Comstock Resources, Inc. Aktie

Thank you. Good day and thank you for standing by. Welcome to the second quarter, 2026 Comstock Resources Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during this session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again.

Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and Chief.

officer please go ahead thank you for the introduction uh i want to welcome everyone to the comstock resources second quarter 2026 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 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer. Dan Harrison, our Chief Operating Officer, and Ron Mills, of finance and investor relations. Please refer to slide two in our presentations and note that our discussion today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

On slide three, if you'd turn there, we summarized the highlights of the second quarter. We did see the return of production growth in the quarter. Production increased 16 percent over the first quarter of 2026 and 1 percent over the second quarter of 2025. However, lower natural gas prices drove up. of lower financial results in the quarter. Natural gas and oil sales, including realized hedging gains, were $332 million. Operating cash flow, excluding working capital changes, was 189 million, or 65 cents per share. Adjusted EBITDOX for the quarter was $245 million.

Our legacy Hainesville Horseshoe and Western Hainesville drilling results are driving future production and reserve growth. 11 Western Hainesville wells turned to sales so far in 2026 with an average lateral length of 10,331. 31 feet and a per well initial production rate of 31 million cubic feet per day. 22 legacy Hainesville wells turned to cells with an average lateral length of 12,052 feet and a per well initial production rate of 31 million cubic feet per day. Eight of the legacy Hainesville wells were horseshoe wells. On June 15th, we completed our mid-spring equity placement by selling a 27% stake in Pinnacle Gas Service for $600 million, which we used to retire the Pinnacle's preferred equity and all of Pinnacle's outstanding debt, which I will discuss more detail on the next couple of slides if you'd turn over to slide four. On June 15th, 2026, we sold a minority equity interest in our mid-range subsidiary Pinnacle Gas Service to certain funds managed by Sixth Street. Next Street invested $600 million in Pinnacle to acquire a 27% non-controlling common equity interest. This transaction is another validation of the future potential of our Western Angel acreage, which is well positioned to service the growing demand for natural gas and our region, the western Hainesville represents one of the largest undeveloped natural gas resources. With access to the growing demand along the Gulf Coast, it will also serve the recently announced Texas Power Generation Hub in Anderson County, Texas.

The transaction with 6th Street will represent an important milestone for CompStock and a strong validation of the value we have created in the Western Hainesville. With six streets in investment, we strengthen our balance sheet by reducing debt and simplified PGS's capital structure. You'll turn to slide five. Sixth Street's investment of $600 million in Pinnacle Gas Service for a 27% stake implies a $2.2 billion enterprise value for Pinnacle. We retained a 73% controlling common equity interest in Pinnacle, which would have a $1.6 billion implied value. The strong valuation reflects the expected future production growth from our Western Hainesville drilling program. After the transaction, Pinnacle is now debt-free and is saving $40 million in fixed charges annually. Comstock retained a 73% controlling equity interest in Pinnacle, and after a certain return hurdles are met, our ownership increases to 80.5%.

We also maintained operational control, and key decision-making of the Pinnacle system, critical to supporting our growing Western Angel asset. I'll now have Roland Barnes review the financial results for the quarter. Roland? All right. Thanks, Jay.

On slide six, we cover the second quarter financial results. Our production in the second quarter averaged 1.2%. BCFE per day, which was up 16% from the first quarter of this year and slightly higher than the second quarter of last year. Our oil and gas sales after hedging were $332 million, reflecting the lower natural gas prices we experienced in the quarter. EBITDAX came in at $245 million and we generated $189 million of cash flows in the quarter. We did report a $9 million profit for the quarter, or 3 cents per share. included in that number was a $1 million mark-to-market unrealized gain related to our hedge book. If you exclude the mark-to-market gain and expiration expense, which is solely related to the seismic that we're shooting in the western Hainesville, and other non-recurring items such as the gain on sales, and the related income taxes to those items.

We reported a similar net income of $8 million for the quarter, or also $0.03 per share. On slide seven is the year-to-date financial results. Production in the first half of the year averaged about 1.2 BCF per day. Also our oil and gas sales for the six months were $670 million. EBITDAX was $496 million, and we had $380 million of cash flow. We reported a profit of $116 billion for the first six months, or 40 cents per share. That includes a pretty large pre-tax $84 million mark-to-market unrealized gain on our hedge book.

So if you exclude that gain... expiration expense and other non-recurring items and the related income tax effect of those are adjusted net income would have been $48 million for the first six months of this year, or $0.16 per share. Slide 8 breaks down the natural gas price realizations we had in the quarter. In the quarter, the weighted average NYMEX settlement price averaged $2.89. And the weighted average Henry Hub spot price for the quarter was $2.93. So 32% of our gas was sold in the spot market, so the approximate NYMEX reference price would have been about $2.91 for our production. Our realized gas price during the second quarter averaged $2.54, collected a 35-cent basis differential compared to the NYMEX settlement price and a 37-cent differential compared to the reference price. second quarter we were 63% hedged which increased our realized gas price for the quarter to $2.93. In slide 9, we detail our operating costs for MCFE and our EBITDAX margin.

Are unit operating costs returned to normal levels in the quarter compared to where they were in the first quarter of this year? Our operating costs per MCFE averaged 77 cents in the second quarter, which which improved 16 cents from the first quarter rate and was in line with where we were really in the second half of last year. Lifting costs was down 4 cents per MCFE. G&A was down 3 cents per MCFE. Both of those improvements were due to the higher production level in the quarter. Production and ad valorem taxes were also down by 4 cents in the quarter. Um, that some of that was due to the lower gas prices we had but also The divestitures that we completed last year, you know, helped reduce our ad valorem taxes in the quarter. Gathering costs, we're down five cents in the quarter.

That's also due to the higher production level and utilizing more of our firm transportation. Our EBITDAX margin in the quarter improved at 74%. On slide 10, we recap our spending on our our drilling and other development activity in the quarter and for the first half of this year. spent a total of $390 million on development activities in the second quarter, and $734 million during the first half of this year. first six months of this year we've drilled 22 or 19.4 net horizontal Hainesville wells and 12 or 11.5 net Bossier wells for a total of 34 or 30.9 net wells. We turned 29 or 24.4 net operated wells to sales which had an average initial production rate of 30 major and give it fee per day overall. Slide 11 summarizes our capitalization at the end of the second quarter. We ended the quarter with $545 million of borrowing to outstanding under our upstream credit facility. upstream borrowing base is two billion dollars and in our electric commitment under that facility is 1.5 million dollars At the end of June, the midstream credit facility had no borrowings outstanding following the Pinnacle transaction with 6th Street. Our last 12 months leverage ratio has averaged exactly three times.

At the end of the second quarter, we have almost $1.2 billion of liquidity. So I'll turn it over to Dan to kind of talk about the operating results in the quarter.

Okay, thank you Roland. If you look on slide 12, this is just our latest overall acreage footprint in the Hainesville-Boser shell in East Texas and North Louisiana. We now have 1,078,228 gross acres and 809,244 net acres that are prospective for commercial development of the Hainesville and Bossier Shales. Our western Hainesville footprint has now grown to just over 545,000 net acres. We currently have just over 264,000 net acres located in our legacy Hainesville area. We have 41 wells currently producing on our western Hainesville acreage. We have another 13 wells that are in various stages of development. Slide 13 outlines the drilling inventory in our legacy Hainesville area at the end of the year. into the second quarter.

We have 926 gross operated locations with a 77% average working interest. 717 net locations. We have 779 gross non-operated locations with a 13% average working interest or 99 net locations. The drilling inventory is divided into our four different groups based on the lateral length. 449 of our 926 gross operated locations are nearly 50% of the inventory lateral surpassing 10,000 feet while the average lateral length in the inventory now stands at 10,153 feet. The gross operating inventory is evenly split with 51% of our locations in the Hainesville and 49% of our locations in the Bossier Shell. Our legacy Hainesville inventory also includes 113 gross locations with 53% of those in the Hainesville and 47% in the Bossier. We are currently running five rigs on our legacy Hainesville area, and this inventory provides us with a long runway for future drilling locations. Slide 14 outlines our estimated drilling inventory in the western Haynesville.

We have 3,277 gross operated locations and 2,528 net locations in the Western Hainesville. which equates to an average working interest of 77 percent. Our total net locations are estimated since much of our Western Hainesville Acreage has not yet been unitized. We have the Western Haynesville inventory also divided into our four different groups based on the different lateral links. And in this inventory, we do not have any short laterals less than 5,000 feet. 1,321 of the 3,277 gross operated locations, or 40%, have laterals surpassing 10,000 feet. 61% of our gross operating locations have lab rules surpassing 8,500 feet. The average lateral length in our western Haines limitory is 8,875 feet. The western Hainesville inventory is weighted more to the Bossier formation with nearly two-thirds of the inventory in the Bossier and one-third of the inventory in the Hainesville. We are currently running four rigs on our western Hainesville acreage.

Slide 15 recaps our ongoing horsey well development activity within our legacy Hainesville area. To date we have drilled a total of 19 horseshoe wells to total depth and 11 of these horseshoe wells have been turned to cells. We continue to realize significant cost savings with the horse sheep development compared to the alternative of drilling the shorter 5,000-foot laterals. Our well performance has also met expectations as we have our average IP is 31 million a day for all 11 horsey wells that we have turned to sales. For the year, in 2026, we plan to drill a total of 16 horseshoe wells and turn 17 of those to sales. Drilling inventory does include 113 horse shoe locations. Slide 16 outlines our average lateral lengths drilled based on the wells that have been drilled to total depth.

The average lateral lengths are shown separately for the legacy Haynesville and for the western Haynesville. In the second quarter, we drilled 13 wells to total depth in the legacy Hainesville area. Those had an average lateral length of 11,457 feet. The individual labrals range from 9,495 feet up to 15,564 feet. Our longest drill to date in the Legacy area is still at 17,409 feet. In the second quarter, we also drilled four wells to total depth in the western Hainesville with an average length of 10,281 feet. The individual laterals range from 78, 173 feet up to 14,783 feet.

The longest lateral drill to date in the western Hainesville is 14,783 feet. To date, we've drilled a total of 50 wells to total depth in the western Hainesville 21 of these wells have laterals exceeding 10,000 feet. Slide 17 summarizes the 22 wells that returned to sales in our legacy Hainesville area so far in 2026. The average lateral length was 12,052 feet. The individual laterals ranged from a low of 9,304 feet up to a high of 15,772. The average IP for the 22 wells was 31 million cubic feet a day. and included in these results are eight of our horsey wells. Slide 18 outlines the 11 wells that we've turned to sales on our western Hainesville acreage so far this year.

These 11 wells had an average lateral length of 10,331 feet and an average initial production rate of 31 million cubic feet per day. The last five wells we've turned to sales since our first quarter update have ranged from 30 to 35 million QB fee a day. Again, we have a total of 41 wells currently producing in our western Hainesville area. Slide 19 highlights our drilling efficiency in the legacy Hainesville area. These are for our benchmark long lateral wells. greater than 8,500 feet long. In the second quarter, we drilled 13 of these mid-smart long lateral wells to total depth in the legacy Hainesville area and averaged 24 days to total depth. Correspondingly, we averaged 1,017 feet drilled per day in our legacy Hainesville area, which represents a 10% increase versus the first quarter of 2026.

Six of the 13 wells we drilled in the second quarter were horseshoe wells. Slide 20 highlights our drilling progress in the western Hainesville area. During the second quarter, we drilled four wells to total depth in the western Hainesville. This gives us a total of 48 wells drilled to total depth through the end of the second quarter. We averaged 59 drilling days for the four wells drilled to total depth during the quarter. This is quarter. This is also reflected in the drilling speed. 469 feet per day during the second quarter, which is 2% lower than the first quarter. The main driver affecting the lower drilling efficiency in the second quarter was the depth, deeper depths, mean higher temperatures.

The average true vertical depth for the four wells drilled in the second quarter was approximately 1,200 feet deeper than the average TBDs of the five wells we drilled in the first quarter. Slide 21 details our D&C cost through the second quarter. for the benchmark long lateral wells in the legacy Hainesville area. These costs reflect all of our legacy Hainesville wells with laterals greater than 8,500 feet. The drilling costs are based on the quarter in which the well has reached TD. And the completion costs for the quarter are based based on the quarter in which the wells were turned to cells. During the second quarter, we drilled 13 of our bit spark long lateral wells to total depth. The second quarter drilling cost averaged $710 a foot, which is a 1% increase compared to the first quarter.

Although we drilled six horseshoe whales in the second quarter compared to four horseshoe whales in the first quarter, we're able to keep our drilling costs nearly flat due to better drilling performance on our horseshoe wells in the second quarter. During the second quarter, we also turned 12 of our benchmark long ladder wells to sales. Our legacy Hainesville acreage and five of these were horsey wells. The second quarter completion cost came in at $680 a foot, which represents a 4% increase compared to the first quarter. And the higher completion cost in the second quarter was the result of this slightly higher cost associated with some longer drill outs and also slightly higher flow back cost. On the drilling side in the Legacy Hainesville, we are continuing to deploy rotary steerable drilling technology. We're using this particularly on our horseshoe whales, making really good progress and having improved repeatability.

On slide 22 is a summary of our D&C costs through the second quarter for all wells drilled in the western Hainesville. During the second quarter, we drilled four wells, the total depth in the western haisel with an average lateral length of 10,281 feet. Our second quarter drilling cost averaged $1,738 a foot. This represents a 13% increase compared to the first quarter. Our drilling costs in the second quarter was attributable to the wells encountering some steering difficulties in the laterals resulting in additional trips and BHA runs. The higher drilling cost for these two wells was partially offset by the lower drilling costs associated with our first big hole, record long lateral, that was also drilled in the second quarter. That well was drilled at an attractive cost of $1,306 per lateral foot, which is 25% lower than our quarter average.

During the second quarter, we also turned four wells to sales in our western Hainesville acres that had an average lateral length of 9,439 feet. The second quarter completion cost averaged $1,609 a foot. This is a 5% increase compared to the first quarter. Higher completion costs in the second quarter can be attributed to higher profit loading. Had a lower average lateral length in the second quarter compared to the first quarter. and we had a higher percentage of single well pads that we completed in the second quarter. Based on the successful results of our first big hole long lateral drill in the second quarter, we're now in the process of drilling our second and third big hole laterals to confirm the repeatability of our results on the first well. The big hole lateral creates lower downhole temperatures, which leads to longer, more reliable runs from our downhole drilling assemblies.

And also this fall we will be deploying our first 10,000 PSI rig in the western Hainesville, which will increase our drilling speeds in both the vertical and the horizontal hole sections. Also near term, we will be testing some new higher temp rated drilling motors, which we expect to lead to longer runs, better drill times. And then on a more longer timeline, we're continuing discussions with some of our industry partners regarding the development of a 20,000 pound fraction. which would allow us to significantly increase our FRAC efficiencies and generate superior performing wells with our EURs. This would be a 2027 event. And I'll now turn the call back over to Jay.

Excellent report, Dan. Thank you, Roland. If you'll turn to page 23, We'll summarize our outlook for 2026. As you can tell, our primary goal continues to be advancing a western anvil that will position Comstock to benefit from a longer-term growth in natural gas demand. We have four operated rigs drilling in a western anvil to continue to delineate the new plate. We expect to drill 22 wells and turn 21 wells to sales in 2026. We expect drilling efficiencies and changes to our completion design to continue to drive up productivity and drive down drilling and completion costs. We have five operator rigs drilling in a legacy handful to support production growth in 2026 and 2027.

We expect to drill 48 wells and turn 48 wells to cells in 2026. And lastly, we continue to have strong financial liquidity of almost $1.2 billion. So everyone that's listening, I wanna thank you for your time today. Slide 25 provides guidance for the rest of 2026 which Ron can discuss with you directly if you have any questions. For the rest of the call, I will take questions from analysts who follow the company.

As a reminder, to ask a question, please press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. In the interest of time, we ask that you please lend yourself to one question and one follow-up. Please stand by while we compile the Q&A roster. Our first question comes from Derek Whitfield with Texas Capital. Your line is open. Good morning, all, and thanks for your time.

I wanted to start with your DNC optimization efforts in the Western Hainesville. While we're still very early in optimizing this trend, the steps you guys are taking are clearly important to value extraction over time. With that said, if we were to assume you move forward with the tangible changes, including the big hole design and higher spec rigs, where do you see well cost per foot trending? And as a tack on to that, if you were to assume the use of more leading edge technologies like the higher temp rated drilling motors you talked about, and the higher PSI rated frag spreads, where do you see cost trending when all the drivers are working together?.

So that's a really good question, Derek. So on the drilling side, we definitely see the cost going down. We're pretty excited about the big hole. Lateral that we drill albeit. We just have drilled the one we're drilling the second third one now We got five on our drill schedule slated to be drilled with the bigger lateral and Probably got another dozen or so that we've kind of got targeted for the bigger hole. Just, you know, we need to get the results on these second and third wells. But the first well, the Dolly Jones, I mean, at $1,306 a foot, that's a good bit cheaper than any other well we've drilled at a similar TVD. Obviously, the deeper TVDs, that well had about a $16,400. foot TDD average and it's by far the cheapest well of anything, any well we have that's 16,000 foot or deeper.

So we didn't even really have the motors that we use on the first well were not the exact. or the motors we wanted, we kind of used some stuff that was more off the shelf because obviously, We hadn't done any big hole work in the western high school, so they didn't have anything really fitted for us exactly for that first well we drilled. So, you know, we're hoping we'll have a little better performance there, because we've had time now to kind of dial in and get something fitted a little bit better for these second, third wells that we're drawing. And I really see that the majority of the future wells we drilled will probably be with this bigger lateral. Not only cheaper, but we get some intangible benefits there as well. We had a lot better steering ability. In this first well we drilled with the big hole versus the slim holes. want to make course corrections it's just a lot easier and quicker to do so you get a lot better yields you know So you're not sitting there fighting and sliding for longer periods of time trying to get it to turn or go up or down. And I think it's just going to be a little bit more predictable.

You know, in the slim holes, we bounce around a little bit more. I think the big holes hopefully will be more predictable on performance, cheaper and more predictable. So, completion side you know we're pretty darn efficient really on the completion side just You know, we had a couple of wells. Last quarter, we left a couple of motors in the hole, but we've gone to drilling out all of our wells. Basically, we've quit running motors on our drill outs. We basically just, you know, we do everything with stick pipe in the western Hainesville, 7 units of stick pipe, And now we don't run motors anymore. We just basically put a bit on the end of the pipe and we go to the bottom, and that eliminates a ton of risk.

Doesn't really add any time, and that's possible because – all of this technology, with these modern plugs, they're dissolvable. So really, we say we drill out plugs to the bottom, but it's really you're more washing the bottom. And occasionally, you hit a couple of spots you've got to drill through. So I think going forward we're going to have a whole lot less risk of any kind of little hiccups on the completion side. Now we are pumping the larger fracks. We started pretty much with all the wells we completed in the second quarter. We're either 25% or 50% larger profit loading than before that.

Okay. I'm seeing really good pressures at the rates we're flowing at initially and We think it'll definitely bear fruit on the higher EURs. We got, you know, everybody knows we have to wait to prove that out. But so for the cost on the completion side, with the bigger fracks, obviously that goes up. I see us going, we're going to be going cheaper on the drill side, we're going to be going a little bit higher on the completion side. So overall, D and C cost, you know, I don't know which one of those in the future kind of maybe weighs the most. I think we're looking at something pretty similar to where we've been, but because we've been, you know, we're going to get that drill cost going down with these big hole laterals, and so even though we're pumping the big frags, we're not going to see any higher cost. It's going to be the same or a little bit cheaper.

Great. Thank you. Our next question comes from Charles Mee with Johnson Rice. Your line is open.

Good morning, Jay, Roland, and Dan, to the rest of your team there at Comstock. Dan, maybe the first one... Yes, thank you, Jay. Jay, maybe this is for you, maybe it's for Dan, but... I think you guys have done a great job explaining why this big hole design. is, is, uh, is helping you on the, uh, the drilling side. But, uh, I'm curious if you'd offer any kind of opinion, uh, on what it might ultimately, you know, what it might mean for well productivity once you complete the well. And I imagine that, you know, with just the larger internal diameter, you're going to have an easier time getting your fracks off. Maybe you can talk about what it might mean on the cost side of the completion, but more importantly on the productivity of the well.

Well, I think it's going to let us get, you know, on average, these big hole wells, we're probably going to be looking at longer laterals, which, you know, the longer the lateral gets, it gets, you know, just the toe stages are just a little further out, takes a little more horsepower. So running that bigger pipe, you know, in general, conceptually, right, it takes a little more horsepower. It creates a little bit lower reading pressure with the bigger pipe, less pipe friction, get a little more rate, get a little bit better frac efficiency. pump a little faster, shorter pump time. So it creates all of those things for you. But you know the biggest, the biggest obviously, I mean the drilling side is where it really just makes, you know, makes the big difference for us. So, like I said, we had expectations for the first well. We beat those expectations and now we just need to show that it's repeatable with second and third well.

Well, you know, like Dan said, I do think that what he said, we do have a lot of site through drilling, you know, techniques, which we've implemented on these 50 wells. We have been tweaking our completion designs. And all that is, as you know, Derek had asked, it should be done. should materially drive down costs. And it'll enhance well productivity, Charles. I think that's what you're asking about. It is amazing, and Charles, you're one of the bigger ones out there that have known us for a long, long time. I mean, you're actually seeing the birth of a major natural gas field every 90 days.

I mean, every 90 days, We show you everything, which is unusual. But we're 50 wells into it. And we're super pleased with where we have come from, where the future's taken us, and as we all, everyone is still on this call, you know, it is all driven by the demand for natural gas because there is inventory depletion. And what we don't have, we don't have to buy inventory. So everything really plays a part. focuses on not what we paid for inventory, but we paid not much for inventory, we're really spent our money on drilling and completion side. So I would ask all of you to look at that and say if you own the footprint, and you don't have a lot in it, and the reserves are there, and you've drilled maybe 60, 70, 80 miles apart, and we've got some peer companies out there that are now in the game, which we're their biggest cheerleader, And those wells look good that we are as a group, but as an oil and gas sector, we're trying to de-risk because we do need another major gas field in Texas near LNG corridor, near the data center demand. And I think we're going to deliver that.

So that's everything we do, that's our goal.

Got it. Thank you, Jay. And then if I could ask about the U-turn of Horseshoe Wells in the legacy Haynesville. I think... For the second quarter in a row now, your highest IP has come from a horseshoe well in the legacy Hainesville. And I think, I believe, but maybe you can confirm part of that is because you've got these kind of stranded single section units in some of the the best parts of the Haynesville that were developed early and that's why they're stranded now but other than that is is there something else going on you Maybe with your different frack recipe that you're still breaking new ground as far as productivity in the legacy hands with these wells?.

So we don't pump a different frac design on the horse ewe wells. It's still the same profit loading. fluid loading that we pump in the other wells. I will say that the execution has been pretty flawless. We just haven't run into any kind of issues that I think a lot of people may, no fear or expect before they try one. If you don't know it's a horse you will and you're sitting there, you know, completing the well, you really can't tell the difference. But I'll say that the rotary steerable work that we kind of started here a few quarters ago, it's really the big benefit we're getting from it is on these horseshoe wells, because we're able to drill the curve. I mean, all of that horseshoe turn, instead of sliding with a conventional assembly, we're rotating the whole time all the way around around right as we're turning that well around 180 degrees.

