Operator: 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 speakers' presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press *11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press *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.
M. Jay Allison: 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 will find a presentation entitled second quarter 2026 results. I am Jay Allison, chief executive officer of Comstock. With me is Roland O. Burns, our president and chief financial officer Daniel S. Harrison, our chief operating officer and Ronald Eugene Mills, our VP of finance investor relations. Please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws, while we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. On Slide 3, if you 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 $0.65 per share. Adjusted EBITDAX for the quarter was $245 million Our legacy Haynesville, Horseshoe and Western Haynesville drilling results are driving future production and reserve growth. Eleven Western Haynesville wells turned to sales so far in 2026 with an average lateral length of 10,300 feet and a per well initial production rate of 31 million cubic feet per day. Twenty-two legacy Haynesville wells turned to sales with an average lateral length of 12,100 feet and a per well initial production rate of 31 million cubic feet per day. Eight of the legacy Haynesville wells were Horseshoe wells. On June 15, we completed our midstream equity placement by selling a 27% stake in Pinnacle Gas Services 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 4. On June 15, 2026, we sold a minority equity interest in our midstream subsidiary, Pinnacle Gas Services, 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 Haynesville acreage which is well positioned to service the growing demand for natural gas in our region. The Western Haynesville 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 Haynesville With Sixth Street's investment, we strengthened our balance sheet by reducing debt and simplified Pinnacle's capital structure If you will turn to Slide 5, Sixth Street's investment of $600 million in Pinnacle Gas Services 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 Haynesville 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 Haynesville asset I will now have Roland Burns review the financial results for the quarter. Roland?
Roland O. Burns: Alright. Thanks, Jay. On slide 6, 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 flow 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 exploration expense, which is solely related to the seismic shooting in the Western Haynesville, and other nonrecurring items such as a gain on sales and the related income taxes to those items, we reported a adjusted net income of $8 million for the quarter, or also $0.03 per share. On slide 7 is the year-to-date financial results. Production in the first half of the year averaged about 1.2 Bcfe 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 pretax $84 million mark-to-market unrealized gain on our hedge book. So if you exclude that gain, exploration expense, and other nonrecurring 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, you know, 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 reflected a $0.35 basis differential compared to the NYMEX settlement price and a $0.37 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. Slide 9, we detail our operating cost per Mcfe and our EBITDAX margin. Our unit operating cost returned to normal levels in the quarter compared to where they were in the first quarter of this year. Our operating cost per Mcfe averaged $0.77 in the second quarter, which improved $0.16 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. G&A 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 $0.05 in the quarter. that is 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 have 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 have returned 29 or 24.4 net operated wells to sales, which had 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 borrowings outstanding under our up upstream credit facility. Our upstream borrowing base is $2 billion and our elective commitment under that facility is $1.5 billion. 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 3x. At the end of the second quarter, we have almost $1.2 billion of liquidity. So I will turn it over to Daniel to kind of talk about the operating results for the quarter.
