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 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 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 Executive Officer. Please go ahead.

Thank you for the introduction. 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, our VP of Finance and Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. On slide three, if you had turned there, we summarize the highlights of the second quarter. We did see the return of production growth in a quarter. Production increased 16% over the first quarter of 2026 and 1% over the second quarter of 2025. However, lower natural gas prices drove 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 EBITDA for the quarter was 245 million dollars. Our legacy Hainesville horseshoe and Western Hainesville drilling results were driving future production and reserve growth. Eleven Western Hainesville wells turned to sales so far in 2026 with an average lateral length of 10,331 feet and a per well initial production rate of 31 million cubic feet per day. Twenty-two legacy Hainesville wells turned to sales 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-string 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 turn over to slide four. On June 15, 2026, we sold a minority equity interest in our midstream subsidiary Pinnacle Gas Service to certain funds managed by Sixth Street. Sixth 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 Hainesville acreage which is well positioned to service the growing demand for natural gas in 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 Sixth Street represents an important milestone for Comstock and a strong validation of the value we have created in the Western Hainesville. With Sixth Street's investment, we strengthen our balance sheet by reducing debt and simplified PGS's capital structure. We'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 certain return hurdles were 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 Hainesville 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 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 three 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 Haynesville 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 million for the first six months or $0.40 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, our adjusted net income would have been $48 million for the first six months of this year or $0.16 per share. Slot 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, reflected a 35-cent basis differential compared to the NYMEX settlement price, and a 37-cent differential compared to the reference price. In the second quarter, we were 63% hedged, which increased our realized gas price for the quarter to $2.93. On slide nine, we detail our operating costs per MCFE and our EBITDAX margin. Our 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 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 cost was down $0.04 per MCFE, GNA was down $0.03 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 $0.04 in the quarter. Some of that was due to the lower gas prices we had, but also the divestitures that we completed last year helped reduce our ad valorem taxes in the quarter. gathering costs were 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 in the quarter improved at 74 percent on slide 10 we recap our spending on our drilling and other development activity you know in the quarter and for the first half of this year we spent a total of 390 million dollars on development activities in the second quarter, and $734 million during the first half of this year. In the first six months of this year, we've drilled 22 or 19.4 net horizontal Haynesville 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 million cubic feet per day overall. Slide 11 summarizes our capitalization at the end of the second quarter. We ended the quarter with 545 million dollars of borrowings outstanding under our upstream credit facility. Our upstream borrowing base is two billion dollars and in our elected commitment under that facility is 1.5 million dollars. At the end of June, our 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 dollars of liquidity. So I now 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 Bosier 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 Bosier Shells. Our western Hainesville footprint has now grown to just over 545,000 net acres. 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 second quarter. We have 926 gross operated locations with a 77% average working interest. This is 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, or nearly 50% of the inventory, have laterals surpassing 10,000 feet, while the average lateral length in the inventory now stands at 10,153 feet. The gross-operated inventory is evenly split with 51% of our locations locations in the Hainesville and 49% of our locations in the Bossier shell. Our legacy Hainesville inventory also includes 113 gross horseshoe 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 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 Haynesville, which equates to an average working interest of 77%. Our total net locations are estimated since much of our Western Haynesville acreage has not yet been unitized. We have the Western Hainesville Inventory also divided into our four different groups based on the different lateral lengths. 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 operated locations have laterals surpassing 8,500 feet. The average lateral length in our Western Hainesville inventory 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. And we are currently running four rigs on our Western Hainesville acreage. Slide 15 recaps our ongoing horseshoe well development activity within our legacy Hainesville To date, we have drilled a total of 19 horseshoe wells to total depth, and 11 of these horseshoe wells have been turned to sales. We continue to realize significant cost savings with the horseshoe 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 Horseshoe 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 Horseshoe 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 Haynesville area. Those had an average lateral length of 11,457 feet. The individual laterals 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 7,873 feet up to 14,783 feet. The longest lateral drill to date in the Western Hainesville is 14,783 feet. And 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 we've turned to sales in our legacy Haynesville area so far in 2026. The average lateral length was 12,052 feet, and the individual laterals ranged from a low of 9,304 feet up to a high of 15,772 feet. The average IP for the 22 wells was 31 million cubic feet a day, and included in these results are eight of our Horseshoe 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 cubic feet a day. And 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, so all wells greater than 8,500 feet long. In the second quarter, we drilled 13 of these benchmark 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 an increase of two days compared to the first quarter. This is also reflected in the drilling speed of 469 feet per day during the second quarter, which is 2% lower than the first quarter. The main driver affecting our lower drilling efficiency in the second quarter was the depth, the 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 Haynesville 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 wells reached TD, and the completion costs for the quarter are based on the quarter in which the wells were turned to sales. During the second quarter, we drilled 13 of our midspark long lateral wells to total depth. The second quarter drilling costs averaged $710 a foot, which is a 1% increase compared to the first quarter. Although we drilled six horseshoe wells in the second quarter compared to four horseshoe wells in the first quarter, we were 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 on our legacy Haynesville acreage, and five of these were horseshoe 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 a 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 wells, making really good progress and having improved repeatability. On slide 22 is a summary of our DNC cost through the second quarter for all wells drilled in the Western Hainesville. During the second quarter we drilled four wells to total depth in the Western Hainesville 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 higher drilling cost 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 wealth of sales in our Western Hainesville They 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. And the higher completion cost 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. 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 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 longer timeline, we're continuing discussions with some of our industry partners regarding the development of a 20,000 pound frack spread, which would allow us to significantly increase our frack efficiencies and generate superior performing wells with higher URs. 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 Hainville that will position Comstock to benefit from a longer-term growth in natural gas demand. We have four operated rigs drilling into Western Hainville to continue to delineate the new 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 Hainesville to support production growth in 2026 and 2027. We expect to drill 48 wells and turn 48 wells to sales in 2026. And lastly, we continue to have strong financial liquidity of almost $1.2 billion. So, everyone that's listening, I want to 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 1-1 again. In the interest of time, we ask that you please limit 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, Alan. 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, 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 drawing side we definitely see the cost going down uh we're pretty excited about the big hole uh 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 uh 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 TVD average. And it's by far the cheapest well of anything, any well we have that's, you know, 16,000 foot or deeper. So we, you know, we didn't even really have the motors that we used on the first well were not the exact fits or the motors we wanted. We kind of used some stuff that was more off the shelf because, you know, obviously there weren't, we hadn't done any big hole work in the Western Hainesville, 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 the second, third wells that we're drilling. And I really see that the majority of the future wells we drilled will probably be with this bigger lateral. Not only cheaper, but, you know, we get some intangible benefits there as well. We had a lot better steering ability, you know, in this first wheel we drilled with the big hole versus the slim holes you know if you want to make course corrections it's just a lot easier and quicker to do so you get a lot better yields you know um 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 uh you know so i think it's just going to be a little bit more predictable you know in the slim holes where we bounce around a little bit more i think the big holes, hopefully it'll be more predictable on performance, cheaper and more predictable. So on the 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 pipes the Western Hainesville subunits and stick pipe and now we don't run motors anymore we just basically you know 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 you know that's possible because of all of this technology you know with these modern plugs they're dissolvable so really we say we drill out plugs to bottom but it's really you're more washing you're really more washing the bottom And occasionally, you know, you hit a couple of spots, you got to drill through. But so I think going forward, we're going to have a whole lot less risk of, you know, 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, you know, before that. 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, you know, so for the cost on the completion side, they're going to, I mean, with the bigger fracks, obviously, that goes up. So 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&C costs, you know, depending on 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 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. But it's going to be the same or a little bit cheaper.