It's definitely helped us shave some time off of what we thought those looked like in the beginning. But on performance, it really is mostly, I think, where a lot of those wells are. A lot of the horseshoe wells we've drilled are in good type curve areas because they were stranded. Like you said, we weren't going to drill them as 5,000 foot laterals. and just due to the efficiency. And so, you know, they haven't disappointed for sure. They look really good. And we, you know, we found that out. They've all been to Louisiana so far.

We've drilled three horseshoe wells in Texas, We've completed our first one and we have it on flow back now. So we'll, you know, we'll see how those look on the next call.

Well, Charles, I think that the thesis of the oil and gas sector, I mean, 22 or three years ago, nobody drilled a lateral, much less a 15,000, 20,000 foot lateral. You know, only several years ago, you're really drilling horseshoes. That's all technology. And, you know, we use this rotary steerable and all of a sudden we've added. 114 new locations that were there but they weren't as economic. We take that technology and we can drill in 2008 and help discover the legacy of Ansel Bossier. All we're doing now is we're moving one more checker to show show you what we think we can be doing in the Western Angle. Those questions are great. It is all driven by technology. So everybody that's asked a question is asked the right question.

That is great detail. Thank you, Jay. Thank you. Thank you. Our next question comes from Kevin McCurdy with Pickering Energy Partners. Your line is open.

Hey, thanks for taking my question. I wanted to ask about production cadence and not to get too far ahead of ourselves, but last quarter you talked about the exit rate this year could bring you back to the kind of peak levels you experienced in early 2024. And I just wanted to check if that was still the case or if there's any changes to your.

Kevin, this is Ron. What we've said historically is that we think the fourth quarter can get back to where we were in the first half of 24. the first half, the first and second quarter were fairly different. But we're still on track to get to that level. And in terms of relative cadence between the third and fourth quarter, the it's the both quarters should grow by a similar amount sequentially It's peeking back into that via the guidance. Appreciate that, Ron.

And then maybe a different direction with my follow up. Some of your competitors have shown interest in the southern end of the Hainesville. You guys have some acreage there in Sabine Parish. And just curious what your experience is in drilling in that region and maybe your thought on the extent of the Louisiana area.

Yes, I think we, I mean, we like that acreage down there. We have drilled a few wells down on the south end. We don't, you know, the meat of our acreage is not really down in that area, but I think I think we have a couple of horsey whales planned for, I can't remember if it's later this year or early next year, that are going to be down on the south end. So yes, we got some good whales down there. Mosier and Hazel were both You know, really good performing. And so definitely not against it. Just, you know, it's just where it layers into the drill schedule amongst all the other opportunities.

Thanks, appreciate that. Thank you. Our next question comes from Jacob Roberts with TPH & Co. Your line is open.

Good morning. Morning. I wanted to start on leasing with the increase to the overall Western Hainesville position by I think 5,000 acres or so. I'm just wondering if you could speak a little bit about what's compelling about some of these smaller transactions relative to that overall position? How they fit into the program going forward and just what are you looking for?.

for in these types of transactions? Yes, that's the question. Of course, as we are putting together the units in the Western Haynesville, we've kind of leased a lot of large tracts and have blocked up the acreage really well, but there's a continual maintenance of picking up any remaining acres before we finally wanna drill the well. So part of that program is really twofold. I think part of that program is is to complete billing out the units. Typically we're, we'll end up with 100 of the well for the most part that's been most of what our experience been so far um and And then on the, there is a little bit of extensional areas that we like based on reprocessing seismic and stuff that are maybe the other part, you know, just where we see like, but I don't think it's really very large, but you know, just as we kind of fill in, you know, any gaps that are available, maybe a lease becomes available that wasn't available earlier.

So obviously we monitor that. Well, and I think when we go lease to clean up acreage that we need to clean up. If you're a mineral owner and you know we've drilled 50 wells and we're going to drill 50 more and 50 more and 50 more after that, that's our goal. you're probably going to lease those. Because if you really want a well-drilled, you're probably going to call us. And that's what we see happening on a quarterly basis. We've added a little acreage here and there. And it's all to make the existing acreage even better.

That's what you see. Perfect. That's helpful. I'll try to ask about 2027. I know it's early. But if we think about the nine-rig program and Fort Frack crew continuing into next year and throughout the year, can you give us a point of reference on what you think the growth rate would be? And then, you know, I know a lot of folks have been saying, well, we're going to have to wait. I think we all agree that there is a demand wave coming. The forward curve doesn't necessarily reflect that next year. So I am curious if prices do maintain where they're at, are we going to see a potential holding back on some of that activity until that demand is there?.

Yes, we've definitely been disappointed with the gas prices as we've kind of gotten to the summer, you know, and going to continue to watch that. So, you know, we really will look at our 27 activity as we get late in the year. and kind of look at the view at that point, you know, so, um, Yes, so I think that's really to be determined, what we would view, and we definitely would want to see probably a stream stronger prices, especially stronger prices that we could hedge into, you know,.

to support that activity into next year? You know, I'll tell you what our goal is. If you look at where the Circle Inn was built, the latter part of 21, early 22, and where the Elijah one is, which is 30, 40, 50 miles to the north, whatever, Well, what we want to do, we see that LNG demand growth and it's expected, and we know that there's going to be a lag between when it's actually delivered and the gas, that's going to be lumpy. So what our goal is, is let's just try to de-risk as much of this as we can, and like Dan said, of its bozier and bozier is much easier than the lower otter Hainesville but it's all held by production so we just want to be ready to respond quickly when that demand is here in a way we do that is to continue to do what we've been doing so.

I appreciate the time. Thank you. Our next question comes from Noel Parks with Tuohy Brothers Investment Research. Your line is open.

Hi, good morning. I apologize if you had already touched on this, but the topic of the experimentation with motors that have better heat resistance, I wondered if you could just talk a little bit about that and what it can do. if you've made a transition to using those more widely, just what that might look like in terms of, you know, cost or time practice.

Well, we've been working with one of our vendors to make the higher temp motors available. I've been waiting to get them for a little bit. So sometime hopefully here in the next two or three months, we'll take delivery of some of those some of those and get them deployed in the wells. And we think basically we just need to stay on bottom longer, so a motor that's the elastomer in the motor, the rubber, the elastomer, for the higher temperature, the motor's going to last longer. We're just going to be able to stay on bottom drilling, you know, longer hours, you know, maybe an extra day on average, you know, what have you. So if you can deploy those and you stay on bottom longer with longer runs and make less trips until you get the well drilled to TD, that's how you cut days off the well. You can just eliminate one trip, you know, you can eliminate two to three days.

Two trips, you know, four to five days. So that's, you know, that's the task. I think that's where Dan talks about the motors. You mentioned briefly about what we expect the motors and the new motors to be able to do. We're always leaning into what we think will improve all costs and time. That's also where that big whole lateral, when we're drilling with the That's basically, we say big hole, the lateral is 8 1⁄2 inch bit size or diameter or something. This is a six and three quarter in our normal, you know, slim holes that we drill.

When you're drilling in the bigger hole, you're circulating. You're just circulating the mud faster. When you're circulating faster, it keeps the hole cooler. When the hole stays cooler, the tools last longer on bottom. So that's what we're achieving there. Now this higher temp motor, we can basically take that technology and they can just basically take that same higher temp elastomer and they can put it in the bigger motors that we use for the big hole. And we also get the same benefit there.

So we got our eyeball on that also. Great. And I guess just to sort of refresh my memory, I think of a period maybe about three, four years ago where there was another wave of improvement. I think it was mostly around downhole tools I don't know if it was logging specifically, but it's just that there are kind of like these step changes of improvement that can come along and help. So I wonder if you just have any thoughts about... any other similar improvements that could be meaningful, and, you know, just kind of what else you might be looking forward to in the next couple years, you know, keep developing out there.

Well, you're right. It is step changes. Really, I think maybe a few years ago, maybe what you were talking about, we first started using the coated or insulated drill pipe. which, you know, when we were drilling some of those, the deeper TVD, Hainesville wells, they were really hot. I mean, they were over 400 degrees. And so we went to that insulated drill pipe. It's the same basic thing we're trying to accomplish. We're trying to keep the mud cooler on bottom, make the tools last longer. So when we ran that insulated drill pipe, we got a big change in downhole circulate temperatures, 20, 30 degrees, which makes a huge difference on the life of those tools.

We've been utilizing that ever since. And now we also use insulated drill pipe when we drill the big hole laterals also. So you get that benefit there as well. So I think that's the next big step change. We're always tweaking motors and fits, different motors and then you know some work some don't but I think this big holes our next big step change down it's going to drive the cost down and you know and then we'll we'll try these higher temp motors hopefully here the next two three months we're going to be able to get those and put them in the ground and we'll get the great, the better performance from those. And then in my prepared remarks I talked about, we've got this 10,000 PSI rig, it's been upgraded. All the rigs are rated up to 7,500 PSI.

So this one will be a 10,000 PSI, so we'll be able to pump a little faster. Just basically put a little more weight on a bit and just put more horsepower on these wells and get them to drill faster. So looking forward to that. I think that's going to probably be in October when we get that 10K rig deployed. So looking forward to that. We've also got a second rig that we're in talks with to be upgraded to 10,000 PSI. If that works like we expect it to, all of the rigs in the western hines will eventually be upgraded to 10,000 psi. On the frac side, we've been talking for a while about this 20,000 pound frac fleet. That's obviously a pretty good capital investment.

We're just still working through some particulars with our industry partners on maybe how we could... how we could, you know, put that together to make it work for us.

Great. Thanks a lot. Thank you. Our next question comes from Carlos Escalante with Wolf. Your line is open.

Hey, good morning, team. Thank you for taking my question today. your headlines. I always look at that. Tells me what your heart's saying. Oh, Lord, Jay. Well, thank you. We can take that offline. Dan, question for you on the completion side. I guess we want you to help us parse through the headline B and C cost, cost trend, particularly as you've been ramping on your, uh, pound per foot on the prop end side. And you've been, uh, fracking on tighter stages. I wonder if you can perhaps walk us through, You know, what batch of wells do you think it would be a good proxy for us in the market to look at and perhaps for us to think, okay, well, this batch of wells is close to what they think is the ultimate completion design because it does feel like you feel good about the larger fracks overall.

So I wonder if you can maybe point us to which wells or maybe which batch of wells across the last three to four quarters we can hang on to and look towards the future and determining whether or not the larger fracts are working and are meeting your expectations.

on the EUR front? We had... So all of the wells, we talked about going to the higher profit loading. So basically, when we... when we went to the higher profit loading, all of the wells that we completed, that we turned to sales in Q2, was the first batch of wells that we used you know, systemically went up to the larger profit loading. Now we did pop a larger frack on one of the really earlier wells, but And Q2, so, you know, we, those are the oldest ones have been on now for maybe three months, two or three months that we turned the sales in March. We had some that we pumped at 5,000 pounds per foot, some at 6,000 pounds per foot. It will definitely take time to see how they decline out, but the initial results look really good. The flowing pressures look really good at the time rates you know at the IP rates we're having that with you know and we're obviously managing the drawdown very conservatively and maintaining that high flowing pressure on them.

Got it. Got it. And so just to clarify, did you ramp the prop unloading at the same time you started doing tatter frag stages, or were those independent of each other?.

Those are independent of each other. So we went to the tighter cluster spacing in the smaller stages. last year and had, you know, when we were still pumping our standard frac design at 4,000 pounds per foot, we've maintained that you know, spacing, smaller stage space, and we've maintained that as we've increased the profit loading.

Okay, that makes sense. And then my follow-up, and I hope this is going to make sense, but because you're executing an ongoing HBP campaign where presumably most of your initial leases perhaps conform to set of unit optimization parameters. Is it fair to say that since you're working on that were signed five years ago and you're holding a pitch today, that because of the age of them, that you were confined there and have been confined to drilling or being you're being constrained to drilling shorter laterals than you would like today. if it was an HBP-free campaign, if you will, and you were purely trying to optimize and appraise wealth the best way you could.

but definitely the drilling program like we said it's based on holding acreage and in the age of so it's not able to look to see the most optimal places you can drill or the And then that's been the nature of the drilling program. And it'll slowly shift. We're able to drill some. fill wells later, but that's the nature of it. That's correct. You're really looking at using your program to make sure you put these term leases into held by production status.

Yes, I think that's the point, Carl, because we haven't drilled on a pad for infill development where you drill six, seven, eight, nine, ten, or fifteen wells off a pad. We have not attempted to do that at all, even though you've got the gathering there, you've got the you've got cost to come down materially. What we attempted to do was on a very cautious basis, we tried to lean into technology. We have looked at our debt level. We wanna manage our debt level. We wanna improve execution. And along the way, Carlos, again, I read everybody's research report. I think to kind of hold hands here together.

That Dolly Jones well, Dolly is a big word and Jones is a big word. You stick them both together, Dolly Jones, it should be a big whole well success, eight and a half inches. We're delivering that. I think that if you hold hands and you've got NextEra out there, NextEra sees abundant reserves. They see what others don't have. We have pipelines, transmission infrastructures. They're already on the ground. It's a perfect site between Dallas, Houston and Austin. And then you're really, really looked at hard with Sixth Street.

That should make Carlos you happy. They managed $135 billion. They see this growth and they see the need for Pinnacle. So all of this leans into this demand that we will have because the dollars are being spent, whether it's for data centers or LNG. I mean, we're going to need another 13 plus Bs between now and probably 2031, and that is without data center gas demand. Those are the things that we're doing, and we under the microscope every 90 days so you gotta you gotta endure a little bit of this and knowing we commit to you that you know almost 38 nine years you've been doing this we will not waste your money period we don't do that.

Yes, I appreciate it. And really not to hijack here the conversation, but just to drive the point home. What Dan said that when drilling costs per foot are going to come down and completion costs are going to go up because of the larger price. So all things equal, it's going to be roughly the same. That does not include and that does not factor in larger.

had developments where your overall cost, because you have synergies, are going to come down. Is that fair to say that? Right, you're kind of comparing this play to a very mature play in the legacy Hainesville, where this cost was incurred years ago, and now we're just drilling wells that have pads that we've already paid for. Here a single well is bearing all these costs. So I think the future costs are going to be significantly lower than our current costs now, just for the nature of developing. uh, out what we've proven up, you know, and, and perfecting, uh, you know, the completion design and the drilling design, you know, and, and, uh, and I do think that, you know, the other, the other element is, uh, we do feel like, you know, given the pressure of the reservoir, um, the quality of the formation that we've now taken cores and studied. You know, we do think that larger fracts are going to yield larger EURs and... of the gate, like the wells completed this quarter, the pressures are significantly higher than, and I think that's going to bode well for their EURs, but we're going to have to let them have some time to prove that out.

Yes, Carl, it's like, you know, we, like Roland said, if you go to the Barnett or you go to the Parmy in Delaware or the Midland Basin, you go to our Legacy, those interstate highways have already been built. And then they come back and build buildings along the side of them. We're building the road. And then we own everything on the side of it. And where are we going? Well, we're going to the federal power generation hub. tremendous upside of where we're going. And that should begin in a lot of part 2728. But that's where we're going in. It's in Anderson County. I mean, we created that story.

story and every 90 days you get to look at it. Thank you. This concludes the question and answer session. I would now like to turn it back to Jay Allison for closing remarks.

You know, they say the fewer words you say, the less you have to be accountable for. So my closing is thank you for having your ears tuned to a definitely pure play natural gas company.

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

This live transcript is auto-generated without human intervention or review.

[Call has ended.]

Good day, and thank you for standing by. Welcome to Q1 2026 Comstock Resources, Incorporated earnings conference call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Thank you, everyone. Thank you for joining us. Welcome to the Comstock Resources First Quarter 2026 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 First Quarter 2026 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 presentation 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.

If everyone would please go to Slide 3. On Slide 3, we summarize the highlights of the first quarter. Lower production, partially driven by production impacts from significant winter weather in the first quarter drove the lower financial results in the quarter compared to the first quarter of 2025.

Our natural gas and oil sales were $339 million. We generated $192 million of operating cash flow or $0.66 per share. Adjusted EBITDAX for the quarter was $251 million, and we reported adjusted net income of $44 million or $0.15 per share.

During the quarter, we had very strong drilling results, which will drive production back up for the remainder of the year. Almost all the wells we turned to sales in the first quarter were very late in the quarter. Since our last update, we put 6 new Western Haynesville wells online with an average per well initial production rate of 29 million cubic feet per day. In our legacy Haynesville, we turned 10 wells to sales with an average lateral length of 12,312 feet and a per well initial production rate of 31 million cubic feet per day.

Now the Power Generation Hub. On March 19, the United States Department of Commerce selected our Western Haynesville site to host a new 5.2 gigawatt natural gas-fired power generation hub to be located in Anderson County, Texas, as shown on Slide 4. We are very excited about this development and what it means to have a large commercial customer in our backyard. The project is part of Japan's $550 billion investment commitment in the United States as part of the U.S.-Japanese trade deal. The U.S. and Japan would own the projects while NextEra Energy Resources will develop, build and operate it.

NextEra is actively developing the project, advancing site development, procurement, permitting and commercial structuring as they work toward definitive agreements with the U.S. and Japan. This project takes advantage of our abundant natural gas supply and a strong transmission infrastructure in the area. The Anderson County facility will have up to 5.2 gigawatt of natural gas-fired generation capable of serving up to 5 gigawatts of large load demand. Comstock will provide the natural gas supply for the facility, which could reach almost 1 billion cubic feet per day by 2031.

Roland will now provide some more details from the financial results we reported yesterday. Roland?

All right. Thanks, Jay. On Slide 5, we cover the first quarter financial results. Our production in the first quarter averaged 1.1 Bcfe per day. Oil and gas sales after hedging in the quarter were $339 million, reflecting the lower production level we had in the quarter. EBITDAX came in at $251 million, and we generated $192 million of cash flow during the first quarter.

We reported a $107 million profit for the quarter or $0.38 per share, but included in that number was a pretax $83 million mark-to-market unrealized gain related to our hedge book. So excluding the mark-to-market gain, exploration expense, which is related to seismic that we're shooting in our Western Haynesville play and other nonrecurring items and the related income tax effect of those items, we reported adjusted net income of $44 million or $0.15 per diluted share for the quarter.

On Slide 6, we break down our natural gas price realizations in the quarter. The quarterly weighted average NYMEX settlement price averaged $4.96 in the first quarter and the weighted average Henry Hub spot price was at $4.90. 26% of our gas was sold in the spot market, so the appropriate NYMEX reference price would have been $4.94 for our production. Our realized gas price during the quarter averaged $4.27, reflecting a $0.69 basis differential compared to the NYMEX settlement price and a $0.67 differential compared to the reference price.

Significant disconnects existed during the quarter between the regional hub prices and NYMEX, kind of drove the higher differentials in the quarter. We also had to purchase higher-priced gas to make up for shut-in production during the winter storm event.

In the quarter, we were also 72% hedged, which reduced our realized price down to $3.45. We did improve the overall price realizations by $0.05 to $3.50 with our third-party gas sales during the quarter.

On Slide 7, we detail our operating cost per Mcfe and our EBITDAX margin. Per unit costs were negatively impacted by the lower production level in the quarter as much of our field costs are fixed. Our operating cost per Mcfe averaged $0.93 in the quarter, up $0.16 from the fourth quarter rate. Both lifting costs and G&A were up $0.04, attributable to the lower production level.

Production ad valorem taxes increased $0.03 due to the higher gas prices in the quarter. And our gathering costs were up $0.05, mainly due to some prior period adjustments that we recognized. Overall, our EBITDAX margin in the quarter was 73%.

On Slide 8, we recap the spending on our drilling and other development activity in the quarter. We spent a total of $343 million on our drilling program. We drilled 11 or 9.3 horizontal Haynesville wells and 6 or 6 net Bossier wells for a total of 17 wells in the quarter or 15.3 net wells. We turned 13 wells to sales or 11.7 net wells, which had an overall average per well IP rate of 31 million per day.

Slide 9, we summarize our capitalization at the end of the first quarter. We ended the quarter with $350 million of borrowings outstanding in our upstream credit facility. Our upstream borrowing base is $2 billion, and we -- and our elected commitment under our facility is $1.5 billion.

In March, we entered into a new $150 million midstream credit facility for Pinnacle Gas Services. At the end of March, the midstream credit facility had $47 million outstanding. Our last 12 months ratio was 2.9x. At the end of the first quarter, we had almost $1.3 billion of liquidity.

I'll now turn it over to Dan to discuss our operations in the quarter.

Okay. Thanks, Roland. Over on Slide 10, this is just our updated overview of our acreage footprint in the Haynesville and Bossier shales across East Texas and North Louisiana. We now have 1,074,868 gross acres and 806,980 net acres that are prospective for commercial development of the Haynesville and Bossier shales. On the left is our Western Haynesville footprint, which we have now grown to over 540,000 net acres. And on the right is our 266,570 net acres that's in our legacy Haynesville area.

We currently have 36 wells producing on our Western Haynesville acreage, which is relatively undeveloped compared to the legacy Haynesville area. And of course, with the higher pay thicknesses and the very high pressures we incur in the Western Haynesville versus the legacy core, we expect the Western Haynesville will yield significantly more resource potential per section than our legacy Haynesville.

On Slide 11 is our current drilling inventory in our legacy Haynesville area at the end of the first quarter. Our operated inventory in the legacy Haynesville now consists of 955 gross locations, 740 net locations, which equates to average working interest of 78%. On our non-operated inventory in the legacy Haynesville, we have 819 gross locations with 98 net locations, which is a 12% average working interest.

Our drilling inventory, we split into 4 buckets. We have our short laterals less than 5,000 feet. We have our medium length laterals that are from 5,000 to 8,500 feet. Our long laterals between 8,500 and 10,000 feet and our extra-long laterals are everything over 10,000 feet. Within our gross operated inventory in the legacy Haynesville, we now have 30 short laterals, 141 medium laterals, 337 long laterals and 447 extra-long laterals.

The gross operated inventory is pretty much split 52% in the Haynesville and 48% of our locations in the Bossier. Our legacy Haynesville inventory also includes 114 gross horseshoe locations with 53% of those being in the Haynesville and 47% in the Bossier. Over 80% of our gross operated inventory have laterals that are longer than 8,500 feet long. And as of today, our average lateral length in the legacy Haynesville inventory has climbed up to 10,019 feet. So this inventory provides us with decades of future drilling locations based on our current activity levels.

On Slide 12, we show our estimated drilling inventory in the Western Haynesville. Our Western Haynesville inventory consists -- currently consists of 3,331 gross locations, 2,546 net locations, which equates to an average working interest of approximately 76%. The number of our net locations is estimated since much of our Western Haynesville acreage has not yet been unitized. Our Western Haynesville inventory is more weighted to the Bossier formation with nearly 2/3 of the inventory in the Bossier shale and 1/3 of the inventory is in the Haynesville shale.