Daniel S. Harrison: Okay. Thank you, Roland. If you look on slide 12, this is just our latest overall acreage footprint in the Haynesville-Bossier shale in East Texas and North Louisiana. We now have 1.08 million gross acres and 809,000 net acres that are prospective for commercial development of the Haynesville and Bossier Shales. Our Western Haynesville footprint has now grown to just over 545,000 net acres. We currently have just over 264,000 net acres located in our legacy Haynesville area. We have 41 wells currently producing on our Western Haynesville acreage We have another 13 wells that are in various stages of development. Slide 13 outlines the drilling inventory in our legacy Haynesville area. At the end of the second quarter, we had 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 4 different groups based on the lateral length, 449 of our 926 gross operated locations are nearly 50% of the inventory have laterals surpassing 10,000 feet. While the average lateral length in the inventory now stands at 10,200 feet. The gross operated inventory is evenly split with 51% of our locations in the Haynesville. And 49% of our locations in the Bossier Shale. Our legacy Haynesville inventory also includes 113 gross Horseshoe locations. With 53% of those in the Haynesville and 47% in the Bossier. We are currently running 5 rigs on our legacy Haynesville 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 3,280 gross operated locations and 2,530 net locations in the Western Haynesville. Which equates to an average working interest of 77%. Our total net locations are estimated since most of our Western Haynesville acreage has not yet been unitized. We have the Western Haynesville inventory also divided into our 4 different groups. Based on the different lateral lengths. And in this inventory, we do not have any short laterals less than 5,000 feet. 1.32 thousand of the 3,280 gross operated locations are 40% have a lateral surpassing 10,000 feet 61% of our gross operated locations have laterals surpassing 8.5,000 feet. The average lateral length, in our West Haynesville inventory is 8,880 feet. The Western Haynesville 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 Haynesville. And we are currently running 4 rigs on our Western Haynesville acreage. Slide 15 recaps our ongoing Horseshoe well Development Activity. Within Our Legacy Haynesville 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 sales We continue to realize significant cost savings with the Horseshoe development compared to the alternative of drilling the shorter 5 thousand foot laterals. Our well performance has also met expectations as we have our average 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 the one13 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 11.5,000 feet. They range the individual laterals range from 9,490 feet up to 15,600 feet. Our longest drill to date in the legacy area is still at 15,409 feet. In the second quarter, we also drilled 4 wells to total depth in the Western Haynesville, with an average length of 10,300 feet. The individual laterals range from 7,870 feet, up to 14,800 feet. The longest lateral drill to date in the Western Haynesville is 14,800 feet. And to date, we have drilled a total of 50 wells to total depth in the Western Haynesville. 21 of these wells have laterals exceeding 10,000 feet. Slide 17 summarizes the 22 wells that turned to sales in our legacy Haynesville area so far in 2026. The average lateral length was 12,100 feet, and the individual laterals ranged from a low of 9,300 feet up to a high of 15,800 feet. The average IP for the 22 wells was 31 million cubic feet a day, and included in these results are 8 of our Horseshoe wells Slide 18 outlines the one1 wells that we have turned to sales on our Western Haynesville acreage so far this year. These 11 wells had an average lateral length of 10,300 feet and an average initial production rate of 31 million cubic feet per day. The last 5 wells we have turned to sales since our first quarter update have ranged from 30 million to 35 million cubic feet a day. And, again, we have a total of 41 wells currently producing on the Western in our Western Haynesville area. Slide 19 highlights our drilling efficiency in the legacy Haynesville area. For our-- these are for our benchmark long lateral wells. So all the wells greater than 8.5,000 feet long. In the second quarter, we drilled 13 of these, benchmark long lateral wells to total depth in the legacy Haynesville area in averaged 24 days to total depth. Correspondingly, we averaged 817 feet drilled per day in our legacy Haynesville area, which represents a 10% increase versus the first quarter of 2026. 6 of the one3 wells we drilled in the second quarter were Horseshoe wells, Slide 20 highlights our drilling progress in the Western Haynesville area. During the second quarter, we drilled 4 wells to total depth in the Western. 