CRK - NYSE

Good day, and thank you for standing by. Welcome to the Comstock Resources Second Quarter 2025 Earnings Call. [Operator Instructions] 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 am 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 2 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 Haynesville. Today, our Western Haynesville 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 Haynesville shale and 14 from the Bossier Shale. The Western Haynesville 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 Haynesville and Bossier shales in this area are rich in organic content, very thick and have high pressure. This year, we have drilled 2 pilot holes, taken logs and hold course 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 Haynesville, we are 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 5 new Western Haynesville wells to sales. These wells include the Eliza 1 to the north and the Bell-Meyer 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 per completed lateral foot, which is substantially less than the wells we completed in the last 3 years. Over the last 3 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 Haynesville land position and derisking this new play. 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 Haynesville area, which still accounts for over 80% of our production. We now have 4 rigs working in our Legacy Haynesville area, which will allow us to stabilize production there as we grow the Western Haynesville. So far this year, we have turned 21 wells to sales 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 are 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 are 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 $0.71 per diluted share. Our adjusted net income for the quarter was $40 million or $0.13 per share. We're also excited to announce that we are 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 Haynesville 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?

Yes. Thanks, Jay. On Slide 4, we cover the second quarter financial results. Our production in the second quarter averaged 1.23 Bcfe 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 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 $0.13 per diluted share compared to a loss in the second quarter of 2024. Slide 5 is the financial results for the first half of this year. Production averaged 1.26 Bcfe per day in the first 6 months of the year, 15% lower than the same period in 2024. And our oil and gas sales in the first 6 months of this year increased 22% to $749 million. EBITDAX in the first 6 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 $0.32 per diluted share as compared to a loss in the same period of 2024. Slide 6 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 HubSpot price in the second quarter averaged to much lower at $3.16. So 32% of our gas is sold in the spot market. So the appropriate NYMEX kind of reference price for our activity was about $3.35 for the second quarter. Our realized gas price for the second quarter was $3.02, reflecting a $0.42 basis differential compared to the NYMEX settlement price and a $0.33 differential compared to the reference price. We were at 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 7, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.80 in the second quarter, $0.03 lower than the first quarter rate and $0.04 lower than the second quarter of 2024. Our EBITDAX margin was 74% in the second quarter compared to 76% in the first quarter. Production and Ad Valorem taxes were down $0.01 from the first quarter rate due to lower natural gas prices and our lifting costs improved by $0.02 in the quarter. Gathering and G&A costs remained unchanged in the second quarter compared to the first quarter. Slide 8, we recap our spending on drilling and other development activity. We spent $268 million development activity in the second quarter. And for the first 6 months of this year, we've now drilled 16 wells or 14.5 net wells. And those are in that target, the Haynesville Shale. And then we've also drilled another 3 gross wells or 3 net wells that target the Bossier Shale for a total of 19 wells drilled so far this year. We turned 24 or 20.3 net operated wells to sales, which had an average IP rate of 27 million cubic feet per day. On Slide 9, we recap our -- 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 our elected commitment still is $1.5 billion. Our last 12 months leverage ratio has improved to 3x 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. I'll now 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 Haynesville/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 Haynesville and Bossier shales. Over on the left is our Western Haynesville acreage footprint, which we have grown to nearly 525,000 net acres. And over on the right is our 302,000 net acres in our Legacy Haynesville area. We have 24 wells currently producing on our Western Haynesville acreage, which is virtually undeveloped compared to our Legacy Haynesville area. With the high pay thickness and pressures we encounter in the Western Haynesville, we expect the Western Haynesville will yield significantly more resource potential per section than our Legacy Haynesville. On Slide 11 outlines our new development plan, utilizing the horseshoe lateral concept. The horseshoe well design concept combines 2 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 10,000 lateral horseshoe wells compared to a 5,000-foot sectional lateral well. Our drilling inventory in the Legacy Haynesville now includes 149 horseshoe locations. We completed our first horseshoe well last year, the Sebastian 11 #5. 