And we also have our Western Haynesville inventory divided into the 4 separate groups by length, with our short laterals less than 5,000 and the medium laterals between 5,000 and 8,500 feet and the long laterals between 8,500 and 10,000 feet and the extra-long laterals over 10,000 feet. So in our Western Haynesville gross operated inventory, we don't have any short laterals today. We got 1,319 medium laterals, we have 646 long laterals and 1,366 extra-long laterals. So 60% of our Western Haynesville gross operated inventory has laterals greater than 8,500 feet.

On Slide 13, just an update to our new horseshoe development program. The horseshoe well design, of course, combines the 2 separate and adjacent shorter laterals into a longer single lateral, which results in a much more efficient use of our capital. On average, we realize 35% savings in our drilling cost when we drill a 10k horseshoe well compared to 2 5,000 foot sectional lateral wells.

Our drilling inventory in our legacy Haynesville area now includes the 114 horseshoe locations. The Camptec 29-14-9#2 was turned to sales in the first quarter with a 41 million cubic feet per day IP rate, and we plan to drill a total of 16 horseshoe wells total in 2026.

On Slide 14, there's a chart outlining our average lateral lengths drilled that are based on when the wells have been drilled to total depth. The average lateral lengths are shown separately for the legacy Haynesville and for the Western Haynesville areas. In the first quarter, we drilled 12 wells to total depth in our legacy Haynesville area, and these wells had an average lateral length of 10,872 feet. The individual laterals range from 8,497 feet up to 15,772 feet. Our longest lateral drilled to date on our legacy Haynesville acreage still stands at 17,409 feet.

In the first quarter, we also drilled 5 wells to total depth in the Western Haynesville and these wells had an average lateral length of 10,356 feet. The individual lengths range from 9,400 feet up to 11,393 feet.

Through the first quarter, our longest lateral drilled in the Western Haynesville stood at 12,763 feet. As of last month, we have since exceeded that length in the Western Haynesville with a new record lateral length of approximately 14,800 feet. The well, which is the Dolly Jones RP #1H, reached total depth in mid-April, and we have it scheduled for completion later this summer. So to date, we have drilled 47 wells to total depth in the Western Haynesville. That includes 21 wells with laterals over 10,000 feet and 7 of the wells had laterals over 12,000 feet.

On Slide 15, this outlines the 10 wells that we turned to sales on our legacy Haynesville acreage since our last call. The average lateral length on these was 12,312 feet and the individual laterals range from the low end of 9,465 feet up to a high of 15,143 feet. The individual IP rates on these wells range from a low of 15 million a day up to a high of 41 million a day, and the average IP was 31 million a day. And 5 of our 9 rigs are drilling on the legacy Haynesville acreage.

Slide 16. This one outlines the 6 wells that we have turned to sales on our Western Haynesville acreage since the last call. So these 6 wells had an average lateral length of 10,874 feet with an average initial production rate of 29 million cubic feet per day. And we have 4 of our 9 rigs that are currently drilling on our Western Haynesville acreage.

On Slide 17, this highlights the average drilling days and our average footage drilled per day in the legacy Haynesville area. And this is for our benchmark long lateral wells that are greater than 8,500 feet long. In the first quarter, we drilled 12 of our benchmark long lateral wells to total depth in the legacy Haynesville area, and we averaged 26 days to TD.

In the first quarter, we averaged 921 feet drilled per day in our legacy Haynesville acreage, which represents a 3% increase versus the fourth quarter of 2025. Four of the wells drilled in the first quarter were our horseshoe wells, which do take -- it takes a few extra days compared to our normal straight levels.

Slide 18. This highlights our drilling progress in the Western Haynesville. During the first quarter, we drilled 5 wells to total depth in the Western Haynesville. This now gives us a total of 44 wells that we have drilled to total depth through the end of the first quarter.

We averaged 57 days for the 5 wells drilled to total depth during the first quarter. This is an increase of 3 days compared to the fourth quarter. You can see this is also reflected in the drilling speed of 478 feet per day during the first quarter, which is 4% lower than the fourth quarter.

Aside from drilling issues we have, our quarter-to-quarter drilling performance in the Western Haynesville is mainly dictated by our vertical depth, our temperatures and our lateral lengths, and this varies considerably across our acreage footprint. So where the wells are being drilled has a big impact on our drilling performance numbers quarter-to-quarter. Our fastest well drilled to date in the Western Haynesville still stands at 37 days, and it was drilled with a 12,045-foot lateral.

On Slide 19, this is a summary of our D&C cost through the first quarter for our benchmark long lateral wells that are located on our legacy Haynesville acreage position. These are laterals greater than 8,500 feet. These costs reflect all of our legacy area wells with greater than 8,500 feet. The drilling costs are based on when the wells reach TD and the completion costs are based on when the wells are turned to sales.

During the first quarter, we drilled 12 of our benchmark long lateral wells to total depth. The first quarter drilling cost averaged $700 a foot. This is a 3% increase compared to the fourth quarter. The increase in the first quarter drilling cost is the result of a combination of factors, mainly being overall short average lateral length in the first quarter, we had a higher number of horseshoe wells drilled and we also had more wells drilled in our East Texas area, which does require additional casing strings that we use to isolate the localized overpressured SWD zones in that area.

During the first quarter, we also turned 8 of our benchmark long lateral wells to sales on our legacy Haynesville acreage. The first quarter completion cost came in at $652 a foot. This is a 9% decrease compared to the fourth quarter. This lower completion cost is due to a combination of using less horsepower and having higher frac efficiency and with a slightly lower drill-out cost.

We're currently running 3 full-time frac fleets. This is after we added our third frac fleet in January. We are adding a fourth frac fleet this month, and we're planning to maintain running 4 frac fleets through the end of the year.

On the drilling side in the legacy Haynesville area, we have continued field testing with our rotary steerable drilling, BHAs, and we're really continuing to make good progress there. So as we accumulate more data and we make further refinements there, we do expect this rotary steerable technology is going to play a larger role in our future drilling program to help drive more cost reductions.

On Slide 20, this is a summary of our D&C cost through the first quarter. This is for all our wells drilled in the Western Haynesville. During the first quarter, we drilled 5 wells to total depth in the Western Haynesville. This is with an average lateral length of 10,356 feet. Our first quarter drilling costs average $1,534 a foot. This represents a 3% increase compared to the fourth quarter. During the first quarter, we also turned 5 wells to sales in the Western Haynesville that had an average lateral length of 11,177 feet.

And our first quarter completion costs averaged $1,537 a foot, which is basically unchanged compared to the fourth quarter. And then also to reiterate what was mentioned earlier, our drilling and completion performance in the Western Haynesville is greatly affected by where the wells are being drilled on the acreage as there's much variability in the vertical depth and formation temps along with the lateral lengths.

And we're also implementing our new performance initiatives that we expect will lead to further time savings and cost reductions. We do have one of our existing Western Haynesville rigs being upgraded to a 10,000 PSI rating that's going to be available to us by late summer. With this upgrade, we will be able to increase the drilling speeds in both the vertical and horizontal hole sections, further reducing our cost.

We also intend to test some new higher temp rated drilling motors later this year, which we expect will lead to faster drill times and some longer runs. Once we get more successful and consistent runs of the rotary steerable drilling system in our legacy Haynesville area, we will be looking to deploy this technology into our Western Haynesville area.

I also mentioned it earlier, but we also drilled our record longest lateral to date in the Western Haynesville with a 14,800-foot lateral and the well surpassed our initial performance expectations. The well was drilled with a larger hole size in the lateral, which allowed us to use larger insulated drill pipe, which leads to lower downhole temperatures, more reliable motor performance from the downhole drilling assemblies and longer motor life.

So we plan to implement this new well design in more of our future wells, which along with the other performance initiatives being undertaken are going to lead to significantly lower, more predictable cost structure for our future wells.

I'll now turn the call back over to Jay.

All right. Dan, thank you. Roland, thank you. If everyone would please turn to Slide 21. I know we are dealing in a 90-day capsule on this call. I understand that. But the Comstock story over the past 5 years has been defined by our quest to add substantial drilling opportunities in the Western Haynesville, not just the last 90 days capsule.

Over that period, we have leased or acquired drilling rights on 728,000 gross acres, comprised of approximately 30,000 individual leases over that 5-year period. Overall, our leases have favorable terms supporting our development program. And as a result of that program, over 5 years, not the last 90 days, we now have 2,546 net locations identified on our acreage. We have been joined by 3 other companies now who are actively drilling and working in the Western Haynesville Basin.

The Haynesville shale is viewed in our opinion as the most important basin to supply natural gas to Gulf Coast LNG facilities and now to data centers being built in Texas, Louisiana. The arrival of the Western Haynesville is the game changer as the market looks into the future to where the needed natural gas will come from. They all ask that question.

Now our relationship with NextEra, which goes back to 2015, combined with our ideal locations and the drilling results that Dan has just talked about in the Western Haynesville, it led to the March 19, 2026 announcement of what? That the U.S. Department of Commerce selected our Western Haynesville site to host a new 5.2 gigawatt natural gas-fired power generation hub to be located where? In Anderson County, Texas.

So our current goals for the company, they're fivefold, and the fifth one you'll really want to hear. Fivefold. Number one, enhance our legacy Haynesville drilling program, which we accomplished by adding 114 horseshoe wells to our near-term drilling program, which Dan talked about. They're fantastic performing wells. Currently, 3 of our 5 rigs deployed in our legacy Haynesville area are drilling horseshoe wells.

Two, strive to continue to be the low-cost operator. The combination of having the lowest cost and an abundance of drilling inventory closest to the growing natural gas demand will drive the market value for Comstock.

Third, obvious, continue to protect the balance sheet, which was greatly helped by the divestitures we made in 2025 and by our robust hedging program as outlined on Slide 22 as well as our strong financial liquidity of almost $1.3 billion.

Four, support the build-out of our midstream company, Pinnacle Gas Services. The formation of Pinnacle Gas Service by us in 2023 to gather and treat our natural gas in the Western Haynesville not only supports our drilling program, but also led the Power Generation Hub opportunities.

By controlling our midstream, we'll be able to keep our producing cost low and capture the future value by owning the infrastructure. PGS is now in a position to have its separate credit facility, and we believe we're nearing the end of a very, very strong process of finding an equity partner to allow us to continue to grow our midstream footprint and to take advantage of future opportunities to connect the Western Haynesville to premium markets.

And finally, number five, which is what most of this conversation has been on, optimize the drilling and completion of our wells in the Western Haynesville. Of the 44 wells we have drilled through the first quarter, many have different vertical designs and they were drilled to various depths with laterals of various lengths, which were drilled and completed with different methods and tools as Dan has gone on and on about.

We've also produced the wells by employing different drawdown levels. The well performance has varied, which should be expected in a new shale play. That is the good news as we are very encouraged that we are cracking the code on the best way to drill the wells and complete the wells to unlock what? Tremendous natural gas value and wealth in the future.

Now I want to thank you for your time today. There will be questions. I'll turn it over to Ron, if you want to call in and ask Ron questions. And I also want to make one more comment. As an initial founder or developer in the legacy Haynesville in 2008, we learned from mistakes that were made there, but we did learn and we understand -- and the thing that we didn't want to do in our 700-plus thousand acres in the Western Haynesville, which might have unprecedented wealth because it has been a wealthy basin 20, 30 years ago, is to make the mistakes that were made in the legacy starting in 2008, '09, '10. That's 4 million acres in the legacy.

We have about 800,000 acres that we think are in the Western Haynesville. The mistakes that were made were drilling too fast because leases were expiring, and you destroyed value. The rocks are established. They cannot move. What we have to do as a company is we have to make those rocks valuable. And the way we do that -- and I understand cash burn and slow pace of resource delineation is a little taxing. I get that. But that is what we're doing to create the value that we already possess.

So now with that, I'll turn it over to ask questions.

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

I appreciate the...

Carlos? Carlos?

How are you, Jay?

Thank you for headlining cash burn and slow pace of resource delineation risk, investor patience. I love that headline. That's why I brought it up in my narrative because I think that's exactly right. That is not a negative. It's a positive. But it's not a positive for everybody. So I just want you to know that, okay? Thank you for being honest and coming up with that headline. It helped me.

Sure. And I appreciate you saying that and giving an overview on how you feel about the long-term value proposition. So why don't we start there. If you don't mind, maybe you can expand on your initial thoughts. But you're dealing with a tough gas state as are all of your other peers, that on your current plan, as you mentioned, may extend the period of that cash burn.

So how patient do you expect investors to be, acknowledging that there is a long-term value proposition, but that you still have to get through X amount of quarters where your production and your capital at times hasn't been in line with or aligned with what you've stated in the quarter prior. If maybe you can frame that for us, that would be tremendously helpful.

Well, Carlos, I think, number one -- and this is hard. It's like going into the first day of advanced math and not understanding anything and barely remembering your teacher's name when you walk out because it's so confusing. But if you look at our business plan, yes, we did miss production in the quarter by 10%, 12%, 13%, whatever the number is, and our CapEx was higher. Well, if you have our business plan, which is -- no is a big word, but it's no M&A. If you throw M&A in here, you issue equity, typically, you add production and you add inventory and you kind of stir up the pot every quarter, every year. We have not had M&A.

So if you don't have M&A, the only way you can increase production, which it will be a time lapse. It may be 90 days, 120 days, but there will be a lapse. Because if you're trying to protect your balance sheet last year and you lay down 1, 2, 3, 4 rigs, you're going to lose that production a year later.

So what happens is it's a day of reckoning. We laid down the rigs. We didn't do M&A. We kept adding a couple of 2,000 or 3,000 acres every month through our Western Haynesville, and most of that is the best of the best acreage, and we kept spending that money.

Now in order to turn the cycle, we did sell $445 million of assets that in our business plan were not important to us in the next 15 years. But when you do that, then you pay down that debt. And then what happens? Well, you're going to have to lever up a little bit.

And we did say that we would outspend maybe $400 million, $450 million, whatever. That depends on the price of natural gas. What you see in this quarter is production was down. Yes, we missed it, headline missed it. We'll put some positive headline out there about the biggest data center in the U.S. I don't see that out there from some of you.

But yes, we missed production. And CapEx was up a little bit. But if you don't do M&A and you don't puke up equity all the time by issuing equity to everybody when you buy stuff, what happens is you have a quarter like we have. We protect every share of equity that everybody has. Production is down. But you know what? Now you see production up. Our production should be up 13%, 14%, 15% for the second quarter. I think, Carlos, we have turned the corner.

And the corner is hard. You know that 90 days is hard because you have to actually spend money on those 4 new rigs. You have to have these horseshoe wells really work. You have to have Dan Harrison have the freedom to figure out the best way to drill and complete repeatable Western Haynesville wells in both the Bossier and the Haynesville, and they can be 90 miles apart from each other, much less 20 miles from the east and west direction. So I think, Carlos, we've turned the corner.

Now maybe the second quarter, because we did add that fourth frac fleet, you'll see a little bit of hesitance in there. But the well performance is good. The dollars that we took last year, we paid down our debt, and we're not doing anything radical to destroy value in the Western Haynesville.

And like I said, the acreage that we have -- if you keep the 4 rigs busy that we have right now in our Western Haynesville, every acre that we own will be HBP, every acre with those 4 rigs. And we don't even have to have those 4. So the plan works.

In the past, Carlos, you'd say, well, you bought another 15,000, 20,000 acres. It's another $20 million, $30 million. You kind of hit us on the nose for the quarter. We don't plan on that. We don't see that out there. We don't see it. We see 1,000 or 2,000 acres every month. And if we could get more, we'd get it. But it's not out there to be taken. So that's where I think we have crossed the bridge. And what we're talking about now is a bridge we crossed is a hard bridge to cross. We've crossed it now. Let's look at where the future is going.

Sounds great to me, Jay. I appreciate the answer on that. My follow-up will be to you, Dan. Can you talk briefly about the Hutto Rodell IP? It looks like it underperformed the broad group and really the initial production rates of all the wells that you brought online -- the average of all the wells you brought online in the basin. So wondering if you can qualify for us what was the root cause? Was it completion design, geology?

And what specifically changes can you make on your next pad to prevent whatever was the case that drove this underperformance relative to your very solid and quality-like IP rates on the Western Haynesville?

Yes. Well, that's a good question. And I'll give you the really quick answer and then I can give you a little bit more. So...

Give him the more.

So we've drilled -- of the 36 wells that we've got producing, we got 7 of them that we've drilled. I call it uphill. The laterals go basically up, instead of going down. Most of them go down quite a bit just due to the geology. But this -- the Hutto Rodell is the furthest one by far as far as the TVD difference between the hill and the toe. I mean, it's nearly 1,400 feet from the hill to the toe.

And so the main reason we didn't get a good IP on this well is this well made a lot of water during flowback. All during flowback, we were making really high water volumes. And the same with wells in the core. Or no matter where we're at, if you're making a lot of water, it's just hard to get a high IP rate.

So that's why we didn't get a good IP rate on the well. We are still kind of trying to triangulate and zero-in on really is it may be more than just the geometry. It may be some geology involved. We did have -- our Brown Trueheart BB well is, I'll say, next to it. It's about a mile away. But they were both Haynesville targets, they both drilled uphill. The Brown Trueheart didn't go as far uphill, but it also made a lot of water during flowback. We got a little bit better IP because the water wasn't quite as high.

But those are -- of the 7 wells we drilled uphill, those 2 wells, the Brown Trueheart BB and the Hutto Rodell, are in our deeper pay, those deeper TVDs, 17.5 to 18.5, 18.8 range. And both of those wells made a lot of water during flowback.

Now we have drilled 5 wells up on our shallower acreage up in the 14 to 16 to 17 TVD range that also went up hill, not at 1,400 foot, but maybe up 600 or 700 foot from the hill to the toe. And those wells made a little more water during the initial part of flowback. By the time we released flowback, the water volumes were down.

So that's why I say -- I don't know if I'm going to hang my head 100% on the fact that they were drilled uphill for the high water volumes. I think it contributes to higher water volumes. I don't know if it's the sole reason for the high water volumes.

We are fracking another well right next to those as we speak, the Jones #1, not to be confused with the Dolly Jones #1 that I mentioned as our long lateral we just drilled. This is another Jones #1, but it's right there in line with those other 2 wells. And so it is a Bossier as opposed to these being 2 Haynesville. And so we're just going to have to see how that well responds, to see if we can kind of draw a conclusion that it is the geometry or if it's maybe just the Haynesville versus the Bossier. A little bit of geology in that answer, too.

But the short answer is, when you make a lot of water during flowback, it's hard to get IPs. And we probably had -- out of the 36 -- we had 3 wells, I would say, out of those 36 that we made really high water volumes during flowback that greatly affected the IP rates.

And that's our frac water.

I mean that's load water. That's not formation water. That's correct. And this is across -- I mean, look, we're drilling from one end to the other of the wells that we've tested so far. I mean, we're looking at like 50 to 60 miles. That's like going from East Texas all the way down to the deep Natchitoches fault zone in Louisiana. That is a huge distance. And there's a lot of variability in what these wells are going to make and perform and how much water they're going to make.

So that's part of it. I'd say the other kind of comparing the Western Haynesville to the core, the core -- everything in the core -- we don't really have a lot of wells that go TVD-wise downhill or uphill. And they're all like pretty much horizontal, like maybe from 85 to 95 degrees or maybe even a little flatter than that.

In the Western Haynesville, it's different. We got wells whether -- we're drilling the hold acreage is the reason we kind of drill some of these wells uphill, a 2-well pad, one goes south, it's going down dip, one goes north or northwest, I mean, that's going up dip. So -- but we have a lot more dip. We've got a lot more dip in the Western Haynesville that leads to these higher angled wellbores.

Our next question comes from the line of Charles Meade from Johnson Rice.

Jay, I wanted to -- forgive me if this is kind of a basic question, but I wonder if you could just give us the whole picture from your point of view on this Texas Power Generation Hub. It's -- you made a bunch of announcements about it. And -- but from my point of view, it looks like you're the -- I guess you're the surface owner for where this site is going to be, at least I think that seems to be the case. You're going to supply gas to the power gen facility, but I guess that's not finalized. So maybe you could just give us an outline for what roles Comstock is playing there and how close you are to finalizing commercial terms for gas sales?

Well, I think -- so that's a great question. And I love your headlines, too. We slightly missed production, blah, blah, blah. That's good headline. I wish you would put in what we're doing with NextEra. But you asked the question. I love that.

If you look at all the dancing on the floor about AI, hyperscalers, all the things that have happened and all the things that are not funded, you can -- that's background noise to us. What has happened here is, if you have a hyperscaler in your office, most of them will say, "I really like Texas. It's a state that has a lot of natural gas, and we need it to power the generation that the NextEras of the world see." And they like it. But you have to have a location that works.

And so if you can come out, and like we've done with the Western Haynesville, and you're in a really great geographic location, there's a lot of people. You do own a big footprint. So the sky is the limit as they say. What happens is NextEra will say okay. The federal government comes in with the agreement with the Japanese and say -- the Japanese will say, "We've committed this $550 billion." The federal government then will choose NextEra and NextEra will choose where their basin may be. It goes back to that 2015 relationship we've had with NextEra. And they said, "We've done a lot of business with you in the past. We love the Western Haynes. We've been out there. This is where we'd like to have the data center."

So what happens is -- we don't own the surface. All we do as far as dollars spent, Charles, is we provide the gas. In other words, the obligations to build and stuff like that, we don't have that. What we have is we provide them the gigawatt, the 5 gigawatts, the 1 billion, whatever it is. It may grow a lot higher than that to provide the data for the turbines. So it's a really great event because it's at the United States government level. It's then at NextEra's level, and it's our gas. We're a natural gas company.

So whatever the big packages under the Christmas tree for the benefits, which will be the profits, whatever they are, you just wait and open those up when everybody else has discussed what the terms will be and when you have your first power that's needed. But it is unimaginable that we would be the one that would have the acreage that we captured to have the upside and the midstream. You have to have the midstream to provide that gas, to provide what NextEra sees as a huge role for U.S. shale gas to power AI hyperscalers and data centers.

Got it. And then if I could actually ask a follow-up about the Western Haynesville. I really like these maps. I'm looking at Page 16, where you give us the red dots on where these -- where your recent well results are. And I'm wondering if you could talk about the wells that are -- it looks like you had 2 wells that are further up dip. And if you could talk about what you're seeing as far as how the play changes. I'm guessing you have probably lower D&C because it's less vertical depth, but what you're seeing with the productivity on those wells as you move up dip also.

Yes. And I'm going to let Dan do that. I want to put a little asterisk on that, Charles. If you were to look at where we drilled in the Circle M in 2022, we produced at 8 months in 2022 and then we started drilling in '23, '24, '25. If you were to go where we have drilled several wells and you were to infill drill, I mean, you could drill dozens and dozens and dozens, dozens, if not hundreds of wells and infill drill them and you've got gathering near there on that pad site. But you want to get cost down, you could do that. That is not part of our business plan either.

That's why we went 40, 50 miles to the north to drill that Elijah one because we had seismic, we had well control. We have, I think, 1,000, maybe 100 penetrations in all this footprint we have. And then we have the seismic. And now we've got cores. But before we had the core, we'd go north because the plan was -- and that goes back to Carlos. You're going to have enough patience to delineate this. Well, in 1 year, you jump 40, 50 miles to the north. That's pretty quick delineation. They never did that in the core, not with any control.

