Good day. 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, one, one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and Chief Executive Officer. Please go ahead. Thank you for the introduction. I want to welcome everyone to the Comstock Resources second quarter 2026 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation entitled Second Quarter 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. On slide three, 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 EBITDA 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 10,331 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 12,052 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 15th, we completed our midstream equity placement by selling a 27% stake in Pinnacle Gas Services for $600 million, which we used to retire Pinnacle's preferred equity and all of Pinnacle's outstanding debt, which I will discuss more detail on the next couple of slides. If you turn over to slide four. On June 15th, 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. W ith Sixth Street's investment, we strengthen our balance sheet by reducing debt and simplified Pinnacle Gas Services's capital structure. If you'll turn to slide five. 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'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 flow in the quarter. We did report a non-GAAP 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 that we're shooting into Western Haynesville and other non-recurring items, such as a gain on sales and the related income taxes to those items, we reported a similar net income of $8 million for the quarter or also $0.03 per share. On slide seven is the year-to-date financial results. Production in the H1 of the year averaged about 1.2 Bcf per day. Also, our oil and gas sales for the six months were $670 million. EBITDAX was $496 million, and we had $380 million of cash flow. We reported a profit of $116 million for the first six months or $0.40 per share. That includes a pretty large pre-tax, $84 million mark-to-market unrealized gain on our hedge book. 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've been $48 million for the first six months of this year or $0.16 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. 32% of our gas was sold in the spot market, the approximate NYMEX reference price would've been about $2.91 for our production. Our realized gas price during the second quarter averaged $2.54, reflecting 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. On slide nine, we detail our operating cost 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 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 H2 of last year. Lifting costs 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'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 H1 of this year. We spent a total of $390 million on development activities in the second quarter and $734 million during the H1 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 operating wells to sales, which had an average initial production rate of 30 million cubic feet per day overall. Slide 11 summarizes our capitalization at the end of the second quarter. We ended the quarter with $545 million of borrowings outstanding under our upstream credit facility. Our upstream borrowing base was $2 billion, and our elected commitment under that facility is $1.5 billion. At the end of June, 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. I'll now turn it over to Dan to 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 Haynesville Bossier Shale 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 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 four different groups based on the lateral length. 449 of our 926 gross operated locations or nearly 50% of the inventory have laterals surpassing 10,000 feet, while the average lateral length in the inventory now stands at 10,153 feet. The gross operated inventory is evenly split with 51% of our locations 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 five rigs on our Legacy Haynesville area. This inventory provides us with a long runway future drilling locations. Slide 14 outlines our estimated drilling inventory in the Western Haynesville. We have 3,277 gross operated locations and 2,528 net locations in the Western Haynesville, which equates to an average working interest of 77%. Our total net locations are estimated since much of our Western Haynesville acreage has not yet been unitized. We have the Western Haynesville inventory also divided into our four different groups based on the different lateral lengths. In this inventory, we do not have any short laterals less than 5,000 feet. 1,321 of the 3,277 gross operated locations or 40% have laterals surpassing 10,000 feet. 61% of our gross operated locations have laterals surpassing 8,500 feet. The average lateral length in our Western Haynesville inventory is 8,875 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. We are currently running four 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. 