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 4 wells drilled to total depth during the quarter. This is an increase of 2 days compared to the first quarter. This is also reflected in the drilling speed of 769 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 4 wells drilled in the second quarter was approximately 1,200 feet deeper than the average TVDs of the 5 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 Haynesville wells with laterals greater than 8.5,000 feet. The drilling costs are based on the quarter in which the wells reached TD. And the completion cost for the quarter based on the quarter in which the wells were turned to sales. During the second quarter, we drilled 13 of our benchmark 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 6 Horseshoe wells in the second quarter compared to 4 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-lateral wells to sales on our legacy Haynesville acreage, and 5 of these were horseshoe wells. The second quarter completion cost came in at $608 per foot, which represents a 4% increase compared to the first quarter. And the higher completion costs in the second quarter was the result of slightly higher costs associated with some longer drill outs and also slightly higher flowback costs. On the drilling side in the legacy Haynesville, we are continuing to deploy rotary steerable drilling technology. We are using this particularly on our horseshoe wells, making really good progress in having improved repeatability. On slide 22 is a summary of our D&C cost through the second quarter for all wells drilled in the Western Haynesville. During the second quarter, we drilled 4 wells to total depth in the Western Haynesville with an average lateral length of 10,300 feet. Our second quarter drilling cost averaged $1,070 per foot. This represents a 13% increase compared to the first quarter. Higher 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. Higher drilling cost for these 2 wells was partially offset by the lower drilling cost 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 $1,310 per lateral foot which is 25% lower than our quarterly average. During the second quarter, we also turned 4 wells to sales in our Western Haynesville acreage that had an average lateral length of 9,440 feet. The second quarter completion cost averaged $1,610 per foot. This is a 5% increase compared to the first quarter. Higher completion costs in the second quarter can be attributed to higher proppant loading. We 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 drilled in the quarter, we are 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 Haynesville. This will increase our drilling speeds in both the vertical and the horizontal hole sections. Also, near-term, we will be testing some new higher-temperature-rated drilling motors, which we expect to lead to longer runs, better drill times. And then on a longer timeline, we are continuing discussions with some of our industry partners regarding the development of a 20,000-horsepower frac spread,. Which would allow us to significantly increase our frac efficiencies and generate superior performing wells with higher EURs. This would be a 2027 event. And I will now turn the call back over to Jay.
M. Jay Allison: Excellent report, Daniel. Thank you, Roland. If you will turn to page 23, we will summarize our outlook for 2026. As you can tell, our primary goal continues to be advancing our Western Haynesville, which will position Comstock to benefit from a longer-term growth in natural gas demand. We have 4 operated rigs drilling in the Western Haynesville to continue to delineate the new play. We expect to drill 22 wells and turn 21 wells to sales in 2026 We expect drilling efficiencies in changes to our completion design to continue to drive up productivity and drive down drilling and completion cost. We have 5 operated rigs drilling in our legacy Haynesville 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 to everyone that is listening, I want to thank you for your time today. Slide 25 provides guidance for the rest of 2026, which Ronald 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.
Operator: As a reminder, to ask a question, please press *11 on your telephone. Wait for your name to be announced. To withdraw your question, please press *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 Derrick Whitfield with Texas Capital. Your line is open.
Derrick Whitfield: Good morning, all, and thanks for your time. Morning. Wanted to start with your D&C optimization efforts in the Western Haynesville While we are still very early in optimizing this trend, the step you guys are taking is 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-temperature-rated drilling motors you talked about and the higher PSI rated frac spreads, where do you see cost trending when all the drivers are working together?