So our goal is to keep those rigs busy. And 99% of the time is to continue to hold acreage, not infill drill around existing known repeatable locations. That's a different business plan. So now with that, I want Dan to answer that question.

Yes. So I'll definitely just reiterate the last thing he said there. We are -- all of the -- all of the locations we're drilling for the hold acreage, I'd say more than 9 out of every 10 is the hold acreage. And so those 2 -- what those 2 dots are, Charles, that's actually 2 pads right there. So those 2 dots, if you're looking at that slide, that represents those 2 Bumpurs and 2 Pollard wells at that location.

And so we drilled on each pad. We had a well to the north and a well to the south. So one of the Bumpurs goes north, the NMH goes north, the DHGJ goes to the south, the Pollard TFG goes to the north and the Pollard MBK goes to the south holding acreage. So those -- we started after looking at just what we do constantly, right, looking at well performance. We knew we probably were understimulating these wells. We need to pump bigger fracs. So all 4 of those wells were pumped with bigger fracs up in that area than what we had pumped on the offset wells in that little area there that you're looking at. And so -- and all 4 wells look really good.

And I kind of will speak -- 2 of those wells that went uphill was kind of 2 of the wells when I was answering Carlos' question earlier. We did not see -- we may see a little water in the first couple of days on flowback, but really we didn't see any big water volumes. By the time we're off flowback and getting the well IP-ed, they had pretty well dried up. So they only go uphill there about 600 or 700 feet from the hill to the toe. But they look really good, all 4 of those. We're really happy with them. That's probably 14 to 16.5 TVD range on those wells. Maybe the toe of the down dip wells may be closer to 17. But it is less pressure. They are cheaper to D&C.

As a matter of fact, the record -- a record fastest, cheapest well today, which we just referenced as the record well that we TD-ed in 37 days was a direct offset to one of those pads. It was the Jennings pad, the Jennings Lower and the Jennings FSRA. The Jennings FSRA was right next to those wells. It was up dip. We drilled, TD-ed in 37 days. We just had some great motor runs. And so we -- the EUR will be a little bit less just because you got less pressure and it's at a shallower depth, but we offset that with the faster D&C cost -- faster drill and lower D&C cost.

Our next question comes from the line of Derrick Whitfield from Texas Capital.

Jay, I appreciate your kind of bigger picture comments to open up the call. Maybe, Dan, I wanted to start with you. As you think about really some of the new concepts that you guys are testing, you highlighted this quarter the use of rotary steerable drilling systems and your first well with a big hole design. Could you perhaps speak to what these developments could mean in cost if they're successful as you think they will be?

Well, I'll talk. So rotary steerable, so that's going to probably be deployed later in the Western Haynesville. We are -- we've had several runs so far in the legacy Haynesville. The system that we're using, we probably started running it maybe 5 or 6 months ago, I want to say, and we're still making some tweaks. It's a learning process. But I'll tell you, we've had some really fantastic -- I mean, really fantastic runs to date with that rotary steerable, too. We've also had some that didn't make it very far just due to just some issues in the tool that they're getting tweaked.

But I'll say when they rolled out the same technology in the Permian Basin a few years ago, I mean, it took them 18 months or 2 years to get this tool refined to where it was humming. So it's not an overnight thing. It's -- all of these tools that work well in other basins, the last basin they come to, to get -- is the Haynesville just due to the depths and the temperatures? And so that's kind of where we're at.

We are super excited about the fantastic runs that we've had. But we need to get more of those under our belt and we need to get them done with more consistency. And then we will roll it out into the Western Haynesville because that's just a much more difficult environment with temperatures.

But a lot of -- we've run several of them on these horseshoe wells. Just super pleased with it. So a lot of running room there. I think the 10-K rig that's coming at the end of the summer, we're super excited. That's just going to give us -- we're going to be able to pump faster, just more horsepower on bottom, better ROPs, knock some days off. So pretty excited about that.

And maybe the most exciting thing is this last well we drilled that was -- we drilled the big hole laterals, 8.5-inch bit size instead of the 6.75. But we had some expectations for it when we set out to drill it. We needed a project that gave us the ability to drill a long lateral, right, because you got to spend a lot more money before you ever get to the lateral because you got all your casing strings up top that have to be a whole size bigger. The casing has to be one size bigger, right?

So before you ever get to the lateral, you're in the red basically, right? You're a little more expensive. So you have to have kind of a longer lateral that you think you're going to drill faster to make up that to breakeven or come out even cheaper. And what we did was we came out even cheaper than what we expected. So we -- our drill cost on that well was basically lower than any of these bars you see on Slide 20 on our cost per foot, slightly lower.

So we feel also -- it's a little bit more predictable than what we've done in the slim hole. And we can slide and turn a little bit more effectively than we can in the slim hole. So there's some intangible benefits from that also that we think are going to help us. We just need to drill more of them, right? I mean, obviously, you need to get the proofs in the pudding. We've only done one. It looks really good. We're going to make some changes, hopefully, up in the vertical. Kind of working on that. We think we'll make that a little bit cheaper there.

But we're super excited about it. I mean we thought maybe we need to drill 14,000 or 15,000 to have a breakeven versus the slim hole laterals we've been drilling on early. We don't need to drill. We maybe only need to drill 11,000 or 12,000 foot for it to be cost competitive with the slim hole.

Derek, going back to the question that Charles asked earlier, some of these are Bossier, some are Haynesville. So when Dan talks about a particular well -- I mean, we may -- 80 miles away, we may have another Haynesville, but it's not exactly the Haynesville that he's talking about today. In other words, they all are a little different. And that's why we saw a lot of value destroyed in the legacy Haynesville back in '08, '09, '10, '11.

Not only was there too many rigs drilling, they had leases that were expiring. So now you've got -- and then you had gas prices and natural gas prices collapse. So if we look at all of that -- and I love the point that you said, the bigger picture concept, because it's like we're planting a bunch of these seeds around and these trees are starting to grow up. But you can't do it too fast.

Even -- we're in an unprecedented bull market opportunity, I think, headed our way for LNG and data centers. I think our timing is going to be perfect for that, only because we're in the correct geographical location in America. That's the difference. But if you own the basin -- and there's just the other companies out there that they're drilling stuff, but they don't own what we own. So you have to treat it different. If it's valuable and precious, you have to treat it valuable and precious. And that's exactly what we're trying to tell everybody today.

Now that may be, yes, the wrong type of candy in the candy store and you don't like it, but that is what we are selling. And I will tell you the Board is 100% behind it, management of the Jones family. Almost every day they're in it. They understand it. And we would like to go quicker, but you can't. You'll get in trouble if you go quicker. But I think it's kind of like what Carlos had asked too. Well, I think we've turned that curve because it's production going down and CapEx going up that gives you indigestion. And I have it too and I know everybody does. But I think we've turned that curve on that.

So production should go up. We should have really great growth in the rest of this year, particularly in the third and fourth quarter. And we did add that extra frac rig. So I don't know. I just see the big sunshine out there.

So Derek, did I answer your question?

All good. And Jay, I agree with you on NextEra. When you really think about that recent development and how meaningful and differentiated it is for you within the sector, just on the scale and the nearness of development, I agree that's a big development that probably is not getting enough headline or time this morning.

I did want to get back to Dan, though, on another topic because I think this is also important in evaluating the play. Clearly, the D&C optimization stuff you guys are working through now. But just, Dan, when you think about what you're seeing right now on restricted flowback testing to date, is that an optimization now that you're likely to turn as you progress development in Western Haynesville?

I mean absolutely. I think we -- I mean, I'll just sum it up. We need to be pumping bigger fracs, better stimulation. And with those bigger stimulations, the volume of rock that you're out there touching, you need to keep it all open. If you keep it all open, you're exposed to significant, significant reserves. And so to keep it open, you have to have that really conservative drawdown.

And I'd say we're probably maybe even at slightly more conservative drawdown really this year going forward than where we were just in the last 6 months. If you get the bigger EURs, you get a lot better PV-10 values. And if you still can get that volumes within the first couple of years, you're really not going to affect your rate of return. I mean, it's going to be about the same number.

So that -- to me, that is the answer, significant resource in the ground. I mean you're talking -- just due to the thickness and the pressures. In the big fracs, you're out there touching a lot of reserves and you have to keep those fracs open. What you created, you got to keep it open to extract that -- those volumes and that value. So the bigger fracs, very conservative drawdown going forward.

Derek, we put boots on the ground. Dan and a couple of the other top-tier people in the drilling group, 2 weeks ago, they went to Germany. They had boots on the ground at the Baker plant. In other words, look and see it, touch it, what are we doing, how can we tweak it to make it better, quicker, faster. But we take them there. In other words, if they're offering to teach you and to show you what we need to be doing maybe, and they're going to spend their own money developing what we need, then we go there.

So I think it's important. Whether it's Carlos, Charles, Derek, everybody that asks these questions, we love them over here. We're giving you our best. And it comes out in a word, it comes out in an emotion. It comes out in what we do for 38 years. We give you our best, and we don't tell a weird story. This is a story that -- it's a hard story. It's the greatest story, though. So -- and again, on the equity side, every share is precious. We treat it like it's precious.

Perfect. Maybe just one more just for the benefit of investors because I know that many are thinking about it. But just philosophically on guidance. When you guys provide guidance, should we think of that as a P50 with a little bit of risking, so call it, P45, P55 range? I know you guys are giving your best on the guidance and what you think you can execute against, but just would love any color that you could share on that.

I mean we give you our best guess based on what the expectations are from a drilling and completion time frame, Derek. I don't know what else to say about more than that.

I think it's -- I'd say the Western Haynesville -- we've got the legacy versus the Western Haynesville. The legacy has probably been a little bit more predictable to date than the Western Haynesville. But I think with the more conservative drawdown -- the bigger fracs, the more conservative drawdown is going to make the -- guiding the Western Haynesville volumes more predictable, I think, than looking forward than looking backwards.

Yes. And pure volume in the Western Haynesville will take out some of the lumpiness.

Our next question comes from the line of Leo Mariani from ROTH.

I wanted to kind of turn to the funding side a bit here. So obviously, you guys secured the Pinnacle credit facility here, which you mentioned briefly. It looks like that you guys are consolidating that. It is on your balance sheet. I wanted to get a sense. Is that debt recourse to Comstock there? And then just additionally, you've spoken about other financing needed at the Pinnacle level. I know you're attempting to take Quantum out, which I guess supposedly pays them. So is there additional equity as well that you're looking to raise at the Pinnacle level? Or you think you're going to be good with this credit facility for the near future?

That's a good question, Leo. We are running a process to raise equity in Pinnacle and that we hope we can report on that at the next conference call. That's going very well. It's a great opportunity to bring in more of a common equity partner versus the preferred equity partner we have with Quantum. So we have that opportunity to not only redeem the preferred units, which have a big distribution on them and bring in a common equity partner, which will -- and I think we'll raise a little extra equity to help pay down some of the -- add a little equity to Pinnacle along with the credit facility.

So it isn't a -- the way the midstream is being built out, it's -- obviously, you have to build everything before and be ready for the wells and do everything way ahead of the volumes. And so we're -- we have done that and spent a lot of capital heavy upfront with our second frame being put in. It will be operational this summer. Once that's done, we'll be -- have a lot of treating capacity and we'll really just be spending money on going out and picking up the wells as we go forward. So the CapEx will be a little bit lower as you go forward in Pinnacle. And then the volumes will show up for that off in the future. That's the nature of the midstream operator.

But I think that we're hoping that the process -- like I said, Jay said it's going well. We'll have that resolved soon. And we think that should maybe even highlight the value that the midstream company will have. I think it will start to have a lot more visibility in the number. And yes, it is all consolidated as we have the majority interest and have full control of the entity. And it is in a separate credit structure. So it's -- the upstream has its complete structure that includes the bonds and the credit facility and the midstream has just the credit facility and 2 separate credit structures, and there's no recourse between the 2 with each other.

Leo, I think that Quantum was a perfect partner for a while, perfect, perfect, perfect. And then the way their funds work is that if we can pay them off, which we will, and get a longer-term equity owner, years and years and years of investments, to grow the gathering and we control it, that's the next step. And there's been pent-up demand, as I've told you. And we should see good results in that in the near future.

Okay. That was very thorough, guys. I really appreciate all that additional color. Just wanted to jump back to the Anderson County 5-gigawatt facility here. Could you provide a little bit more color in terms of where we are these days on the commercial negotiations for gas supply? Is it still a bit of a competitive process? Are they talking to kind of multiple parties? Or are they just kind of honed in on Comstock at this point in time? And can you give us a sense of like -- maybe I don't know where the talks are these days, but is there any kind of high-level indication of how that gas could be priced?

We don't make any comments on that, Leo. That's a much bigger question than you're asking. So we don't comment on that.

I would only add, though, that if you can see this in NextEra's comments that our agreement is that we are the gas supplier. So it's not -- but we are -- all the negotiations involved a lot of parties. And so that's what's ongoing. So we think that's a process that NextEra is controlling. But they were clear in their earnings call that the gas was coming from Comstock. So that's not something to debate.

Yes. Great question. Nobody has the answer disclosable now.

Our next question comes from the line of Jacob Roberts from TPH & Company.

Maybe starting on Q1 realizations. I understand there's a lot of moving pieces and maybe a bit of a onetime event. But just curious if you could speak to any key takeaways from the quarter in terms of how you think about marketing in the future.

Yes, I think the -- and the Q1, it was a very volatile quarter for gas, both spot prices and the first of month prices have huge variability. We had very unusual February, where the NYMEX price got set very high at the last minute and then spot prices were almost 50% of that almost immediately when the month even opened up. So you had a very strange quarter. You had a -- and then we're also kind of impacted by some production that had to be shut in during the storm event, and then also the delays that got created with a lot of wells that were going to come on. Several week delays in wells that didn't get to come on because you couldn't -- we had to shut down the frac equipment, couldn't move drilling rigs, et cetera, because of the bad road conditions, especially in Louisiana. So just a lot of noise there.

I don't -- we think that was especially in the Haynesville and -- but we don't think that's a real -- something to really take forward. And you could get back to a more normal gas market. We tend to try to have about 75% of our gas nominated to sell on a first month basis and 25% in the spot to allow us to adjust if there's a well down or just the new wells coming on. And that's kind of our philosophy. And that kind of matches -- we have about 55-plus percent of our gas hedged. So we want to have that -- those hedges are really tied to that first of the month. So you don't want to tie those to the spot prices.

So I think our philosophy will be similar. I think we would have been maybe better served in the first quarter if we just had more production available on the spot market. We probably could have realized a lot better price. I think having not much gas to make up the first of the month commitment probably hurt us on the realization during the time you had high gas prices.

I appreciate the response. Jay, your comments are well taken in terms of trying to develop this asset the right way. And I'm going to circle back to the Western Haynesville. Our investor conversations remain focused on the state data coming out of the basin. And what we're seeing is a step down in cumulative production over 6 or 12 months in the '24 and 2025 vintages. And I think that's mirrored to some extent by the IP you guys present in these decks.

So within the context of the optimization and trying to get this right, can you walk us through internally what you're seeing on the most recent EURs and how those compare to the earliest wells that might have been in that 3 to 3.5 Bcfe per 1,000 foot range?

Well, I'd say the earliest wells that we drilled in the play with the first 6 or so were in Robertson County. And what we've seen if we just basically were to shut down today and just measure everything on the 36 wells that we got producing, the best wells have been the wells over in Robertson County if you just compare them to the ones in Leon. We just had one producing to date way up on the Northeast end, 50, 60 miles away, the Eljah one. And it's really a good well up there also.

But by and large, on average, the better -- the best wells to date have been those in Robertson County. We've got good thick pay rock qualities there. And I'm going to go back and say 15 years ago, somewhere in there, Encana came out here to drill the very first 2 shale wells and they drilled them in that area. So we -- and we pulled those wells harder in the beginning. So those are the early wells when you look at -- '22 and '23 are those wells. And then as you get into '24, '25, you're in the stuff that moved over into Leon. I mean, still good wells. Just we're going to have that variability across the footprint.

Our next question comes from the line of Paul Diamond from Citi.

I just want to touch base on -- yes, let's talk about the development of Western Haynesville. Can you remind us of the kind of the time frame and the cadence towards full utilization there? Is it still kind of that late '27 period? Or do you see any movement?

In terms of HBP, Paul?

Yes, in terms of what the realization -- HBP.

Yes, that HBP -- again, we add acreage every month. But if you look at the model we have today, you keep the 4 rigs busy this year and next year, part of the -- even the -- maybe by the middle of '28, you've got it all HBP. That's a pretty good guess on that. I mean I think the real question is you have to drill wells you don't want to drill in the time frame. If you don't want to drill them, the answer is no. We had 2 rigs several years ago. We're going to add a third. We didn't have the third because gas prices were low. We came in later last year and added 4. And that didn't impact holding the acreage that we've leased.

So I think the real question is with the rigs that we have now or even if you reduce them by a rig, I'll just take the negative, could we hold all the acreage that we've now leased? The answer is yes.

Got it. Understood. And then just speaking on that, kind of the downside here, can you talk a bit about the optionality in your operational cadence in coming quarters? I guess what would cause a shift in the current strategy of 5 rigs in Western Haynesville, 4 rigs in the core and those 4 fleets across the acreage?

So what's the question now?

What would change the current strategy?

Yes, we reduce rigs or add rigs. I think that ultimately we're looking to see the best time to move one of the legacy Haynesville core rigs to the Western Haynesville. So we're still deciding on that. That's probably -- but I think the current cadence is probably -- is the plan that we could be running consistently even maybe into next year. But we'll look for the opportunity to add another -- moving one of the rigs to the Western Haynesville is kind of the biggest decision we have to make, I think.

Yes. I think, Paul, the rig count is 9. Remember, 5 in the core, 4 in the Western Haynesville. That rig count is, as we see it today, is static. I mean it's -- and like Roland said, I think all the rigs we have, all 9 of them except one -- Dan, you can correct me -- is capable of moving over to the Western Haynesville.

That's correct.

So if we needed to, we could move a rig from the core over to the Western Haynesville. But I think the 9 is good. I think that it accomplishes every goal we have in '26 and '27. It meets any contracts that we had to provide gas. We have a takeaway for that. We have the rigs deployed for that. We have the frac crews committed for that. So I think that works good.

Yes. And the only other thing I'll add to that is just as far as the cadence, I think 4 is good. And we also have all of these -- still these things that we're learning. We got the 10-K rig upgrade coming. We've got some high temp motors we're going to be testing end of the year. We've got this big hole that looks really good that we're -- we're trying to get some more of those in the mix. So that cadence with rigs is just -- we want to learn some more of these things before we add rigs to the Western Haynesville.

Our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research.

Just trying to sort of triangulate some of what you're talking about, that you need to be able to demonstrate that you can keep the formation open after the frac. So if I'm understanding right, is part of that just your protocol for chokes? Or is also, for instance, proppant part of that? And is there going to be a need for considerable exploration on that front -- or I'm sorry, experimentation on that front going forward?

I think most of it is the drawdown. All fracture systems naturally close over time as you produce some large cumulative amount of gas. That's just the natural progression. You see a little bit more of it in the deeper formations versus something that's really shallow. But you can mitigate that. Larger volumes of sand, higher concentrations of sand, the viscosity of the fluid you're fracking with as far as creating a little bit more width of the fracture when you put that sand in there, all of those things contribute, but I think the greater one is the -- the greater lever is how fast you draw them down.

So like we've stated, we need to -- we want to get exposed to a large volume of rock because the resource is so huge, and then we want to be very conservative on how fast we pull it back out.

Great. And you were mentioning Robertson County as the home of some of the early wells. And I know this is sort of like a -- a big sort of decision point that I imagine it's way too early for you to really have the data for. But I mean, do you have some sense of how far you might be from sort of designating a core to the play and maybe with an eye towards beginning or heading towards sort of like a manufacturing mode on a more contained part of the play?

I mean it's all been very productive. I would hesitate to say that we know enough to say where the core of the play is. We still got a lot of acreage left to drill. We've only got one well that's producing up on the northeast end up there, the Elijah one. We got several more there -- that's where we drilled the Dolly Johns at 14,800-foot lateral that we're going to complete later this summer. So we need to get a lot more of those in the door. But I mean so far, let me just say, there's not any of this acreage so far that we don't like. There's just a little bit of variability, but it all looks good.

Yes. And we think that more of the results -- the wells have been done -- drilled differently, different landing zones. They've been drawn down differently. And I think the very early wells in Robertson County were drawn down pretty hard. So they did produce a lot of gas upfront. We think that the more restrictive choke in Leon and other counties are going to still yield very attractive EURs on the nature of the 3.5 Bcf per 1,000. But we can't pull them as hard. And so I think the data just looks different.

But we still see very strong recoveries from the wells. It's really -- you've seen other -- the other operators have had some wells that have obviously going to exceed 4 and 5 Bcf per 1,000. So there's a lot of -- and a lot of it is, how do you want -- if you want to pull out gas out really quickly, you're going to get a lower EUR. If you're going to manage the choke properly, you're going to get a higher EUR.

So that's kind of the balance that we're learning. And I think the very early wells, we think we pulled them too hard. And some of them can handle it better. Some of them couldn't. But I don't think that overall it really means that, that's the only area that has those kind of EURs.

I mean I think we're going to get a great -- we're going to get a very high -- the Elijah one is going to be a well that has a very high EUR than 3.5 plus for sure. And I think we probably -- early wells probably understimulated them. We think looking at all the data that's -- and so now the better frac design is -- I think is going to contribute to better recovery from the wells.

I think how prolific this is. We have over 1,000 penetrations where we have seen what the molecules look like, what the Haynesville, Bossier look like in all of our footprint, the 740,000 gross acres, whatever. If you look at a competitor to the northeast, I mean, they have 75,000 net acres. They've drilled a well. They said we like what we've seen. We like -- that is 80 miles away from where we drilled our first well. I mean, if I put you in a pair of tennis shoes to go 80 miles, it would take you 2, 3 days to get there. That's how far away this is. That's how massive this play is. That's how thick some of this is.

So that's why we say we're at the very beginning of this, and we're not going to ruin the basin that we control like happened in the legacy back in 2008, '09, '10. Too many wells. They didn't know how to drill them and complete them. They couldn't go long enough laterals. They didn't know what kind of proppant to use. They didn't have midstream. All of those things we have avoided in the basin that we call the Western Haynesville.

This concludes the question-and-answer session. I would now like to turn it back to Jay Allison for closing remarks.

First of all, you've been with us for an hour 20, an hour 30. So I mean, I hope that you can tell how compassionate we are about giving you the truth and about telling you where we are in this big play. I want to always thank you for taking a look at the business plan. I always want to remind you that whether it's the Jones or the Board or the management, we are really of one mind and we try to do what is just and right for everybody. Whether it's a bondholder or an equity owner, it doesn't matter. We really try to stay strong and do our work.

We do see that Comstock is a great story for LNG. It's a great story for power generation, the data center play, and it's a great story with the bounty of inventory that we have. And if you can check the boxes with the Pinnacles that we have and the NextEras that we have and the banks that we have backing us and then the growth with LNG with Golden Pass and Cheniere, Venture Global, et cetera, et cetera, we look to be teed up to have a big win on the scoreboard. So if you just stay with us and keep asking questions, it will make us better, and we're thankful for that. So thanks for your time.