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

Just good morning, Jay, Roland, and Dan, to the rest of your team there at Comstock. Dan, maybe the first one – yeah, 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 helping you on the drilling side. But I'm curious if you'd offer any kind of opinion 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. But maybe you can talk about, you know, 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 creates a little bit lower treating pressure with the bigger pipe, less pipe friction, get a little more rate, get a little bit better frack efficiency, pump a little faster, shorter pump time. So it creates all of those things for you. But the biggest, obviously, I mean the drilling side is where it really just 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, you know, with second and third well.

Well, you know, like Dan said, I do think that what he said, we do have a line of sight through drilling, you know, techniques, which we've implemented on these 50 wells. We have been tweaking our completion designs. And all that is, you know, Derek had asked, it should materially drive down cost. 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 focuses on not what we paid for inventory, but we paid not much for inventory. We really spent our money on drilling and completion side. So, you know, I would ask all of you to look at that And so if you own the footprint, 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 pure 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 of a row now, your highest IP has come from a horseshoe well in the legacy Haynesville. And I think, I believe, maybe a current part of that is because you've got these kind of stranded single-section units in some of the best parts of the Haynesville that were developed early, and that's why they're stranded now. But other than that, is there something else going on, you know, maybe with your different frack recipe that you're still breaking new ground as far as productivity in the legacy Hainesville with these wells?

So we don't pump a different frack design on the Horseshoe wells. It's still the same profit loading, you know, fluid loading that we pump in the other wells. I will say that, you know, the execution has been pretty flawless. You know, we just haven't run into any kind of issues that I think a lot of people may, you know, fear or expect, you know, before they try one. You know, if you're, if you don't know it's a horseshoe well 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, you know, the curve. And, I mean, all of that horseshoe turn instead of sliding with a conventional assembly, you know, we're rotating the whole time all the way around, right, as we're turning that well around 180 degrees. So it's definitely helped us shave some time off of what we thought those looked like in the beginning. But, you know, 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, they just, 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 flowback now. So we'll, you know, we'll see how those look on the next call.