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 2 additional horseshoe wells. So in 2025, we plan to drill a total of 9 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 Haynesville and Bossier. Our drilling inventory is comprised of short laterals less than 5,000, our medium laterals are between 5,000 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 Haynesville and 50% in the Bossier. Over 75% of the gross operated 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 Haynesville 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 levels. On Slide 13, is 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 Haynesville area and our Western Haynesville area. In the second quarter, we drilled 8 wells to total depth in the Legacy Haynesville, 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 Haynesville acreage still stands at 17,409 feet. In the second quarter, we drilled 4 wells to total depth in the Western Haynesville, and these wells had an average lateral length of 7,933 feet. The individual lengths range from 6,708 feet up to 8,836 feet. Our longest lateral drilled to date in the Western Haynesville 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 returned to sales on our Legacy Haynesville acreage this year. So far for the year, we've turned 21 wells to sales on our Legacy Haynesville 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 laterals range from 9,252 feet up to 17,409 feet. And 4 of our 8 rigs that we have currently running are drilling on our Legacy Haynesville acreage. Slide 15 outlines the 5 wells that have been turned to sales on our Western Haynesville acreage this year. We discussed the 24-mile step-out well, the Olajuwon during our last quarter's conference call. Since we last reported earnings, we've turned 4 additional wells to sales. These 4 wells had an average lateral length of 11,044 feet and an average initial production rate of 35 million cubic feet a day. And 4 of our 8 rigs are currently drilling on our Western Haynesville acreage. Slide 16 highlights the average drilling days and our average footage drilled per day in the Legacy Haynesville area. In the second quarter, we drilled 8 wells to total depth in the Legacy Haynesville, and we averaged 28 days to total depth. This is 2 days slower than the prior quarter. In the second quarter, we averaged 921 feet per day on our Legacy Haynesville. 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. 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 2 wells in our East Texas area that experienced some drilling difficulties associated with some highly over-pressured SWD zones. The best well drilled to date on our Legacy Haynesville 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 Haynesville. During the second quarter, we drilled 4 wells to total depth in the Western Haynesville. This now gives us a total of 29 wells that we drilled to total depth through the end of the second quarter. Since we start our initial well in the fourth quarter of '21, we have seen significant improvement in our drilling times. Our first 3 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 4 wells that we drilled to total depth. This is a decrease of 1 day compared to the 2024 full year average, but reflects an increase of 3 days compared to the first quarter. And the increase in the drilling days compared to the first quarter can really be attributed to 2 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 4 of the wells drilled in the second quarter were over 1,500 foot 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 drilled to date in the Western Haynesville still stands at 37 days, and that well had a 12,045-foot lateral. Slide 18 is a summary of our D&C costs through the second quarter for our benchmark long lateral wells that are located in our Legacy Haynesville 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 are turned to sales. So during the second quarter, we drilled 7 of our benchmarked long lateral wells to total depth. The second quarter drilling costs 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 over-pressured SWD zones. During the second quarter, we also turned 8 wells to sales on our Legacy Haynesville acreage. The second quarter completion costs 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 4 rigs running on the Legacy Haynesville acreage, and as we look ahead, we believe our D&C costs will remain relatively flat to slightly lower for the remainder of the year. On Slide 19 is a summary of our D&C costs through the second quarter for all the wells drilled on our Western Haynesville acreage. During the second quarter, we drilled 4 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-ed in the first quarter. We do plan on targeting much longer laterals in the Western Haynesville as we go forward. Also, 1 of our 4 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 6 wells to sales on our Western Haynesville acreage that had an average lateral length of 10,445 feet. We did not turn any wells to sales in the first quarter. So second quarter completion cost averaged $1,305 a foot. This is a 1% decrease compared to the fourth quarter of 2024. Our frac crews have continued to execute with very good efficiency. And during the second quarter, all but 1 of our 6 wells that we turned to sales were frac using a blended fuel of natural gas and diesel. We do currently have 4 of our rigs running in the Western Haynesville. We also have 2 full-time dedicated frac 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 Haynesville that will position us to benefit from the longer-term growth in natural gas demand. We currently have 4 operating rigs drilling in the Western Haynesville and continue to delineate the new play. We expect to drill 19 or 18.9 net wells and turn 13 net wells to sales in the Western Haynesville this year. We'll continue to build out our Western Haynesville midstream assets to keep up with the growing production from the area. Our new Marquez gas treating plant started operations this month, which more than doubled our gas treating capacity. In the Legacy Haynesville, we are currently running 4 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 Haynesville this year. Given the tremendous interest in acquiring properties in the Haynesville, we currently plan to divest certain noncore 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 Haynesville areas. We've 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.

[Operator Instructions] Our first question comes from the line of Carlos Escalante with Wolfe Research.

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 shallow well, and so I think we should expect some cooler temperatures when you run 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 local cost trend?

Well, Dan, that's the Olajuwon to the north, you drop down to the Bell-Meyer margin, to the left is the Jennings and then the Menn.