11 of these Horseshoe wells have been turned to sales. We continue to realize significant cost savings with the Horseshoe development compared to the alternative of drilling the shorter 5,000-foot laterals. Our well performance has also met expectations as our average IP is 31 million a day for all 11 Horseshoe wells that we have turned to sales. For the year, in 2026, we plan to drill a total of 16 Horseshoe wells and turn 17 of those to sales. Our drilling inventory does include the 113 Horseshoe locations. Slide 16 outlines our average lateral lengths drilled based on the wells that have been drilled to total depth. The average lateral lengths are shown separately for the Legacy Haynesville and for the Western Haynesville. In the second quarter, we drilled 13 wells to total depth in the Legacy Haynesville area. Those had an average lateral length of 11,457 feet. The individual laterals range from 9,495 feet up to 15,564 feet. Our longest drill to date in the Legacy area is still at 17,409 feet. In the second quarter, we also drilled four wells to total depth in the Western Haynesville with an average length of 10,281 feet. The individual laterals range from 7,873 feet - 14,783 feet. The longest lateral drill to date in the Western Haynesville is 14,783 feet. To date, we've 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 we've turned to sales in our Legacy Haynesville area so far in 2026. The average lateral length was 12,052 feet, and the individual laterals ranged from a low of 9,304 feet up to a high of 15,772 feet. The average IP for the 22 wells was 31 million cubic feet a day. Included in these results are eight of our Horseshoe wells. Slide 18 outlines the 11 wells that we've turned to sales on our Western Haynesville 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 sale since our first quarter update have ranged from 30million - 35 million cubic feet a day. Again, we have a total of 41 wells currently producing in our Western Haynesville area. Slide 19 highlights our drilling efficiency in the Legacy Haynesville 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 benchmark long lateral wells to total depth in the Legacy Haynesville area, and averaged 24 days to total depth. Correspondingly, we averaged 1,017 feet drilled per day in our Legacy Haynesville 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 Haynesville area. During the second quarter, we drilled four wells to total depth in the Western Haynesville. This gives us a total of 48 wells drilled to total depth through the end of the second quarter. We averaged 59 drilling days for the four wells drilled to total depth during the quarter. This is an increase of two days compared to the first quarter. This is also reflected in the drilling speed of 469 feet per day during the second quarter, which is 2% lower than the first quarter. The main driver affecting the lower drilling efficiency in the second quarter was the depth. Deeper depths mean higher temperatures. The average true vertical depth for the four wells drilled in the second quarter was approximately 1,200 feet deeper than the average TVDs of the five wells we drilled in the first quarter. Slide 21 details our D&C cost through the second quarter for the benchmark long lateral wells in the Legacy Haynesville area. These costs reflect all of our Legacy Haynesville wells with laterals greater than 8,500 feet. The drilling costs are based on the quarter in which the wells reached TD, and the completion costs for the quarter are based on the quarter in which the wells were turned to sales. During the second quarter, we drilled 13 of our 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 six Horseshoe wells in the second quarter compared to four Horseshoe wells in the first quarter, we were able to keep our drilling costs nearly flat due to better drilling performance on our Horseshoe wells in the second quarter. During the second quarter, we also turned 12 of our benchmark long lateral wells to sales on our Legacy Haynesville acreage, and five of these were Horseshoe wells. The second quarter completion cost came in at $680 a foot, which represents a 4% increase compared to the first quarter. The higher completion cost in the second quarter was the result of the slightly higher cost associated with some longer drill outs and also slightly higher flowback cost. On the drilling side in the Legacy Haynesville, 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 D&C cost through the second quarter for all wells drilled in the Western Haynesville. During the second quarter, we drilled four wells to total depth in the Western Haynesville 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 two of 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 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 $1,306 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 Haynesville acreage 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. The higher completion cost in the second quarter can be attributed to higher proppant loading, had a lower average lateral length in the second quarter compared to the first quarter, and we had a higher percentage of single-well pads that we completed in the second quarter. Based on the successful results of our first big hole long lateral drill in the second quarter, we're now in the process of drilling our second and third big hole laterals to confirm the repeatability of our results on the first well. The big hole lateral creates lower downhole temperatures, which leads to longer, more reliable runs from our downhole drilling assemblies. Also this fall, we will be deploying our first 10,000 PSI rig in the Western Haynesville, which will increase our drilling speeds in both the vertical and the horizontal hole sections. Near term, we will be testing some new higher temp-rated drilling motors, which we expect to lead to longer runs better drill times. On a more longer timeline, we're continuing discussions with some of our industry partners regarding the development of a [20,000 PSI]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. 