

Well, it's 38 million a day IP at a shallower depth.

Yeah, and looking at our just, even though they haven't been on long, when we look at the initial production rates and we look at the pressure decline,

just over that little short period those those three wells do are three of our best looking wells terrific very helpful color guys um i guess taking a step back now and looking at it from a more general perspective um considering that you you started the year out guiding for 17 tills in the western hansville um and you know due to unforeseen issues we're down to 13 What are the ramifications of this to your 2027 target of HBPing all your leases through 70 wells? Is that pushed to the right? And also, it's a 1B question. What is the run rate for tails in the western hand zone?

Yeah, go ahead. I mean, I don't know the number right off the top of my head, but I'm going to say it's not a big... It's really not a big mover. I mean, we've got, obviously our drilling speeds are getting faster, so that's pulling wells forward. We have the one well that has the midstream issue that we're waiting to get it connected. And then, of course, we've drilled two pilot holes also. So that pushes the dates back a little bit. But overall, in general, like you asked, in the general sense, it's not really pushing any of these wells back.

No, I think that's more of a function of these wells could have come on in December and now they're forecast to be January. You're talking about a month or so kind of delay as far as how they fall this year, which could change again based on... Midstream issues, a little bit more randomness in that as far as if some of them are going to be delayed, but

Overall, our drilling times, in the greater sense and over a longer term, our drilling times is what's going to really drive those cadence of those numbers.

Our next question comes from a line of Derek Whitfield with Texas Capital.

Good morning, all, and thanks for your time.

Morning. Good morning.

So similarly, kind of taking a step back and looking at the Western Hainesville more holistically, you guys have had considerable exploration and donation success and have drastically improved the commerciality of the plate with limited missteps to date. To be clear, again, for the benefit of investors, the increase in capital allocation to the legacy Hainesville is in no way an indication of change in relative value of the Western Hainesville and was part of a broader initiative to return the legacy play to maintenance levels of spending in a more concerted gas environment. Do I have that part right?

Yes. You know what? I didn't even think about that. When you brought that up, I mean, we didn't add a rig in the legacy area because we have any doubts about the Western Angel at all. In fact, you're the very first person I've ever heard say that, so I'm kind of shocked at that. But I guess that's a common sense question. But no, no, what we did is we said – The strength of our legacy allowed us to want to drill the Circle M well, even in 2021, 2022. And then, you know, when prices shot up in 23, you know, most of the acreage that we acquired in Western Ainsville was from free cash flow because prices were high. But what got the Joneses and the shareholders in the game initially was, was the value and the predictability of our legacy acreage. And so when you start cutting the rig back from nine to eight to seven to six, five to four to three, then the predictability of our growth is not there. So you've gotta go ahead and add another rig and then the core, which is the legacy, in order just to offset some of the risks that you may have and delays that you may have as while we de-risk this giant footprint in the Western Hainesville. So Derek, in no way at all does it imply that we pulled anything back as far as the attitude about the Western Hainesville at all. I mean, that is a great question, but it never even came into my mind ever. I mean, like ever.

And I would add that it more reflects the fact that, you know, drilling and completion costs are down and, we can add this rig and stay in our original budget. And the availability of those services is with the lower oil prices. And it also reflects kind of our decision to sell some non-core properties. And so this is getting kind of prepared to replace that production. And it also reflects kind of the excitement about the horseshoe wells and the ability to kind of add a lot of those to the schedule. you know, which are going to be in the legacy Hainesville. So it kind of, it's probably more reflects opportunity that we see in those areas versus, you know, any doubts about, you know, putting the capital in the western Hainesville.

