Comstock Resources Inc (CRK) Q3 2026 Earnings Call Transcript

Good day, and thank you for standing by. Welcome to the Q3 2026 Comstock Resources, Inc. 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 the session, you will need to press star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Ellison, Chairman and CEO. Please go ahead.

Thank you. I know that there are several companies presenting at the same time, so those of you that have joined this call, you know, we're always appreciative and thankful. So welcome to the CompSoc Resources third 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 result presentation. There you'll find a presentation entitled Third Quarter 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock, and 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 a meeting of security laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you would turn to slide three, we summarize the highlights of the third quarter. Our production grew 9 percent from 2025 and was 8 percent higher than the second quarter driven by new wells turned to sales from our drilling program. In the quarter 16, Legacy Hainesville wells were turned to sales with an average lateral length of 10,812 feet and an average per well initial production rate of 25 million cubic feet per day. Six of those were horseshoe wells. We also turned six new Western Hainesville wells to sales in the third quarter, with an average lateral length of 9,829 feet and an average per well initial production rate of 33 million cubic feet per day. The higher production drove our financial results, which Roland will go over in a few minutes. Starting September 1st, we entered into a drilling venture with Jerry Jones, covering 27 wells. 18 of the wells are in the Western Hainesville, with 9 in the Legacy Hainesville. The new venture will allow us to generate free cash flow in the fourth quarter, while also allowing us to continue our development and delineation program in the Western Hainesville. On November 9th, yesterday, we entered into a definitive purchase and sale agreement with SOCAR for a $1.65 billion divestiture. The proceeds from the transaction will substantially improve our balance sheet. We also just extended the maturity of our bank credit facility by a year, which will further extend an additional four years after closing the SOCAR transaction. I will cover all of those strategic transactions in the next slides. Turn to slide four, we summarized the drilling venture with Jerry Jones. Beginning September 1, 2026, Arcoma 3, a partnership owned by the Jones family, will fund the drilling and completion cost of 85% of 18 Western Hainesville wells and 80% of 9 Legacy Hainesville wells. Our comma 3 will fund an estimated $300 million of capital expenditures in 2026 and an additional $150 million in 2027 on these 27 wells. Prior to September 1st, Comstock had spent $180 million on these wells, which will be recovered by Comstock from 100% of the net revenues from the first production of these 27 wells. Arcoma 3 will receive the net revenues after the pre-venture costs are recovered until Arcoma 3 has recovered its cost and a 15% return. After the return on investment has achieved 50% of the interest, and the 27 wells revert to Comstock, the drilling venture allows us to generate free cash flow in the fourth quarter while supporting the continued development and delineation of our 547,000 net acres in the Western Hainesville, as well as providing volumes to Pinnacle Gas Service. If you'll turn over to slide five, we'll summarize the strategic partner with SOCAR. SOCAR is purchasing a 20% interest in our legacy Haynesville, a 15% interest in our western Haynesville, and 15% of our interest in Pinnacle Gas Service for $1.65 billion. We recently executed the definitive purchase and sale agreement and expect the transaction to close by year-end 2026. Proceeds from the transaction will be used for debt repayment. Comstock will remain the operator of the properties, and Comstock and SOCAR will jointly participate in further leasing and acquisitions in the Hainesville. SOCAR will offer Comstock future LNG marketing opportunities. SOCAR's 15% interest in the Western Hainesville reduces to 7.5% after five years, and once SOCAR has achieved a 15% return on investment in those assets. As a result, Comstock will have an increased participation in the future upside of the Western Hainesville assets. Creating a balanced structure that aligns both parties around the long-term performance of those assets. Slide 6 shows the ownership interest in the Legacy Hainesville, the Western Hainesville, and Pinnacle Gas Services upon closing of the SOCAR transaction. As previously mentioned, after five years and upon SOCAR achieving a 15% return on the investment in the Western Hainesville upstream assets, Comstock's interest in the Western Hainesville assets will increase from 85% to 92.5%. Sixth Street owns the remaining 27% of Pinnacle Gas service, which reduces to 19.5% after certain return hurdles are met. At that point, Comstock's interest in Pinnacle Gas Service will increase to 69.5%. Please turn to slide 7, and I'll show you the key partnership impact of the SOCAR transaction to Comstock. The $1.65 billion purchase price provides strong validation of the value implied by the quality and longevity of Comstock's upstream assets in the Legacy Hainesville and Western Hainesville, while reaffirming our significant midstream value embedded within Pinnacle Gas Service. SOCAR's investment-grade balance sheet and global LNG marketing operations should help create value for Comstock shareholders. Comstock will use the proceeds. From the SOCAR transaction to repay the outstanding balance under Comstock's revolving credit facility, with pro-forma net debt decreasing to about $1.7 billion compared to $3.4 billion at the end of the third quarter. The stronger balance sheet will support continued delineation and development of Comstock's 547,000 net acres in the Western Hainesville. Comstock remains operator of the properties and retains further upside in the western Hainesville through the reversion provisions. On slide 8, we'll show you the benefits of the strategic partnership with SOCAR. The partnership with SOCAR combines Comstock's Gulf Coast location, Access to significant gas reserves and midstream operations with SOCAR's LNG and trading platform. The scaled footprint across both the Legacy and Western Hainesville provides decades of drilling inventory. As a result, Comstock is positioned to maximize natural gas pricing netbacks across domestic and international markets while mitigating volatility via strategic partnership in power supply and midstream investments. Both the Jones family and SOCAR are aligned as long-term strategic stakeholders. Lastly, the delivered balance sheet provides development flexibility across our asset base. I will now turn it over to Roland Burns to discuss the third quarter financial results.