Daniel S. Harrison: that is a really good question, Derek. So on the drilling side, we definitely see the cost going down. We are pretty excited about the big-hole lateral that we drilled, albeit we just have drilled the one. We are drilling the second and third ones now. We have five on our drilling schedule. Slated to be drilled with the bigger lateral. Probably got another dozen or so that we have kinda 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 $1,360 per foot, that is that is a good bit cheaper than any other well we have drilled at a similar TVD. Obviously, the deeper TVDs. That well had about a 16,400-foot TVD average. And it is by far the cheapest well of any well we have that is you know, 16,000-foot or deeper. So we, you know, we did not even really have the motors that we use on the first well were not the exact fit through the motors we wanted. We kinda used some stuff that was, more off-the-shelf because, you know, obviously, there were not we had not done any big-hole work in the Western Haynesville, so they did not have anything really fitted for us exactly for the for that first well we drilled. So we are hoping we will have a little better performance there because we have had time now to dial in and get something a little fitted a little bit better for the second and third wells that we are 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, you know, we get some intangible benefits there as well. We had a lot better steering ability, you know, in this first well we drilled with the big-hole versus the slim-hole wells. You know, if you wanna make course corrections, it is just a lot easier and quicker to do so. You get a lot better yields You know? So you are not sitting there fighting and sliding for longer periods of time trying to get it to turn or go up or down. And, you know, so I think it is just gonna be a little bit more predictable. You know, in the slim-hole wells, we bounce around a little bit more. I think the big-holes hopefully will be more predictable on performance. Cheaper and more predictable. So, on the completion side, you know, we are we are pretty darn efficient, really, on the completion side just we had we had a couple of wells. Last quarter, we left a couple of motors in the hole, but we have gone to drilling out all of our wells. We have quit running motors on our drill outs. We basically, we do everything with stick pipe, the Western Haynesville, to a unit and stick pipe. and now we do not 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. That really add any time,, and, you know, that is possible because of all of this technology, you know, with the these modern plugs, they are dissolvable. So, really, we say we drill out plugs to the bottom, but it is really you are more washing-- really more washing to the bottom. And, occasionally, you know, you hit a couple of spots you got to drill through,, but so I think going forward, we are 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 fracs. We started pretty much with all the wells we completed in the second quarter. We are either 25% or 50% higher proppant loading than before that. We are seeing really good pressures at the rates we are flowing at initially, and we think it will definitely bear fruit on the higher EURs. We have got-- everybody knows we have to wait to prove that out. But, you know, so for the cost on the completion side, they are gonna I mean, with the bigger fracs, obviously, that goes up. So I see us going we are gonna be going cheaper on the drill side, gonna be going a little bit higher on the completion side. So overall, D&C costs you know, depending on which 1 of those in the future kind of maybe weighs the most. I think it I think we are looking at something pretty similar to where we have been. Because we have been-- we are gonna get that drill cost going down with these big-hole laterals. And so even though we are pumping the big fracs, we are not gonna see any higher cost. it is gonna be the same for a little bit cheaper. Great. Thank you.
Operator: Our next question comes from Charles Meade with Johnson Rice. Your line is open.
Charles Meade: Good morning, Jay, Roland and Daniel to the rest of your team there at Comstock.
M. Jay Allison: Daniel, maybe the first 1-- yeah. Thank you, Jay.
Charles Meade: Jay, maybe this is for you, maybe it is for Daniel. But I think you guys have done a great job explaining why this big-hole design is helping you on the, the drilling side. But, I am curious if you would 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 then I imagine that, you know, with just the larger internal diameter, you are gonna have an easier time getting your fracs off. But maybe you can talk about, you know, what it might mean on the cost side of the completion, but importantly, on the productivity of the well.
Daniel S. Harrison: Well, I think it is gonna let us get, you know, on average, these big-hole wells, we are probably gonna be looking at longer laterals, which you know, the longer the lateral, it gets just the toe stages or 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, 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 the big difference for us. And so we like I said, we had expectations for the first well. We beat those expectations, and now we just need to show that it is repeatable. you know, second and third well.
M. Jay Allison: Well, like Daniel said,, I do think that what he said, we do have a line of sight through drilling you know, techniques, we have implemented on these 50 wells. You would have been tweaking our completion designs And all that is, you know, the Derek had asked, it should materially drive down cost, and it will enhance well productivity, Charles. I think that is what you are asking about. It is amazing. And, Charles, you are you are 1 of the bigger ones out there that have known us for a long, long time. I mean, you are 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 is unusual. But we are 50 wells into it. And we are 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 are what we do not have, we do not have to buy inventory. So everything really focuses on not what we paid for inventory, what 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 say, if you own the footprint, and do not have a lot in it and the reserves are there and you have drilled maybe 60, 70, 80 miles apart. And we have got some peer companies out there that are that are now in the game, and we are their biggest cheerleader. And those wells look good. That we are as a group. But as an oil and gas sector, we are trying to derisk it because we do need another major gas field in Texas near LNG corridor near the data center demand. And I think we are gonna deliver that. So that is everything we do. that is our goal. Got it. Thank you, Jay.