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 Haynesville that will position Comstock to benefit from a longer-term growth in natural gas demand. We have four operated rigs drilling into 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 and changes to our completion design to continue to drive up productivity and drive down drilling and completion costs. We have five operated rigs drilling into Legacy Haynesville to support production growth in 2026 and 2027. We expect to drill 48 wells and turn 48 wells to sales in 2026. Lastly, we continued to have strong financial liquidity of almost $1.2 billion. Everyone that's listening, I want to thank you for your time today. Slide 25 provides guidance for the rest of 2026, which Ron can discuss with you directly if you have any questions. For the rest of the call, I will take questions from analysts who follow the company. As a reminder to ask a question, please press star, one, one on your telephone and wait for your name to be announced. To withdraw your question, please press star, one, one 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. Good morning, all, and thanks for your time. Morning. Wanted to start with your D&C optimization efforts in the Western Haynesville. 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? As a tack on to that, if you were to assume the use of more leading-edge technologies like the higher temp rated drilling motors you talked about and the higher PSI rated frac spreads, where do you see cost trending when all the drivers are working together? That's a really good question, Derrick. On the drilling side, we definitely see the cost going down. We're pretty excited about the big hole 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 we need to get the results on these second and third wells. The first well, the Dollye Jones, at $1,306 a foot, that's a good bit cheaper than any other well we've drilled at a similar TVD. Obviously, the deeper TVDs. That well had about a 16,400 foot TVD average, and it's by far the cheapest well of any well we have that's 16,000 foot or deeper. The motors that we used on the first well were not the exact fits for 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 Haynesville, so they didn't have anything really fitted for us exactly for that first well we drilled. We're hoping we're going to have a little better performance there because we've had time now to kind of dial in and get something a little fitted a little bit better for these second and third wells that we're drilling. 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 well 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. You're not sitting there fighting and sliding for longer periods of time trying to get it to turn or go up or down. 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. Just 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 do everything with stick pipe in the Western Haynesville, sub units and stick pipe. Now we don't run motors anymore. We just basically put a bit on the end of the pipe, and we go to the bottom, and that eliminates a ton of risk. Doesn't really add any time, and that's possible because of all of this technology. With these modern plugs, they're dissolvable. Really, we say we drill out plugs to bottom, but you're really more washing the bottom, and occasionally you'll hit a couple of spots you got to drill through. I think going forward, we're going to have a whole lot less risk of any kind of little hiccups on the completion side. Now we are pumping the larger fracs. We started pretty much with all the wells we completed in the second quarter were either 25% or 50% larger proppant loading than before that. Seeing really good pressures at the rates we're flowing at initially. We think it'll definitely bear fruit on the higher EURs. Everybody knows we have to wait to prove that out. For the cost on the completion side with the bigger fracs, obviously that goes up. I see 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. Overall D&C cost, depending on which one of those in the future maybe weighs the most, I think we're looking at something pretty similar to where we've been. Because we're going to get that drill cost going down with these big hole laterals, even though we're pumping the big fracs, we're not going to see any higher cost. It's going to be the same or a little bit cheaper. Great. Thank you. Thank you. Our next question comes from Charles Meade with Johnson Rice. Your line is open. Good morning, Jay, Roland, and Dan, to the rest of your team there at Comstock. Morning, Charles. Yeah. Thank you, Jay. Jay, maybe this is for you, maybe it's for Dan Harrison, but I think you guys have done a great job explaining why this big hole design is helping you on the drilling side. I'm curious if you'd offer any kind of opinion on what it might mean for well productivity once you complete the well. I imagine that with just the larger internal diameter, you're going to have an easier time getting your fracs off. Maybe you can talk about what it might mean on the cost side of the completion, but more importantly on the productivity of the well. Well, I think it's going to let us get on average, these big hole wells, we're probably going to be looking at longer laterals. Which, the longer the lateral gets, the toe stages are just a little further out takes a little more horsepower. Running that bigger pipe in general, conceptually. It creates a little bit lower treating pressure with the bigger pipe. Less pipe friction, you get a little more rate, you get a little bit better frac efficiency, pump a little faster, shorter pump time. It creates all of those things for you. The biggest, obviously, the drilling side is where it really just makes the big difference for us. Like I said, we had expectations for the first well. We beat those expectations, and now we just need to show that it's repeatable with second and third well. Well, like