Comstock Resources Inc Q2 FY2025 Earnings Call

Good day, and thank you for standing by. Welcome to the Comstock Resources Second Quarter 2025 Earnings Call. 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 held 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 operation, 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 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.

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 2024, 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 Hub Spot price in the second quarter averaged 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 details 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 recaps our spending on drilling and other development activity. We spent $268 million on development activity in the second quarter. 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. 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 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 is still $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 a 35% savings in our drilling costs when drilling a 10,000 lateral horseshoe well 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 feet, long laterals between 8,500 feet and 10,000 feet, and our extra-long laterals over 10,000 feet. Our gross operated inventory has 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. 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 started our initial well in the fourth quarter of 2021, 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 2024 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. 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. Secondly, all 4 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 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 associated with 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. The lower completion costs in the second quarter were partially driven by lower frac costs that we had associated with lower fuel costs. 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 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, one 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 costs 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 fracked using a blended fuel 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 de-leveraging 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 have 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 ahead and open up to Q&A.

Our first question comes from 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. Carl, when you mention the Northwest, I believe that's our Jennings well. We drilled a two-well pad there.

That one, right there.

Yes, that well was shallower, definitely on the shallower side of the acreage compared to some of the other ones we drill. Jay mentioned it earlier in his opening remarks, discussing the true vertical depth ranges, and that particular well is the 14,000-foot bookend of those, with a range from 14,000 to 19,200 feet. It is a 14,000-foot TVD well. Additionally, it is our record fastest well, taking just 37 days to reach total depth. This significantly impacts the number of drilling days and costs based on where you're drilling on the acreage. That well was also our cheapest and fastest, and notably less costly. We have a good range of depth, temperatures, and drilling costs across the acreage, so I just wanted to highlight that.

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.

Due to the high pressures on the initial wells we drilled, we decided to flow the wells up the casing at a later date instead of doing it right away because of the extreme shut-in and flowing pressures. In the area where the Jennings wells are located, which are shallower and have lower pressure, we're more comfortable flowing those wells up the casing. Although we did run tubing in those wells, for future wells at greater depths, we plan to flow them up the casing as well, which could reduce our costs by at least $150 per foot. If we hadn't run tubing in that well, we would likely have seen a well cost of under $2,000 per foot.

I want to add a comment about the Olajuwon well. We completed it somewhat differently than our other wells. However, we reached the Bell-Meyer well, which is approximately 33 miles from the Olajuwon, and we completed it in the same manner. As we have reported, both are among the two best wells we have drilled. We adjusted the completions slightly. The focus of the program is to optimize our 525,000 net acres and reserve pool. Every 90 days, we provide updates on how we are refining our approach to minimize risks and create significant value, particularly for the natural gas required for LNG and industrial demand. The Menn well, however, is somewhat different. Dan, you may want to discuss that further.

Yes. We adjusted the completions for the Menn well by tightening our stage spacing a bit, which increases intensity. Essentially, we're fracking over shorter distances. The Menn well is located in our shallower acreage, similar to the Jennings well. Its production has been outstanding, even though it has only been producing for a couple of months. The drilling and completion costs are low, and we've seen good results. As Jay mentioned, the Olajuwon, Bell-Meyer, and Menn wells are the three where we've made the most adjustments in completions with the tighter stage spacing.

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

Yes. Even though they haven't been on long, when we look at the initial production rates and the pressure decline over that short period, those three wells are among our best-performing 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 don’t have the exact number in front of me, but I can say it’s not significant. Our drilling speeds are improving, which is helping us bring wells online faster. We do have one well with a midstream connection issue that we’re waiting on, and we’ve also drilled two pilot holes, which slightly delays things. However, in a general sense, these factors aren’t causing significant delays for the wells.

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.

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 the 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 would add that it reflects the decrease in drilling and completion costs, allowing us to add this rig while staying within our original budget, and the availability of those services benefits from lower oil prices. It also shows our decision to sell some non-core properties, which prepares us to replace that production. Additionally, it indicates the enthusiasm for the horseshoe wells and our ability to add many of those to the schedule in the Legacy Haynesville. Overall, it reflects the opportunities we see in those areas rather than any concerns about allocating capital in the Western Haynesville.