Yes, that would be correct. And I think, Carl, 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 2-well pad up there. And that well --

That one, right there.

Yes, that well was shallower -- definitely on the shallower part of the acreage versus some of these other ones we drill. And Jay mentioned it earlier in his opening remarks, just the TVD depth ranges and so that particular well is the 14,000-foot bookend of those -- he gave you 14,000 to 19,200. That's the 14,000-foot TVD well. Significantly -- 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 the number of drilling days and also the cost. That well was also our cheapest, fastest, significantly cheaper really. So we've got a pretty good range here of depth, temperatures, drilling cost, across the acreage. So yes, just kind of point that out.

If you look ahead two blocks, some of the wells that were deeper, hotter. And so Dan, you may talk about not having to TD some of these wells.

So we have just due to the pressures on the initial wells we drilled, of course, are extremely high pressures. Everything that we flow up in the core flows -- 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, we kind of are looking at a cutoff depth. Those are definitely above it. We'll flow those -- those wells or the wells in that depth range up to casing in the future, and that will 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 Olajuwon, we completed it a little different than we did the other wells. But we came down to the Bell-Meyer, which is 30 miles away, really about 33 miles away from the Olajuwon, and we completed it the same way that we completed the Olajuwon. And both of those, as we reported, they're some of the 2 best wells we'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 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 derisk it to create this tremendous value for what? For the natural gas that's needed for LNG data, industrial demand, et cetera. So -- and then the Menn well is a little different well. You may want to talk about that, Dan.

Yes. The Menn well was also one that we tweaked and 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 Menn well was also a well in -- on 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 low D&C costs, good results. We've had, Jay mentioned, so we've had the Olajuwon, the Bell-Meyer and the Menn are really the 3 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.

Yes. 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 3 wells we do are 3 of our best-looking wells.

Terrific. Very helpful color, guys. I guess taking a step back now and looking at it from a more general perspective, considering that you started the year out guiding for 17 TILs in the Western Haynesville and due to unforeseen issues, we're down to 13. What are the ramifications of this to your 2027 target of HVP all your leases through 17 wells? Is that pushed to the right? And also the 1B question, what is the run rate for TILs in the Western Haynesville? Yes, go ahead.

I mean I'm not -- 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 number. 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 2 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.

Right.

As far as how they fall this year.

Yes. Correct.

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, I mean, 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 the line of Derrick Whitfield with Texas Capital.

So similarly, kind of taking a step back and looking at the Western Haynesville more holistically, you guys have had considerable exploration and delineation success and have drastically improved the commerciality of the play with limited missteps to date. To be clear, again, for the benefit of investors, the increase in capital allocation to the Legacy Haynesville is in no way an indication of change in relative value of the Western Haynesville, and was part of a broader initiative to return the Legacy play to maintenance levels of spending in a more constructive 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 Haynesville at all. In fact, you're the very first person I've ever heard say that. So I'm kind of shocked at that I guess that's a common sense question. But 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 when prices shot up in '23, most of the acreage that we acquired in Western Haynesville was from free cash flow because prices were high. But what got the Joneses and the shareholders in the game initially was the value and the predictability of our Legacy acreage. And so when you start cutting the rig back from 9 to 8 to 7, 6, 5, 4 to 3, then the predictability of our growth is not there. So you've got to go ahead and add another rig in the core, which is the Legacy, in order just to offset some of the risk that you may have and the delays that you may have as why we derisk this giant footprint in the Western Haynesville. So Derrick, in no way at all does it imply that we pulled anything back as far as the attitude about the Western Haynesville at all. That is a great question, but it never even came into my mind ever. I mean like ever.

I would add that it more reflects the fact that 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 noncore 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 schedule, which are going to be in the Legacy Haynesville. So it kind of -- it's probably more reflects opportunity that we see in those areas versus any doubts about splitting the capital in the Western Haynesville.