All right. Thanks, Jay. On slide nine, we covered the third quarter financial results. Our production in the third quarter averaged 1.3 BCFE per day, which was up 8% from the second quarter of this year, and was 9% higher than the third quarter of last year. Oil and gas sales after hedging were $359 million, reflecting the impact of the higher production, being offset a little bit by lower natural gas prices in the quarter. EBITDAX in the quarter was $266 million, and we generated $208 million of cash flow, or $0.71 per share, before any working capital changes during the quarter. We reported a $22 million profit for the quarter, or $0.08 per share. Included in that number was a pre-tax $35 million mark-to-market unrealized gain related to our future hedges. So excluding the mark-to-market gain, expiration expense, and other non-recurring items, and the related income tax impact of those, we reported net income of $6 million for the third quarter, or two cents per share. Slide 10 covers the year-to-date financial results, production in the nine months. Of the year, average 1.2 BCF per day. Oil and gas sales after hedging were $1 billion in that period, and EBITDAX was $763 million, and we generated $588 million of cash flow, or $2.02 per share. We reported a $138 million profit for the first nine months of this year, or $0.47 per share. That number included $119 million mark-to-market unrealized gain on our future hedges, so excluding that mark-to-market gain, expiration expense, and other non-recurring items, and the related income taxes, we reported adjusted net income of $54 million for the first nine months of this year, or $0.18 per share. Slot 11 breaks down our natural gas price realizations in the quarter. The quarterly weighted average NYMEX settlement price averaged $2.95 in the third quarter, and the weighted average Henry Hub spot price averaged $2.87 in the quarter. So we sowed a third of our gas in the spot market, so an appropriate NYMEX reference price for our quarter would be about $2.93. Our realized gas price averaged $2.61 in the quarter, reflecting a $0.34 basis differential compared to the NYMEX settlement price and a $0.32 differential compared to the reference price. In the third quarter, we were 59% hedged, so that increased our realized price to $2.93. We also made an additional $0.02 per MCFE from our third-party marketing activities. Slide 12 details the operating costs per MCFE and our EBITDAX margin. Our operating costs per MCFE averaged 80 cents in the third quarter, up 3 cents from our second quarter rate. Lifting costs were down 2 cents. G&A was down 1 cent. Both a triple to that higher production level we had in the quarter. Production and ablorum taxes increased by 3 cents in the quarter. Really due to prior period true-ups, and gathering costs were up three sets. So overall, our EBITDAX margin was 73% in the third quarter. Slide 13, we recap the spending. So far this year in our drilling activity and other development activity, we spent a total of $383 million on development activities in the third quarter and $1.1 billion during the first nine months of this year. In the first nine months of this year, we drilled 39 wells, or 28.6 net to our interest. So, we've been doing both 15,000-operated wells. And those are in the Haynes-V tolerated well. And we drilled another 16 or 10 net wells in the Boazner's shale formation for a total of 55 wells or 38.7 net wells. We turned 52 wells, or 44.7 net operated wells, to sails so far this year, with an average overall IP rate of 29 million cubic feet per day. Slide 14 summarizes our capitalization at the end of the third quarter. We ended the quarter with $800 million of borrowing outstanding under our upstream credit facility. Our upstream borrowing base is $2 billion under the credit facility, and the elected commitment under that facility is at $1.5 billion. And all of that was recently reaffirmed in our early November bank meeting. The maturity date of our facility was recently extended also to November 2028. After closing the SOCAR transaction, the maturity will further be extended on our bank credit facility to November 15, 2031. At the end of the third quarter, the midstream credit facility had no borrowings outstanding. Our last 12 months' leverage ratio was 3.2 times, and we ended the third quarter with over $850 million of financial liquidity. For the SOCAR transaction, our debt will be reduced by half, and our leverage ratio improves to two times. Given the impact of the Jones drilling venture on the fourth quarter capital spending, we anticipate generating free cash flow in the fourth quarter, which will further reduce our debt, you know, before closing the SOCAR transaction. I'll now turn it over to Dan, you know, to discuss the operations in more detail.