Dan Harrison said, I did think that what he said, we do have a line of sight through drilling techniques, which we've implemented on these 50 wells. We have been tweaking our completion designs. All that is as Derrick Whitfield had asked, it should materially drive down cost. It'll enhance well productivity Charles Meade, I think that's what you're asking about. It is amazing. Charles Meade, 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. Every 90 days, we show you everything, which that's unusual. We're 50 wells into it, and we're super pleased with where we have come from, where the future's taking us. As we all, everyone that's 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. Everything really focuses on not what we paid for inventory. Well, we paid not much for inventory. We really spent our money on drilling and completion side. I would ask all of you to look at that and say, if you own the footprint and don't have a lot in it, and the reserves are there, and you've drilled maybe 60, 70, 80 miles apart. We've got some peer companies out there that are now in the game, which we're their biggest cheerleader. Those wells look good. That we are, as a group, 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. I think we're going to deliver that. That's everything we do. That's our goal. Got it. Thank you, Jay. If I could ask about the U-turn of Horseshoe wells in the Legacy Haynesville. I think for the second quarter in a row now, your highest IP has come from a Horseshoe well in the Legacy Haynesville. I believe, or maybe you can confirm, part of that is because you've got these kind of stranded single section units in some of the best parts of the Haynesville that were developed early, and that's why they're stranded now. Other than that is there something else going on maybe with your different frac recipe, that you're still breaking new ground as far as productivity in the Legacy Haynesville with these wells? We don't pump a different frac design on the Horseshoe wells. It's still the same proppant 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 the well, you really can't tell the difference. I'll say that the rotary steerable work that we started here a few quarters ago, the big benefit we're getting from it is on these Horseshoe wells, because we're able to drill the curve and all of that Horseshoe turn instead of sliding with a conventional assembly. We're rotating the whole time all the way around as we're turning that well around 180 degrees. It's definitely helped us shave some time off of what we thought those looked like in the beginning. On performance, it really is mostly, I think, where a lot of those wells are. A lot of the Horseshoe wells we've drilled are in good type curve areas because they were stranded. Like you said, we weren't going to drill them as 5,000-foot laterals, and just due to the efficiency. They haven't disappointed for sure. They look really good. 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 see how those look on the next call. Well, Charles, I think that the thesis of the oil and gas sector two or three years ago, nobody drilled a lateral, much less a 15,000- 20,000-foot lateral. Only several years ago, were you really drilling Horseshoe. It'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, we can drill in 2008 and help discover the legacy Haynesville Bossier. All we're doing now is just we're moving one more checker to show you what we think we can be doing in the Western Haynesville. Those questions are great. It is all driven by technology. Everybody that's asked a question has asked the right question. That is a great detail. Thank you, Jay. Thank you. Thank you. Our next question comes from Kevin McCurdy with Pickering Energy Partners. Your line is open. Thanks for taking my question. I wanted to ask about production cadence, not to get too far ahead of ourselves, last quarter, you talked about the exit rates this year could bring you back to the peak levels you experienced in early 2024. 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 H1 of 2024, which the H1, the first and second quarter were fairly different. We're still on track to get to that level, 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. Appreciate that, Ron. 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, just curious what your experience is in drilling in that region and maybe your thought on the extent of the Louisiana Haynesville. Yeah, 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 wells planned for, I can't remember if it's later this year or early next year, that are going to be down on the south end. Yeah, we got some good wells down there. Bossier and Haynesville 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. I wanted to start on leasing with the increase to the overall Western Haynesville 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 Haynesville, we've leased a lot of large tracts and have blocked up the acreage really well. There's a continual maintenance of picking up any remaining acres before we finally want to drill the well. Part of that program, it's really twofold. I think part of that program is to complete filling out the units. Typically, we'll end up with 100% of the well, for the most part. That's been most of what our experience been so far. There is a little bit of extensional areas that we like based on reprocessing seismic and stuff that are maybe the other part, just where we see like. I don't think it's really very large, but just as we fill in any gaps that are available. Maybe a lease becomes available that wasn't available earlier. Obviously, we monitor that. 