Yes, I would say that 50% of our gas is hedged for 2025 and the same for 2026. We've made adjustments for risk. We've added many horseshoe wells, totaling 149, and we are considering increasing our budget for 2025 if we add a rig primarily to drill these wells. The economic potential is impressive for these new wells. We are taking a more cautious approach to developing the Western Haynesville, focusing on exploration and exploitation across a wide area, drilling up to 80 miles north and south, and 20 to 30 miles east and west because we are confident in what we are discovering. When our geological team recommends coring some wells, we understand that it requires time and financial investment, so we will core all those wells. We also plan to drill one more pilot hole near the Olajuwon possibly this year, which will help us better understand the geological connections. However, I want to emphasize that we are more optimistic than ever about the potential in the Western Haynesville. In discussions today, we agreed that we have no intentions of issuing equity to fund growth in the near future. We will instead divest some noncore assets and use those funds to reduce our debt. This approach will allow us to manage our leverage for a while. Meanwhile, Dan and the team will continue drilling and completing these Western Haynesville wells, especially since we have completed our major land acquisition. We have set aside around $25 million to $30 million for land in 2025, some of which is for core areas and some for cleanup activities in the Western Haynesville. We're excited about this new direction; it presents a remarkable opportunity. Thank you for the 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.

That's a good question. One of the things we recognized early on in this area is that it is both deep and hot. If you examine the acreage in the core of the area, you'll notice that in the deeper sections, it's important to be more careful about how we manage well drawdowns. Here, we are at the extreme end in terms of depths and pressures. We have observed that the wells show different behaviors depending on how we flow them. We've tested various approaches and found that restricting flow in the first year leads to a greater decline; this has contributed to our lower production, which was intentional. We've been more aggressive in managing well drawdowns to maintain a disciplined approach. The results reflect this, and when we model it and look at competitors’ data, it suggests that we might achieve better estimated ultimate recoveries if we flow the wells at more conservative rates. I believe that’s true. The key is finding the right balance between modeling the economics for return and payout versus the long-term value in the present value of future cash flows, and that’s what we are currently navigating.

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 de-leveraging. 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?

That's a great question. We see an opportunity in our market that has shifted significantly this year. In the past, the focus was primarily on selling proven developed properties, but now there is increasing interest in our basin from new participants who are keen on drilling locations. With rising gas prices, some previously lower return projects in the Haynesville have become very appealing and profitable. We have a substantial inventory in the Legacy Haynesville, but given our current situation, we won't be able to access much of it over the next decade. Therefore, selling some of that inventory which we don't plan to develop in the near term could significantly enhance the company's net present value since we would be creating value from it. So, we are concentrating more on that approach rather than primarily selling off production or proved reserves.

Well, and remember, as we de-risk 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 locks 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 right. We have two reasons for drilling pilot holes. We have some preliminary plans for where to place these holes across our entire area, though those might change for various reasons. In certain locations, we need to drill a pilot hole to obtain logs since we lack well control in those areas, which is essential for guiding our lateral drilling and determining our landing point in the zone. The second reason is to cut cores and conduct scientific analysis to establish what the original gas in place numbers might be, as well as to gather mechanical properties that could inform adjustments to our completions.

I would like to point out that 80% of the Western Haynesville is held by production, and some of the key areas we plan to drill are within this HBP acreage. The initial wells will be in the locations necessary to maintain our holdings. Additionally, there's a noteworthy Japanese company drilling a well in the Olajuwon area, utilizing the same frac crew we employ for our wells. However, we are interested in coring a well nearer to the Olajuwon site, and we do have a 3D seismic survey underway in that area. This is the only location where we believe further seismic analysis is required. Consequently, we have initiated that program, which is a proactive effort. This requires funding, and it is included in our budget. To reiterate, we are not expanding through mergers and acquisitions; we are cultivating our existing asset base. We are simply reducing risks and validating our holdings. Regarding your initial question, if there are assets in the Legacy that won't be drilled for an extended period, that's beneficial as it allows us to obtain a premium price. This arrangement can be advantageous for both the buyer and seller, and we should consider reallocating resources to safeguard our balance sheet, which is precisely what we are 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, etc. 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 believe that if you consider our current situation in the second quarter compared to the end of last year, our drilling and completion costs have decreased by about 10%. Much of this is due to lower pipe prices, which we began to notice in the first quarter, with some savings seen in the fourth quarter as well. As long as tariff issues do not cause prices to rise again, this will significantly contribute to our lower costs for the rest of the year. Additionally, there has been a slight reduction in vendor costs, which may be influenced by a slowdown in the Permian region due to lower oil prices and the fact that rig activity in gas hasn't significantly increased. This trend is evident across all our 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, you mentioned previously that there was a different completion design for the Olajuwon Pickens well. Could you provide an update on how that well is performing with this design, and have you applied this type of design in any of your more recent wells?