Well, and Charles, I think that the thesis of the oil and gas sector, I mean, two or three years ago, nobody drilled a lateral, much less a 15,000, 20,000 foot lateral. Only several years ago, you're really drilling horseshoes. That's all technology, and 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 Ansel Bossier. All we're doing now is just we're moving one more checker to show you what we think we can be doing in the Western Ansel. 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 um 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 you know 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 uh or if there's any changes to your cadence um 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 which the first half the first and second quarter were fairly different but we should still 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 if you can back into that via the guidance appreciate that ron um and then maybe a different direction with my follow-up uh some of your competitors have shown interest in the southern end of the haynesville um you guys have some acres there in sabine parish and just curious what your experience is and drilling in that regions and maybe your thought on the extent of the the louisiana uh louisiana cancel yeah i think

we i mean we like that acreage down there we have drilled a few wells down on the south end And we don't, you know, the meat of our acreage is not really down in that area. But I think we have a couple of horseshoe whales planned for, I can't remember if it's later this year or early next year, you know, that are going to be down on the south end. So, yeah, no, that's, we've got some good whales down there. Mosier and Hazel are both, you know, really good performing. And so definitely not against it. 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. 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, you know, how they fit into the program going forward, and just what are you looking for in these types of transactions?

Yeah, that's the question. Of course, you know, as we are putting together the units in the Western Hainesville, you know, we've kind of leased a lot of large tracts and have blocked up the acreage really but there's a continual maintenance of picking up any remaining acres before we finally want to drill the well. So, you know, part of that program is really twofold. I think part of that program is to, you know, complete building out the units. Typically, we'll end up with 100% of the well for the most part. That's been most of what our experience has been so far. And then on the – there is a little bit of extensional areas that we like based on reprocessing seismic and stuff that – or 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, you know, 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 us. 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 you know 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 that's helpful and i'll try to ask about 2027 i know it's early but if we think about the the nine rig program and four frat crew continuing uh into next year and throughout the year can you give us a point a reference on what you think the growth rate would be. And then, you know, I know 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?

Yeah, 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 we really will look at our 27 activities kind of as we get delayed in the year and kind of then look at the view at that point you know so you know so I think I think that's that's really to be determined you know what we would you know what would you view and we definitely would want to see probably a stronger prices especially stronger prices that we could hedge into, you know, you know, to support that activity into next year.

You know, I'll tell you what our growth, our goal is, if you look at where the circle in was drilled, the latter part of 21, early 22, and where the Elijah one is, which is, you know, 30, 40, 50 miles to the north, whatever. Well, what we want to do, we see that LNG demand growth, 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, you know, two-thirds of it's Bossier. And Bossier is much easier than the lower, hotter Hainesville. But it's all held by production. So we just want to be ready to respond quickly when that demand is here. And the way we do that is to continue to do what we've been doing.

Thanks, Ed. I appreciate the time.

Thank you. Our next question comes from Noel Parks with Tui 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 was wondering if you could just talk a little bit about that and if you've made a transition to using those more widely, just what that might look like in terms of cost or time practice.

Well, we've been working with one of our vendors to make the higher temp motors available. We've been waiting to get them for a little bit, But so sometime hopefully here in the next two or three months, you know, we'll take delivery of some of those and get them deployed in the wells. And, you know, we think basically we just need to stay on bottom longer. So a motor that's, you know, the elastomer in the motor, you know, the rubber, the elastomer rated for the higher temperature, the motor is 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. But 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, the TD, you know, 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 that's the task.

I think that's where Dan talks about the motors. You know, 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.

And that's also, you know, where that big hole lateral, you know, when we're drilling with the, you know, that's basically, we say big hole, the lateral is 8.5 inch bit size or diameter versus a 6.75 in our normal, you know, slim holes that we drill. So 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. And when the hole stays cooler, the tools last longer on bottom. So that's, you know, what we're achieving there. Now, this higher temp motor, it will also, 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 sort of wave of improvement. I think it was mostly around downhole tools, 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 hit you're right it is it is step changes really and 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 you know it's the same basic thing we're trying to accomplish for trying to keep the mud cooler on Bob and make the tools last longer. So when we ran that insulated drill pipe, you know, we got a big change in down hole circulate temperatures, you know, 20, 30 degrees, which is, makes a huge difference on the life of those tools. So, you know, we've been utilizing that ever since. And now, you know, we also use insulated drill pipe when we drill the big hole laterals also. So, you know, you get that benefit there as well. So that's, I think, that's the next big step change. You know, we're always tweaking motors and fits, trying different motors, and then, you know, some work, some don't. But I think this big hole is our next big step change down that's going to drive the cost down. And, you know, and then we'll try these higher temp motors. Hopefully here in the next two, three months, we're going to be able to get those and put them in the ground. and, you know, we'll get the better performance from those. And then, you know, in my prepared remarks I talked about, we've got this 10,000 PSI rig. It's been upgraded. All the rigs are rated, you know, up to 7,500 PSI. So this one will be a 10,000 PSI, so we'll be able to pump a little faster, you know, 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're also got a second rig that we're in talks with to be upgraded to 10,000 PSI and if that works like we expect it to all of the rigs in the western Hainesville will eventually be upgraded to 10,000 PSI So, on the frac side, you know, we've been talking for a while about this 20,000-pound frac fleet. That's obviously a pretty good capital investment. So, we're just still working through some particulars with our industry partners on, you know, maybe 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. Dan, I'd like to ask.