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'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. That's what we see happening on a quarterly basis. We've added a little acreage here and there, and it's all to make the existing acreage even better. That's what you see. Perfect. That's helpful. I'll try to ask about 2027. I know it's early, but if we think about the nine-rig program and four-frac 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? I think we all agree that there's a demand wave coming. The forward curve doesn't necessarily reflect that next year. 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 got into the summer. Going to continue to watch that. 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. I think that's really to be determined, what would you view. We definitely would want to see probably stronger prices, especially stronger prices that we could hedge into to support that activity into next year. I'll tell you what 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 30, 40, 50 miles to the north or whatever. What we want to do, we see that LNG demand growth, it is expected. We know that there's going to be a lag between when it's actually delivered, and the gas. That's going to be lumpy. What our goal is let's just try to de-risk as much of this as we can. Like Dan said, two-thirds of it's Bossier, and Bossier is much easier than the lower, hotter Haynesville, but it's all held by production. We just want to be ready to respond quickly, when that demand is here. 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'd 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 contracting. We've been working with one of our vendors to make the higher temp motors available. We've been waiting to get them for a little bit, sometime hopefully here in the next two or three months, we'll take delivery of some of those and get them deployed in the wells. We think basically we just need to stay on bottom longer. A motor the elastomer in the motor, the rubber, the elastomer rated for the higher temperature, the motor's going to last longer. We're just going to be able to stay on bottom drilling longer hours, maybe an extra day on average, what have you. If you can deploy those and you can stay on bottom longer with longer runs and make less trips until you get the well drilled to TD, that's how you cut days off the well. If you can just eliminate one trip, you can eliminate two to three days. Two trips, four - five days. That's the task. I think that's where Dan talks about the motors. 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 our costs time. That's also where that big hole lateral. When we're drilling, that's basically, we say big hole. The lateral's 8.5 inch bit size or diameter versus a 6.75 in our normal slim holes that we drill. When you're drilling in the bigger hole, you're circulating the mud faster. When you're circulating faster, it keeps the hole cooler. When the hole stays cooler, the tools last longer on bottom. That's what we're achieving there. Now, this higher temp motor, we can basically take that technology, they can just basically take that same higher temp elastomer they can put it in the bigger motors that we use for the big hole. We also get the same benefit there. We got our eyeball on that also. Great. I guess just to sort of refresh my memory, I think of a period maybe about three, four years ago where there was another sort of wave of improvement. I think it was mostly around down-hole tools. I don't know if it was logging specifically, but it's just that there are kind of like these step changes of improvement that can come along and help. I wonder if you just have any thoughts about any other similar improvements that could be meaningful and just what else you might be looking forward to in the next couple of years to keep developing out there. You're right. It is step changes, really. I think maybe a few years ago, maybe what you were talking about, we first started using the coated or insulated drill pipe, which when we were drilling some of those. The deeper TVD Haynesville wells, they were really hot. They were over 400 degrees. We went to that insulated drill pipe. It's the same basic thing we're trying to accomplish. We're trying to keep the mud cooler on bottom make the tools last longer. When we ran that insulated drill pipe, we got a big change in down hole circulate temperatures, 20, 30 degrees, which makes a huge difference on the life of those tools. We've been utilizing that ever since. Now, we also use insulated drill pipe when we drill the big hole laterals also. You get that benefit there as well. 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. I think this big hole is our next big step change down. It's going to drive the cost down. Then we'll try these higher temp motors. Hopefully here in the next 2, 3 months, we're going to be able to get those and put them in the ground and, we'll get the better performance from those. Then, in my prepared remarks, I talked about we've got this 10,000 PSI rig. It's been upgraded. All of our rigs are rated up to 7,500 PSI. This one will be a 10,000 PSI, so we'll be able to pump a little faster, just basically put a little more weight on a bit and just put more horsepower on these wells and get them to drill faster. Looking forward to that. I think that's going to probably be in October when we get that 10K rig deployed. Looking forward to that. We're also got a second rig that we're in talks with to be upgraded to 10,000 PSI. If that works like we expect it to, all of the rigs in the Western Haynesville will eventually be upgraded to 10,000 PSI. On the frack side, we've been talking for a while about this [20,000 PSI frack fleet. That's