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

Good day, and thank you for standing by. Welcome to the Fourth Quarter 2025 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded.

I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Thanks for the introduction, and I want to thank everybody for joining the call. It is always a highlight to report on what happened in the prior year and then to kind of give you a visual for what we think tomorrow may look like in today is the day.

So welcome to the Comstock Resources Fourth 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 on the quarterly results presentation. There, you'll find a presentation entitled Fourth Quarter 2025 results. I am Jay Allison, Chief Executive Officer of Comstock. 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 presentation 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.

If you'll turn on Slide 3, we highlight our major 2025 accomplishments. We added 3 operated rigs to our operated program with an additional rig coming in early 2026 to drive production growth in 2026 and 2027. The additional production combined with an improved 2026 gas price outlook will substantially drive down the balance sheet leverage. In 2025, we drilled 52 or 44.2 net successful operated Haynesville/Bossier wells with an average IP rate of 27 million cubic feet per day. The 2025 drilling program replaced 229% of our 2025 production with 1 Tcfe of drilling-related proved reserve additions achieving an overall finding cost of $1.02 per Mcfe.

We announced we were partnering with [ NextEra ] on a data center project in the Western Haynesville. [ NextEra ] plans to build new behind-the-meter power generation to support hyperscaler data center development with an initial capacity of 2 gigawatts with potential expansion up to 8 gigawatts. In the third and fourth quarters, we completed $445 million of divestitures, which improved our balance sheet. We completed the sale of the legacy Cotton Valley assets in September and the sale of the Shelby Trough assets in December, we recognized a pretax gain of $292 million on the divestiture. The assets sold consisted of 1,084 producing wells with only 17 million cubic feet per day of net production. The sales proceeds were used to reduce debt and improve our leverage position.

Over the last 2 years, Comstock has the highest total shareholder return of any public E&P company at 162% almost twice the second highest company's total shareholder return. For the last 2 years, Comstock was #1 in total shareholder return along -- among its public natural gas producers.

On Slide 4, we summarize the highlights of the fourth quarter. Higher natural gas prices in the fourth quarter drove the improved financial results in the quarter compared to the fourth quarter of 2024. Our natural gas and oil sales grew to $365 million. We generated $222 million of operating cash flow or $0.75 per share. Adjusted EBITDAX for the quarter was $277 million, and we reported adjusted net income of $46 million or $0.16 per share.

During the fourth quarter, we put 4 new Western Haynesville wells online, increasing the number of wells turned to sales in 2025 in the Western Haynesville to 12 wells. These 4 wells had at an average lateral length of 8,399 feet and an average per well initial production rate of 29 million cubic feet per day. In our legacy Haynesville, we turned 35 wells to sales in 2025 with an average lateral length of 11,738 feet and a per well initial production rate of 25 million cubic feet per day.

In December, we closed on the sale of our Shelby Trough assets in [ East 6s ] for total net proceeds of $417 million in net proceeds after selling expenses. We used the proceeds from the asset sale to reduce borrowings under our revolver. Roland will provide some more details on the financial results that we reported today. Roland?

Thanks, Jay. Slide 5, we cover the fourth quarter financial results. Our production in the fourth quarter averaged 1.2 Bcfe per day, and our oil and gas sales in the quarter increased 8% to $364 million in the fourth quarter this year despite the lower production number.

EBITDAX for the quarter was $277 million, and we generated $222 million of cash flow in the fourth quarter. Reported a $281 million profit for the quarter or $0.97 per share. Included in that number were some unusual items, including the pretax gain on the asset sales of $294 million a $37 million mark-to-market unrealized gain on our hedge positions and a $29 million impairment on our nonoperated Eagle Ford Shale acreage. Excluding these items and exploration expense and the related income tax related to these items, we reported adjusted net income of $46 million for the quarter or $0.16 per diluted share the same as the adjusted net income in last year's fourth quarter.

Slide 6 is the financial results for the full year 2025. For the full year in 2025, our production averaged 1.2 Bcfe per day, which is 14% lower than production in 2024. But the improved natural gas prices we had in 2025 increased our oil and gas sales by 15% to $1.4 billion compared to 2024. EBITDAX for 2025 totaled $1.1 billion, and we generated $861 million of cash flow last year. For the year, we reported a $396 million profit or $1.43 per share. That also includes the unusual items, including a pretax gain of $292 million on the 2025 property sales, a $62 million mark-to-market unrealized gain on the hedges and that $29 million impairment. Excluding these items and exploration expense and related income taxes, we reported adjusted net income of $160 million for 2025 or $0.54 per diluted share compared to a net loss in 2024.

On Slide 7, we break down our natural gas price realizations. The quarterly NYMEX settlement price in the quarter averaged $3.55 in the fourth quarter. The average Henry Hub spot price in the quarter averaged $3.69, approximately 4% above the NYMEX settlement price. 27% of our gas was sold in the spot market in the quarter so the appropriate NYMEX reference price for our production would have been $3.58. Our realized gas price during the fourth quarter averaged $3.29, reflected a 26 basis differential compared to the NYMEX settlement price and a 29 differential compared to that reference price for the quarter. Also in the fourth quarter, we were 57% hedged, which decreased our realized price to $3.27.

Slide 8, we detail our operating cost per Mcfe in our EBITDAX margin. Our operating cost per Mcfe averaged $0.77 in the fourth quarter pretty much unchanged from the rate we had in the third quarter. Our EBITDAX margin was 77% in the fourth quarter, up 3% from the third quarter. In the quarter, our lifting costs improved by $0.01 in the quarter, and our production in [indiscernible] also decreased by $0.03 in the quarter. That was offset by increases in both our gathering cost and cash G&A costs, which both increased by $0.02 for the quarter.

Slide 9, we recap our spending on drilling and other development activity in 2025. We spent a total of $270 million development activities just in the fourth quarter and [ $1.55 ] billion for the entire year in 2025. Last year, we drilled 36 or 29.6 net horizontal Haynesville shale wells and another 16 or 14.6 net Bossier shale wells for a total of 52 wells. We turned 47 of those wells to sales or 40.3 net wells and we had an average overall IP rate of 27 million cubic feet per day.

Slide 10, we recap our capitalization at the end of the fourth quarter. We ended the quarter with $260 million of borrowings out under our credit facility after using the proceeds from the Shelby Trough sale to pay down the revolver. Our borrowing base is currently at $2 billion under the credit facility and our -- with an elected commitment of $1.5 billion. Our last 12 months leverage ratio has improved to 2.6x and should continue to improve throughout 2026, given the growth we expect in EBITDAX. At the end of the fourth quarter, we had almost $1.3 billion of liquidity.

Slide 11, we recap our proved reserves at the end of 2025, which came in at 7.2 Tcfe based on reserves determining year-end NYMEX market prices adjusted for our differentials. Proved reserves determined using year-end NYMEX prices were slightly higher than proved reserves determined under the SEC rules and those reserves were 7 Tcfe at year-end. We were able to grow our reserves 8% in 2025, excluding the impact of our -- of the Cotton Valley and Shelby Trough asset sales which totaled 419 Bcfe. 2025 drilling additions of 1.1 Tcf replaced 229% of our 2025 production of 450 Bcfe. We spent [ $1.55 ] billion in our drilling program in 2025 give us the total overall finding cost of $1.02 in 2025.

In addition to the proved reserves that we reported, we also have 1.9 Tcfe of proved undeveloped reserves, which are not included in our proved reserves only because they're not expected to be drilled within the 5-year rule as prescribed by SEC rurals. We also have another 2.5 Tcfe of 2P or probable reserves and an additional 7.7 Tcfe of 3P or possible reserves for a total of 19.3 Tcfe of reserves on a P3 basis. This does not include a substantial amount of the reserve potential for much of our Western Haynesville acreage, where we have only included 5.4 Tcfe related to the Western Haynesville [ NRP3 ] reserve estimates.

I'll now turn it over to Dan to discuss the drilling results we've had.

Okay. Thanks, Roland. On Slide 12, this is an overview of just our latest acreage footprint for both the Haynesville and Bossier Shales in East Texas and North Louisiana. We have 1,069,991 gross and 802,769 net acres that are prospective for commercial development of the Haynesville and Bossier shales. If you look on the left is our Western Haynesville [indiscernible] footprint, which we've now grown to over 535,000 net acres. On the right is our 267,289 net acres in our legacy Haynesville area. We have 30 wells currently producing on our Western Haynesville acreage, which is relatively undeveloped compared to our legacy Haynesville. With a higher pay thickness and the pressures we encountered in the Western Haynesville, we'll expect that Western Haynesville will yield significantly more resource potential per section than the legacy Haynesville.

Slide 13 is our updated drilling inventory in our legacy Haynesville area the end of '25. Our total operated inventory in the legacy Haynesville now consists of 1,009 gross locations and 785 net locations, and this equates to an average working interest of 78%. On the nonoperated inventory in the legacy Haynesville, we have 839 gross locations in 101 net locations, which comes out to a 12% average working interest. Drilling inventory is split into 4 buckets comprise the short laterals, which are less than 5,000, the medium laterals between [ 5 ] and 8,500 feet, the long laterals between 8,500 and 10,000 feet and our extra long laterals for everything over 10,000 feet.

In our gross operated inventory in the legacy Haynesville Today, we have 34 short laterals, 145 medium laterals, 397 long laterals and 433 of the extra loan levels. The gross operated inventory is evenly split with 50% in the Haynesville and 50% in the Bossier. So this sets up over 80% of our gross operated inventory in the legacy Haynesville with laterals growth than 8,500 feet. Our legacy Haynesville inventory also includes 115 gross horseshoe locations with close to a 50-50 split between the Haynesville and the Bossier. The average length in our inventory has now signed up to 10,077 feet, which is up 116 feet, from the end of the third quarter. The inventory provides us with decades of future drilling locations based on our current activity levels.

Over on Slide 14, we show our estimated drilling inventory in the Western Haynesville. Our Western Haynesville inventory consist 3,343 gross locations in 2,561 net locations, equating to a working interest of approximately 77%. The number of net locations is estimated since much of our Western Haynesville acreage has not yet been unitized. Our Western Haynesville inventory is more weighted to the Bossier formation. We got nearly 2/3 of our inventory in the Bossier and 1/3 of the inventory is in the Haynesville. With the same as our legacy Haynesville inventory, our Western Haynesville inventory is also divided into the 4 separate bucket lengths with our short laterals less than 5,000 feet, our medium laterals between 5,000 and 8,500 feet, the long laterals between 8,500 and 10,000 and our extra long laterals over 10,000.

So in our Western Haynesville gross operated inventory, we don't have any current short laterals. We have 1,326 medium laterals, we got 653 of the long laterals and 1,364 extra long laterals. Approximately 60% of this gross operated inventory has laterals over 8,500 feet.

Now on Slide 15, it's a chart that outlines our average lateral length drilled based on the wells that have been drilled to total debt. The average lateral lengths are shown separately for both our legacy Haynesville and our Western Haynesville areas. In the fourth quarter, we drilled 12 wells to total depth in the legacy Haynesville area, and these wells had an average lateral lenth of 11,381 feet. The individual link range from [ 9,340 ] up to 15,700 feet. A record long lateral in the legacy Haynesville area still stands at 17,409 feet.

In the fourth quarter, we also drilled 4 wells to total depth in the Western Haynesville, and these wells had an average lateral length of 9,944 feet. The individual lengths on these wells range from 9,355 feet up to 11,249 feet. Our longest lateral drilled to date in the Western Haynesville is 12,763 feet. And to date, in Western Haynesville, we have drilled 39 wells to total depth. This includes 16 wells laterals over 10,000 feet and 6 wells with laterals over 12,000 feet.

Slide 16 outlines the 35 wells that we've turned to sales on our legacy Haynesville acreage in 2025. This includes 7 wells since our last earnings call. The average lateral length was 11,738 feet and the individual laterals ranged from a low 4,968 feet up to a high of 17,409 feet. The individual IP rates on these wells range from 16 million cubic feet per day up to 37 million cubic feet per day, and our average IP was 25 million cubic feet per day. 5 of our 9 rigs currently drilling are drilling on our legacy Haynesville acreage.

Slide 17 outlines the 12 wells that we turned to sales on our Western Haynesville acreage in 2025. Since we last reported earnings, we've had 4 additional wells that have been turned to sales. These 4 wells had an average lateral length of 8,399 feet and an average initial production rate of 29 million cubic feet per day. 4 of our 9 rigs currently drilling or drilling on the Western Haynesville acreage.

On Slide 18, this highlights the average drilling days and average footage drilled per day in the legacy Haynesville area. This is for our benchmark long lateral wells, which are greater than 8,500 feet long. In the fourth quarter, we drilled 12 of these [indiscernible] long lateral wells to total depth in the legacy Haynesville area, and we averaged 27 days to total depth.

In the fourth quarter, we averaged 893 feet drilled per day on our legacy Haynesville acreage, which this represents a 11% decrease versus the third quarter of 2025. And the primary reason for the lower drilling rate in the fourth quarter is that we had 5 of our 12 wells we drilled were located inside the [indiscernible] gas stores field and all 5 of these wells it necessitates running an additional intermediate casing string on those wells. We also drilled 3 horseshoe wells in the fourth quarter, and that naturally lowers our average drilling rate compared to our normal straight levels.

Slide 19 highlights our drilling progress in the Western Haynesville. During the fourth quarter, we drilled 4 wells to total depth. This gives us a total of 39 wells drilled to total debt through the end of the year. We averaged 54 days to TD for the 4 wells drilled during the quarter. This is an increase of 2 days compared to the third quarter. This is also reflected in the drilling speed of 499 feet per day during the fourth quarter, which is 3% lower than the third quarter. Aside for many drilling issues we have, the drilling performance in the Western Haynesville quarter-to-quarter is mainly affected by our vertical depth, temperatures and our lateral [indiscernible] so where the wells are being drilled has a big impact on our drilling performance quarter-to-quarter. This batch of wells drilled in the fourth quarter were nearly 1,000 foot deeper vertically and hotter than the wells drilled in the third quarter, while the average lateral lengths were similar.

Our fastest well drilled to date in the Western Haynesville still stands at 37 days and that well was drilled with a 12,045 foot lateral.

On Slide 20 is a summary of our D&C costs through the fourth quarter for our bit smart long lateral wells located on our legacy Haynesville acreage page. The costs reflect all of our legacy area wells, again, that have the laterals greater than 8,500 feet long. Our drilling costs are based on when the wells reach TD the completion costs are based on when the wells are turned to sales. During the fourth quarter, we drilled 12 of these bit smart long lateral wells to total depth. The fourth quarter drilling costs averaged $681 a foot. This is a 22% increase compared to the third quarter. The increase in the fourth quarter is the result of a shorter average lateral length and for the same reasons mentioned on the efficiency slide where we had 5 wells within the [indiscernible] gas storage field with an additional intermediate casing string. We also drilled the 3 horseshoe wells in the fourth quarter.

During the fourth quarter, we also turned 5 of these [ Benchmark ] long lateral wells to sales in the Legacy Haynesville. The fourth quarter completion cost came in at $721 a foot. This is a 7.5% increase compared to the third quarter. The higher completion costs in the fourth quarter is due to a combination of slightly lower frac efficiency, coupled with we had a higher average drill-out cost in the fourth quarter.

Overall, in 2025, we achieved the total drill and complete cost of $1,347 per foot, which is one of the lowest in the basin. This was 11% lower than our average cost of 1,510 per foot in 2024. Last month, we added an additional frac fleet, and we're now running 3 full-time frac fleet in the legacy Haynesville. This additional frac fleet will be working full time in our legacy Haynesvillary along with the increase in the rig activity for that area. On the subject of performance initiatives in 2025, we began running trials with the rotary steerable drilling assembly in our legacy Haynesville area, and we've made great progress to date. As this technology becomes further refined, for the high temperature environment in the Haynesville Shale, we fully expect this technology to play a much larger role in our future drilling program and make a significant impact on further drilling cost reductions.

Slide 21 is a summary of our D&C costs through the fourth quarter for all wells drilled in the Western Haynesville. During the fourth quarter, we drilled 4 wells to total depth with an average lateral length of 9,944 feet. The fourth quarter drilling costs averaged $1,489 a foot. This represents a 7.5% increase compared to the third quarter. Our drilling cost was driven slightly higher in the fourth quarter as a result of the wells being slightly deeper and hotter than the wells drilled in the third quarter.

During the fourth quarter, we also turned 4 wells to sales in our Western Haynesville acreage that had an average lateral length of 8,399 feet. The fourth quarter completion cost averaged $1,542 a foot. This is a 5% decrease compared to the third quarter. The lower completion cost was the result of us being able to obtain lower frac pricing along with we had lower horsepower usage in the fourth quarter. In addition to the earlier cost initiatives, we have enacted in the Western Haynesville, including the use of the insulated drill pipe. We are undertaking additional measures to further reduce our cost. We have recently arranged to have one of our existing Western Haynesville rigs upgraded to a 10,000 psi pressure rating, and that will be available to us by late summer.

With this upgrade, we'll be able to increase our drilling speeds in both the vertical and horizontal hole section significantly reducing our costs. Also following up on the successful trial runs of the rotary steerable drilling system in our legacy Haynesville area, we will be rolling out this fiscal [indiscernible] in our Western Haynesville area in the near future. We believe the application of this technology to the hot hole environment of the Western Haynesville along with insulated drill pipe will lead to additional time savings and cost reductions.

On the completion side, we're also investing to upgrade one of our existing frac fleets to a 20,000 psi rating, along with the frac stacks, which will lead to improved track stimulations as well as making it easier for us to execute larger and more aggressive stimulation treatments. All of these initiatives together are going to lead to a substantially lower cost structure for future wells while enhancing the well performance. And by substantially lower, we believe we'll be able to cut drill times about 2 weeks and release our drilling cost by another $300 a foot on top of our earlier cost reductions we've made to date.

With that said, I will now turn the call back over to Jay.

Thank you, Dan and Roland, thank you. If you would, please refer to Slide 2, where we will summarize our outlook for 2026.

In 2026, we will continue to be focused on building out our great asset in the Western Haynesville that will position Comstock to benefit from the longer-term growth in natural gas demand driven by LNG exports and build-out of power for data centers. We have 4 operated rigs drilling in the Western Haynesville to continue to delineate the new play. We expect to drill 19 wells and turned 24 wells to sales in 2026. We plan to have 5 operated rigs drilling in legacy Haynesville to support production growth in 2026 and 2027. And we expect to drill 47 wells and turned 48 wells to sales in 2026.

One of those rigs may move to the Western Haynesville later this year. We expect to commercialize our Western Haynesville data center project in 2026, where we have partnered with [ NextEra ], which is the nation's largest developer of power. We're also working to recapitalize our Western Haynesville midstream company with Pinnacle Gas Services. In 2026, we plan to put in a new bank credit facility and redeem the preferred units held by our partner to be funded by selling equity in Pinnacle. We continue to have the industry's lowest producing cost structure and are striving to create additional drilling efficiencies to drive down our drilling and completion costs in 2026 in both the Western and legacy Haynesville areas.

And lastly, we continue to have strong financial liquidity of $1.3 billion, which was recently built up by our successful 2025 property sales. In 2020, we started leasing in the Western Haynesville. Today, after several acquisitions and direct leasing with over 100 land men, we now own 20,000 leases covering 535,000 net acres in our Western Haynesville. The legacy Haynesville play, which is covered in 2008, it covers approximately 4 million acres and has produced about 48.5 Tcf from 7,600 wells. We estimate the remaining recoverable reserves in the legacy Haynesville to be 75 Tcf. Net to our working interest we have about 14 Tcf of reserves in our legacy Haynesville properties. The Western Haynesville play that we drilled our first well and turn to sales in 2022 covers approximately 800,000 acres and has produced 300 Bcf from only 36 wells. We estimated recoverable reserves in the Western Haynesville could reach 99 Tcf. Comstock would have almost 50 Tcf net to the working interest we own in a play.

As Dan Harrison said earlier, we have drilled 39 wells to date in the Western Haynesville and have turned 30 of those to sales. In 2025, we turned 1 Western Haynesville well to sales every month, along with 3 legacy Haynesville wells every month. This year, our activity level will increase as we expect to turn to Western Haynesville wells per month and turned 4 legacy Haynesville wells from month to sales in 2026.

Our Pinnacle Gas service midstream company we own is also a success which services our new play. We're excited about the progress we're making in reducing well costs in the Western Haynesville, which is [indiscernible] by using thermal or insulated drill pipe, new purpose-built rigs and new hot hold [ MWD ] tools, also drilling more wells on 2 well pads and optimizing casing designs have contributed to improving our well cost. New initiatives to improving costs we are implementing in 2026, including applying rotary steerable drilling assembly technology that we're having great results in with our legacy Haynesville horseshoe wells that we are currently drilling.

We have learned from the development of legacy Haynesville play that started in 2008 how this new Western Haynesville play should be developed to maximize its future value. We believe the Western Haynesville Basin is needed to supply the natural gas for growing industrial demand LNG demand as well as to generate power for data centers.

Thank you for your time today. The next slide provides guidance for 2026, which Ron can discuss to you directly if you have questions. For the rest of the call, we'll take questions from analysts who follow the company. I'll turn it back over.

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

Maybe to start with guidance, that seems to be the focal point for investors. Is it fair to say that the budget was put together in a slightly more constructive gas environment? And when it comes time to spend the capital, if the price isn't there, the capital won't be there either? And maybe just to build on to that guidance question, if we assume the capital program as outlined, I suspect the exit rate will be higher than what we anticipate today, given that legacy Haynesville has faster cycle times and there's likely some friction from 1Q that will bleed into Q2 as well. So maybe if you could offer any color on cadence of production that would be helpful as well.

Yes, sure, Derrick. It's been -- of course, gas prices have been all over the board since Thanksgiving and had a huge rally there, then you had a fairly warm second half of December, first half of January, then you had a cold second half of January. And so it's been -- we've actually had 2 great index prices for January and February gas that are extraordinary. But obviously, gas prices have been everywhere, and that's not unexpected. We expected this to be a very volatile year for gas prices given the given the new demand that's coming on and the difficulty in trying to match supply to demand.

And so weather has played a major role in and whether gas is considered undersupplied or oversupplied and probably we'll continue to play that role throughout the year. And obviously, we have -- we did want to get enough frac equipment and drilling rigs that we could execute a good program for 2026 in place and then running well. We always run the equipment in the legacy Haynesville before moving into the Western Haynesville. So we put that in place for this year. But obviously, if gas prices disappoint, we have as many as 4 rigs that we could with short notice, take out of action and the same thing with the frac crew.

So always have the ability to flex our drilling budget based on how things come out. But I think overall, given we did sell a lot of properties to finish out last year, sell some production. We did want to invest back in the properties, build the production levels up, and we think that's the best way to get -- to achieve the leverage goals we have will be really generate some higher EBITDAX. A lot of that will be more directed toward the second half of the year, obviously, fairly noisy first month or so of this year, given the disruptions in January.