Your headlines, I always look at that. It 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 trend, And particularly as you've been ramping on your pound per foot on the prop end side and you've been fracking on tighter stages, I wonder if you can perhaps walk us through, you know, what batch of wells you think would be a good proxy for us in the market to look at and perhaps for us to think, like, 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, you know, we talked about going to the higher profit loading. So basically, when we went to the higher profit loading, all of the wells that we completed, that we said we completed, that we turned to sales in Q2 was the first batch of wells that we, 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 in Q2, so, you know, we, those, the oldest ones have been on now for maybe three months, two or three months, that we turned to sales in March. And, you know, we had some that we pumped at 5,000 pounds per foot, some at 6,000 pounds per foot. So it will definitely take time to, you know, see how they decline out. But the initial results look really good. The pressure, the flowing pressures look really good at the rates, you know, at the IP rates we're having at with, you know, and we're obviously managing the drawdown very conservatively and maintaining that high flowing pressure on them.

Got it.

Got it. um and so just to clarify did you ramp did you ramp the prop unloading at the same time you start doing tighter frack stages or were those independent of each other those are independent of each other so we went to the tighter we went to the tighter cluster spacing in the smaller stages uh last year and had you know when we were still pumping our standard frack design at 4,000 pounds per foot. We've maintained that, you know, spacing, smaller stage spacing. 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 contain, where presumably most of your initial leases perhaps conform to a different set of unit optimization parameters, is it fair to say that since you're working on leases that were signed five years ago and you're holding a pitch today, that because of the age of of 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 a an hbp-free campaign if you will and you were purely uh trying to optimize and appraise wells the best way you could well definitely the drilling program like we said it's based on holding acreage and in the age of, so it's not, you're 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 infill wells later, but, you know, that's the nature of it. That's correct, you know, that you're really looking at, you know, using your program to make sure you put these leases, term leases, you know, into held by production status.

Yeah, I think that's the big one, Carlos, because we haven't drilled on a pad for infill development where you drill 6, 7, 8, 9, 10, or 15 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 pad there, you've got costs to come down materially. What we've attempted to do was on a very cautious basis, we've tried to lean into technology. We have looked at our debt level. We want to manage our debt level. We want to improve execution. And along the way, Carlos, again, I read everybody's research report. I think that kind of hold hands here together. That Dolly Jones well, you know, Dolly's a big word and Jones is a big word. You stick them both together. Dolly Jones, it should be a big a whole well success, eight and a half inches. We're delivering that. I think that if you hold hands and you've got Nexteria out there, Nexteria 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, you're really, really looked at hard with Sixth Street. That should make Carlos you happy. They manage $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 And we are under the microscope every 90 days. So you've got to 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.

Yeah, I appreciate it. And really not to hijack here the conversation, but just to drive the point home, So 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 facts. So all things equal, it's going to be roughly the same.

That does not include and that does not factor in larger pad developments where your overall cost, because you have synergies, are going to come down. right you're kind of comparing this play to a very mature play in the legacy haynesville where we we this cost was incurred years ago and now we're just we're drilling wells that have you know pads that we've already paid for you know here a single well is bearing all these costs so you know it's i think the future costs are going to be significantly lower than our current costs now just for the nature of developing out what we've proven up, you know, and perfecting the completion design and the drilling design, you know, and I do think that, you know, the other element is we do feel like, you know, given the pressure of the reservoir, the quality of the formation that we've now taken course and studied, you know, we do think that larger fracks are going to yield larger EURs and out 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.

Yeah, Carl, it's like, like Roland said, if you go to the Barnett or you go to the Parmian 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. It's tremendous upside of where we're going and that should begin you know latter part 27 28 but that's where we're going and it's in anderson county i mean we we created that story that story and every 90 days you get to look at it thank you this concludes the question and answer session oh now i'd 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 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.

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