Okay, thanks, Roland. On slide 15, this is our updated overview of our total acreage footprint in the Hainesville and Bozer. Shales East Texas and North Louisiana. So overall we currently have 1,084,812 gross acres and 809,883 net acres that are prospective for the commercial development of the Hainesville and Bossier Shales. We currently have just over 262,000 net acres across our legacy Hainesville area, and our western Hainesville footprint has grown to just over 547,000 net acres. Our producing well count now stands at 47 wells in the western Hainesville. This is up six wells since our last call. We currently have another 15 wells that we have in various stages of development. On slide 16, this outlines the drilling inventory in our legacy Hainesville area at the end of the third quarter. We have 899 gross operated locations with a 78% working interest. or 698 net locations. We have 770 gross non-operated locations with a 12% working interest or 96 net locations. 442 of our 899 gross operated locations, or nearly 50%, have laterals exceeding 10,000 feet. The average lateral length in our inventory stands at 10,212 feet. Our gross operated inventory is evenly split between the Hainesville and the Bossier. Also included in the legacy Hainesville inventory is 108 gross horseshoe locations with 50% Hainesville and 50% in the Bossier. We currently have four rigs, you know, they're running on our legacy Hainesville area, which provides us with a long runway of future filling locations. Slide 17, this outlines our estimated drilling inventory in the Western Hainesville. We have 3,255 gross-operated locations and 2,507 net locations in the Western Hainesville, which equates to an average working interest of 77%. Our total net locations are estimated since much of the Western Hainesville acreage has not been unitized. Roughly 40% of our 3,255 gross-operated locations or 1,317 locations have laterals exceeding 10,000 feet. 61% of our gross-operated locations have laterals exceeding 8,500 feet. And the average lateral in our Western Hainesville inventory is 8,884 feet. Our Western Hainesville drilling inventory is more weighted to the Bossier Formation with nearly two-thirds of the inventory in the Bossier and one-third of our inventory is in the Hainesville. And we currently have five rigs running on our Western Hainesville acreage today. Slide 18 is an overview of our Horseshoe Well Drilling Program, which allows for extended REITs and reentry opportunities for higher return drilling locations. The improved drilling economics of the horseshoe wells unlocks previously stranded acreage by converting two sectional laterals into a single two-mile lateral. Since starting the horseshoe program, we've turned 17 horseshoe wells to sales with an average IP of 29 million cubic feet a day and an average lateral length of 10,223 feet. The two most recent horseshoe wells have an average lateral length of 13,518 feet. And as mentioned on the previous slide, we have 108 remaining horseshoe locations as of the end of the third quarter. In addition to the drilling of horseshoe wells, we've identified a number of enhancements to further improve returns, including the rotary steerable technology, Redevelopment opportunities, the longer laterals, up to 15,000 to 20,000 foot. And some drill through applications. Slide 19 outlines our average lateral length drilled based on the wells that we drilled to total depth. The average lateral lengths are shown separately for our legacy Hainesville area and our western Hainesville areas. In the third quarter, we drilled 16 wells to total depth in the legacy Hainesville area with an average lateral length of 11,905 feet. The individual laterals range from 6,050 feet up to a max of 15,923 feet. The longest lateral drill to date in the Legacy Hainesville area still stands at 17,409 feet. In the third quarter, we also drilled five wells to total depth in the western Hainesville with an average lateral length of 8,587 feet. The individual laterals range from 6,936 feet up to a max 10,920 feet. Our longest lateral drill to date in the Western Hainesville is 14,783 feet. To date, we have drilled 54 wells to total depth in the Western Hainesville. 23 of these 54 wells have laterals exceeding 10,000 feet. Slide 20 summarizes the 38 wells that we have turned to sales in our legacy Hainesville area so far in 2026. The average lateral length was 11,530 feet, and the individual laterals ranged on the low end from 8,497 feet up to a high of 15,772 feet. The average IP for the 38 wells is 28 million cubic feet per day. And included in these 38 wells is 14 horseshoe wells. Slide 21 outlines the 17 wells that we have turned to south on our western Hainesville Lake, which is so far in 2026. These 17 wells had an average lateral length of 10,153 feet and an average initial production rate of 31 million cubic feet per day. Since our last call, we have turned six additional wells to sales with IP rates ranging from 26 to 40 million cubic feet per day and an average IP of 33 million cubic feet per day. We have a total of 47 wells currently producing on our western Hainesville acreage. Slide 22 highlights our drilling efficiency in the Legacy Hainesville area. This is for our benchmark long lateral wells that have laterals over 8,500 feet long. In the third quarter, we drilled 14 of our benchmark long lateral wells to total depth in the Legacy Hainesville and averaged 22 days to total depth. Correspondingly, we averaged 1,156 feet drilled per day on our Legacy Hainesville acreage. And this represents a 14% increase versus the second quarter of 2026. Five of the wells we build in the third quarter were horsey wells. Slide 23, this highlights our drilling progress in the Western Hainesville. During the third quarter, we drilled five wells to total depth. This gives us a total of 52 wells drilled to total depth through the end of the third quarter. We averaged 56 drilling days for the five wells drilled to total depth during the quarter. This is a decrease of three days compared to the second quarter. The drilling speed of 461 feet per day during the third quarter was 2% lower than the second quarter. The main reason the drilling speed decreased from the second and third quarter was the Dolly Jones. That was our first big hole ladder we drilled during the second quarter. And this well drilled 25% faster than our other wells. If we had taken the Dolly Jones, it would have been excluded. Our drilling speeds would have improved in the third quarter. Slide 24 details our DNC costs through the third corridor for our benchmark long lateral wells in the legacy Hainesville area. These costs reflect all of the wells with laterals over 8,500 foot long. The drilling costs are based on the corridor in which the wells were reached TD, and the completion costs are based on the wells during the corridor on the wells that return to sales. During the third quarter, we drilled 14 of our bent-spark long lateral wells to total depth, including five horseshoe wells. Our third quarter drilling costs averaged $634 a foot. This is an 11% decrease compared to the second quarter. Our improved drilling performance in the third quarter can be attributed to had much stronger lateral drilling performance compared to the second quarter, which outweighed the impacts of the slightly higher service costs we did experience during the quarter. The rotary stirruble drilling technology being deployed in our legacy Hainesville area, especially in our horseshoe wells, has continued to deliver superior results that's driving our drilling efficiencies higher. During the third quarter, we also turned 15 of our bitsmarked long ladder wells to sales on our legacy Hainesville acres, of which five were horseshoe wells. The third quarter completion cost came in at $715 a foot. This is a 5% increase compared to the second quarter, and the higher completion cost in the third quarter is partially the result of completing three single well pads during the third quarter, compared to nine during the second quarter. We also experienced the higher service costs during the third quarter. Slide 25 is a summary of our DNC cost through the third quarter for all wells drilled in the Western Hainesville. During the third quarter, we drilled five wells to total depth in the Western Hainesville. Average lateral length was 8,587 feet. The third quarter drilling cost averaged $1,934 a foot. This represents an 11% increase compared to the second quarter. The biggest factor in our higher drilling costs for the third quarter was the shorter average lateral length of 85, 187 feet for the wells in this quarter. And to a lesser extent, the higher service costs we experienced also contributed to the higher drilling costs for the quarter. During the third quarter, we drilled our second big hole lateral. This time we drill it to a more challenging lateral target in the Haynesville, but again, our results met our expectations. During the third quarter, we also turned six wells to sales in our western Haynesville acreage that had an average lateral length of 9,829 feet. The third quarter completion cost averaged $1,959 a set. This is a 22% increase compared to the second quarter. And we had several drivers affecting the higher completion costs during the quarter. The primary drivers have been the transition to pumping the larger fracks. This led to we had a 12% higher profit loading in the third quarter compared to the second quarter. Couple that with the higher service costs that we had. We also teamed up all but one of our third quarter wells as opposed to only tubing up one of our wells in the second quarter. Back to the drilling side, we've been very pleased with the results of our first three big hole lateral wells, and we're planting more of these wells for the future. The bigger hole in the lateral creates the lower downhole temperatures, and we're seeing longer, more reliable runs from our downhole drilling assemblies, and it has also provided us with much better steering ability so that we can keep our laterals on target. One last item I want to update from our last call. We should be deploying our first 10,000 PSI rig in the Western Hainesville towards the end of this month, which we fully anticipate will lead to faster drill times, and we're planning to upgrade two additional or two more of our rigs to 10K capability in the second quarter of next year. I'll now turn the call back over to Jay.

