Comstock Resources, Inc.

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 discussion 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'd turn there, we summarize the highlights of the second quarter. We did see the return of production growth in the 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. 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 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-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 in 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 Angel 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 6th Street represents an important milestone for Comstock and a strong validation of the value we have created in the Western Hainesville. with Six Streets Investment, we strengthened our balance sheet by reducing debt and simplified PGS's capital structure. If you'll turn to slide five, Six Streets 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 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 Burns 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 $0.03 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 3 cents 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 40 cents per share, but that includes a pretty large pre-tax $84 million mark to market unrealized gain on our hedge book. So if you exclude that gain, exploration 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 16 cents per share. Slide eight 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. Slot 9, 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 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. 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 5 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 drilling and other development activity in the quarter and for the first half of this year. We spent a total of $390 million 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 a 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 of borrowing outstanding under our upstream credit facility. Our upstream borrowing base is $2 billion and our electric commitment under that facility is $1.5 million. At the end of June, our The midstream credit facility had no borrowings outstanding following the pinnacle transaction with Sixth 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 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-Bossier 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 shells. 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 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 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 in the Hainesville and 49% of our locations in the Bossier Shale. Our legacy Hainesville inventory also includes 113 gross horsey 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 Hainesville. 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%. Our total net locations are estimated since much of our Western Hainesville acreage has not yet been unitized. We have the Western Hainesville 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 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 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 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 cells. For the year, in 2026, we plan to drill a total of 16 horseshoe wells and turn 17 of Mills to sales. Our 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 Hainesville area. Those had an average lateral length of 11,457 feet. The individual laterals ranged 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 ranged from 7,873 feet up to 14,783 feet. The longest lateral drill to date in the Western Hainesville was 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 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 feet. 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 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 the wells greater than 8,500 feet long. In the second quarter, we drilled 13 of these mid-smart long ladder 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 for the first quarter, 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, the deeper depths mean higher temperatures. The average true vertical depth for the four-wheels drilling the second quarter was approximately 1,200 feet deeper than the average TBDs of the five-wheels 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 wells reached TD, and the completion costs for the quarter are based on the quarter in which the wells returned to sales. During the second quarter, we drilled 13 of our BitSpark 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 wells in the second quarter compared to four horseshoe wells in the first quarter, we were able to keep our drilling cost 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 Hainesville 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, the 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 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. And a 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. 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 frac spread, which would allow us to significantly increase our frac efficiencies and generate superior performing oils 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 anvil that will position Comstock to benefit from the longer-term growth in natural gas demand. We have four operated rigs drilling in a western anvil to continue to delineate the new play. We expect to drill 22 wells and turn 21 wells to cells 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 and 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, you'll 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 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 Capitol. Your line is open.

Good morning, all, and thanks for your time. Morning. 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 frac 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. All right, so we've got a lateral that we drilled, albeit we just have drilled the one. We're drilling the second and third one now. We got five on our drill schedule slated to be drilled with the bigger lateral. 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. and a similar TBD, obviously the deeper TBDs. That well had about a 16,400 foot TBD average and is 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 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 obviously 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 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 drill 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 wheel we drilled with the big hole versus the slim holes. If you want to make course corrections, it's just a lot easier and quicker to do so. You get a lot better yields 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. 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. On the completion side, we're pretty darn efficient, really, on the completion side. 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, 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 the bottom, but it's really, you're more washing, you're really more washing the bottom, and occasionally, you know, you hit a couple spots you gotta drill through, but, so I think going forward, we're gonna 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 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. Everybody knows we have to wait to prove that out. 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. It's going to be the same but 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. 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 why 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, you know, the biggest, obviously, I mean, the drilling side is where it really just makes the big difference for us. And 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 lot of sites through drilling techniques, which we've implemented on these 50 wells. We have been tweaking our completion designs. And all that is, as Derek had asked, it 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. 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, that's 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, 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 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 pure companies out there that are that are now in the game, which we're their biggest cheerleader. And those wells look good. 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 these – 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 Haynesville. And I think, I believe, but maybe a concurrent part of that is because you've got these kind of stranded single-section units in some of the are the best parts of the Hainesville that were developed early, and that's why they're stranded now. But other than that, is there something else going on? 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, 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 fear or expect before they try one. If you don't know it's a horseshoe well and you're sitting there completing a well, you really can't tell the difference. 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'll rotate we're rotating the whole time all the way around right as we're we're turning 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 in 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 than 15,000, 20,000 foot lateral. Only several years ago were you 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-Boger. All we're doing now is we're moving one more checker to 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 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 or if there's any changes to your cadence 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, both quarters should grow by a similar amount sequentially. If you can back into that via the guidance.