So -- and then some of that completion activity got pushed a little bit as we took down our frac crews started most of the winter storm. But generally, I think we have a very exciting year plan for 2026, we think.

Well, Derrick, it's very flexible. If we want to get rid of 1, 2 or 3 of our drilling rigs, we could on notice given probably 45-day notice. It's very flexible. We've got quality drilling contractors. We've got quality group of fracking companies. And as Dan has said, I think we're going to get better and better and better on our drilling completion times in the Western Haynesville.

In 2025, as the year went along, we ended up with the 4 rigs in the Western Haynesville. So if you look at 2026, I think it will be a lot more predictable what the outcome can be. And particularly, a lot of these wells will be drilled on 2 well pads. And I think these costs are going to go down. And what we do focus on is you need to have 3%, 4%, 5% growth every year, and we were negative 14% last year. So we come in a little bit of negative in the first to second quarter '26, but then we make that up in the third and fourth quarter. And if you do look at this natural gas demand, we believe on a yearly basis, the demand is going to grow about 3 Bcf every year between now to 2030. That's just based upon LNG facilities and data centers that are being built that has nothing to do with FIDs.

So we want to lean into that and a way to lean into that is if we have sold an asset and we didn't give up a lot of production, we gave up a little bit and we paid down our borrowing base of our credit facility. We do have a little bit more flexibility to lean in to 2026 earlier. And that is what we're doing. I look at these -- all these E&P companies, they really are searching for tomorrow's drilling inventory. And you're really asking the question is, what do you -- what's your tomorrow look like? Well, Well, most of these are looking for tomorrow's drilling inventory. They're searching across the globe but to Wall Street Journal yesterday, they're across the globe. But so if you really are a pure natural gas company in the U.S. and you want to be near for the majority of the demand for LNG is located as well as where these investments for AI data centers are being made.

And Derrick, that's exactly where we are. So we're just trying to manage this potential 50 Tcfe of upside in the Western Haynesville in the decades to come to bring that to fruition to show everybody what we are trying to do. Our tomorrow, we're looking at today we're just trying to derisk it and deliver it.

Great, Jay, I'll maybe lean in just there on kind of the tomorrow, particularly with AI demand along the Gulf Coast. With respect to NextEra, do you have a view on how the JV will scale from the 2 gigawatts you hope to commercialize in 2026 to the [indiscernible] lot it could be? And how should we think about the price and/or cost advantage of selling to NextEra versus traditional marketing?

Well, I think my comment without getting into gray areas is if you listen to what most of the hyperscalers would tell you, I think they would like to be in Texas, if they could. I think a regulatory wise, it's going to be in Texas. Now you have to be in an area where there's people to hire. If you build 8 gigawatts, you might be building a city of 20,000 people. So you got to have location, but you have to have water. If you want water, if you look at where we are, we're 100 miles from Dallas, 100 miles from Houston, and you have to have an airport where you get in and out in and out.

So what all we've done is we said we have untapped what we call the basin. I think we control a new basin, not some acreage in the legacy area, but we control a basin. It's how we look at it. That's how we're developing it. And we're developing it based upon how the legacy was developed and some of that value was not captured because of what was happening during '08, '09, '10, '11. So as we look at that and we look at NextEra and NextEra, we've been partners with for 10 years. They come in and say, we do think you have a really great place and we want to collaborate with you and I think we were taking those next steps hand-in-hand with them or we wouldn't be discussing it, but you start out with 2 gigawatts. And then they said at their analyst meeting that they would like to ratchet up to 8 gigawatts, if that's where the demand is.

I think the demand will be there, and I think we can provide them everything they need, particularly because we do own our midstream. Most of these companies on their midstream. That's why they have to deal with midstream companies that have upstream companies gas. So we're trying to capture both of it.

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

Maybe this first question is for Roland. This question is on Pinnacle Gas Services. In your remarks, you mentioned addressing the preferred equity at that entity. Wondering how we should think about the cost of doing that? And if you plan to backfill the funding with [ Bank Tet ], how should we think about the size of that facility and whether it's sufficient to execute on the scope of your midstream ambitions?

Yes, that's a good question. Yes, we have -- we've kind of put in place a plan to kind of recapitalize Pinnacle now that it's ready to make the next step as it's got a really great future ahead of it, starting to generate much more significate EBITDAX, which probably people aren't really expecting because it just hasn't had it in the past but it's ready to move on from the development capital that our partners put in and they've given us an opportunity to redeem them. And so that's the plan we've put in place, including the new credit facility.

We also have an initiative here that we're going to sell just common equity in the midstream company, and that's how we plan to eliminate the preferred equity that has a dividend that's pretty expensive. And so now that cash flow that before was -- was mainly going out of the company to our partner, we'll be able to be available to fund its CapEx and also have its own low-cost credit facility now that it is -- it has the credit metrics to deserve that. So we expect a lot of that. Hopefully, our goal is to have a lot of that in place by May of this year.

A positive move for our midstream. In other words, it was [indiscernible]. We had 145 miles of high-pressure line, we had the [ mettle ] plant. And then as it progressed, we added more [indiscernible]. And then now it's progressed where we have a giant foothold in the Western Haynesville, and we want the Pinnacle system to mature as we add rigs and production. And remember, some of this gas will go to serve the data center demand, much less the LNG that we service right now.

Just to follow that up, have you already fielded interest on the potential equity sell-down? And then can you kind of talk about the timing rationale for the marquee expansion, is that being motivated by the NextEra data center project timing in which case, utilization of that plant doesn't increase until the data center project is online?

Yes. With the Marquee plant, which is being -- we think it's next train will be operational sometime this summer. Again, as a midstream provider, you've got to have these assets available before the production is there. Otherwise, it's holding up thing.

So also with the other potential operators in the area, we thought it was a great opportunity for us to have ample treating so then we can really also pick up third-party business for Pinnacle as now we have several operators in the area and want to be positioned to continue to capture that market. So a lot of that capital for midstream company all has to come way ahead of when you actually get your revenue and then you have a long period of collecting fees after that. And so by this summer about the time we kind of probably finished the recapitalization, kind of a lot of our heavy CapEx will be behind us. And I think you'll see the entity well positioned to fund itself and still keep a low leverage profile with its own credit facility.

And I think the audience that we'll look at the Pinnacle system as an equity investor, I think what they'll do is they'll dig a little deeper into what we are showing in the Western Haynesville. And I think that more they dig, the more they like is our opinion. So we'll find out.

Our next question comes from Carlos Escalante with Wolfe Research.

Thank you for having me on today. This one is perhaps for Dan. Dan, might be a little bit unfair because you had a tremendous program for the Western Haynesville throughout the year. But if I may, cherry pick up one of your late as well as the [ brown true heart BB ] that well looks like the IP rate base is slightly underperformed the broader group. And now I think it's normal for you to assume that you'll have a laggard on any given program for the year. But it is in close proximity to another well that had underperformed in the past a miles well. So just wondering if you can perhaps provide your perspective on anything that you might be seeing on the rock quality or perhaps any kind of water handling issues, something that maybe qualifies this specific area where these 2 wells are, which is, I suppose, closer to the heart of your position on the basin.

Yes. So the [ brown heart ] well was that's -- if you look on the acreage map, it is the furthest one that we've -- as we've kind of fanned out and drilled more to the Northeast, it's kind of on that not the far northeast in were the [indiscernible], but the furthest northeast of that trend of wells we've drilled. It was a 2-well pad. We drill the well up dip and down dip. This well was drilled up dip. And actually, we drilled 4 wells kind of right during that same spot to 2 well pads and just because of the geology, if you're drilling south, you're going down dip and if you're drilling north, you're going up dip.

So this well, I think it's -- it basically is just because of the well was making a lot of water during flowback. And when we see wells that make a lot of water during flowback, it's more difficult just to get a good IP rate, even though the wells are still really good. And that's what happened on this well, the down dip well just roster off the same pad. We IP-ed at 30 million a day and this one was 22. And the only difference [indiscernible] 2 wells was this one was making was making more water during the flowback period.

That's very helpful. And then my follow-up, this one is for you, Jay and Roland. The M&A market in the Haynesville last year was pretty hot, and you saw deals that implied pretty high dollars per location across the board. And that was with lower quality acreage, I think that I can say that objectively speaking.

So I wonder what your views on the recent trend coming into the year on M&A activity. And when you see the second largest operator taken out, do you and the team feel compelled to keep business as usual? Or does it prompt you to feel compelled to participate on it?

I think, Carlos, I think we're -- this is me. And again, this goes back to 5.5 years. This goes back to probably July 2020 when we first looked at the Western Haynesville. I believe we're sitting on some of the most viable gas in the world. And the reason I believe that is where the LNG facilities are being built and have been built and are being built and that the U.S. is the largest exporter of gas in the world. It's only going to get bigger and bigger, bigger.

As you know, I mean, the [indiscernible], et cetera, et cetera, they're all adding their venture levels they're adding, the data centers are adding. So I think to answer your question, our business plan is to show what our Western Haynesville might be. And the way we do that is we talk about relatively steerable innovations. We talk about our hot hole tools. We talk about the different rigs to drill the wells. So we talk about efficiency the Holy Grail for an upstream company, which is M&As or upstream, it's your quality drilling locations. And I think we have that not only in our core, but our core, you wouldn't buy that, but you would buy that the Western Haynesville area because I don't know of any company our size or remotely our size, that has 2,561 locations that are almost all that's undedicated.

So our goal -- and [ Jerry Jones ] is a master plan behind this that's let us think out of the box and act out of the box. It is to make sure our balance sheet is strong, make sure our liquidity is strong, make sure that we report to you every 90 days, all the good to bad. And if we needed to add a rig, which I think that's the only negative truly in the call as we added a rig that's $150 million to $70 million as we use per rig per year. But that is to what it's continue to shore up our legacy and then add to the Western Haynesville performance. We're not looking for inventory. They are looking for inventory. We're looking to develop what we own now and we've got a great amount of gas.

So that and always -- you always want to be the Beauty Queen. It's like the Olympics. We don't want a silver or bronze metal that'd be great to begin there. It'd be great. But if you're going to go out there, you're going to go for the gold, [ Lindsey Baum ] was 5 inches away from maybe having a gold or where she was, but she was dead aimed to get the goal because she wanted a dozen times. That's exactly what we hope you know that we've been doing for a decade after decade at Comstock. We're never deviated from who we are. We've got our same name. We get true. And the Jerry Jones of the world came in and said, I'm behind you. I want to go with it. Let's develop this. And you know what, we'll see where the value comes. We'll see where it comes from.

Our next question comes from Charles Meade with Johnson Rice.

Dan, in response to the earlier question about the [ Brown II Heart BB ], I wanted to ask one more question response there, can you tell whether the water you're producing there? Is that completion water? Or is that formation water? And could it be related to the azimuth of that well and whether your toe up versus to down? Is there any -- what's your thought process there?

Well, that's a really good question. I don't think anytime these -- we've had several wells in the core that will make high water in the very beginning. And when we do make high water in the beginning, it's just hard to get a good eye pre-great until that water comes off. But I don't know of any really shell well that I can remember that we've made formation water. There is no formation water. It's all load water coming back from what you fracked and they have not owned the [ Brown True Heart ], but in other areas in the past, there's been discussions when we've had high water about did the frac orientation change along the wellbore, instead of being perpendicular to the lateral from the toe to the hill due to some regional local stresses, maybe those fracs turn more closer to being in parallel with the wellbore than being perpendicular, and that will definitely lead to a well that makes more water.

Now that's possible on the [ Brown True Heart ]. We don't think that's what's happening on the [ Brown True Heart ]. I think this is probably the second well. We've only had a few wells that have drilled up dip. This well was drilled up dip. And we -- it could be that or it could be a geometry thing, just how much they make from flowback when you drill uphill versus drilling downhill. Like I said, this was a 2-well pad. We had the downhill -- the down dip well IP-ed at over 30 million a day and this one we IPed at 22 million a day while it was making a lot higher water rate. We could have got a higher IP rate than that, but we'd have been pulling a lot more water, too. And obviously, that's not good for the well.

Well, you fight gravity, you drill up dip and your 1,000 foot shorter than the [ Brown True Heart ] that be number one. You're 1,000 foot shorter, you're up dip and you fight gravity, water was going to slow down. So we [indiscernible] paid the [indiscernible] at 22 and the other one at 32.

And all these wells where we have an instance where the water is high upfront it -- what happens is it comes down over time, but it's after you've IP-ed the well and you're off a flowback. The water eventually drives up, it comes down and you still end up with the similar [ EUR ] that you got on the other wells that are down dip.

Right. That's all really interesting color, Jay, I want to go back and ask a bigger picture question about the 1.1 Ts that you added with your drilling program this year. That's a big number. And I guess we'll get some more detail when we see your K, but I wonder if you could just maybe give us a little preview and tell us how much of that is PDP adds? How much of it was [ PUDs ] I think 3/4 of your wells in '25 were legacy, a quarter were Western Haynesville, but what's the ratio of those reserve adds, whether legacy versus Western Haynesville?

Yes. I don't know if we have all those exact stats for you, Ron, probably to work on that for you. But basically, there was definitely some good growth in the PDP reserves but you also had kind of a situational change here. You're looking at -- you're coming off of a -- we've added additional drilling rigs. So basically, in the next 5 years, we've got more ability to have proved undeveloped reserves in our reserve report. Also, we sold some inventory, which got to be replaced by new projects. There's still a lot of -- we've got a lot of reserves that could easily be proved undeveloped reserves that we could put on the books, et cetera, we just -- we cannot develop those in a 5-year period, which is that arbitrary SEC rule.

So a lot of it is just extensions. Of course, obviously, with we're able to book in the Western Haynesville as we had some new wells so we can have offsets to those. So it's a combination of all those things. I think that you got back to a normal growing kind of drilling program going forward versus a contracting program that you had last year, the last couple of years where we were pulling in activity because of low gas prices.

Remember in 2024, our finding costs were 2025 or $1.02 went up $0.02, but I think there were probably better adds this year than in '24.

And those numbers that we provided were all on the -- using the NYMEX reserves because they were fairly comparable in price between the end of last year the this year. So that isn't reserves that we've got put back on the books because of improvement in gas prices. that you would see in our SEC reserves, which had tremendous amount of additions because a lot of reserves left the SEC case came back. Those are true -- that number the 1.1 Ts is true additions that are related to drilling activity, not to prices move around.

Our next question comes from [ Fu Sam ] with ROTH Capital Partners.

Yes. You got [ Leo Mariani ] here from [indiscernible]. Wanted to just touch a little bit more on the Pinnacle deal here. So I wanted to just kind of get a sense from you folks. It looks like you're trying to replace Quantum as a capital partner here. Can you basically just give us a little bit more color on where you are in the process? Has it just kind of recently started, I heard you earlier talk about trying to get something accomplished this summer and does that mean that in the near term, quantum is not going to be completing sort of contributing any capital for the next several months, and you guys need to kind of find that new partner before seeing some of that capital gets kind of offset? Just a little bit more color on that would be great.

Yes. I would just -- we just have an opportunity to replace Quantum, and we're going to do that with the -- and we just started this process, so we can't give you a lot of details yet because it just started but it's an opportunity to replace a preferred kind of capital structure that Pinnacle has now with a common capital structure, so much more equity like and then allow the cash flow to be used at Pinnacle and not have the large kind of preferred distribution going out.

So business as usual until all that happens, I think the credit facility that we will be putting in soon. That was the natural part of the business plan of Pinnacle was to have that and it was provided for originally, but we were waiting to it grew up and have the credit staff to deserve that, which it has now and that we'll probably have that in place first and then hopefully complete an equity sale to allow us to do the full redemption the summer.

Okay. No, that's helpful. And then just with respect to Pinnacle, I presume there's probably no debt on that entity right now at the moment. And then additionally, do you expect Pinnacle to be free cash flow positive, maybe that's next year or something like that? Can you just give us any color in terms of where it is and its kind of life cycle from a cash flow perspective?

Sure. I think it becomes really free cash flow positive in the second half of this year. The first half is kind of this last putting in the treating plants is a really large capital expenditures that it's had. So as we get to that with Marquee Train 2 coming in, we'll have over a Bcf a day of treating capacity. So we'll be well positioned to where will only be just spending money on well connections. So that's really what it becomes much more cash flow positive.

Also, the credit facility will be more than adequate, we think, with its cash flow to fund its capital in the future. So the need for the capital infusions like [ Quantum ]made last year, shouldn't be there. And so it's just -- it's made those before it had a revenue stream, now it has one.

Our next question comes from Kevin MacCurdy with Pickering Energy Partners.

I wanted to ask again about the production trajectory throughout the year. I know you won't have any turn in lines in the first quarter, but with less downtime, do you expect second quarter to kind of resemble more where you ended the year? And do you care to put out kind of an exit rate for production assuming that you run the non-rigs this year?

Well, we put out the guidance that we'd like to put out. So we don't really exit rates or so. Yes, they are interesting, but they're also so dependent on timing that well could come online a week later and be in January versus December. So given that our capital program a big wells, and they come on and usually groups of 2 to 3. So the timing of their production is really critical to one day's production. So yes, I think generally.

I think what I would add to that is we'll see quite significant growth over the course of the year just based on our well completion schedule, we only have 5 wells turning to sales here in the first quarter. That means over the remainder of the year, we have 65-plus wells coming online. Those are not -- those are pretty evenly spread between the quarters with a little bit more in the second quarter than in the third. That would point towards a strong kind of fourth quarter rate.

Historically, what we had said on the 8-rig program that we could by the fourth quarter, get back to kind of the first half of '24 type levels with the ninth rig, I think that remains intact, if not a little bit higher. Remember, adding a rig now, we're not going to really start to see any impact from that until very late in the year, sometime in the fourth quarter. And so the addition of that rig is really going to have a much greater impact on the production profile in '27 than it will this year. It's just the capital lag versus production.

I appreciate that. I think that helps. As a follow-up, I wanted to ask on lateral lengths in the Western Haynesville, it looks like they were a little lower this quarter, and that might have affected the per-foot costs. Do you have any -- do you have any color on what the lateral lengths will look like going forward in 2026? And have you guys kind of decided on what the long-term goal should be for lateral lengths in that plan?

Well, I will say the long-term goal is obviously to be longer. A lot of our sticks are controlled by the geology and your dead on when we have an average short lateral length in any 1 quarter, it definitely leads to a higher cost. And we've got -- like I said, we've got 6 that we've drilled over 12,000 foot long, but we also have -- we've got several that are on the short end. I think the shortest one is about 7,800 foot that we've done to date. But we do have here in the very near future, we're going to be drilling towards our first -- targeting our first 15,000-foot lateral. And we have -- we think we're going to be successful there.

So I think the upside is definitely going to be longer than where we've been, if you look backwards on the average level length. So as long as the geology, we're in areas where we don't have to stop short due to a fault, or something that's -- of that nature, we will definitely be longer in the future. I think the rotary steerable. You know that we've gotten -- that's been working good for us in the core that we're going to deploy down here and the 10-K rig upgrade, we got just the 1 rig we're upgrading right now. Those things are going to definitely help us get longer on the laterals.

Our next question comes from Jacob Roberts with TPH & Co.

I don't want to belabor the point, and I appreciate the color on the [ Brown True Heart ]. But just taking a step back and looking at Slide 17 compared to the equivalent in last year's Q4 deck, the lateral adjusted IP rate on average has moderately come down year-on-year. So I'm just wondering if you could talk a little bit about this dynamic? And then maybe if you could remind us what EUR you're expecting or underwriting across the Western Haynesville at the moment?

So the -- as far as we have made an effort to have basically control our drawdowns a lot more than we did in the very beginning. We're not looking -- all these wells can be IP-ed at what we want to be IP-ed at. We've -- we like to get them up to about 30 million, 35 million day range and IP on there, but all of these wells are capable of IP at over 40 million a day if we want to, but we don't want to pull the wells that hard.

So I wouldn't read a lot into that, just the IP rate on a length-adjusted basis because I think that's part of what you're seeing there is just how we're flowing the wells back. But I think as we find out across the acreage, we're going to see a little bit different performance in different areas. And so we still have some of the acreage that we haven't drilled on yet. We're going to be drilling more wells this year up on the Northeast end by the Alagon. And I think all the offset wells to that went up here will resemble that well, which had a good IP could have been a lot better IP, but -- so I think that's going to ebb and flow. I wouldn't read a lot into that as far as any kind of a trend.

Well, another question that I think you should ask is what are we seeing from our cores and where are our cores and Dan can follow up with that too.

Yes. So we've taken -- we've drill 4 pilot holes to date, we've cored 3 of those. All of the course look great. We are -- I mean no surprises to the downside on any of the core work that we've done fully supports the resource that's estimates that we've had in place. We are taking the learnings from the cores along with the logs and try to get a little bit better at where we want to target putting the laterals. That obviously makes a big difference on how good the wells are going to be, where they're landed, where we -- in the very beginning, we talked on several of the calls, we had a laser focus to get costs down, we did. We used the insulated drill pipe. We just -- we got our motor runs a little more efficient, a little bit longer but we were also not trying to keep the laterals exactly maybe where we wanted them.

We let them wonder just a little bit, just keep our drilling speeds up. And as we look back on some of these, we probably need to put a little bit more emphasis on keeping the laterals landed kind of closer to where we want, but not for sake that maybe to drill a lot faster. So that's just -- that's -- day to day, that's just a balance for us, where we want the well to be and how fast we're trying to drill the well.

And the cores tell us now really where we should land these laterals. So we didn't have that data before.

That's right. And we've got 1 core. We just cored a well up on the northeast end of the field by the [indiscernible] that we're the rigs on now. And our other 2 cores are back down towards the other end where the bulk of all the wells have been drilled.

I appreciate that. And Jay, I appreciate the 3 questions. Maybe staying on the productivity side of things, looking at the state data on the legacy side of the basin. And I know there's various factors that might have impacted production or production reporting last year, but it looks like there's a step down in productivity in 2025 vintages. At a high level, could you comment on your views around the Louisiana productivity per foot in 2025 and maybe where you see that heading in '26 and '27?

I speak in the core, I think if you just look across the entire area up there, all operators, I mean, there's obviously been some small amount of degradation as the basin has been filled down. I mean, it's been obviously thousands and thousands of wells drilled. Everybody drills their -- where they think their best areas and their best wells are first. And then they kind of start kind of working down their inventory mix from there.

Plus the way as the gas prices pick up, I think you see more people starting to drill in maybe some -- even some of the lower type curve areas at the higher pricing when those become a lot more economic. I think we will see on our side, I think we'll see maybe a little bit movement back in the other direction now that we're drilling a lot more of these horseshoe wells because a lot of the horseshoe wells were from a lot of our stranded short laterals were in our better type curve areas.

So once we kind of the horseshoe route and they've been looking great for us. We've drilled -- we've got 10 of those TD to date, going really good. And the performance of those is has been better just because they're in the better type curve areas. So like I said, it's been a natural degradation I think, just for the whole basin wide on how the laterals are drilled. So I'd say next year, flat kind of to this past year, where we are.