Yeah, I would say, again, 50% of our gas is hedged for 25, same in 26. That's risk adjustment. We've added a lot of horseshoe wells, 149, and we said, okay, we want to increase our budget to in 2025 if we add this rig to drill wells, and mainly it's to drill horseshoe wells. And you saw the economics are incredible. So those are all new in the last year, that 149 list. So we just said, why don't we soften up the development of the Western Angle? Because like we said, it's exploration, exploitation, but we're scattered out, we're drilling 80 miles to the north and south and 20, 30 miles to the east and west because we're so comfortable with what we think we're finding and what we've found. And at the same time, you know, when the geological group says we need to core some wells, well, it does cost some time and money. We said, okay, well, let's core all those wells. And then, you know, we plan on really drilling one more pilot hole in Cornish near the Elijah one maybe this year. So you work that in the numbers too. And that gives you a little bit more time to tie geologically everything together. But no, no, no. If anything, we have never, ever been more encouraged about what we're sitting on in the Western Hainesville period. And as I was talking to the Joneses today, he said, you need to broadcast for sure. We're not ever, right now in the foreseeable future, even thinking about issuing equity to grow this stuff at all, period. In other words, That'd be another question that might be out there. We're going to divest some non-core assets. We're going to use those dollars to pay down our debt. We'll deliver that way for a while, and then we'll let Dan and the group drill and complete these western hand for wells with the big land grab, Derek, being behind us. Now, we do have probably $25 million or $30 million budgeted for land in 2025, but Some of that's in the core. Some of it's just a cleanup in the Western Hainesville. But that's where we're going. And it is a different story, but it's such an incredible story. So great question.

Understood. It makes complete sense. And as my follow-up, I wanted to see if you could offer some perspective on what you're seeing in the Western Hainesville that's leading you down the path of testing restricted check management. I know it's been part of a broader optimization process in all plays. But I imagine there's a specific reason as to why you guys are approaching that in the second half from a testing perspective, based on whether it's your data or competitive data, but some data.

Right, that's a good question. And so we are, you know, one of the things we knew kind of early on coming into this play was obviously it's deep and it's hot. And just if you look across the acreage up in the core of the play, you know, you can see that when you get in the deeper parts of the core, you know, you need to probably be a little bit more disciplined on how you draw the wells down. So down here, we're at the very, you know, end of that scale as far as with the depths and the pressures that we have. And so I think, you know, pressure-dependent PARM, what we've seen on the wells is that we float our wells in a lot of different ways. We've got wells kind of all the way across the board trying to kind of see what works. And what we see is if, you know, a little bit more of a decline in year one, just basically choking them back, which is part of the reason our production is low, is this was just self-imposed. You know, we've gotten more aggressive at choking the wells back, trying to maintain a real disciplined drawdown. And so that's, you know, and the results we see, and when we model it out, and we do look at competitor wells, you know, state data, leads you to think that you should get a little better EURs, you know, if you flow them at basically more conservative rates. And I do believe that. You just got to find the right balance, you know, as far as when you're modeling the economics for return and payout versus, you know, the long-term value in the PV10s. And that's just what we're working through right now.

And I think, Derek, that's one reason we came up and adjusted the production. In other words, we said whatever we see every 90 days, we're going to tell you. We're gonna tell you, then we're gonna adjust it accordingly. And that's just what it's telling us to do. And it's like Dan said, if you can choke it back a little bit more and have a much higher EUR, and the IRR looks fantastic, and the payout looks good, et cetera, and you've got this inventory on 525,000 net acres, then that's how we wanna manage it. It is managing, like we said, It's taken care of today, but it's also managing for long term.

Our next question comes from Kalei Akamain with Bank of America.

Hey, good morning, guys. Jay Rowland. Good morning. My first question, good morning. I want to ask you about the non-core sales effort here. Can you talk a little bit about how you think about sizing a sale? i.e., do you intend to minimize the associated PDP? I would imagine that you'd want to keep that because that's gas torque, and if gas prices go up, then that's your pathway to deleveraging. And then on top of that, are there any metrics that you can point to to help us understand the value of locations in this market?

Yeah, that's a good question. I mean, I think that we are looking to – there's an opportunity, I think, in this market, in our basin, you know, to – you know, where before, I think the last several years until this year, you know, basically the market was really around selling PDP and, you know, out there, those are the type buyers that dominated the acquisition space. And it's changed a lot this year. There's a lot of interest in our basin and new players coming in that are very interested in drilling locations. And, you know, with a higher gas price, you know, some, some lowered, lower return projects in the Hainesville now become very attractive and make a lot of money for folks. So, you know, we have a very deep inventory in the legacy Hainesville and some of it we just, you know, in our particular circumstance for the next 10 years, we just can't get to any of that. And so selling off some of that inventory that we view that we would not develop, you know, anytime soon, you know, can add a lot of, NPV value to the company because we'd create value out of it. So, yeah, I think we're focused on more of that than really selling a lot of, you know, production or, you know, approved producing reserves.