Yes. 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 in 2025 if we add this rig to drill wells and mainly is 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 Haynesville because like we said, it's exploration, exploitation, but we're going to -- 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 found. And at the same time, when the geological group says we need to core some wells, well, that does cost some time and money. We said, okay, well, let's core all those wells, and then we plan on really drilling one more pilot hole near the Olajuwon, 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, we -- if anything, we have never ever been more encouraged about what we're sitting on in the Western Haynesville, period. And as I was talking to the Jones 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 would be another question that might be out there. We're going to divest some noncore assets. We're going to use those dollars to pay down our debt. So we'll de-lever that way for a while. And then we'll let Dan and the group drill and complete these Western Haynesville wells with the big land grab, Derrick, being behind us. Now we do have probably $25 million or $30 million budgeted for land in 2025. Some of that's in the core, some of it's just a cleanup in the Western Haynesville. 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 Haynesville that's leading you down the path of testing restricted choke 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 -- 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 can see that when you get into the deeper parts of the core, 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 end of that scale as far as with the depths and the pressures that we have. And so I think pressure-dependent perm. What we've seen on the wells is that we -- and we flowed our wells in a lot of different ways. We got wells kind of all the way across the board, trying to see what works. And what we see is that a little bit more of a decline in year 1, just basically choking them back, which is part of the reason our production is low as this was just self-imposed. We've gotten more aggressive at choking the wells back, trying to maintain a real disciplined drawdown. And so that's in the results we see and when we model it out, and we do look at competitor wells, state data, lead you to think that you should get a little better EURs if you flow them at basically more conservative rates. And I do believe that. You just got to find the right balance as far as when you're modeling the economics for return and payout versus the long-term value in the PV-10s, and that's just what we're working through right now.

And I think, Derrick, 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 going to tell you that we're going to 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, and that's how we want to 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 Akamine with Bank of America.

I want to ask you about the noncore 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?

Yes, 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 and -- where before, I think the last several years until this year, basically, the market was really around selling PDP and 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 with a higher gas price, some lower return projects in the Haynesville now become very attractive and make a lot of money for folks. So we have a very deep inventory in the Legacy Haynesville and some of it we just -- 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 anytime soon, can add a lot of NPV value to the company because we create value out of it. So yes, I think we're focused on more of that than really selling a lot of production or proved producing reserves.

Well, and remember, as we derisk the Western Haynesville, we add inventory. In other words, if we thought that we wouldn't potentially be adding material inventory in the Western Haynesville, 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 lock in somebody else into the area and mainly for LNG demand.

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 kind of base case for the Western Haynesville is basically 3,000 locations across 3 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 you’re kind of spot on there. So we have -- of course, there's 2 reasons to drill pilot holes out here for us. We -- and we've got kind of 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. But we -- 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 where we're landing it in the zone. And then secondary reason is basically to cut cores and do all of that science work, get our TLCs and 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 will help us make some tweaks to our completions.

I would comment that remember, 80% of the Western Haynesville is HBP and some of the cores that we would probably drill would be in the HBP 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 Olajuwon, you've got a really good company that's a Japanese company that's drilling a well there, they're completing their well now, I believe, with the same frac crew we use to complete our wells, but we would still like to core a well closer to that Olajuwon. And we do have a 3D shoot 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 -- we didn't grow through M&A. We're growing -- we own our asset base. We're just derisking it and proving it up. And then 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.

I wanted to ask a follow-up question on the noncore 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.

Yes. I think next quarter, hopefully, we'll be able to kind of provide that. So we have an ongoing process, and so we just don't think that's helpful to the process. We don't believe on the tax side, though, that there's any significant tax liability. Matter of fact, the passage of the one big beautiful bill is very supportive of, especially, our situation and the ability to use, have future deductions for things like interest, et cetera. 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, making adjustments to that. But I think we see that all very positive and probably reducing the future tax level 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 rig count going to 8 here in the back half of the year from 7 in Q2 and something a little less than 7 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 if you look at where we're at really today and just in the second quarter versus end of last year, our D&C costs are down probably on the order of 10% or so in that neighborhood. A lot of that is the pipe prices. We started seeing significant savings in our pipe prices, mainly in the first quarter. We got a little bit in the fourth quarter. So as long as those --hopefully, the tariff issues don't send that the other way. But as long as that continues, that's a big piece of that, lower cost for the remainder of the year. And then the rest of it is just basically spread out on vendor costs, the costs are just down a little bit. I think some of that may be 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 of completion activity in the second half of the year than was in the first budget.

Our next question comes from Charles Meade with Johnson Rice.

Jay, I believe you have talked in the past that you guys -- on the Olajuwon 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?

Charles, yes, we have. The Olajuwon was the first well that we made the tweak on. And basically, we just went from 150-foot to 100-foot stages. 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 address that, we decided to go to tighter stages. And we basically carried it out for the entire lateral on the Olajuwon. We wanted that to be -- we didn't want to have a mixed bag along the lateral of how we completed it. So the entire lateral was completed with 100-foot stages. We've done really 2 other wells since then, the Menn 1H and the Bell-Meyer. And I think it is making a difference. It's early. We've only had the Olajuwon on for about 3.5 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.