I 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. Just curious what your experience is in drilling in that region and maybe your thought on the extent of the Louisiana Hainesville.

Yeah, I think we like that acreage down there. We have drilled a few wells down on the south end. The meat of our acreage is not really down in that area, but I think we have a couple of horseshoe whales planned for later this year or early next year that are going to be down on the south end. We've got some good whales down there. Mosier and Hazel are both really good performing. Definitely not against it. 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. One of us started on leasing with the increase to the overall Western Hainesville position by, I think, 5,000 acres or so. 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 in these types of transactions?

Yeah, that's a question. Of course, as we are putting together the units in the Western Hainesville, we've 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 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 billing out the units. Typically, we're will end up with 100% of the well. For the most part, that's been most of what our experience 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 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 to 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 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. And I'll try to ask about 2027. I know it's early. But if we think about the nine-rig program and four-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 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 really will look at our 27 activity kind of as we get late in the year and kind of look at the view at that point, you know. So, you know, so I think 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, 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 M 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 or whatever, 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. It'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, guys. 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 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 you know 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 the elastomer in the motor the 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 to 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, he 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 eight and a half inch bit size or diameter versus a six and three quarter in our normal you know, swim 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 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 just kind of what else you might be looking forward to in the next couple of 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 we're trying to keep the the mud cooler on Baldwin 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. So 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 that's, I think, that's the next big step change. We're always tweaking motors and fits, trying different motors and then some work, some don't, but I think this big hole's our next big step change down that's gonna drive the cost down. And then we'll try these higher temp motors, hopefully here in the next two, three months we're gonna be able to get those and put them in the ground and we'll get the better performance from those 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. 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, so we're just still working through some particulars with our industry partners on maybe how we could 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...

I always look at your headlines. I always look at that. It tells me what you're hard 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 costs 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 what batch of wells 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 in determining whether or not the larger products are working and are meeting your expectations on the EUR front.

So all of the wells, 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 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 pump a larger frac 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 the 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 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 tighter frac 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 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 HVP campaign 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 acreage today, that because of the age of them that you were confined there and have been confined to drilling or 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 wells the best way you could?

Definitely, the drilling program, like we said, is based on holding acreage and the age. So, 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 uh you know that's 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 you put these lease term leases you know into held by production status.

Yeah I think that's the point because we you know 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 that 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 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 to 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 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 gonna 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 are under the microscope every 90 days. So you gotta endure a little bit of this and knowing that we commit to you that almost 38, nine years we'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, what Dan said that when drilling, 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 Hainesville where we 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. 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 and perfecting the completion design and the drilling design. 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 cores and studied, you know, we do think that larger fracts are going to yield larger EURs and out of the gate, like the wells completed this quarter, Yeah, the pressures are significantly higher than, and I think that's going to bode well for their EURs, but you know, we're going to have to let them have some time to prove that out.

Yeah, 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. It's a tremendous upside of where we're going. And that should begin in a lot of part 27, 28. But that's where we're going. And it's in Anderson County. I mean, 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. I would now like to turn it back to Jay Allison for closing remarks.

You know, they say that 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.