obviously a pretty good capital investment. We're just still working through some particulars with our industry partners on maybe how we could put that together to make it work for us. Great. Thanks a lot. Thank you. Our next question comes from Carlos Escalante with Wolfe. Your line is open. Hey, good morning, team. Thank you for taking my question today. Dan, I'd like to ask Carlos, I always look forward to your research reports, your headlines. I always look at that. Tells me what your heart's saying. Oh, Lord Jay. Well, thank you. We can take that offline. Dan, question for you on the completion side. I guess we want you to help us parse through the headline D&C cost trend, particularly as you've been ramping on your pound per foot on the proppant side, and you've been fracking on tighter stages. I wonder if you can perhaps walk us through 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. 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 front. All of the wells, we talked about going to the higher proppant loading. Basically when we went to the higher proppant loading, all of the wells that we completed, that we say we completed, that we turned to sales in Q2, was the first batch of wells that we systemically went up to the larger proppant loading. Now we did pump a larger frac on one of the really earlier wells. In Q2, the oldest ones have been on now for maybe three months, two or three months, that we turned to sales in March. We had some that we pumped at GBP 5,000 per foot, some at GBP 6,000 per foot. It will definitely take time to see how they decline out, but the initial results look really good. The flowing pressures look really good at the IP rates we're having that with. We're obviously managing the drawdown very conservatively and maintaining that high flowing pressure on them. Got it. Just to clarify, 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. We went to the tighter cluster spacing and the smaller stages last year and when we were still pumping our standard frac design at 4,000 pounds per foot. We've maintained that spacing, smaller stage spacing. We've maintained that as we've increased the proppant loading. Okay, that makes sense. My follow-up, and I hope this is going to make sense, but because you're executing on an ongoing HBP 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? Well, definitely the drilling program, like we said is based on holding acreage. You're not able to look to see the most optimal places you can drill, that's been the nature of the drilling program. It'll slowly shift. We're able to drill some infill wells later. That's the nature of it. That's correct, that you're really looking at using your program to make sure you put these term leases into held by production status. It is constraining your lateral length. Yeah, I think that's a good point, Carlos, because we haven't drilled on a pad for infill development where you drill six, seven, eight, nine, 10 or 15 wells off a pad. We've not attempted to do that at all. Even though you've got the gathering there, you've got the pad there, you've got cost to come down materially. What we've attempted to do was on a very cautious basis. We've tried to lean into technology. We have looked at our debt level. We want to manage our debt level, and we want to improve execution. Along the way, Carlos, again, I read everybody's research report. I think to kind of hold hands here together, that Dollye Jones well, Dollye's a big word and Jones is a big word. You stick them both together at Dollye Jones, it should be a big hole 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. You're really, really looked at hard with Sixth Street. That should make Carlos, you happy. They manage $135 billion. They see this growth, and they see the need for Pinnacle. All of this leans into this demand that we will have because the dollars are being spent, whether it's for data centers or LNG. I mean, we're going to need another 13+ Bcf between now and probably 2031, and that is without data center gas demand. Those are the things that we're doing, we are under the microscope every 90 days. You got to endure a little bit of this, 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. Really not to hijack here the conversation, but just to drive the point home, what Dan said that when drilling costs per foot are going to come down and completion costs are going to go up because of the larger fracs. 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. Fair to say that? Right. You're kind of comparing this play to a very mature play in the Legacy Haynesville, where this cost was incurred years ago, and now we're 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 from the nature of developing out what we've proven up, and perfecting the completion design and the drilling design. I do think that the other element is, we do feel like given the pressure of the reservoir, the quality of the formation that we've now taken cores and studied, we do think the larger fracs are going to yield larger EURs. Out of the gate, like the wells completed this quarter, the pressures are significantly higher. I think that's going to bode well for their EURs. We're going to have to let them have some time to prove that out. Yeah, Carlos, 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 along the side of them. We're building the road, and then we own everything on the side of it. Where are we going? Well, we're going to the federal power generation hub. It's tremendous upside of where we're going. That should begin latter part 2027, 2028. 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. 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.