Yes, we have made some changes. The Olajuwon was the first well where we implemented these adjustments, specifically reducing the stages from 150 feet to 100 feet. We've observed that many of these wells, particularly the deeper ones in this range, often start out below our designed fracking rate. To tackle this, we opted for tighter stages and applied this method throughout the entire lateral of the Olajuwon to maintain consistency in the completion. Since then, we’ve executed two other wells, the Menn 1H and the Bell-Meyer, and I believe this approach is showing positive results. Although it's still early, with the Olajuwon only producing for about 3.5 months, it's performing a bit under the 27 million starting rate we set, and the daily pressure drop appears to be very promising. We are optimistic about this direction moving forward.

Roland, I understand your hesitation to discuss the divestiture program for valid reasons. However, when I review your acreage map, it seems to me that the most logical area for Comstock to consider selling, given the industry's limited inventory compared to your extensive holdings, would be the Angelina River trend. Is this a fair assessment, or are you not planning to pursue that?

No, that's a reasonable point. It's a scenario that we just haven't pursued, but it's present in the industry. So yes, hopefully, we'll have a clearer perspective in our next report. We're really optimistic that this will help us accelerate our de-leveraging objectives this year while still allowing us 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.

I wanted to discuss the Horseshoe well program. I understand you mentioned 10 wells this year and 10 next year. I'm curious about what factors might lead you to adjust that plan. Have you seen improved results that might allow for more investment, or have results been less favorable, prompting a reevaluation? I'd like to understand your strategy regarding this.

We are really encouraged and excited about the horseshoe wells. We started our first one last year and view it similarly to a 10,000-foot straight well. Many of our horseshoe wells in inventory are located in some of our best type curve areas, even better than our standard straight wells. This is a significant advantage for us. To date, we've drilled three, and we just completed the third one last week. We encountered no problems during drilling. It typically adds just about two days to the drilling of a 10,000-foot straight well to bend it and make it into a horseshoe, and we've had no issues with either drilling or completing the first well. We expect to complete the next ones in the upcoming quarter. Overall, we have no concerns about them at this time.

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?

It's still early for us to discuss our 2026 plans, which haven't been announced yet. However, we are pleased with the company's current position regarding the balance program and both the Legacy and Western Haynesville areas. We expect to benefit from the increased production linked to our spending this year, as it typically takes about nine months to see production gains after adding a rig. I don't foresee any situation where we would exceed our spending limits, and we will adjust our activity levels as needed. We're optimistic about how 2026 will turn out for both plays. We'll set our budget later this year, usually in the fall, when we assess our activity. We have significant flexibility in managing our operations, particularly in our core areas with numerous well-to-well rig contracts. This allows us to adjust our activities based on our outlook. Our outlook for 2026 remains positive, especially considering the expected market demand and our discussions regarding long-term supply agreements with major users, much of which will start to materialize in 2026.

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.

That's a great question about the timeline. It's a lengthy process because quick answers are not possible. We have approached this in various ways and have been quite aggressive in some areas. Recently, we have started to reduce the pressure on some wells and pull back the rigs somewhat. Based on our early modeling, we anticipate slightly improved estimated ultimate recoveries with this conservative approach. We have not yet conducted a truly conservative test, which is something we are planning to do soon by producing at a significantly lower rate from the outset. As for the timeline to gather that data, it will likely take at least a year to get an idea of the results, and possibly 18 months to 2 years to nailing down a precise answer.

But you have your daily feedback from the drawdowns as you produce, which gives you clues about whether you are on the right path.

Yes. There are other industry players that have drilled some wells and have state data that's included in our dataset, and we're analyzing it. I believe we are making progress, but it does require some time to see how things develop and determine the direction they are heading.

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

Thank you for your time today. To wrap things up, it's important to emphasize that we want to protect the balance sheet. That's our top priority. We are confident in our ability to execute this noncore asset sale if it benefits both us and the buyer, and we plan to use the proceeds to reduce our debt. We have never been more optimistic about the Western Haynesville. We want to assure you that we are actively managing our 545,000 net acres, with 80% held by production, and we are committed to this strategy. Additionally, we are excited about our collaboration with NextEra on potential data center opportunities. Our goal is to grow our inventory organically, rather than through mergers and acquisitions. As demand for LNG continues to rise, it's clear that the Haynesville will play a crucial role in meeting that demand, and we intend to be a significant contributor. Thank you for your patience and for allowing us to be transparent about our direction. We will provide another update in 90 days. Thank you.

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