Charles Meade: And then if I could ask about these U-turn, or Horseshoe, wells in the Legacy Haynesville, I think I think for the second quarter in a row now, your highest IP rate 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 have got, you have got these kind of stranded single section units in, in some of the best parts of the Haynesville that were developed early, and that is why they are stranded now. But other than that, is there something else going on you know, maybe with your with your different your different frac recipe that you are still breaking new ground as far as productivity in the legacy Haynesville? With these wells?
Daniel S. Harrison: So we do not have we do not pump a different frac design on the Horseshoe wells. it is still the same proppant loading fluid loading that we pump in the other wells. I will say that the execution has been pretty flawless. You know? We just have not run into any kind of issues that I think a lot of people may you know, fear or expect before they try 1. If you do not know it is a Horseshoe well and you are sitting there, you know, completing the well, you really cannot tell the difference. But I will say that the rotary steerable work that we kind of started here a few quarters ago, the big benefit we are getting from it is on these horseshoe wells because we are 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 will rotate we are rotating the whole time all the way around, right, as we are we are turning that well around a 180 degrees. So it is it is 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 have drilled are in good type curve areas because they were stranded. Like you said, they just were not gonna drill them as 5 thousand foot laterals. And just due to the efficiency. And so, you know, they have not disappointed for sure. They look really good. And we you know, we have fanned that out. They have all been to Louisiana so far. We have drilled 3 Horseshoe wells in Texas. We have completed our first 1, and we have it on flowback now. So we will you know, we will see how those look. On the next call.
M. Jay Allison: Well, and Charles, I think that the thesis of the oil and gas sector, I mean, 23 years ago, nobody drilled a lateral. Much less than 15 thousand 20 thousand-foot lateral. You know, only several years ago were you really drilling it is all technology. And, you know, we use this rotary steerable, and all of a sudden, we have added 114 new locations that were there but they were not as economic. You know, we take that technology and we can drill in 2008 and help discover the legacy Haynesville/Bossier. All we are doing now is just we are moving 1 more checker to show you what we think we can be doing in the Western Haynesville. Those questions are great. It is all driven by technology. So everybody that is asking questions asks the right question. That is great detail. Thank you, Jay.
Operator: Thank you. Thank you. Our next question comes from Kevin McCurdy with Pickering Energy Partners. Your line is open.
Kevin McCurdy: 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 is any changes to your cadence.
Ron Mills: Kevin, this is Ronald. What we have said historically is that we think fourth quarter can get back to where we were in the first half of 2024. Which the first half the first and second quarter were fairly different. But we should still we are 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. As you can back into that via the guidance. Appreciate that, Ronald.
Kevin McCurdy: Then maybe a different direction with my follow-up. Some of your competitors have shown interest in the southern end of the Haynesville. 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 Haynesville.
Daniel S. Harrison: Yeah. I think we I mean, we like that acreage down there. We have drilled a few wells down on the south end. We do not you know, the meat of our acreage is not really down in that area, but, I think we have a couple of horseshoe wells planned for cannot remember if it is later this year or early next year. You know, that are gonna be down on the south end So yeah. Noel. that is we have we have got some good wells down there. Bossier and Hazel were both You know? Really good performing. And so definitely not against it. Just, you know, it is just where it layers into the drill schedule, much all the other opportunities. Thanks. Appreciate that.
Operator: Thank you. Our next question comes from Jacob Roberts with TPH and Co. Your line is open.
Jacob Roberts: Good morning. Good morning. I wanted to start on leasing with the increase to the overall Western Haynesville position by, I think, 5,000 acres or so. Wondering if you could speak a little bit about what is 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?