Dan, great job. Roland, great job. If you'll go over slide 26, we'll summarize our outlook for 2026. Again, our primary goal continues to be advancing our Western Hainesville that will position Comstock to benefit from the longer-term growth in natural gas demand. We have five operated drilling rigs in Western Hainesville to continue to delineate the new plate. You know, we expect to drill 19 wells and turn 20 wells to sales in 2026, and we expect drilling efficiencies and changes to our completion design to continue to drive up productivity and drive down DNC costs. We have four operated rigs drilling in Legacy Hainesville to support production growth in 2026 and 2027 and expect to drill 52 wells and turn 45 wells to sales in 2026. The Jones-Zerling venture allows us to generate free cash flow in the fourth quarter while supporting the ongoing delineation and development of the Western Hainville. The SOCAR transaction will allow us to retire half of our debt outstanding, providing us a strong balance sheet as we enter 2027. Comstock has captured the massive Western Hainesville footprint and been successfully drilling wells there since 2021. At the same time, we own Pinnacle Gas Service, our midstream, to ensure takeaway. We believe natural gas will be undersupplied by 2029, with the demand growth of LNG going from about 20 BCF a day now to 35 BCF a day by 2032, plus the additional 12 BCF needed to provide turbines, power for turbines, for data centers. Where our Hainesville-Bosier leases are located is the sweet spot for demand. Our goal is to protect our natural gas assets, protect our midstream company, PGS, prudently develop our Western Hainesville footprint, and add to it monthly, protect our balance sheet, and have the best partner in the world on our side. With the addition of Nextera, Sixth Street, and Socar, I believe we have the winning team. When Jerry Jones and his family touched Comstock in 2018, we became who we are today. That support 100% allowed us to purchase Covey Park in 2019, close the numerous acquisitions around the Western Hainesville, acquire PGS and lease thousands of acres in our Western Hainesville at a time of very low natural gas prices. The Jones relationship also helps secure Socar as a forever partner that provides us LNG marketing opportunities in Europe. And on September 1st, 2026, the Jones Drill Co, $450 million, allows us to generate free cash flow in the fourth quarter while supporting the continued development and delineation of our 547,000 net acres and our Western Handle, as well as provide volumes to Pinnacle. Jerry asked me to make the following comment. His commitment to Comstock is because of his unwavering faith in management, an exemplary natural gas asset base that we control, and the tremendous value of U.S. gas in the future. That is why the Jones family have invested over a billion dollars in Comstock equity. With that, I want to thank you for your time. Slide 28 provides guidance for the rest of 2026, which Ron can discuss with you directly. If you have questions for the rest of the call, we'll take questions from analysts who follow the company. I'll turn it back over to you.

Okay, thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. We ask that everyone limit to just one question and one follow-up question. Please stand by while we compile the roster. Our first question comes from the line of John Annis with Texas Capital. Go ahead. Your line is open.