And then Roland, on the -- 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 Comstock, you guys being really deep in inventory with the rest of the industry, at least in the Haynesville, really short on inventory, it would be in that Angelina River trend. Is that a reasonable inference? Or is that not the direction you're going?

No, that's a reasonable --

I think from Einstein, that's a good guess. Right.

That's a reasonable -- look, you could also -- it's a scenario that we just haven't been active in but is active in the industry. So yes, hopefully, we'll have a good view of that at our next report. And we're kind of really hoping that really lets us accelerate our deleveraging goals this year while still being able to invest in the Western Haynesville.

Our next question comes from Noel Parks with Tuohy Brothers Investment Research. Noel, you may be on mute. Our next question comes from Paul Diamond with Citi.

Just wanted to touch a bit on the Horseshoe well program. I know you guys have talked about 10 this year, 10 next. I just want to get an understanding of how -- what would cause you to move off that? Like have you started to see better results, could you lean in, worse results, could you lean out? Just kind of how to think about your -- how about the strategy there?

So Paul, I think we're encouraged, excited about the horseshoe wells. We've had -- we put our first one on last year. We essentially see it as no different than a 10,000 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 3 to date. We just TD-ed our third one here probably just last week. We've had 0 problems drilling them. I've said before, add maybe 2 days to a 10,000-foot straight well, just add 2 days to bend it around and make it a horseshoe. Just 0 issues drilling, 0 issues completing that first one. We'll complete these next ones here probably in the next -- over this next quarter. But so really, there's nothing we don't like about them right now.

And 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?

We've done business with NextEra for at least 10 years, and we've got a big footprint and most of our Western Haynesville is undedicated, and it is 100 miles away from both Houston and the Dallas Metroplex. So if we can collaborate, which we've done is in agreement, with the largest natural gas fleet in the United States, NextEra, 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. And we said, well, let's just see if we can go forward on this. So we don't go into any more details of our customers, but we do think that we have a really good site for a data center near the Western Haynesville area. And I don't think we could pick a better partner.

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

When we look at 2026, I think at current strip prices, we'd see you guys in $100 million to $150 million of free cash flow next year. Just curious if pricing were to retrench to $3.75, 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 Haynesville over the last 18 months?

Well, it's real early for us still to be talking about our '26 activity, which we haven't announced yet. But I think that we really like the -- where the company is now with the balance program and both the Legacy and the Western Haynesville, and we'll be reaping the benefit of the higher production from the money we're spending this year because it takes almost 9 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. So yes, we're very bullish about how 2026 will look for the company, both plays. So -- but yes, we'll be setting our budget later this year. It's usually 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 -- obviously, the core where we have a lot of well-to-well rig contracts. So we always have the ability to flex activity based on the outlook that we see. But we're still very bullish about '26 and what you see in the future’s market and the demand we know that's coming on and even with our direct talks about providing long-term supply to some of the really large users, a lot of that is starting to crank into '26.

Okay. And I wanted to circle back to some of the choke management in the Western Haynesville. 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 data before you're able to make a decision as to what the optimal approach is? Is it, 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 on several different ways. We've been really aggressive on some. More of the wells, of late, we've been very proactive as far as starting to choke them back and basically bring the rigs back down a little bit. Just based on early modeling stuff we've done, we're definitely expecting a little bit better EURs with the conservative drawdown. We haven't done one yet that's really conservative. That's probably the next test that we're kind of looking at here in the near future is flowing one at a much lower rate straight out of the gate. And as far as the timeline to get that data, I mean, it's -- 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 2 years to really start dialing in on an exact answer.

But you have your daily -- you have your feedback of the drawdowns as you produce, but that's given you clues, I guess, are you on the right path?

Yes. 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 and we're looking at. So 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 Allison for closing remarks.

Again, thank you for your hour plus time. I want to conclude it in that, one, we -- that Joneses in particular, but all of us, we want to protect the balance sheet. That's number one, number one, number one. And then I think that we can deliver this noncore asset sale if it's a win-win for us and for the buyer, and we'll use those proceeds to delever. But over and over and over, we have never been more positive about the Western Haynesville. We just want you to know how we're managing it every 90 days. But we do have that 545,000 net acres, 80% of the HBP, and we commit to you that we're managing it. At the same time, NextEra comes in, and we are 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 Haynesville 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 in where we're going, and we'll report again in 90 days. Thank you.