Roland O. Burns: Yeah. that is the question. Course, you know, as we are putting together the units in the Western Haynesville, you know, we have kind of leased a lot of large tracts and it blocked up the acreage really well. But there is a continual maintenance of picking up any remaining acres before we finally want to drill the well. So part of that program is I would say it is really twofold. I think part of that program is to, you know, complete building out the units. Typically, we are we will end up with 100% of the well. For the most part, that is been most of our experience so far. And then on the other side 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, but I do not think it is really very large, but, you know, just, as we kind of fill in, you know, any gaps that are available, Maybe a, a lease becomes available that was not available earlier So, yeah, obviously, we monitor that.
M. Jay Allison: Well, now I think when we lease to clean up acreage that we need to clean up, if you are a mineral owner, and you know we have drilled 50 wells and we are going to drill 50 more and 50 more and 50 more after that. that is our goal. Know, you are you are probably gonna lease us because if you really want a well drilled you are you are probably gonna kinda call us and that is that is what we see happening. On a quarterly basis. We have added, you know, a little acreage here and there. And it is all to make the existing acreage even better. that is what you see. Perfect. that is that is helpful.
Jacob Roberts: And I will ask about 2027. I know it is early. But if we think about the 9 rig program and 4 frac crews 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 I know I think we all agree that there is a demand wave coming. The forward curve does not necessarily reflect that next year. So I am curious if prices do maintain where they are at, are we going to see a potential holding back on some of that activity until that demand is there?
Roland O. Burns: Yeah. We have we have definitely been disappointed with the with the gas prices as we have gotten to the summer. We have gotta continue to watch that. So, you know, we really, will look at our 2027 activity kind of as we get late in the year. And look at the view at that point. You know? So you know, so I think I think that is that is really to be determined, you know, what we would you know, would you view and we definitely would wanna see probably a stronger prices, especially stronger prices that we could hedge into, you know, you know, to support that activity into next year.
M. Jay Allison: You know, I am-- what our growth our goal is if you look at where the Circle M was drilled, the latter part of 2021, early 2022, and where the Elijah-1 is, which is, you know, 30, 40, 50 miles to the north, whatever. What we wanna do, we see that LNG demand growth is expected. And we know that there is gonna be a lag between when it is actually delivered and the gas. So that is gonna be lumpy. So what our goal is let's just try to derisk as much of this as we can And like Daniel said, you know, two-thirds of our exposure in the Bossier is much easier than the lower, hotter Haynesville it is all held by production. So we just wanna be ready to respond quickly when that demand is here in the way we do that is to continue to do what we have been doing. So Thanks, guys. I appreciate the time.
Operator: Thank you. Our next question comes from Noel Parks with Tuohy Brothers Investment Research. Your line is open.
Noel Parks: Hi, good morning. I apologize if you 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 what if you have made a transition to using those more widely just what that might look like in terms of you know, cost or time savings.
Daniel S. Harrison: Well, we have been, working with 1 of our vendors to you know, make the higher-temperature motors available. We have been waiting to get them for a little bit. But sometime,, hopefully, here in the next two or three months, you know, we will take delivery of some of those and get them deployed in the wells and, know, we think, basically, we just need to stay on bottom longer. So a motor that is you know, the elastomer and the motor-- the rubber, the elastomer-- rated for the higher temperature, the motor's gonna last longer. We are just gonna be 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 is 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 is, you know, that is the that is the task.
M. Jay Allison: Well, I think that is where Daniel 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 are we are always leaning into to what we think will improve all costs Yeah and time.
Noel Parks: that is also, you know, where that big-hole lateral. When we are drilling with the you know, that is basically we say big-hole. The lateral is 8.5-inch bit diameter, versus a 6.75-inch bit in our normal slim-hole wells that we drill. So when you are drilling in the bigger hole, you are circulating You are just circulating the mud faster. When you are circulating faster, it keeps the hole cool. And when the hole stays cooler, the tools last longer on bottom. So that is, you know, what we are achieving there. Now this higher-temperature motor, it will also it we can basically take that technology, and they can just basically take that same higher-temperature 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 or four years ago where there was another true wave of improvement. I think it was mostly around downhole tools. I know it was logging specifically. But it is just that they are they are kinda 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 your what else you might be looking forward to in the next couple years? Keep developing out there?