Well, and remember, as we de-risked the Western Angel, we had inventory. In other words, if we thought that we wouldn't potentially be adding material inventory in the Western Angel, we wouldn't be looking at divesting anything in our legacy. But If you look at the legacy and you say you have 30, 40 years of inventory and the market tells you that there's a demand for some drilling inventory and they win and we win, if we sell and they buy, then we should take a hard look at it if it makes Comstock a much better company and it launches somebody else into the area, and mainly for LNG demand.

got it i appreciate that for my second question i'm hoping that you can talk about your coring program and what you're attempting to learn here our our kind of base case for the western hayesville is basically 3 000 locations across three fairways each with a different number of drilling horizons does that kind of align with how you guys see it and will this program help confirm that case yes i think i think you're kind of spot on there so we have

Of course, there's two reasons to drill pilot holes out here for us. We've got some tentative plans on where we want to drill our pilot holes across the entire footprint right now. Those will probably move around a little bit for various reasons. In some areas, we just need to drill a pilot hole just to get the logs, just because we don't have any kind of well control. in that area and we need it to be able to steer our lateral and know, you know, know where we're landing it in the zone. And then, you know, secondary reason is, you know, basically to cut cores and, you know, and do all of that science work. Get our, you know, TOCs and, you know, basically let that help you back into kind of what an original gas in place number looks like. And also to basically just get all of the mechanical properties and maybe we can Maybe it'll help us make some tweaks to our completions.

Now, I would comment that, remember, 80% of the Western Hainesville is HPP'd, and some of the cores that we would probably drill would be in the HPP'd acreage. Now, the first ones will be in the acreage that we need to drill to continue to hold. But even if you look at the Elijah one, you've got a really good company. that's a Japanese company that's filled a well there. They're completing their well now, I believe, with the same frack crew we use to complete our wells. But we would still like to core a well closer to that Elijah one. And we do have a 3D chute in that area. That's the only area that we think we need to have a little bit more seismic work done. So we've implemented that program too. So this is proactive work. Now, it costs money to do that. And that is all in our budget, too. And that goes back to, you know, we didn't grow through M&A. We're growing. We own our asset base. We're just de-risking it, improving it up. And as you do that, to your first question, if there's something over in the legacy that you won't drill for a long time, that's good, and you can get top dollar for it, and both the buyer and the seller win, then we should be shuffling that around, too, and protect our balance sheet That's exactly what we're doing.

Our next question comes from Phillips Johnston with Capital One.

Hey, thanks for the time. I wanted to ask a follow-up question on the non-core asset sale program. Can you maybe just give us a sense of what sort of order of magnitude we're talking about in terms of potential proceeds? And also, would you expect any sort of tax leakage on those sales?

No, we really don't go into the details on what the divestiture would look like.

Yeah, I think next quarter hopefully we'll be able to kind of provide that, you know, so we have an ongoing process, and so we just don't think that's helpful to the process. Okay. We don't believe on the tax side, though, that there's any significant, you know, tax liability. Matter of fact, the passage of the one big beautiful bill is very – supportive of our situation and ability to use, you know, have future deductions for things like interest, et cetera. But that's actually going to be a real positive benefit, I think, on our tax rates going forward, and especially the third quarter when that was adopted, you know, making adjustments to that. But I think we see that all very positive and probably positive reducing the future tax liability that we might have seen before the bill was passed.

Okay, good. And then your implied capex guidance for the second half of the year, it's relatively flat versus the first half of the year. And that's despite your rate count going to eight here in the back half of the year from seven in Q2 and something a little less than seven on average in Q1. And despite, I guess, the outlook for 32 wells drilled in the second half versus 19 in the first half. So what gives you guys confidence that CapEx won't increase in the second half of the year?

I think, you know, if you look at where we're at really today, just in the second quarter versus end of the last year, you know, our DNC costs are down probably on the order of 10% or so in that neighborhood. A lot of that is the pipe prices. You know, we started seeing significant savings in our pipe prices, mainly in the first quarter. We got a little bit in the fourth quarter. So, you know, as long as those, you know, hopefully the tariff issues don't send that the other way, but, you know, as long as that continues, that's a big piece of that lower cost for the remainder of the year. And then, you know, the rest of it's just basically spread out, you know, on vendor costs. The costs are just down a little bit. I think some of that may be, you know, the The slowdown in the Permian with the lower oil prices and just the fact that the rigs haven't really just exploded and taken off on the gas side. So we just see it across all the services.