Well, if you can add a rig and drill 115 gross horseshoe wells, 50 Haynesville/Bossier, which you will drill 16, I think, this year. But let's say you use that rig and you say, "Well, we're just going to drill horseshoe wells." Remember, like Dan said, those are [ 2, 2.1 ] [indiscernible] those were really, really good locations, except they were shorter laterals. So now all of a sudden, you kind of jump start that and you bring it to the front with a rig, and it makes economic sense to do that. So that's one reason we found a rig and added it earlier on.

Our next question comes from Paul Diamond with Citi.

Just wanted to touch base, you have talked a lot about the deviation over the last few years between Western Haynesville and the core and then some of the noncore asset sales. I guess, is there anything on the horizon that would kind of shift more of the legacy core into that, I guess, noncore category in which you'd be potentially looking to monetize? Or with these the deals towards the end of last year more one-offs?

Yes. We don't have any current plans to invest at any properties but we obviously react to people coming to us or react to activity in the area, though, but there's no planned divestitures for 2026.

Yes. We look at that and Shelby was kind of dangling out there, and we had inbound calls, and we look to see where we might drill that. And then if we could monetize it, what we would do with the dollars particularly, we would have never sold that have we not been adding inventory in the Western Haynesville, but that also proves that we trust what we're derisking in the Western Haynesville.

Understood. Appreciate the clarity. And then just talk a bit about other improvements in capital spending, whether it's river steering, high-pressure apparatus or other addition rate you talk a bit about in the Western Haynesville, how you see that deployment timing shaping out? Is this relatively near through '26? Or is it back half of the '27 type weighted? Is when do you expect some of those tangible cost savings to flow through?

Yes, that's a good question. So all the operators in the core, I'd just say really this rotary steerable started the vendors have been putting R&D dollars into the rotary steerable systems for the Haynesville. They're used extensively in all the other basins because they're lower temperature not really in the Western Haynesville till, say, the last half of '25. We've had probably 10 runs to date with that system so far and really made good progress. The vendors -- they're tweaking their tools and as far as deploying it to the Western Haynesville, I'm going to say some time here within the next 3 months, we'll be making our first run in the Western Haynesville. We're going to make -- we do plan to make several runs in the Western Haynesville over this year.

As far as the full cost savings, I think we'll get pretty immediate cost savings when we get our -- that first [ 10,000 ] rig in place late this summer. -- the rotary steerable, I think, will be more -- a little bit more of a gradual increase as far as the realized savings on that system. But hopefully, this -- I think this 2 weeks by this time next year, we can be achieving this 2 weeks reduction in drill times from where we're at today on average. So I mean, we've got -- like I said, the vendors are super interested. They're putting a lot of money in R&D for these tools. all the operators are trying to -- they're running the tools in the core.

So we've looked at all the numbers, and it's very doable in the Western Haynesville. And I think once we see some success early on in the Western Haynesville, we'll be pushing to get the temperature rating on that tool even higher. And I think that may be maybe deeper into next year as far as having a say, a 392-degree rated rotary steerable tool. But like I said, if we just can repeat in the first half of our Western Haynesville laterals of what we've seen in the core, we're going to definitely cut off a lot of days.

And our final question comes from Phillips Johnston with Capital One.

Just a couple of follow-up questions about the year-end reserve report. First, what is the average EUR per 1,000 foot assumed by [indiscernible] in the Western Haynesville? And then can you maybe talk about how that compares to the legacy Haynesville?.

Yes. I'm not sure why you referenced -- [ Lake Elan ], our reserves are audited by Netherlands [ Sewell ], Leo. I mean, Phillips. Yes, so the Western Haynesville basically, I think, the overall average reserve EURs or probably they do range from anywhere from per 1,000 foot of lateral to 4 Bs per 1,000 foot lateral kind of a range. I think that only the ones that really have a long performance have that really higher one. But I think generally 3.5 is a good average for the Western Haynesville sale.

Okay. Sounds good. Yes. Sorry about that. I forgot it was so -- just one more on the reserve report. What's sort of the implied next 12-month PDP decline rate in your report and how does that maybe compare to the decline rate in your year-end '24 in the quarter?

It's actually come down a little bit. It's from 40%, it's down like 1% or 2%. Part of that is a function of was expected to start to come down as we have a greater percentage of our production in the Western Haynesville, and we're starting to see that. It's just a small piece of the overall reserve. So it will -- that first year PDP decline will improve over time, not all at once.

Thank you. This concludes the question-and-answer session. I would now like to turn it back to Jay Allison for closing remarks.

[indiscernible], the only thing I would tell you is that I think there is concern about U.S. shale maturity. I think there is a little bit of spirit about wildcatting now because you've got to have inventory. And if you just look at these numbers in the legacy Haynesville, which is 4 million acres, has produced 48.5 Ts from 7,600 wells, and we think Comstock is exposed to 50 Ts, well, that's 4 that's been produced from the legacy Haynesville.

That's why when you ask Dan, the question about are the service companies trying to figure out how we can drill and complete these wells quicker, faster cost savings, absolutely, yes. Yes, because they have a lot of work built in for decades if they can do that, and they're spending their own money doing it. So they not only believe what we're doing. We believe what we're doing and the 1,000 penetrations that we have from North, Southeast, West that triggered this whole play shows that we probably have a great belief it is accurate.

So that, we are thankful. We're fortunate that we captured that footprint. And I think that goes back to toggling. As I visit with Jerry, we will toggle stuff. Do you have X amount of land man leasing acreage you toggle it. What do we do in the Western Haynesville? Do you add 2 more rigs in 2024? No, because gas prices are low, so you do it in '25, kind of like what Dan is doing with these rotary steerables, you accelerate it and going to the Western Haynesville. So and then if the opportunity comes or we should divest something in the core that we won't drill for years, but somebody else would drill now and you can both win, you toggle that. So that is what we've been doing, and that's what we will do for all the equity stakeholders and the bondholders and the banks and everybody else that believes in us. And I can tell you that we work really hard. We're going to try to give you good news when it's there. And if some is not there, we'll always say the truth. A pretty good world we live in. Thank you.

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

Good day, and thank you for standing by. Welcome to the Q3 2025 Comstock Resources Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to turn the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

All right. Again, I want to thank you for the introduction and thank those that are on the call. It's been a really good morning. Welcome to the Comstock Resources Third 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 Third Quarter 2025 Results.

I'm Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our President and CFO; Dan Harrison, our COO; 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 of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you'll flip over to Slide 3. As we start today, we are really excited to update our stakeholders on the company's progress so far this year. Comstock and our bold moves to create the Western extension of the Haynesville Shale have been the subject of several new stories recently as the interest in natural gas has never been greater.

I don't believe we have ever seen a brighter future for natural gas. Natural gas has become the go-to energy source in the United States, driven by the growth in LNG exports and the push to generate power for AI and data center development. I noticed yesterday that LNG exports reached a record high of 18.7 Bcf and the journal is full of articles on the impact of AI and data centers on future power demand. The Haynesville Shale is on the front line to deliver the gas supply to meet the growing demand. As one of the early pioneers in the Haynesville, we have focused our efforts over the last 5 years on being a leader in expanding the resource in the basin to be able to meet the new demand. The Western Haynesville story is more about utilizing advancements in technology than geologic prospecting as the existence of the Haynesville and Bossier shale in the area has been well known.

Today, we're giving you a preview of the future by providing our estimates of the vast inventory of drilling locations and our emerging play in the Western Haynesville. We also announced the divestiture of some of our legacy Haynesville assets, which we will not need in the future as we shift more of our resources to the Western Haynesville. The sale allows us to improve our balance sheet as all of the proceeds to retire long-term debt. This was also a very efficient quarter in our legacy Haynesville drilling program fueled by the additional drilling rig we added at the beginning of the quarter. Our drilling and completion costs in our legacy Haynesville area averaged $1,229 per lateral foot. That is an industry-leading number in the basin. The activity we added last quarter will drive production growth next year into a growing demand market.

On Slide 3, we summarize the highlights of the third quarter. Higher natural gas prices in the third quarter drove the improved financial results in the quarter compared to the third quarter of 2024. Our natural gas and oil sales grew to $335 million. We generated $190 million of operating cash flow or $0.65 per diluted share. Adjusted EBITDAX for the quarter was $249 million, and we reported adjusted net income of $28 million or $0.09 per diluted share. During the third quarter, we put 3 new Western Haynesville wells online, increasing the number of wells turned to sales in 2025 in the Western Haynesville to 8 wells. Those 3 wells had an average lateral length of 8,566 feet and an average per well initial production rate of 32 million cubic feet per day. In our legacy Haynesville, we've now turned 28 wells to sales to date in 2025 with an average lateral length of 11,919 feet and a per well initial production rate of 25 million cubic feet per day.

In September, we divested of our nonstrategic Cotton Valley wells in East Texas and North Louisiana for net proceeds of $15.2 million. We also recently entered into agreement to divest of our Shelby Trough assets in East Texas for $430 million in cash, and that sale is expected to close in December. On the next slide, I will cover the divestitures in more detail. Slide 4, visually, you can see this. It summarizes our recent divestitures. In September, we sold our legacy Cotton Valley wells in East Texas, North Louisiana for net proceeds of $15.2 million. Our Cotton Valley properties, which we sold included 880 or 770.9 net wells producing 7.9 million cubic feet per day net to our interest and another 46 or 27.3 net inactive wells. On October 10, we entered into an agreement to sell our Shelby Trough properties in Nacogdoches, San Augustine and Sabine counties for $430 million. These assets include 36,000 net acres with 155 or 74.5 net wells producing 9.3 million cubic feet per day net to our interest.

The Shelby Trough still is expected to close in December. I'll now turn it over to Roland to discuss the financial results reported today. Roland?

All right. Thanks, Jay. Slide 5, we cover our third quarter financial results. Production in the third quarter averaged 1.22 Bcfe a day, and our oil and gas sales in the quarter increased 10% from the third quarter of last year to $335 million. EBITDAX in the quarter was $249 million, and we generated $190 million of cash flow during the quarter. We reported adjusted net income of $28 million for the third quarter or $0.09 per diluted share compared to a loss in the same period in 2024. Slide 6 is the year-to-date results. Our production for the first 9 months have averaged 1.24 Bcfe per day. And with improved natural gas prices, our oil and gas sales in the first 9 months have increased 18% to $1.1 billion. EBITDAX for the first 9 months of 2025 was $802 million, and we generated $639 million of cash flow. We reported net income of $122 million for the first 9 months of 2025 or $0.41 per diluted share as compared to a net loss for the same period last year.

On Slide 7, we break down our natural gas price realizations. The quarterly NYMEX settlement gas price averaged $3.07 in the third quarter, and the average Henry Hub spot price averaged $3.03, which is slightly below the settlement price. 28% of our gas was sold in the spot market and the balance was sold in the index market. So the appropriate reference price for our gas was $3.06. Our realized gas price during the third quarter averaged $2.75, reflecting a $0.32 basis differential compared to the NYMEX settlement price and a $0.31 differential compared to the reference price. In the third quarter, we were 57% hedged, which increased our realized gas price to $2.99. We broke even from our third-party gas marketing in the third quarter.

On Slide 8, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.77 in the third quarter, $0.03 lower than last quarter. Our EBITDAX margin was 74% in the third quarter, which is unchanged from last quarter. Lifting costs improved by $0.02 in the quarter. Production and ad valorem taxes were up by $0.01 and gathering and cash G&A costs improved by $0.01 in the third quarter. On Slide 9, we recap our spending on drilling and other development activity. We spent a total of $267 million on development activities in the third quarter and $785 million for the first 9 months of this year. In the first 9 months of this year, we've drilled 25 or 21.8 net horizontal Haynesville wells and 11 or 10 net Bossier wells for a total of 36 wells.

We also turned 36 wells or 30.9 net operated wells to sales, which had an average initial production rate of 27 million cubic feet per day. Slide 10 recaps our capitalization at the end of the third quarter. We ended the quarter with $580 million of borrowings outstanding under our credit facility. Our borrowing base is at $2 billion under the credit facility and the elected commitment is $1.5 billion. Our last 12 months leverage ratio has improved to 3x and will continue to improve as you get away from the 2024 results, which are weighed down by low natural gas prices. At the end of the third quarter, we had $239 million of liquidity.

The sale of our Shelby Trough assets that is expected to close in December will improve the leverage ratio and enhance our liquidity since the cash flow that's associated with the properties being sold was minimal. I'll now turn it over to Dan to discuss the drilling results.

Okay. Thanks, Roland. If you look on Slide 11, this is an overview of our latest acreage footprint in the Haynesville/Bossier Shale in East Texas and North Louisiana. We now have 1,055,386 gross and 797,440 net acres that are prospective for the commercial development of the Haynesville and Bossier shales. Over on the left, this is our Western Haynesville acreage footprint, which we've now grown over 530,000 net acres. On the right is our 266,711 net acres in our legacy Haynesville area. We have 27 gross or 26.9 net wells currently producing on our Western Haynesville acreage, which is virtually undeveloped compared to our legacy Haynesville area. Given the higher pay thickness and the higher 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 12, this outlines our new development plan utilizing the horseshoe lateral concept. The horseshoe well design concept combines the 2 separate and adjacent shorter laterals into a longer single lateral, which results in a much more efficient use of capital. We realize approximately 35% savings in our drilling costs when we drill a 10,000 lateral horseshoe well compared to a 5,000-foot sectional lateral well. Our drilling inventory in our legacy Haynesville area now includes 118 horseshoe locations. During the third quarter, we completed our second horseshoe well to date, the Roberts 2623 #1 had 11,453-foot lateral and a 26 million cubic feet per day IP rate. To date this year, we have 1 drilled additional horseshoe well, and we have another 4 horseshoe wells that are currently in progress. We plan to drill a total of 8 horseshoe wells this year, and we plan to drill 10 horseshoe wells in 2026.

Slide 13 is our updated drilling inventory in our legacy Haynesville area at the end of the third quarter. This is adjusted to exclude the locations we're selling in the Shelby Trough. This quarter, we are now presenting our legacy Haynesville and our Western Haynesville drilling locations separately. Our total operated inventory in the legacy Haynesville consists of 1,039 gross locations, 809 net locations, which equates to a working interest of approximately 78%. Our non-operated inventory in the legacy Haynesville includes 873 gross locations, 108 net locations, and this represents a 12% average working interest. Our drilling inventory is comprised of short laterals less than 5,000, medium laterals between 5,000 and 8,500 feet, our long laterals between 8,500 and 10,000 feet and our extra long laterals for all the wells over 10,000 feet.

In our gross operated inventory in the legacy Haynesville, we have 36 short laterals, 157 medium laterals, 425 long laterals and 421 extra-long laterals. Our gross operated inventory is split 51 in the Haynesville and 49% in the Bossier. Over 80% of our gross operated inventory in the legacy Haynesville consists of laterals, which are greater than 8,500 feet. The 118 horseshoe locations mentioned on the previous slide are all in our legacy area. The average lateral length on inventory is now up to 9,961 feet. This is up 275 feet from the end of the second quarter. So our inventory provides us with decades of future drilling locations based on our current activity levels.

On Slide 14, we show our estimated drilling inventory in the Western Haynesville. This represents the first time we've disclosed our Western Haynesville inventory. And our total inventory in the Western Haynesville consists of 3,332 gross locations and 2,559 net locations. This equates to a working interest of about 77%. As much as our Western Haynesville acreage is not unitized, the net locations here are estimated. In the Western Haynesville, the inventory is more weighted to the Bossier formation with 36% of the inventory in the Haynesville and 64% of the inventory in the Bossier. The same as our legacy Haynesville inventory. Our Western Haynesville inventory is broken down into groups of short laterals less than the 5,000 feet, our medium laterals between 5,000 and 8,500 feet, our long laterals between 8,500 and 10,000 feet and our strong laterals over 10,000 feet.

In our Western Haynesville and the gross operated inventory, we assume we have no short laterals. We have 1,347 medium laterals, 642 long laterals and 1,343 extra-long laterals. So approximately 60% of this gross operated inventory in the Western Haynesville consists of laterals greater than 8,500 feet. On Slide 15 is a chart outlining our average lateral lengths that we drilled. This is based on wells that have reached total depth. The average lateral lengths are shown separately for both our legacy Haynesville and Western Haynesville areas. In the third quarter, we drilled 11 wells to total depth in the legacy Haynesville, and these had an average lateral length of 12,593 feet. The individual lengths ranged from 4,968 feet up to 15,466 feet. Our record long lateral in our legacy Haynesville area still stands at 17,409 feet. In the third quarter, we drilled 6 wells of total depth in the Western Haynesville.

These wells had an average lateral length of 10,158 feet. The individual lengths here range from 7,809 feet up to 12,710 feet. Our longest lateral drilled to date in the Western Haynesville still stands at 12,763 feet. To date in the Western Haynesville, we have drilled 15 wells with laterals longer than 10,000 feet, and we have drilled 6 wells with laterals over 12,000 feet. Slide 16 outlines the wells that were turned to sales on our legacy Haynesville acreage this year. So far this year, we've turned 28 wells to sales in our legacy Haynesville area. The individual IP rates on these wells range from 16 million a day up to 37 million cubic feet a day, and the average was 25 million cubic feet a day. The average lateral length was 11,919 feet with the individual wells ranging from 9,252 feet up to 17,409 feet. Just to recap, 4 of our 8 rigs are drilling on our legacy Haynesville acreage.

Slide 17 outlines the 8 wells that we have turned to sales in the Western Haynesville this year. Since we last reported our earnings, we have turned 3 additional wells to sales. These 3 wells had an average lateral length of 8,566 feet and an average initial production rate of 32 million cubic feet per day. And 4 of our 8 rigs are drilling on our Western Haynesville acreage. Slide 18 highlights the average drilling days and the average footage drilled per day in the legacy Haynesville area for our benchmark long lateral wells. These are wells that are greater than 8,500 feet long. In the third quarter, we drilled 10 benchmark long lateral wells to total depth in the legacy Haynesville, and these wells averaged 26 days to total depth. We've averaged 26 days consistently for the last 3 quarters. In the third quarter, we averaged 1,004 feet drilled per day on our legacy Haynesville acreage. This is a 4.5% increase versus the second quarter of 2025 and a 2% increase versus the 2024 full year average of 987 feet drilled per day. The best well drilled to date in the legacy Haynesville still stands at 1,461 feet. which was drilled to TD in 14 days.

Slide 19 just highlights our drilling progress in the Western Haynesville. During the third quarter, we drilled 6 wells to total depth in the Western Haynesville. We now have a total of 35 wells that we have drilled to total depth through the end of the quarter. We averaged 52 drilling days for the 6 wells drilled to total depth in the third quarter. This represents a decrease of 3 days compared to the second quarter and a decrease of 7 days compared to our 2024 full year average of 59 days. Our fastest well drilled to date still stands at the 37-day mark, and that was drilled with a 12,045-foot lateral.

Over on Slide 20 is a summary of our D&C cost through the third quarter for our benchmark long lateral wells located on our legacy Haynesville acreage. These costs reflect all legacy area wells drilled with laterals greater than 8,500 feet long. The drilling costs are based on when the wells reach TD and the completion costs are based on when the wells are turned to sales. During the third quarter, we drilled 10 of our benchmark long lateral wells to total depth. The third quarter drilling costs averaged $558 a foot. This is a 15% decrease compared to the second quarter. We had an abnormally high drilling cost in the second quarter due to drilling difficulties that were associated with some highly over pressured SWD zones. And during the third quarter, we turned 9 wells to sales on our legacy Haynesville acreage. The third quarter completion costs came in at $671 a foot. This represents a 7% decrease compared to the second quarter.

These lower completion costs are due to a combination of we had lower frac pricing, lower fuel costs with all of our wells using natural gas blended fuel and also the longer laterals in the third quarter. Just -- we got 4 rigs running that are running on our legacy Haynesville acreage. Slide 21 is a summary of the D&C cost through the end of the third quarter for the wells drilled in the Western Haynesville. During the quarter, we drilled 6 wells to total depth with an average lateral length of 10,158 feet. The third quarter drilling cost averaged $1,385 a foot. This represents a 24% decrease compared to the second quarter, but is more in line with our previous quarters. The primary factor for the lower drilling costs in the third quarter is the longer laterals. Our average lateral length in the second quarter was very low at 7,933 feet compared to an average lateral length of 10,158 feet in the third quarter.

During the quarter, we also turned 3 wells to sales on our Western Haynesville acreage. These had an average lateral length of 8,566 feet. We didn't turn -- for this year, we didn't turn any wells to sales in the first quarter. The third quarter completion cost averaged $1,622 a foot. This is a 24% increase compared to the second quarter. And the higher completion cost was primarily due to the higher frac costs we had on the wells and a lesser extent -- to a lesser extent, the shorter average lateral length. We did have some higher-than-normal horsepower usage associated with frac in these wells, which were considerably deeper than our average Western Haynesville well and we reserve some higher frac gradients at these deeper depths. To kind of recap our activity levels, we've got 4 rigs running in the Western Haynesville, and we got 4 rigs running in the -- on our legacy Haynesville acreage. We also have 2 full-time dedicated frac fleets that we are running between both our legacy Haynesville area and our Western Haynesville areas. And I'll now turn the call back over to Jay.

All right. Great job, Dan and Roland. Please refer to Slide 22, where we summarize our outlook for 2025. In 2025, we remain primarily focused on building our great asset in Western Haynesville that will position us to benefit from the longer-term growth in natural gas demand. We currently have 4 operated rigs drilling in the Western Haynesville to continue to delineate the play. We expect to drill 19 wells and turn 13 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 in July, which more than doubled our gas treating capacity. In the legacy Haynesville, we are currently running 4 rigs to build production back up in 2026.

We expect to drill 33 or 25.6 net wells and turn 35 or 28.2 net wells to sales in the legacy Haynesville this year. 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. As Roland stated earlier, we have strong financial liquidity totaling more than $900 million, which will be enhanced with proceeds from the Shelby Trough divestiture, which is expected to close in December 2025. If you have any specific questions on guidance for the rest of the year, please feel free to reach out to Ron Mills. Ron?

Antoine, we can turn it over to Q&A.

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

I wanted to start with a broader question around 2026 and not to pin you guys down on any numbers, but really just want to think about it from the standpoint of the higher level of activity you're carrying into 2026 and the operational efficiencies you've gained in both the Western Haynesville and legacy Haynesville. Could you speak to the broader capital efficiency gains you'd expect as you enter the year?

Yes. I'd say we've -- if you kind of -- the kind of 2 different animals, the legacy Haynesville versus the Western Haynesville I mean the efficiency gains in the legacy area, we pretty much -- we're kind of up at the top of the curve there. I think we've picked up a lot, obviously, since we've added the horseshoe wells. As far as just being able to convert a lot of our shorter wells to longer wells, I think we've seen more efficiency there. The horseshoe wells are going great for us. Really, the efficiency gains that we're still looking to pick up and have been still up on the learning curve is in the Western Haynesville. We've got a lot of -- we've had a lot of improvements we've made to date. We still got some -- a few other things kind of coming down the pike that we're going to be looking at implementing in the Western Haynesville to help our efficiencies there. But I think the 4 rigs that we got running in Western Haynesville has a good activity level for us. We're able to learn a lot from it. We've got -- we've made a lot of improvements in our downhole performance. And like I said, we just got a few things in the mill that are kind of turning that are going to help us out, we think, in this next year in 2026.