Daniel S. Harrison: Well, you are right. It is a step change. it is really I think maybe a few years ago, maybe what you were talking about, we first started using the, coated or insulated drill pipe. Which, you know, when we were drilling some of those the deeper TVD Haynesville wells, they were really hot. I mean, they were over 400 degrees, and so we went to that insulated drill pipe. You know, it is the same basic thing we are trying to accomplish. We are trying to keep the mud cooler on bottom and make the tools last longer. So when we ran that insulated drill pipe, you know, we got a big change in downhole circulating temperatures, you know, 20 to 30 degrees, which is makes a huge difference on the life of those tools. So you know, we have been utilizing that ever since, and now, you know, we are 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 is I think that is the next big step change. You know, we are always tweaking motors and fits. Trying different motors, and then, you know, some work, some do not. but I think this big-hole is our next big step change that is gonna drive the cost down. And you know, and then we will we will try these higher-temperature motors, hopefully, here in the next 2 to 3 months, we are gonna be able to get those and put them in the ground, and, you know, we will get the great the better performance from those. And then you know, on my prepared remarks, talked about we have got this 10,000-psi rig been upgraded. All of our rigs are rated you know, up to 7,500 psi. So this one will be a 10,000 psi, so we will 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 is gonna probably be in October when we get that 10,000-psi rig deployed. So looking forward to that. We are also got a second rig that we are in talks with to be upgraded to 10,000 psi? You know? And if that works like we expect it to, all of the rigs in the Western Haynesville will be upgraded to 10,000 psi. So on the frac side, you know, we are we have been talking for a while about this 20,000-horsepower frac fleet. that is obviously a pretty good capital investment. So we are just still working through some particulars with our industry partners on, you know, maybe how we could how we could you know, put that together. To make it work for us.
Noel Parks: Great. Thanks a lot.
Operator: Thank you. Our next question comes from Carlos Escalante with Wolfe. Your line is open.
Carlos Escalante: Hey, good morning, team. Thank you for taking my question today. Daniel, I would like to ask your headline.
M. Jay Allison: I always look at that. Tells me what your heart's saying. Oh, Lord Jay. Well, thank you. We can take that offline.
Carlos Escalante: Daniel, question for you on the completion side. I guess we want you to help us parse through the headline D&C cost trend particularly as you have been ramping on your pound per foot on the proppant side, and you have been, fracking on tighter stages. I wonder if you can perhaps walk us through you know, what batch of wells do you think it would be a good proxy for us in the market to look at and perhaps for us to think, okay. Well, this batch of wells is close to what they think is the ultimate completion design because it does feel like you feel good about the larger fracs. 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 fracs are working and are meeting your expectations on the EUR on the EUR front.
Daniel S. Harrison: We had so all of the wells, you know, we talked about going to the higher proppant loading. So, basically, when we went to the higher proppant loading, all of the wells that we completed that we said we completed that we turned the sales in Q2 was the first batch of wells that we you know, systemically went up to the larger proppant loading. Now we did pop a larger frac on 1 of the really earlier wells, but in Q2 so, you know, we those are the oldest ones have been on now for maybe 3 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 flowing pressures look really good. At the rates you know, at the IP rates we are having and we are obviously managing the drawdown very conservatively and maintaining that high flow and pressure on them. Got it. Got it. And so just to clarify, did you ramp did you ramp the proppant loading 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 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, 4,000 pounds per foot, We have maintained that you know, spacing smaller stage space, and we have maintained that as we have increased the proppant loading.
Carlos Escalante: Okay. That makes sense. And then my follow-up and I hope this is going to make sense,, but because you are you are executing on an ongoing HBP campaign, but presumably, most of your initial leases perhaps conform to a different set of unit optimization parameters Is it fair to say that since you are working on leases that were signed five years ago and you are holding acreage today that, because of the age of them, that you were confined there and have been confined to drilling or being you are 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 the well the best way you could?
