Comstock Resources, Inc. (CRK) Earnings Call Transcript

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.