There's also the cadence of completions. And so when that actually occurs and what period is also a big factor, more so than when the wells are drilling. So I think that's actually probably a little bit less activity completion activity in the second half of the year than was in the first budget.

Our next question comes from Charles Mead with Johnson Rice.

Good morning, Jay, Roland, and Dan, and the whole contact team there. Hello, Charles. Jay, I believe you have talked in the past that you guys on the Elijah Juan Pickens Well that you guys had a little bit of a different completion design there. And I wonder if you could give us an update on how that well is performing with that different completion design, and if you've used that sort of design subsequently in any of these more recent wells.

Hey, Charles. Yes, we have. The Elijah one was the first well that we made the tweak on. And basically, we just went from 150 foot to 100 foot stages. you know we see on a lot of these wells especially the deeper ones in this range we are typically not quite at our frac design rate when we start out and so just to basically uh address that we decided to go to tighter stages and we basically carried it out for the entire lateral on the elijah one we wanted that to be you know we didn't want to have a mixed bag along the lateral how we completed it so the entire lateral was completed with 100 foot stages We've done really two other wells since then, the Mann 1H and the Bellmire, and I think it is making a difference. It's early, we've only had the Elage one on for about three and a half months, but it's still flowing at just a hair under the 27 million starting rate that we set it on, and the pressure drop per day looks really, really good. So we're very encouraged by it, I think we'll be going more in that direction.

Got it. Thank you for that detail. And then, Roland, I get that for good reasons, you're a little reticent to talk about the divestiture program, but I'm curious, when I look at your acreage map, to me, the most obvious sale for CompSec, you guys being really deep in inventory with the rest of the industry, at least in the Haynesville area, really short on inventory, it would be in that, that Angelina river trend. Is that, is that a reasonable inference or is that, is that not direction you're going?

No, that's a reasonable. I think for Einstein, that's a good guess. Right. That's a reasonable look, you know, and it's, you can also, it's an area that, you know, we just haven't been active in and, but is active, you know, in the industry. So, so yeah, yeah. And hopefully we'll, we'll have a, A good view of that at our next report and we're kind of really hoping that that really lets us, you know, accelerate, you know, our deleveraging goals, you know, this year while still being able to invest in, you know, into Western Hainesville.

Our next question comes from Noel Parks with Tuohy Brothers Investment Research.

Oh, you may be on mute.

Our next question comes from Paul Diamond with Citi.

Thank you. Good morning. Thanks for taking the call. Just wanted to touch a bit on the Horseshoe Whale Program. I know you guys have talked about 10 this year, 10 next. I just want to get an understanding of how... is what would cause you to move off that? Like, if you started to see better results, could you lean in? Worse results, could you lean out? Just kind of how to think about your, you know, high-level strategy there.

So, Paul, I think we're encouraged, excited about the horsey wells. We've, you know, had, we've put our first one on last year. You know, we essentially see it as no different than a 10k straight well. I mean, A lot of our horseshoe wells that we have in the inventory are still in some of our better type curve areas than just our regular straight wells that we're drilling. So that's one big thing that we like about them. We've drilled three to date. We just TD'd our third one here probably just last week. We've had zero problems drilling them. I've said before, Add maybe two days to a 10,000 foot straight well, just add two days to bend it around and make it a horseshoe. Just zero issues drilling, zero issues completing that first one. We'll complete these next ones here probably over this next quarter. So really, there's nothing we don't like about them right now.

Understood. Appreciate the clarity. Just a quick follow-up. So you announced the NextEra agreement. I just want to get an understanding of how you guys are thinking about potential scale, structures, duration, timing, if any of that is kind of on the books yet, or is it still just an agreement to kind of look and do it together?