Hey, good morning, all, and thanks for taking my questions. For my first one, the Dolly Jones well delivered a 40 million a day IP using the big hole design, and I think you're now drilling your fourth well with that design. What have you learned about the repeatability of results on drilling and well performance, and then ultimately what portion of the Western Hainesville inventory could ultimately be developed this way?

That's a really good question. So, we are drilling our fourth well at the moment with the big hole design. We haven't seen anything to date that tells us, you know, that you have any concerns with that design. We really need to drill more wells to just hone in on where the breakover is between drilling a slum hole versus, you know, a big hole design. Right now, I'd probably just say it's somewhere between 10,000 and 11,000 foot lateral length. You know, our goal is, of course, we had the shorter average lateral length that we reported for the quarter, and that's just due to where we're trying to hold acreage and, you know, the acreage layout and geology and some other things. But, you know, in the future, we'll definitely be getting the laterals longer, you know, in the years ahead. So I would say probably the majority of all our future wells, you know, maybe not within the next year or so, but further out, I'd say the majority of the wells will be drilled with the big hole design. So, you know, we just need some more data to just hone in on really just kind of where that crossover mark is, but we've been super pleased with it. You asked about the Dolly Jones. That was the first one. That thing really drilled incredibly fast. That was drilled to the Bossier. Our second big hole that I kind of mentioned on one of the slides was drilled to the Hainesville. The Hainesville, just on average out here, is a little bit harder digging than it is in the Bossier. So, you know, we were, the results from the second well were about right on par with what we expected. But I think, you know, maybe one of the things to drive home is the intangible benefit of drilling the big hole. We can steer and keep the laterals on target much more easy than we can than when we're drilling with the slim hole. And, you know, when staying on target, this directly correlates to the performance of these wells. You know, you want to keep that lateral right there in the best rock where you want it. So not only can we drill long, but even when we're drilling long, we can still keep that thing on target way out there at the end, which. You know, the slim holes, they'll start walking, and we have a lot more difficulty keeping them on target when the wells get long. And then that just leads to other issues that add drilling days. So happy with the big holes. I see that as the bulk of the future.

Got it. I appreciate all that color. Maybe staying on completion design, last quarter, you noted the 2Q wells were the first full batch completed with 5,000 to 6,000 pounds of profit per foot and said their early pressures look encouraging. With another quarter of production history, are you seeing a measurable improvement in expected EURs, and is that uplift, in your view, sufficient to justify the 12% or so higher property loading?

Definitely. Absolutely. So we actually transitioned. Our standard frack design when we started out and really for a lot of early wells was 4,000 pounds per foot. We did have one big job we pumped back early on on one of the Robertson County wells, but other than that, they were all 4,000 pounds per foot. We transitioned to the bigger fracks really starting in December of 25 when we started popping them. So every well in 2026 has either been 5,000 or 6,000 pounds per foot, and when you run the math on the economics, I mean, you only need maybe an incremental like 0.2 BCF per 1,000 to justify adding another 2,000 pounds per foot. And when you look at the well performance we have today, which it's early on some of these wells, but they do look really good. So when you take that early data and combine it with the modeling and stuff that the reservoir group has done, we easily could surpass, you know, that 0.2 BCF 1000 incremental. So that's definitely the direction we're going.

Got it. I appreciate the time. I'll turn it back.

Thank you. One moment. Our next call comes from the line of Carlos Escalante with Wolf Research. Your line is open.

Howdy, Jay and Roland and team. How are you guys doing today? Thank you for taking our call. Wanted to ask on your HPP program in light of the now nine rigs you have running across your operations where five are now in the Western Hainesville. Because I don't think that when you gave preliminary outlook of when you thought the HBP program would be done, that you contemplated fabrics in the basin, or at least as quick as you did. So I wonder if you can... Remind us or reframe for us, when do you think you would hit your threshold, and how do you foresee that transition from HBP-driven wells move over to value-driven or return-driven operations, and should we see or should we expect perhaps a quicker inflection on the NC per foot when that does happen anytime sooner? Thank you.

I'll let Dan answer most of it, but I would just say that what the fifth rig is going to allow us to do. Is to put some more development wells into the program and not have to 100% keep all the projects on HBP acreage. So I think we are still on the same kind of time frame because we're very comfortable with that time frame to HBP the acreage. But with the additional rigs, you know, we can now drill some more. Wells on the same pad. Also, drill in areas where we've already really, you know, spent a lot of money to figure out the area really well. So, I think the ability to drill some development wells will definitely start to see a positive impact on the overall program as far as cost. And so, that's kind of the direction. So, we'll probably use the additional drilling rig there just now. And now that we have support of other partners, such as the Jones Partnership and SOCAR, Probably to add infill development wells along the way in the program and meet our HPP goals, you know, with the overall drilling program.

I think we'll have a dual program, which we needed. We're to the point after, I think we'll have drilled 60 wells at the end of this year in the Western Angel. I think our time frame, even though we add acreage every month, our time frame to hold all of it with the four plus rigs is still the same. But now we have a dual goal. We can come in, and the millions of dollars that we have spent for gathering and take away and the pads, we can now drill additional wells on those pads. And I think you'll see material cost savings. And now that we've drilled around a bunch of these wells, we understand where we should keep the lateral. And you add all the new drilling tools that we have, I think you'll see the cost come down. I think you'll see the productivity go up, particularly with the choke management that we're using now. We'll blossom on some of the production rates that we will be giving you in the future.