Derrick, you commented that we've had solid Western Haynesville well results. And I'd just like to comment on Dan. The very first Haynesville well we ever drilled back in '08, Dan was involved with it. So for 17 years, he's touched every Bossier or Haynesville well we've drilled, either be in the core or in the Western Haynesville. So he has complete authority to derisk and optimize the cost on the new Western Haynesville play. That's important.

And just from a capital efficiency standpoint, we did -- we are carrying some capital this year for the addition of that eighth rig with no production really showing up until sometime in the first or second quarter of next year. So when you think about your typical capital efficiency, that should drive improved capital efficiency next year.

Great. And for my follow-up, I wanted to shift over to gas marking. More specifically, I'd love your perspective on how you see gas on gas competition unfolding along the Gulf Coast. As you think about your supply advantage of being able to deliver gas into Sabine Pass and the competing demand opportunities between LNG and power gen, you're arguably in a great position to benefit from both in terms of gas realizations.

Yes, that's a good observation, Derrick. Yes. I think that especially owning our own midstream in the Western Haynesville is going to be really a huge asset for us in the future as we're able to kind of -- instead of having to go through other midstream companies and long-haul pipelines, we can create great markets right there that we can directly sell to end users and become a very reliable supplier. And I think that's what a lot of these large users with new demand are looking to establish direct relationships with the producers. And we've heard a lot of that about that in our industry. So I think we're well positioned there, given that we control the infrastructure of the midstream and obviously, a great location where the gas can support all the growth in Texas and then with the Port Arthur LNG, very close to be able to connect to that. So yes, I think that's a big part of the future for natural gas is not only having the natural gas, but being able to get it directly to the end user.

Well, Derrick, I think if you look at location, location, location, I mean, 100 miles from Dallas and the same distance from Houston and really close to LNG corridor, you're perfectly situated for both AI, data centers and LNG. So you couldn't be in a better area. And then the fact that this is not an exploration play, it's really a development play for the geology that was there. So it's been a very, very, very active oil and gas region for 30-plus years. So for us to just deepen these wells with the new technology and a great footprint where we're located and maybe 6,000 of these acres are dedicated, the rest are undedicated. That's why we say we're around a big bright light bulb and then people are calling because of the inventory, which inventory is the holy grail. I mean that's why you see people expanding to look at this play. It is the holy grail. You got to have inventory.

Our next question comes from Charles Meade from Johnson Rice.

Warm welcome. Jay, I want to ask you about the Shelby Trough sale. That looks -- it looks to us like that's really a great outcome for you guys as far as what the seller paid for those undeveloped locations. So I wanted to see how you would characterize it, how happy you were with those proceeds and then ask if there's anything left in your portfolio that would -- that could fit that same appetite for people who are willing to pay for those undeveloped locations.

Well, first of all, Charles, I think it's a total win-win for everybody. I mean we are really a unicorn out there because we have so much inventory. As we just announced, we almost have 2,600 locations net in the Western Haynesville. That's a big gift that we've been working on for 5 years. So if you look at other really good locations that might be for sale, I mean, I think it's a really smart buy by the buyer. I think we needed to pay down the debt on our balance sheet because we had incurred a lot of money as our investment in the Western Haynesville. And we look at that. We trimmed some of the vertical wells, those 900 or so vertical wells, we sold those early on. So we are always looking as we derisk and kind of fortify our acreage position in Western Haynesville. Is there anything else we can do, and that is to adjust the balance sheet because we need to get our leverage lower. So I was pleased with how both of those transactions came about.

And again, we always look to see, Charles, as you well know, what can we do as a company position where we think we are to become a stronger company in the light of AI, data center demand and LNG demand. That's the only thing we do. And I think everybody won in the trade. Great locations and that we didn't need to be drilling them because we're drilling the Western Haynesville.

Got it. And then the follow-up, following on that same thread, I want to say thank you for sharing this Western Haynesville location count. And I just want to ask a couple of questions around your assumptions and the dynamics there. Just using the kind of back of the envelope math, it looks like you guys have been pretty conservative in your assumptions on number of zones and spacing across zones. But I wonder if you could share what the -- if you'd be willing to share what the important assumptions are in that, I think, the 2,500, 2,600 number. And also, I think Dan alluded to this in his prepared remarks that perhaps -- perhaps because not a lot of the acreage is unitized yet that's actually preventing you from counting location. And -- and my assumption is that would get worked out over time, but maybe you can fold that into the assumptions on the location count.

I'm sure. I think we tried to be conservative on how we looked at well spacing and benches in the play because you obviously don't want to start out at a high number and bring it down. But we think they're very -- it's a very realistic view of the inventory. The comment that was made about the working interest in our legacy Haynesville inventory, I mean, every single location there is pretty exact. We know the exact -- we know what the unit is in. We know our working interest with precision. In the Western Haynesville, those units are being put together still. So the exact working interest in the units is not 100% known. So far, most of the wells, we've had 100% working interest in. So we just looked at our acreage ownership and just made some rougher assumptions there.

So it just doesn't have the level of precision, but I don't think it's a significant -- I think we're within the margin of error as far as looking at how we present the net numbers.

Yes. And Charles, you always discount it back. You say, here's what you could have. Here's kind of a high low number and then you discount it back and say, okay, what is a number that we can throw out right now that we think with some [ bookends ] on, we have a chance of achieving. And like [ Roland ] said, you don't want to be aggressive and then all of a sudden, you have a few less and you're a loser. So we want to throw that out and just say, again, with the [ Asterix ] that we've not unitize some of those locations. So that's a guesstimate.

Our next question comes from Kalei Akamine from Bank of America.

I want to start on the Western Haynesville disclosure. And maybe first off, I think putting your expectations in print really shows your conviction in the asset. For my question, I want to follow up on the unitization comment. You've got some short laterals in that table, 5,000 to 8,500 feet, but this is a large contiguous position. So my question is, what's stopping you from doing the land work to optimize the entire position around 10,000-foot laterals? And if that's possible, how long would that work take?

Yes, that's a great question, too. Look, but I think there are some areas that -- where there's ownership where there's some other operators that we've already kind of identified that we're keeping out of our units. So we've chosen those shorter laterals. Just like the wells we completed this quarter and drilled last quarter, a lot of that was defined by kind of the acreage ownership. And so we've honored that where we don't have it completely contiguous. So I think -- and then there's some -- there's obviously geologic structures that we have identified on seismic that we are avoiding and not wanting to develop and around. And so we've tried -- we've honored a lot of our geologic work too in those assumptions. But it's still early on, you'll be able to probably optimize that over time. And then a lot will depend on how long do you really want to go? Do you want to go to 15,000-foot laterals. And some of that is -- I think there's room to optimize in the future. But I think this was a really good view of how we see the acreage we currently own.

Now we could also lease additional acreage that will change the configuration in the future. And I'm sure that will happen. We're always picking up additional acreage as we put the units together. So there will be moving parts, but I do feel like this was a pretty thorough look at if we stop leasing what it could look like now.

Well, Kalei, you know we added 5,000 acres from the last time we reported. So we do cleanup stuff all the time in the Western Haynesville, just like we do in the core. This is a pretty safe conservative number. We think that we have leased 90% of what we think the real value is in the Western Haynesville, maybe that's expanded, and that will be a good thing. We hope it does expand. But based upon the control that we have and the size that we have and the well results we have, I think that we're in pretty good shape there. But we do -- we keep trying to make it better. And at some point in time, we won't own 100% of all the wells. But until that time is right, we'll kind of drill the lateral lengths that we need to keep the information that we need to keep kind of in our back pocket right now.

For my second question, I want to ask about the second train at the Marquez gas plant. That build looks like it's going to take you to about 1.3 Bs from 900 million cubic feet. So that's quite the scale. My question is, was this part of the original scope of the JV deal with Quantum? And then can you talk about the capacity utilization at those plants? What is it today? And once Marquez 2 is online, perhaps in '27, where do you think the utilization rate will be at that time?

I don't know if we want to forecast the utilization rate that's getting way out there. But we are -- when we originally put together the plan for Pinnacle, the Pinnacle Gas Services and how to service the development program. I mean, obviously, we saw -- and we've commented this a long time ago that we saw trying to create a treating infrastructure to handle up to 2 Bs of gross production over the next 5, 6, 7 years. So I think this is the second phase of Marquez is just -- was the next step that was in our original plan. And then there's another either debating on either an expansion at Bethel or a third gas plant will probably be something way off next in the future. But we do have to keep ahead. We obviously have to provide for the treating way ahead of when we're going to actually produce it. It's not going to be a just-in-time kind of delivery, obviously, because it takes a good 12 to 18 months to put those together.

So yes, right now on Marquez Phase 2, we've got a lot of long lead time components and equipment that are being manufactured that we have to go out and order. And so that's kind of the big process going on now for something that we can hopefully open up next summer would be our goal for that.

And yes, I think the key answer to that is we have a lot of inventory, but we own our midstream, as Roland mentioned in the beginning comments, and we have an incredible financial partner with Quantum, and we look to see what our drilling inventory looks like. We see what our performance looks like. We see what our acreage addition looks like. And then based upon all that, we control the gathering. And as far as the takeaway and the demand, as we said 45 minutes ago, it has never ever looked brighter out there for what the world needs, not just America, the world needs in the form of natural gas. I think we're right there at the right time.

Addition -- other operators, there are a couple of other operators which are running rigs in the area. And so a lot of that will how we actually build out will also depend on do we end up picking up some of that gas or not. And so that's all -- a lot of that is to kind of remain to be seen in the future. But there's other activity in the area that hopefully that we kind of see coming to Pinnacle over time, too, as we build out that great asset that underlies the Western Haynesville.

Our next question comes from Carlos Escalante from Wolfe Research.

I love the way the operator said my name. I want to go back to one of your comments, Jay. You said, hopefully, the Western Haynesville, the footprint that you guys have at least expands and nice work play, by the way. But look, you've done a great job at establishing the core with just under 30 TILs across the play, especially in that southern corridor across Leon and Robertson with what I think that -- what is incremental data proving up acreage to the north of that as well. However, you've seen recent leasing and M&A activity load into the East and Southeast, particularly in Anderson and Houston. So I wonder, when you see that, do you think the core -- do you think there's likelihood that the core of the basin could actually be much larger and it extends into potentially some of your other wells that you drilled earlier this year? So -- in part leads to the question, if I may, along the same lines, if you look at -- it looks like you have a permitted well near Olajuwon. And maybe you can touch on when you plan to go back to this area as well.

Well, yes, the comments would be because of Jerry Jones and because of his billion plus dollar investment in the company, we could literally think and not only think, Carlos, we could act out of the box. And because of the fact that we've always been leaning toward natural gas, I mean, we're one of the front runners in the core of the legacy Haynesville area. Jerry Jones said, here's a well, we showed it, we could drill it, and that's a Circle M well. That over the last 5 years has proved to be successful. So as we move to the call we have [ today ] over 5 years and looking at the seismic 2D, 3D, looking at the wellbore penetrations, looking at the performance of the 30 -- 40 wells we've either drilled, completed or drilling. What we look at, we say we're very comfortable that this is probably 90% of the real value.

Now as you look at Aethon, Aethon says there are monster wells out there. I love that they'd say that. And we've hit a bunch of them. But that's an incredible company. [indiscernible] to come in, they're smart, management is smart. They're money smart. They come in. Expand is -- they're doing what their name says, expanding. Their name says expanding, and they're expanding into the Western Haynesville because why? As I said earlier, the locations are the holy grail. I mean you can do M&A, M&A, M&A, but that doesn't add any new locations on Planet Earth. It gives you more under your umbrella, but we've tried to address the problem and the problem is, can you really add new inventory. And that's where the prior question was asked, what's your inventory count?

And I think we're pretty accurate on 2,500, 2,600 net locations. That's an incredible number. 2,600 locations is an incredible number. So we are always looking, Carlos, to see, do you go east, do you go south? Do you go -- everybody is always doing that. And you know what, there's going to be some gems out there. And I hope they are found because all that does is make our acreage more valuable in our opinion.

You asked about a permitted well up by the Olajuwon. We do -- we actually did spud -- we got a 2-well pad that's up there near the Olajuwon and that pad was spud last week.

So it will be Bossier, one Haynesville.

Yes, we got one -- the Olajuwon is producing from the Haynesville. And the new pad that we spud last week would be an additional Haynesville well and a Bossier test -- our first Bossier test up there.

Yes. And we're coring up in that area, too.

That's correct.

So that the cores we've had, and we're coring there also.

That's terrific color, guys. I appreciate that. And real quick, if I can sneak in my follow-up. You mentioned [indiscernible], Jay. And if I may, I think one of your Tilled wells this quarter, the 2 wells, the [indiscernible] are nearby that area. We've seen their type curve to be quite outstanding in terms of production plateau. And obviously, this well is very strong in terms of initial production. So I guess my question is, is there anything that you're looking at in terms of what they're doing or any kind of near-term collaboration that you can guys potentially benefit from in terms of what you do? Or has it been more a separate effort from that standpoint?

Well, we've done some -- or in the process in some acreage swaps with them, so they can drill longer laterals. We can drill some longer laterals in areas that we want to drill and they want to drill. But I don't have any other comments on that, [indiscernible].

I mean... It's always very -- when you have other operators doing things differently, it's always great learning for a basin. So that's one thing that the Western Haynesville hasn't had near as much of as the original Haynesville had. But as we have some new -- other operators, and they were the first one out there. And so it's going to be, I think, very incremental to us learning how to properly produce the wells and drill the wells, the more activity, the more learning is going to be better for all the operators.

If you have 4 or 5 more new operators come in, I think everybody, particularly Comstock, the learning curve has shortened. I think would be a great thing.

Yes. I think what you say is all the operators, obviously, they all kind of do something a little bit different, bigger fracs, smaller fracs, how they draw their wells down, what kind of casing design, bigger hole laterals, slimmer hole laterals. So all of those things, I think when you get more of that in the [ box ] start looking at the results, like we say, that's definitely going to help everybody.

[Operator Instructions] Our next question comes from Kevin MacCurdy from Pickering Energy Partners.

I know you haven't put out a 2026 guide yet, but is there any color you can provide on how you plan to prosecute the Western Haynesville next year? I'm looking for any thoughts on holding acreage versus development, the size of the pads you might drill and lateral lengths as well as I think you kind of touched on where you might be drilling, but any more color on that would be helpful, too.

I think the 90% of the plan is going to be holding acreage, as we said, we still have a lot of term acreage that we lease in the play. And so that's a big part of where we want to drill the wells. So it's going to be following where we lease the time frame we leased. And -- and so I think that's how we look at it. I think the activity level of 4 rigs that we have operating is sufficient to kind of accomplish all that and not have to worry about losing any acreage that we don't drill, that we want to drill.

And I think you're going to see in 2026, more of our wells will continue to kind of push more in that normally northeastern direction along the trend of where the acreage is.

Great. Appreciate that detail. And then just a question on Slide 13 and 14 on your inventory. Just to confirm, were the changes in the legacy Haynesville and Bossier Shale, was that just driven by the asset sales? Or was there anything else that changed in those inventory numbers?

Well, one time we had some of the Western Haynesville in there, probably a small amount that was based on just the wells we drilled and the other direct offsets, et cetera, that you obviously have in the inventory. And so that's why we kind of chose to break it out. It really wasn't really represented much in the original chart. So you had that plus you had -- obviously, we had the acreage that we sold or in the process of selling that we also removed those locations. And then there's always continued recalibration as wells are -- we find a way to make the laterals longer typically is kind of you can see that the feet continues to get larger, average foot of the lateral. So that's always a process that we continue to optimize.

Our next question comes from Jacob Roberts from TPH & Co.

I wanted to circle back to a Q2 item. One of the things that was discussed was some experimentation on choke management in the Western Haynesville. And I understand that we probably don't have enough data to make a final call, but I'm just wondering if you could talk about maybe the varying methodologies you've applied to the 3 that came online last quarter and then the handful that are going to be coming online in the year.

Yes. We got the 3 that we turned to sales in the last quarter. We've got 4 new wells that are turning to sales here in the fourth quarter. We have had some -- we have varied it a little bit. I'd say we haven't done anything that's been extremely conservative to date. We're taking some of the information from the cores, and we're still doing a lot of detailed rate transient analysis. And basically, I think it's telling us, obviously, the more conservative drawdown is what we need to be following. And I think for the future, we're still looking to transition more into that, probably more conservative approach from where we started at.

Great. Jay, earlier, you mentioned AI data centers, that type of stuff as well as LNG demand, which have both been hugely topical. But recently, we saw one of your peers sign a sizable industrial contract at a premium to NYMEX over in Louisiana. Curious if you could talk about that market, how you see it evolving and maybe Comstock's willingness to participate in industrial agreements moving forward?

Sure. That's a great market, especially in the -- along the river corridor area and areas along the Gulf Coast where there are new industrial plastic plants, et cetera, that are being built, fertilizer plants. And they're competing, obviously, with the LNG feedstock gas. So those customers have been reaching out and interested in long-term supply deals where you know years ago, they were never interested in that. They would just go get gas in the monthly market, it was easy to get. So I think you do see -- I think over time, we see a lot of our market and other producers in the area wanting to establish having more direct sales to end users, capturing more of the value, the value chain and better margins versus having the midstream companies take off a lot of that margin. And so a lot of us are working on long-term plans like that as we are, too.

Our next question comes from Phillips Johnston from Capital One.

Congrats on the asset sales. My first question is really just a housekeeping question for Roland on the Shelby Trough sale. Would you expect any tax leakage on the gross proceeds?

That's a good question. No, we really have lots of tax attributes to actually that -- and we do expect a fairly sizable gain on that transaction because of -- we acquired that acreage way back at the Covey Park acquisition and it wasn't a big part of the value that got allocated in. So there is a pretty sizable bookend tax gain that we expect. You'll kind of see some of that in the 10-Q when we file it later today. But we think we have a lot of tax attributes that we'll just be able to utilize. And so we don't see any real -- cash tax impact of that.

Okay. Sounds good. Then a question for Dan. It's really a follow-up on Carlos’ and Kevin's questions. It sounds like the 2-well pad near Olajuwon has kicked off, which is good to hear. Can you maybe just give us a guesstimate of how many wells up in that northern step-out area might be considered for next year or what percentage of the total might be up in that area?

Good question. We do have more wells planned for up in the area up there. The number escapes me off the top of my head, but we do really like that area up there. The Olajuwon is performing extremely well, super happy with it. So our next step is on this 2-well pad is to test the Bossier, which is much thicker up there. So we want to get a good read on the Bossier and then we'll kind of go from there as far as how we're going to develop out that bench in that area. But we do have, I'm going to say, 5, 6 wells kind of planned up in that area for next year, kind of around -- just around that general area.

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

You did touch a bit on it, but with the new treatment capacity you have, the new plant coming online, have you talked much about sort of like the economics of it, sort of the in-house economics versus the third-party opportunity while you're kind of in the ramp-up mode?

Yes. And I think that's been something we've been studying, obviously, because we don't -- a large part of your cost for treating is really all the facilities you build. And then once you build them, if you can utilize them, your actual operating costs can be very, very, very low, just the actual operating costs associated with it, but you have to recover the capital. So that's kind of where a lot of the costs are. So if you -- obviously, if you own it yourself, you can -- once you recover it, you don't have to keep recovering if you allow a third party to provide it, then they're going to continue to charge whatever they can for that area based on demand for their services in the area, and that cost will never go down unless there's just no demand for services in the area.

So I think -- so these are long-term investments we're making now, but I think they're really going to really pay off in the future for us. They continue to preserve our already industry-leading low cost structure. So that's why we're really excited about what we're able to accomplish out there and be able to do it without too big of a strain on the company with our partnership there that's funding it.

Great. And this is kind of a housekeeping item, but I did take sort of a quick look at the gathering and transportation expense line, and it looks like it might have been down sequentially a bit in the quarter. And I just wonder if I had that right and if there are any drivers behind that?

Yes, it was down sequentially. It was just over $41 million in the second quarter. It was just under $40 million in the third quarter on -- but part of that is driven by we had lower volumes sequentially as well. So you look at it on a GTC per unit basis, it was $0.36 just versus $0.37 last quarter. So it's really -- that's driven by volumes.

Yes. I would say that's properly correct, right.

Our next question comes from Paul Diamond from Citi.

Just wanted to touch quickly on kind of your activity allocation between Western Haynesville and the legacy acreage. Currently split 50-50. If you guys were [ to add it a drop ] any activity over time, where do you think it would come from one or the other?

Well, I think we'd like to keep the 4 operating rigs in the Western Haynesville because just because of the -- strategically, in order to hold all the acreage, that's a pace that makes that a comfortable program. And so I think obviously, we flex in the legacy area where there's no acreage considerations there and you're kind of basing that on what's the supply-demand outlook, what's the price. So obviously, just like last year, we flexed very heavily in the legacy area. And we hope to continue just to steadily add activity in the Western Haynesville as we build that up. So they're kind of 2 different kind of -- I think we're very reactive on the legacy side to the situation, and then we want to be more steady on the Western Haynesville in order to continue to develop that asset and retain that asset.

Got it. Makes perfect sense. And now you guys have given the inventory assumptions in the Western Haynesville acreage. Can you talk about any progression you see on D&C still tracking towards about $30 million per well on 10,000-foot basis. I guess where do you guys see that going through time? What your target longer term?

I think we're going to definitely see the costs continue to come down. There's a pretty good spread depending on where you're drilling at on the acreage as far as what that D&C cost is. Our low end that we've achieved so far is about $2,100 a foot for the stuff that's a little bit shallower [ TBD ]. And then the $30 million mark or assuming like a 10,000 lateral, $3,000 a foot or a little bit higher than that, if you go all the way to the other end to the far deeper stuff, probably just a little bit over that. So as far as any quarter when we're reporting, it just depends on where those rigs have been and what the [ TBD ] areas we're drilling in as far as what the cost comes out to, but we're definitely going to see the cost continue to go down. I think we've gotten a big chunk of it down already and is naturally going time, I think the rate at which the costs come down probably slow a little bit. But we still see -- I mentioned it earlier, we still got a few things kind of coming down the pike that we're going to be trying. We think that's going to help us continue to shave days off.

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

Perfect. I want to thank everybody for listening for over an hour. And November 4, 2025 is a great day for the company when we can tell the stakeholders, which is you, and our financial bankers, which is you, that we've added this giant footprint in the Western Haynesville. So the debt that we have, that is the Western Haynesville acreage that we have been buying. It's 530,000 net acres. So -- but we can report on a day like today, we have over $900 million of liquidity, and that's going to grow. We have Kim report that we have 2,559 Western Haynesville locations at the very beginning of time. And then the legacy locations are 917. So we have a lot of inventory. We're not chasing inventory or we're not chasing M&A and that the management here has been pioneered the Haynesville/Bossier shale going back to 2008, 17 years.

So the man that's in charge of operations has been here the very first day we ever looked at the Haynesville/Bossier, which is Dan Harrison. And then you look at managing the balance sheet, the couple of divestitures that we will make and have made that just tells you that we're watching our balance sheet, which the major stockholder and everybody else wants us to do that. So I just want to thank you for believing in the company, and we'll give you a good day's work every day. So thank you for the call.

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