Well, you know, we've done business with NextEra for at least 10 years, and we've got a big footprint, and most of our Western Angels are undedicated. It is 100 miles away from both Houston and the Dallas Metroplex. So, you know, if we can collaborate, which we've done this, you know, in agreement with the largest natural gas plate in the United States next year, you know, it does bring experience in power generation development and operating natural gas power generation facilities in what we think is an area that will need some data centers. So, we've been working with them for months and months and months. We said, well, let's just see if we can't go forward on this. So we don't go into any more details about customers, but we do think that we have a really good site for a data center near the Western Hainesville area. And I don't think we could pick a better partner.

Our next question comes from Jacob Roberts with Tudor Pickering Holt.

Good morning. Morning. I wanted to, when we look at 2026, I think at current short prices, we'd see you guys in $100 to $150 million of free cash flow next year. Just curious, if pricing were to return to $375, can you give us your thoughts on potentially outspending cash flow to execute growth? And is there a price where we might see you guys reduce activity like we have in the past? And I apologize for the long question. But I'm wondering if that relative capital allocation has changed given the development of the Western Hainesville over the last 18 months.

It's real early for us still to be talking about our 26th activity, which we haven't announced yet. But I think that we really like where the company is now with the balance program and both the legacy and the Western Hainesville activity. And we'll be reaping the benefit of the higher production from the money we're spending this year because it takes almost nine months really to get production when you kind of add a rig line. And so I don't think we'll see any case where we'd be outspending. So obviously we would adjust activity level. But yeah, we're very bullish about Now, 2026, we'll look for the company, you know, both ways. So, you know, but, yeah, we'll be setting our budget later this year. It's usually late, you know, late in the fall when we kind of gauge our activity. We have lots of flexibility in how we do that activity, especially in the, you know, obviously the core where we have a lot of well-to-well rig contracts so that, you know, we always have the ability to flex activity based on the outlook that we see. But, you know, we're still very... very bullish about 26 and what you see in the futures market and the demand we know that's coming on. And, you know, even with our direct talks about providing long-term supply to some of the really large users, you know, a lot of that is starting to crank into 26.

Okay. Thank you. And I wanted to circle back to some of the Koch management in the western Haynesville area. I'm just trying to understand, in terms of trying different things or experimenting different ways, how should we be thinking about the timeline on that well of data before you're able to make a decision as to what the optimal approach is? Is it, you know, you choke now and it's 14 months later that you're able to say this was good or bad? Just kind of any color around that would be great.

Well, that's a really good question on the timeline because it is a longer timeline because you definitely can't get quick answers. We've flowed them several different ways. We've been really aggressive on some. More of the whales of late. We've been very proactive as far as starting to choke them back and basically bring the rates back down a little bit. Just based on early modeling stuff we've done, we're definitely expecting you know, a little bit better EURs with the conservative drawdown. We haven't done one yet that's really conservative. You know, that's probably the next test that we're kind of looking at here in the near future is pulling one at, you know, a much lower rate straight out of the gate. And as far as the timeline to get that data, you know, I mean, you're probably talking a minimum of a year to get an idea. what it's going to do, and maybe even 18 months to two years to really start dialing in on an exact answer.

But you have your feedback of the drawdowns as you produce, so that's giving you clues, I guess, of are you on the right path.

Yeah. And there has been some other industry operators out there that have drilled a few wells and have some state data out there that's in our data set we're looking at. I think we're on the way to getting there, but it does, you do kind of have to wait and let them play out a little bit, see where they're headed.

That concludes today's question and answer session. I'd like to turn the call back to Jay Ellison for closing remarks.

Again, thank you for your hour plus time. I want to conclude it in that one week we and the Joneses in particular, but all of us, we want to protect the balance sheet. That's number one, number one, number one. And then, you know, I think that we can deliver this non-core asset sale if it's a win-win for us and for the buyer. We'll use those proceeds to deliver. Over and over and over, you know, we have never been more positive about the Western Hainesville. We just want you to know how we're managing it every 90 days. But we do have that 525,000 net acres, 80% of it's HPP, and we commit to you that we're managing it. At the same time, you know, NextEra comes in, and we're really excited to work with them on potential data center area. We want to grow our inventory. We're going to grow it organically, not with M&A. And when this LNG demand keeps growing and growing and growing, as other companies have said, the angel needs to supply most of that growth. And we want to be a big part of that. So, again, thank you for your patience. We always try to be very transparent with you and where we're going. And we'll report again in 90 days. Thank you.

This concludes today's conference call. Thank you for participating. You may now disconnect.