I think Jay and Roland gave you a pretty good answer. I don't really have a lot to add to that. You know, we are blending in some infill development wells a little bit in 2027, which allow, you know, those wells we can set up with the longer laterals and in the areas where we already have, you know, proven offset well performance to kind of help balance out that HBP, you know, the HBP program.

Sure. Thank you to the three of you. That sums up a solid answer, I think. And then on productivity, just going a step further, perhaps, on the prior question, if I look at your, particularly one of the Kretschmar, and I'm sure I'm watching that name, Kretschmar Wells, your normalized initial production rate, That's a very quick and dirty metric. Looks to have jumped and actually posted one of the highest numbers in the two years you've been doing a lot of the drilling. So just wondering, that's obviously just one piece of the puzzle, initial production, but what states are you taking or what of the completion design tweaks you've done? Give you confidence that you can flatten the decline rate or, said another way, can lead to maximization of your EUR and really keep that production up the same way that you perhaps did with some of the earlier wells alongside that circle and trend line.

Yeah, so... Yeah, you got the names right, Kretschmar. I think everybody struggles with that a little bit, but we, you know, the answer, you know, without getting real, you know, making it real complicated, is the larger fracks. Definitely leaving the larger fracks like we talked about earlier. It just takes a minimal incremental EUR, which we should easily surpass. And the conservative drawdown strategy. You just want to, you're contacting a lot more rock, you're creating a lot more, stimulating a lot more, you know, reservoir volume. And with the conservative drawdown, you keep that open, you know, that's going to lead to the bigger EURs. The early data that we've got on the wells that we've fracked in the last year with the larger fracks are showing that we're heading in that direction. We do need, you know, longer-term production, you know, to prove that out, but it's all pointing to where we expect it to go.

Thank you.

I think the good thing on your question is if you go probably 90 miles north to south, that's kind of a guess number, but the rock that we have I mean, it is consistent, quality resource rock. And all we're doing now is we've extended it to the north and south, you know, starting with the Cercle M, going to Elijah One, even extended it to the north. Now we're going a little bit west. It is not the inventory, the 2,500 locations, it is not the rock. It is now really with Dan's program. That is, we're getting to the point where we can have some repeatability. And that's another reason we're going to go in and drill some of these infill wells. And why? Because of the demand for natural gas for the future. Thank you, Jake.

One moment. The next question comes from the line of Paul Diamond with Citi. Go ahead. Your line is open.

Thank you. Good morning, all. Thanks for taking the call. Just real quick on the SoCard deal. Can you guys put some, I guess, details around the potential marketing opportunities that you reference or those long-term supply agreements or direct sales? Is there any detail you have available there?

Thanks, Paul. We'd like to, but a lot of that is being developed, and I think our future partner here, SOCAR, is actually in the process of looking to buy offtake in the United States. They're buying their production first, kind of a diverse order of some of the other. Entities that have come in and had the same strategy. So as they lock that down, you know, they'll be able to come up with specific opportunities for us to look at. And their whole reason to invest in the Hainesville shale was to support their global LNG trading operations and, you know, and have this gas available to export. Thank you. As they develop that full value chain, they are going to offer us to kind of follow them on the same path, and we have the option to do that. But getting the full economic arrangements are something kind of in process that will kind of work themselves out over probably the next year or so.

Got it. Appreciate the clarity. And then talking a bit more about the rig upgrades you guys referenced, going at 10,000 PSI, potentially go to 20,000, one on the way, two more being considered. Can you talk about how, like, tangibly or quantitatively that actually translates into higher drill speed? I guess, where does the clip-off go? How much faster do we see?

Good question. I guess we really don't know exactly what that's going to turn out to look like, but we do have the first one. Actually, we've got a rig move probably coming up in a couple of weeks, and that's when the first 10,000, the first pad we drill with the 10K rig will be spudding hopefully here in a couple of weeks. But I think if you just, basically, mathematically write, The higher pump pressures, the higher flow rates you can pump, get better efficiency out of the motors, you get more horsepower to the bit, you know, basically those just conventional thinking, that's going to transfer into higher, you know, ROPs. Some of the motors we run in the laterals, specifically like on slim holes, sometimes we don't get quite the GPMs or flow rate to the motors to have them operating at their peak efficiency. So, you know, the 10K rig, being able to pump faster will let us achieve those things. So, you know, very comfortable. I know there's some other operators that have already taken some 10K rigs and that are adding more 10K rigs. So, I think we're going to see that even industry-wide. I think you'll see this pick up a little bit more also as, you know, everybody gets comfortable with the higher performance.

Thank you.

Got it. Understood.

One moment. Our next question comes from the line of Jacob Roberts with TPH Research. Your line is now open.

Morning. Morning. Morning. Guys, I wanted to start on the Western Haynesville, and when we look at the 2025 and 2026 vintages and the performance we're seeing out of those against Let's call it a $35 to $40 million cost for a 10,000-foot lateral. Can you speak to where you see the full-cycle breakeven gas price today, and then ultimately where you would like to see that head over the coming years? And I say all that, and we do appreciate that this is a longer-term plan, but I just wanted to get a sense of where we're at now versus where we could be in a few years from now.