Roland O. Burns: Definitely, the drilling program, like we said, is based on holding acreage and the age of so it is not. You are not able to look to see the most optimal places you can drill or the and then that is been the nature of the drilling program. And it will slowly shift where we are able to drill some infill wells later, but, you know, that is the nature of it is correct. You know, that you are really looking at you know, using your program to make sure you put these term leases, you know, into held-by-production status.
M. Jay Allison: Yeah, I think it is fine. Lateral length. Because we you know, we have not drilled on a pad for infill development where you drill six, seven, eight, nine, 10, or 15 wells off a pad. We have not we have not attempted to do that at all even though you have got the gathering there, you have got the pad there, you have got you know, cost to come down materially. What we attempted to do was on a very cautious basis We tried to lean into technology. We have looked at our debt level. We wanna manage our debt level. And we wanna improve execution.
Carlos Escalante: And along the way, Carlos, again, I have read everybody's research report.
M. Jay Allison: I think to kinda hold hands here together That Dolly Jones well, you know, Dolly's a big word and Jones is a big word. Just take them both together. At Dolly Jones, it should be it should be a big-hole well success,, 8.5 inches We are delivering that. I think that if you hold hands, and you have got next year out there, next year sees abundant reserves. They see other what others do not have. We have pipelines, transmission, infrastructures. They are already on the ground. it is a perfect site between Dallas, Houston, and Austin. But then you really you are you are really, really looked at hard with Sixth Street. That should make you happy, Carlos. They manage $135 billion. They see this growth. 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 is for data centers or LNG. I mean, we are gonna need another 13-plus Bcf per day between now and probably 2031 and that is without data center gas demand. That those are the things that we are doing. And we are under the microscope every 90 days. So you gotta you gotta endure a little bit of this and knowing that we commit to you that, you know, almost 38 or 39 years you have been doing this, we will not waste your money period. We do not do that. Yeah. I appreciate it. And really not to hijack here the conversation, but just to drive the point home, what Daniel said that when drilling cost per foot are gonna come down and completion cost are gonna go up because of the larger frac So all things equal, it is going to be roughly the same.
Roland O. Burns: That does not include and that does not factor in larger, pad developments where your overall cost because you have synergies. Are gonna come down. Fair to say that? Right. You are kinda comparing this play to a very mature play in the legacy Haynesville where this cost has incurred years ago, and now we are just we are drilling wells that have you know, pads that we have already paid for. You know? Here, a single well has buried all these costs. So, you know, it I think the future costs are gonna be significantly lower than our current cost now just from the nature of developing how what we have proven up. You know, and perfecting the know, the completion design and the drilling design. But I do think that, you know, the other the other element is we do feel like, you know, given the pressure of the reservoir, the quality of the of the formation that we have now taken cores and studied. You know, we do we do think the larger fracs are going to yield larger EURs and out of the gate, you know, like the wells completed this quarter. You know, the pressures are significantly higher than I think that is gonna bode well for their EURs, but, you know, we are going to have to let them have some time to prove that out. Yeah.
M. Jay Allison: Carlos, like, you know, we, like Roland said, if you go to the Barnett or you go to the Permian, 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 alongside of them. We are building the road. And then we own everything on the side of it. And where are we going? Well, we are going to the Texas Power Generation Hub. But it is tremendous upside of where we are going. And that should begin, you know, latter part of 2027-2028. But that is where we are going, and it is in Anderson County. I mean, we created that story. That story. And every 90 days, you get to look at it. Thank you.
Operator: This concludes the question-and-answer session. I would now like to turn it back to Jay Allison for closing remarks.
M. Jay Allison: You know, they say that if you are worthy, the less 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.
Operator: This concludes today's conference call. Thank you for participating. You may now disconnect.