I think we're, you know, with the cost that we have today with where we're at, I mean, I think, you know, we're in that ballpark, just straight up break even. You know, we've had a lot of inflation this year, just obviously, you know, with the diesel prices driving up the cost of everything that we're doing. We're, you know, we're up just from the second quarter to the third quarter, we're up eight to 10% overall on our cost. Hopefully that's going to flatten out. You know, in Q4, we don't see a whole lot of an increase, and maybe hopefully it retreats a little bit next year. Obviously, what happened with the elections and everything, you know, it's kind of who knows really where that's maybe headed. But so I think we're, you know, the break-even process there, and as we get into the future, you know, I think that'll be still somewhere in the same ballpark. And as the performance gets better with the higher fracks, you know, should push that down a little bit.

Okay, I appreciate that. And then maybe just to follow up on that performance comment. So, you know, the 2025 and 2026 vintages, we're starting to see that longer production history. Conversations with investors would point toward folks modeling a pretty big range of outcomes, and some are probably below the 3.5 BCF per 1,000 that we talked about, the initial onset of this play. So I was wondering if you could give any color on how the recent wells are performing on an EUR per foot basis, just to think about the change across the vintages per year or Even, even per quarter.

Well, I think since we've been pumping the larger fracks, like I said, we started in December of 25, so all of the 2026 wells have pumped the larger fracks. Early data is definitely pointing to much improved EURs. I don't know if I would put a certain number on them, but percentage-wise, 10% easily increase in EURs. You know, just what we've seen to date, everything's fitting the way that we got a model. So, you know, we're just really comfortable with the bigger fracks. We definitely need more data to, you know, to basically pinpoint what the numbers are going to end up being.

Thank you. I appreciate the time, guys.

Thank you. One moment. Our next question comes from the line of Jack Cavanaugh with Goldman Sachs. Your line is open.

Morning, team. Thanks for taking my question. Yeah, we'd love to focus on the cost in the Western Hainesville. I know you touched on it a little bit in the call, but can you speak to kind of the trend scene and DNC costs over the last few quarters and also expand maybe on the puts and takes on how you're thinking about the outlook to get those costs lower in the context of, you know, some of these rig upgrades and kind of the things you guys are doing with the big hole design?

I think if you take inflation out of the mix, you know, the cost and, you know, the change in the frack design, basically, I think our costs have been pretty flat if you, you know, if you normalized all of that and took it out. I think the, you know, we got the 10K rigs come. We definitely feel like we're going to shave some days off. That's going to drop our cost a little bit. And, you know, I think in the future long term, you know, we are looking at some rotary steerable technology, but that's a little bit further out in the future. And we also have looked, you know, we're still looking at the, you know, the 20K frack fleets, I think would definitely help us there, even though I think that's probably out further on the timeline.

Yeah, and the major driver of cost on these shell wells is lateral length, and you've seen the legacy Hainesville achieve these great cost levels because we're now just drilling 15,000-plus wells. So the western Hainesville is going to get there, but it's going to take, you know, A longer period to get there. So, you know, I think the overly focused on the cost of short laterals and the legacy is expensive, too. And I think as we improve these drilling and completion techniques and we get the laterals long, which is going to happen in the future, the costs are going to start to look more similar to the legacy. So it's just a different stage of development. So I think that the overall focus. Of the cost, you know, is a little bit, yeah, you have to have a little patience. There's a lot of exploration costs. There's a lot of, you know, single-well pads. There's a lot of things in the Western Hainesville in its early development stage that the legacy of Hainesville had the exact same thing, and they're just at different time stages. But it's trending there, and all the initiatives for the higher-powered rigs, the higher-powered completions, the better motors. Development, infill drilling, those are all going to drive those costs way down from where they are today, and the best thing is that the large reserves in place in the western Hainesville make it all worth it. They're definitely much higher than the legacy of Hainesville across the board, usually twice as much.

You know, we went back to 2008-9-10 and compared the core, which was iffy in 2008-9-10. And the result, and you had to have $5.15 gas to have a 30% IRR. And those were 4,500 foot laterals. I mean, we really didn't start drilling extended laterals, even in the core, until probably 2015. And it's only been the last several years that we've been able to drill 15,000 foot laterals in the core. And so to Roland's point, if you compare where we were in the core, they call it the core back in 08, 09, 10, in the first three or four years of the core versus where we are in the first few years of the Western Amesville, we are light years ahead in the Western Amesville where we were in the core to create value with the reserve potential that, you know, you have maybe 200 feet of pay in the core. You may have 1,500 to 2,000 feet of prospective pay in the Western Hainesville, so it's a completely different game, and the prize is multiple times more valuable in the Western Hainesville. So the question is, do you have the 1100 penetrations for that 90 miles? Do you have the seismic? Do you have the balance sheet and the partners in order to de-risk this? Unlike, it didn't happen in the core, there was recklessness when gas hit $68. We've not been reckless in the Western Hainesville. And we have exemplary partners. And we didn't have, back then, we didn't have LNG and demand for natural gas to power the turbines. That is the game changer. That 30, 40, 50 Bs a day that they've spent trillions of dollars investing in takeaway infrastructure, we didn't have that back then. We have it today.

Got it. That's all super helpful, Collar, so appreciate that, team. And then maybe for my follow-up, just maybe following up on the earlier kind of gas marketing discussion, you know, with the SOCAR relationship obviously gives that access to the international LNG markets. Just kind of how meaningful could you see that exposure become relative to kind of the current domestic marketing portfolio?

Well, obviously today, you know, there's a significant premium to those markets compared to our domestic markets. So, you know, there's a very wide, you know, huge margin there. And so you don't know what the future looks like if those are going to more align with each other. But I think having that optionality, you know, with a strong partner and, you know. We'll be a great asset to our overall marketing portfolio opportunities, and, you know, today we're putting in place several long-term arrangements where we're going to supply natural gas to power generators, and those create, you know, much higher margins for us because we're able to get those contracts done with much better prices. And I also have a very long-term great customer. So I think it's a balance of those two. Those are the two trends in our gas marketing to be able to sell more directly to power generators, including the Anderson County power generation hub that the federal government is putting in on our Western Hainesville footprint. In addition to other long-term power generation deals that we're going to supply directly to other power generators. So the combination of those two, you know, will be kind of a great add to our marketing, you know, portfolio.

And for LNG, you need, really, if you can have it, you really want location closer to the Gulf Coast, and that's just a transportation cost issue, but you want that, and we have it. You want an established production base, we have that. You want a balance sheet, because you can't do without a balance sheet, and you need decades upon decades of inventory. We have all that. So you've got to check those off, and most of them don't have that. And we have all that. And you need to bring a SOCAR in, we have everything plus a big plus sign on it. That's all very helpful.

Thanks, team.

Thank you. One moment. Our last question comes from the line of Tim Moore with Clear Street. Your line is now open.

Hey, guys. This is Paul on for Tim. Just want to go back to the balance sheet. It's great that you... Have SOCAR signs, and you're taking net debt down to around $1.5 billion once that closes. But I'm just curious how you're thinking about the dividend from there. You know, what leverage level would you want to see before bringing it back?

Yeah, let me think. Think about this question that you just asked. Now, think about this. I mean, this is like capturing what is at the end of the rainbow, which is a pot of silver, gold, whatever. Could be a big pot of natural gas if prices are high. Now, just think, this is the most reverberating question I've ever had lately, because we had three-plus times the leverage ratio coverage, and now we've got one-and-a-half, one-seven dividend. That tells you That you see that we've controlled this balance sheet properly, and you're just asking if we're going to continue to do that.

Yeah, and I think that's a great question.

Oh, it's great.

I think, though, I think that, you know, I think our target leverage is to be below one and a half times leverage. So, you know, we would have to look over the horizon, you know, do we have a gas price? A stronger gas price market than we have right now. Do we have the hedge position that secures that prices? Our number one priority, as we've said always, is to continue to advance the Western Haynesville and advance the relationships we have that we're building out, our midstream. Supporting the Anderson Power Hub, et cetera. So those are our top priorities. And if they're all met and there's a great gas price environment and our leverage can stay below our targets, then the dividend can come back. But we're not going to bring it back early. We're going to be very responsible to all our stakeholders because our majority of our stakeholders and partners are focused on the long-term future versus short-term return of capital.

I think you add this fifth rig and you get infill drilling and you get very comfortable repeatability, which is going to happen. And remember, you've got two Haynesville zones and you've got two Bossier zones. So it's not that we're trying to complete the same zone, that 90 miles. We've got maybe three or four different zones that we're completing, and I think as Dan has told you for the last hour, they're getting better and better and better at what they're doing, and you can see the top partners that we have now, and I do believe that the demand for natural gas is real because the investment has been spent, and I believe that we're in the sweet spot for that demand. So the future has never looked better for us, period.

Got it. That's very helpful. Thank you. For my follow-up, I'd just like to shift back to the power hub. In your 10K, you talked about initial capacity of around 2 gigawatts, and the Anderson County hub could go up to 5.2. I guess your supply is reaching close to a BCF a day by 2031. So, is two gigawatts, is that still the right way to think about, you know, that and how the volumes could start to grow from that point?

Well, the very first stage of operations that comes in is a one gigawatt power facility, and then the longer term, you know, longer term. The facilities they're building will be 5.2 gigawatts to 5.3, and so that is the plan, and that is what's being all designed. So it's just the staging. So, yeah, and then there's the possibility that they expand beyond that if they want to, but that is the initial plans that are in the engineering phase right now. A lot of money, a lot of all the equipment's been ordered, you know, so it's off and going. So, yeah, the first phase, you know, that will be, you know, sometime in 28 is when we'll start providing gas under that contract, and then we'll be constructing the facilities, and, you know, next year, especially on our midstream, we'll be constructing all the gas. Facilities for them that we'll need to hook up to the power generation facilities.

Yeah, you'll see first production early 28, and it'll strengthen toward the latter part of 28, and they own the acres, they're spending the money, like Roland said, and really the goal is to have the 5.2 gigawatt position to have that if that demand is there.

Got it. That's helpful. Thanks, guys.

Thank you. This does conclude the question and answer session. I would now like to turn it back to Jay Ellison for closing remarks.

Again, I know there were several competing companies out there, all great companies that you could have listened to. So we're always thankful if you listen to the full hour and five minutes of this. And I always want you to know that, you know, whether you're Socor or Sixth Street or Nextera or the Joneses, we as a management group, there's about 255 of us. We will always give you our very best, and we'll always be very honest with you, and we expect to always deliver. So, thank you.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect.