Comstock Resources, Inc.

Good day and thank you for standing by. Welcome to Q1 2026 Comstock Resources Incorporated 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 1 1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1 1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Thank you, everyone. Thank you for joining us. Welcome to the Comstock Resources first 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 First Quarter 2026 Results. I am Jay Allison, Chief Executive Officer of Comstock. Here 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 presentation and note that our discussions today will include forward-looking statements within the meeting 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. If everyone would please go to slide three. On slide three, we summarize the highlights of the first quarter. Lower production, partially driven by production impacts from significant winter weather in the first quarter drove the lower financial results in the quarter compared to the first quarter of 2025. Our natural gas and oil sales were $339 million. We generated 192 million of operating cash flow, or 66 cents per share. Adjusted EBITDAX for the quarter was $251 million, and we reported adjusted net income of $44 million, or 15 cents per share. During the quarter, we had very strong drilling results, which will drive production back up for the remainder of the year. Almost all the wells we turned to sales in the first quarter were very late in the quarter. Since our last update, we put six new Western Hainesville wells online with an average per well initial production rate of 29 million cubic feet per day. In our legacy Hainesville, we turned 10 wells to cells with an average lateral length of 12,312 feet and a per well initial production rate of 31 million cubic feet per day. Now the power generation hub. On March 19th, The United States Department of Commerce selected our Western Hainesville site to host a new 5.2 gigawatt natural gas fired power generation hub to be located in Anderson County, Texas as shown on slide four. We are very excited about this development and what it means to have a large commercial customer in our backyard. The project is part of Japan's $550 billion investment commitment in the United States as part of the U.S.-Japanese trade deal. The U.S. and Japan would own the projects, while NextEra Energy Resources will develop, build, and operate it. NextEra is actively developing the project, advancing site development, procurement, and permitting and commercial structuring as they work toward definitive agreements with the US and Japan. This project takes advantage of our abundant natural gas supply and a strong transmission infrastructure in the area. The Anderson County facility will have up to 5.2 gigawatt of natural gas fire generation capable of serving up to five gigawatt of large load demand. Comstock will provide the natural gas supply for the facility, which could reach almost 1 billion cubic feet per day by 2031. Roland will now provide some more details on the financial results we reported yesterday. Roland?

All right. Thanks, Jay. On slide five, we covered the first quarter financial results. Our production in the first quarter averaged 1.1 BCFE per day. Oil and gas sales after hedging in the quarter were $339 million. reflecting the lower production level we had in the quarter. EBITDAX came in at $251 million, and we generated $192 million of cash flow during the first quarter. We reported a $107 million profit for the quarter, or 38 cents per share, but included in that number was a pre-tax $83 million mark-to-market unrealized gain related to our hedge book. So excluding the mark-to-market gain, Expiration expense which is related to seismic that we're shooting in our western Hainesville play and other non-recurring items And the related income tax effect of those items we reported adjusted net income of 44 million dollars or 15 cents per diluted share for the quarter On slide six we break down our natural gas price realizations in the quarter The quarterly weighted average NYMEX settlement price averaged $4.96 in the first quarter, and the weighted average Henry Heb spot price was at $4.90. Twenty-six percent of our gas was sold in the spot market, so the appropriate NYMEX reference price would have been $4.94 for our production. Our realized gas price during the quarter averaged $4.27, reflecting a 69-cent basis differential. compared to the NYMEX settlement price at a 67-cent differential compared to the reference price. Significant disconnects existed during the quarter between the regional hub prices and NYMEX kind of drove the higher differentials in the quarter. We also had to purchase higher-priced gas to make up for shut-in production during the winter storm event. In the quarter, we were also at 72% hedge, which reduced our realized price down to $3.45. We did improve the overall price realizations by $0.05 to $3.50 with our third-party gas sales during the quarter. In slide seven, we detail our operating costs per MCFE and our EBITDAX margin. Per unit costs were negatively impacted by the lower production level in the quarter as much of our field costs are fixed. Our operating costs per MCFE averaged $0.93 in the quarter up 16 cents from the fourth quarter rate. Both lifting costs in G&A were up four cents, attributable to the lower production level. Production ad valorem taxes increased three cents due to the higher gas prices in the quarter. And our gathering costs were up five cents, mainly due to some prior period adjustments we recognized. Overall, our EBITDAX margin in the quarter was 73%. On slide eight, we recapped the spending on our drilling and other development activity in the quarter. We spent a total of $343 million on our drilling program. We drilled 11 or 9.3 horizontal Hainesville wells and six or six net Bossier wells for a total of 17 wells in the quarter or 15.3 net wells. We turned 13 wells to sales or 11.7 net wells, which had an overall average per well IP rate of $31 million per day. Slide down, we summarize our capitalization at the end of the first quarter. We ended the quarter with $350 million of borrowings outstanding at our upstream credit facility. Our upstream borrowing base is $2 billion, and the electric commitment under our facility is $1.5 billion. In March, we entered into a new $150 million midstream credit facility for Pinnacle Gas Services. At the end of March, the midstream credit facility had $47 million outstanding. Our last 12 months ratio was 2.9 times. At the end of the first quarter, we had almost $1.3 billion in liquidity. I'll now turn it over to Dan to discuss our operations in the quarter. Okay.

Thanks, Roland. Over on slide 10, this is just our updated overview of our acreage footprint in the Hainesville and Bossier Shales across East Texas and North Louisiana. We now have 1,074,868 gross acres and 806,980 net acres that are prospective for commercial development of the Hainesville and Bossier Shales. On the left is our western Hainesville footprint, which we have now grown to over 540,000 net acres. And on the right is our 266,570 net acres that's in our legacy Hainesville area. We currently have 36 wells producing on our western Hainesville acreage, which is relatively undeveloped compared to the legacy Hainesville area. And of course, with the higher pay thicknesses and the very high pressures we incurred in the western Hainesville versus the legacy core, we expect the western Hainesville will yield significantly more resource potential per section than our legacy Hainesville. On slide 11 is our current drilling inventory in our Legacy Hainesville area at the end of the first quarter. Our operating inventory in the Legacy Hainesville now consists of 955 gross locations, 740 net locations, which equates to average working interest of 78%. On our non-operated inventory in the Legacy Hainesville, we have 819 gross locations, 98 net locations, which is a 12% average working interest. Our drilling inventory, we split into four buckets. We have our short laterals less than 5,000 feet. We have our medium-length laterals that are from 5,000 to 8,500 feet. Our long laterals are between 8,500 and 10,000 feet, and our extra long laterals are everything over 10,000 feet. In our gross operated inventory, in the legacy Hainesville, we now have 30 short laterals, 141 medium laterals, 337 long laterals, and 447 extra long laterals. The gross operated inventory is pretty much split 52% in the Hainesville and 48% of our locations in the Bossier. Our legacy Hainesville inventory also includes 114 gross horsey locations with 53% of those being in the Hainesville and 47% in the Bossier. Over 80% of our gross operated inventory have laterals that are longer than 8,500 feet long. And as of today, our average lateral length in the Legacy Hainesville inventory has climbed up to 10,019 feet. So this inventory provides us with decades of future drilling locations based on our current activity levels. On slide 12, we show our estimated drilling inventory in the Western Hainesville. Our Western Hainesville inventory currently consists of 3,331 gross locations, 2,546 net locations, which equates to an average working interest of approximately 76%. The number of our net locations is estimated since much of our Western Hainesville acreage has not yet been unitized. Our Western Hainesville inventory is more weighted to the bozer formation with nearly two-thirds of the inventory in the bozer shell and one-third of the inventory is in the Hainesville shell. We also have our Western Hainesville inventory divided into the four separate groups by length with our short laterals less than 5,000, the medium laterals between 5 and 8,500 feet, the long laterals between 8,500 and 10,000 feet, and the extra long laterals over 10,000 feet. So in our Western Hainesville gross operated inventory, we don't have any short laterals today. We got 1,319 medium laterals. We have 646 long laterals and 1,366 extra long laterals. So 60% of our Western Hainesville gross operated inventory has the laterals greater than 8,500 feet. On slide 13, it's just a, Update to our new horseshoe development program. The horseshoe well design, of course, combines the two separate and adjacent shorter laterals into a longer single lateral, which results in a much more efficient use of our capital. On average, we realize 35% savings in our drilling costs when we drill a 10K horseshoe well compared to two 5,000-foot sectional lateral wells. Our drilling inventory in our legacy Hainesville area now includes the 114 horseshoe locations. The Camp Tech 29149 number two was turned to sales in the first quarter with a 41 million cubic feet per day IP rate. And we plan to drill a total of 16 horseshoe wells total in 2026. On slide 14, there's a chart outlining our average lateral lengths drilled that are based on when the wells have been drilled to total depth. The average lateral lengths are shown separately for the legacy Haynesville and for the western Haynesville areas. In the first quarter, we drilled 12 wells to total depth in our legacy Haynesville area, and these wells had an average lateral length of 10,872 feet. The individual laterals, ranged from 8,497 feet up to 15,772 feet. Our longest lateral drill to date on our legacy Hainesville acreage still stands at 17,409 feet. In the first quarter, we also drilled five wells to total depth in the western Hainesville, and these wells had an average lateral length of 10,356 feet. The individual lengths range from 9,400 feet up to 11,393 feet. Through the first quarter, our longest lateral drilled in the Western Hainesville stood at 12,763 feet. As of last month, we have since exceeded that length in the Western Hainesville with a new record lateral length of approximately 14,800 feet. The well, which is the Dolly Jones RP number 1H, reached total depth in mid-April, and we have it scheduled for completion later this summer. So to date, we have drilled 47 wells to total depth in the western Hainesville. That includes 21 wells with laterals over 10,000 feet, and seven of the wells had laterals over 12,000 feet. On slide 15, this outlines the 10 wells that we turned to sales on our legacy Hainesville acreage That's our last call. The average lateral length on these was 12,312 feet and the individual laterals range from the low end of 9,465 feet up to a high of 15,143 feet. The individual IP rates on these wells range from a low of 15 million a day up to a high of 41 million a day. and the average IP was 31 million today. And five of our nine rigs are drilling on the legacy Hainesville acreage. Slide 16, this one outlines the six wells that we have turned to cells on our western Hainesville acreage since the last call. So these six wells had an average lateral length of 10,874 feet. with an average initial production rate of 29 million cubic feet per day. And we have four of our nine rigs are currently drilling on our western Hainesville acreage. On slide 17, this highlights the average drilling days and our average footage drilled per day in the legacy Hainesville area. And this is for our benchmark long lateral wells that are greater than 8,500 feet long. In the first quarter, we drilled 12 of our benchmark long lateral wells to total depth in the legacy Hainesville area, and we averaged 26 days to TD. In the first quarter, we averaged 921 feet drilled per day in our legacy Hainesville acreage, which represents a 3% increase versus the fourth quarter of 2025. Four of the wells drilled in the first quarter were our horseshoe wells, which takes a few extra days compared to our normal straight levels. Slide 18, this highlights our drilling progress in the Western Hainesville. During the first quarter, we drilled five wells to total depth in the Western Hainesville. This now gives us a total of 44 wells that we have drilled to total depth through the end of the first quarter. We averaged 57 days for the five wells drilled to total depth during the first quarter. This is an increase of three days compared to the fourth quarter. You can see this is also reflected in the drilling speed of 478 feet per day during the first quarter, which is 4% lower than the fourth quarter. Aside from drilling issues we have, our quarter-to-quarter drilling performance in the Western Hainesville is mainly dictated by our vertical depth, our temperatures, and our lateral lengths, and this varies considerably across our acreage footprint. So where the wells are being drilled has a big impact on our drilling performance numbers quarter-to-quarter. Our fastest well drilled to date in the Western Hainesville still stands at 37 days, and it was drilled with a 12,045 foot lateral. On slide 19, this is a summary of our DMC cost through the first quarter for our benchmark long lateral wells that are located on our legacy hazel acreage position. These are laterals greater than 8,500 feet. These costs reflect all of our legacy Area wells with greater than 8,500 feet. The drilling costs are based on when the wells reach TD. And the completion costs are based on when the wells are turned to cells. During the first quarter, we drilled 12 of our benchmark long lateral wells to total depth. The first quarter drilling cost averaged $700 a foot. This is a 3% increase compared to the fourth quarter. The increase in the first quarter drilling cost is the result of a combination of factors, mainly being overall short average lateral length in the first quarter, had a higher number of horseshoe wells drilled, and we also had more wells drilled in our East Texas area, which does require additional casing stream that we used to isolate the localized overpressured SWD zones in that area. During the first quarter, we also turned eight of our benchmark long lateral wells to sales on our legacy Hainesville acreage. The first quarter completion cost came in at $652 a foot. This is a 9% decrease compared to the fourth quarter. This lower completion cost is due to a combination of using less horsepower and having a higher frack efficiency and with a slightly lower drill-out cost. We're currently running three full-time frac fleets. This is after we added our third frac fleet in January. We are adding a fourth frac fleet this month, and we're planning to maintain running four frac fleets through the end of the year. On the drilling side in the Legacy Hainesville area, we have continued field testing with our rotary steerable drilling BHAs, and we're really continuing to make good progress there. So as we accumulate more data and we make further refinements there, we do expect this rotary steerable technology is gonna play a larger role in our future drilling program to help drive more cost reductions. On slide 20, this is a summary of our D and C cost through the first quarter. This is for all our wells drilled in the Western Hainesville. During the first quarter, we drilled five wells to total depth in the Western Hainesville. This is with an average lateral length of 10,356 feet. Our first quarter drilling cost averaged $1,534 a foot. This represents a 3% increase compared to the fourth quarter. During the first quarter, we also turned five wells to sales in the Western Hainesville that had an average lateral length of 11,177 feet. Our first quarter completion cost averaged $1,537 a foot, which is basically unchanged compared to the fourth quarter. Again, also to reiterate what was mentioned earlier, our drilling and completion performance in the western Hainesville is greatly affected by where the wells are being drilled on the acreage, as there's much variability in the vertical depths and formation temps along with the lateral lengths. We're also implementing our new performance initiatives that we expect will lead to further time savings and cost reductions. We do have one of our existing Western Hainesville rigs being upgraded to a 10,000 PSI rating that's going to be available to us by late summer. With this upgrade, we will be able to increase our drilling speeds in both the vertical and horizontal hole sections, further reducing our cost. We also intend to test some new higher temp rated drilling motors later this year, which we expect will lead to faster drill times and some longer runs. Once we get more successful and consistent runs of the rotary steerable drilling system in our legacy Hainesville area, we will be looking to deploy this technology into our western Hainesville area. I also mentioned it earlier, but we also drilled our record longest lateral to date in the western Hainesville. with a 14,800 foot lateral, and the weld surpassed our initial performance expectations. The weld was drilled with a larger hole size in the lateral, which allowed us to use larger insulated drill pipe, which leads to lower downhole temperatures, more reliable motor performance from the downhole drilling assemblies and longer motor life. So we plan to implement this new well design in more of our future wells, which along with the other performance initiatives being undertaken are gonna lead to significantly lower, more predictable cost structure for our future wells. And I'll turn the call back over to Jay.

All right, Dan, thank you. Roland, thank you. If everyone would please turn to slide 21. You know, I know we are dealing in a 90-day capsule on this call. I understand that. But the Comstock story over the past five years has been defined by our quest to add substantial drilling opportunities in the western Hainesville, not just the last 90 days capsule. Over that period, we have leased or acquired drilling rights on $728 gross acres comprised of approximately 30,000 individual leases over that five-year period. Overall, our leases have favorable terms supporting our development program. And as a result of that program over five years, not the last 90 days, we now have 2,546 net locations identified on our acreage. We've been joined by three other companies now who are actively drilling and working in the Western Hainesville Basin. The Hainesville Shell is viewed, in our opinion, as the most important basin to supply natural gas to Gulf Coast LNG facilities and now to data centers being built in Texas and Louisiana. The arrival of the Western Hainesville is the game changer as the market looks into the future to where the needed natural gas will come from. They all ask that question. Now, our relationship with Nextera, which goes back to 2015, combined with our ideal locations and the drilling results that Dan has just talked about in the Western Hainesville it led to the March 19, 2026 announcement of what? That the U.S. Department of Commerce selected our western Hainesville site to host a new 5.2 gigawatt natural gas firepower generation hub to be located where? In Anderson County, Texas. So, our current goals for the company, they're five-fold, and the fifth one you'll really want to hear. Five-fold. Number one, enhance our legacy Hainesville drilling program, which we accomplished by adding 114 horseshoe wells to our near term drilling program, which Dan talked about. They're fantastic performing wells. Currently three of our five rigs deployed in our legacy Hainesville area are drilling horseshoe wells. Two, strive to continue to be the low cost operator The combination of having the lowest cost and an abundance of drilling inventory closest to the growing natural gas demand will drive the market value for Comstock. Third, obvious, continue to protect the balance sheet, which was greatly helped by the divestitures we made in 2025. And by our robust hedging program, as outlined on slide 22, as well as our strong financial liquidity of almost $1.3 billion. Four, support the build-out of our midstream company, Pinnacle Gas Services. The formation of Pinnacle Gas Service by us in 2023 to gather and treat our natural gas in the Western Hanes will not only support our drilling program, but also lead to power generation hub opportunities. By controlling our midstream, we'll be able to keep our producing costs low and capture the future value by owning the infrastructure. PGS is now in a position to have its separate credit facility, and we believe we're nearing the end of a very, very strong process of finding an equity partner to allow us to continue to grow our midstream footprint and to take advantage of future opportunities to connect the Western Hainesville to premium markets. And finally, number five, which is what much of this conversation has been on, optimize the drilling and completion of our wells in the Western Hainesville. Of the 44 wells we have drilled through the first quarter, many have different vertical designs, and they were drilled to various depths with laterals of various lengths, which were drilled and completed with different methods and tools, as Dan has gone on and on about. We've also produced the wells by employing different drawdown levels. The well performance has varied, which should be expected in a new shelf life. That is the good news, as we are very encouraged that we are cracking the code on the best way to drill the wells and complete the wells to unlock what? Tremendous natural gas value and wealth in the future. Now, I want to thank you for your time today. There will be questions, and we'll turn it over to Ron if you want to call in and ask Ron questions. And I also want to make one more comment. You know, as an initial founder or developer in the legacy Angel in 2008, we learned from the mistakes that were made there that we did learn and we understand. And the thing that we didn't want to do in our 700 plus thousand acres in the Western Angel, which might have unprecedented wealth because it has been a wealthy basin 20, 30 years ago, is to make the mistakes that were made in the legacy starting in 2008, 9, 10. That's four million acres in the legacy. We have about 800,000 acres that we think are in the Western Angle. The mistakes that were made were drilling too fast because leases were expiring and you destroyed value. The rocks are established. They cannot move. What we have to do as a company is we have to make those rocks valuable. And the way we do that, and I understand cash burn and slow pace of resource delineation is a little taxing. I get that. But that is what we're doing to create the value that we already possess. So now with that, I'll turn it over to ask questions. All right.

Thank you. At this time, we will conduct the question and answer session. Please limit to one question and one follow-up. To ask a question, you will need to press star 1 1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1 1 again. Please stand by while we compile the Q&A roster. Our first question comes from the line of Carlos Escalante from Wolf Research. Carlos, your line is now open.

Hey, good morning, guys. Thank you for having us on. I appreciate the- Hey, Carlos.

Carlos?

How are you, Jay?

Thank you for headlining Cash Burn and Slow Pace of Resource Delineation Risk in Vestor Patients. I love that headline. That's why I brought it up in my narrative because I think that's exactly right. That is not a negative. It's a positive, but it's not a positive for everybody. So I just want you to know that, okay? Thank you for being honest and coming up with that headline. It helped me.

No, sure, and I appreciate you saying that and giving an overview on how you feel about the long-term value proposition. So why don't we start there? If you don't mind, maybe you can expand on your initial thoughts. But you're dealing with a tough gas tape, as are all your other peers, that on your current plan, as you mentioned, may extend a period of that cash burn. So how patient do you expect investors to be, acknowledging that there's a long-term value proposition, but that you still have to get through X amount of quarters where your production and your capital at times hasn't been in line with or aligned with what you've stated the quarter prior. If you can frame that for us, that'd be tremendously helpful.

Well, Carlos, I think, number one, and this is hard, you know, it's like going into the first day of advanced math and not understanding anything and barely remembering your teacher's name when you walk out because it's so confusing. But if you look at our business plan, yes, we did miss production in the quarter by, you know, 10, 12, 13%, whatever the number is, and our cap tax was higher. Well, if you have our business plan, which is, no is a big word, but it's no M&A. If you throw M&A in here, you issue equity, typically, You add production and you add inventory and you kind of stir up the pot every quarter, every year. We have not had M&A. So if you don't have M&A, the only way you can increase production, which it'll be a time lapse, you know, it may be 90 days, 120 days, but there'll be a lapse because if you're trying to protect your balance sheet last year and you lay down one, two, three, four rigs, you're going to lose that production a year later. So what happens is it's a day of reckoning. We laid down the rigs. We didn't do M&A. We kept adding a couple, 2,000 or 3,000 acres every month to our western Hainesville, and most of that is the best of the best acreage, and we kept spending that money. Now, in order to turn the cycle, you know, we did sell $445 million of assets that in our business plan were not important to us in the next 15 years. But when you do that, then you pay down that debt. And then what happens? Well, you're going to have to lever up a little bit. And we did say that we would outspend maybe $400 million, $450, whatever. That depends on the price of natural gas. What you see in this quarter is production was down. Yes, we missed it. Headline missed it. We'll put some positive headline out there. about the biggest data center in the US. I don't see that out there from some of you. But yes, we missed production and CapEx was up a little bit. But if you don't do M&A and you don't puke up equity all the time by issuing equity to everybody when you buy stuff, what happens is you have a quarter like we have. We protect every share of equity that everybody has. Production is down, but you know what? Now you see production up. Our production should be up at 13%, 14%, 15% for the second quarter. I think, Carlos, we have turned the corner. The corner is hard. You know that 90 days is hard because you have to actually spend money on those four new rigs. You have to have these horseshoe wells really work. You have to have Dan Harrison have the freedom to figure out the best way to drill and complete repeatable western Hainesville wells in both the Bossier and the Hainesville. And they can be 90 miles apart from each other, much less 20 miles from east and west direction. I think, Carlos, we've turned the corner. Now, maybe the second quarter, because we did add that fourth frack plate, you'll see a little bit of hesitance in there, but the well performance is good. The dollars that we took last year, we paid down our debt, and we're not doing anything radical to destroy value in the Western Hainesville, and like I said, The acres that we have, if you keep the four rigs busy that we have right now in our western handful, every acre that we own will be HVP'd. Every acre with those four rigs. And we don't even have to have those four. So the plan works. And, you know, in the past, Carlos, you'd say, well, you bought another 15,000, 20,000 acres. There's another $20,000, $30,000,000. You kind of hit us on the nose for the quarter. We don't plan on that. We don't see that out there. We don't see it. We see 1,000 or 2,000 acres every month. If we could get more, we'd get it. But it's not out there to be taken. So that's where I think we have crossed the bridge. And what we're talking about now is a bridge we've crossed. It's a hard bridge to cross. We've crossed it. Now let's look at where the future is going.

Sounds great to me, Jay. Appreciate the answer on that. My follow-up will be to you, Dan. Can you talk briefly about the Hutter Rodell IP? It looks like it underperformed the broad group and really the initial production rates of all the wells that you brought online, the average of all the wells you brought online in the basin. So I'm wondering if you can qualify for us. What was the root cause? Was it completion design, geology? and what specifically changes can you make on your next pad to prevent whatever was the case that drove this underperformance relative to your very solid and quality-like IP rates on the Western Hainesville?

Yep. Well, that's a good question, and I'll give you the really quick answer, and then I can give you a little bit more.

Give them the more.

You know, so we've drilled the – 36 wells that we've got producing, we've got seven of them that we've drilled. I call it uphill. The laterals go basically up instead of going down. Most of them go down quite a bit just due to the geology. The Hutto-Rodale is the furthest one by far as far as the TVD difference between the hill and the tow. It's nearly 1,400 feet from the hill to the tow. And so, you know, the main reason we didn't get a good IP on this well is this well made a lot of water during flow back, all during flow back. We were making really high water volumes. And the same with wells in the core, or no matter where we're at, if you're making a lot of water, it's just hard to get a high IP rate. So that's why we didn't get a good IP rate on the well. We are still kind of trying to, you know, triangulate zero in on really, you know, is it maybe more than just the geometry? It may be some geology involved. We did have our Brown True Heart BB well is, I say next to it, it's about a mile away, but they were both Hainesville targets. They both drilled uphill. The Brown True Heart didn't go as far uphill, but it also made a lot of water during flow back. We got a little bit better IP because the water wasn't quite as high. But those are, of the seven wells we've drilled uphill, those two wells, the Brown True Heart BB and the Hoda Rodell, are in our deeper pay. You know, those deeper TBDs, 17.5 to 18.5, 18.8 range. And both of those wells made a lot of water during flow back. Now, we have drilled five wells. up on our shallower acreage up in the 14 to 16, 16 to 17 TBD range that also went uphill. Not up 1,400 foot, but maybe up 600 or 700 foot from the hill to the tide. And those wells made a little more water during the initial part of flowback. By the time we released flowback, the water volumes were down. So that's why I say I don't know if I'm going to hang my hat 100% on the fact that they were drilled uphill for the high water volumes. I think it's I think it contributes to higher water volumes. I don't know if it's the sole reason for the high water volumes. We are fracking another well right next to those as we speak, the Jones number one. Not to be confused with the Dolly Jones number one that I mentioned as our long lateral we just drilled. This is another Jones number one, but it's right there in line with those other two wells, and so it is a bozier. as opposed to these being two Hainesvilles and so we're just gonna have to see how that well responds to see if we can kind of draw a conclusion that it is the geometry or if it's maybe just the Hainesville versus the Bossier. A little bit of geology in that answer too. But the short answer is, when you make a lot of water during flow back, it's hard to get IPs and we've probably had, out of the 36, we've had three wells, I would say, out of those 36 that we made really high water volumes during flow back that you know greatly affected the ip rates and that's our practical and that's a load water that's not formation water that's correct and this is across you know uh i mean look we're drilling from from one end to the other of the wells that we've tested so far i mean we're looking at like 50 to 60 miles that's that's like going from east texas all the way down to the deep and accurate default zone in louisiana that is a That is a huge distance, and there's a lot of variability in what these wells are going to make and perform and how much water they're going to make. That's part of it. I'd say the other kind of comparing the Western Hainesville to the core, the core, everything in the core, we don't really have a lot of wells that go TBD-wise downhill or uphill. They're all pretty much horizontally, like maybe from you know, 85 to 95 degrees, or maybe even a little flatter than that. In the Western Hainesville, it's different. You know, we got wells, whether, you know, we're drilling the whole acreage is the reason we kind of drill some of these wells uphill. Two well pad, one goes south, it's going down dip, one goes north or northwest, that means it's going up dip. So, but we have a lot more dip. We got a lot more dip in the Western Hainesville that leads to these, you know, higher angled well bores.

Understood. I'll turn it back. Thank you, team. Great question. Thank you.

Thank you. Our next question comes from the line of Charles Mead from Johnson Rice. Charles, your line is now open.

Good morning, Jay, Dan, Roland, Ron, and all the other Comstock people on the call. Good morning. Jay, forgive me if this is kind of a basic question, but I wonder if you could just give us the whole picture from your point of view on this Texas power generation hub. You've made a bunch of announcements about it, but from my point of view, it looks like you're the surface owner for where this site is going to be, at least I think that seems to be the case. You're going to supply gas to the power gen facility, but I guess that's not finalized yet. So maybe you could just give us an outline for what roles Comstock is playing there and how close you are to finalizing commercial terms for gas sales.

Well, I think so. That's that's a great question. And you know, I love your headlines too. You know, we slightly missed production, blah, blah, blah. That's good headline. I wish you'd put in what we're doing with NextEra, but you asked the question. I love that. If you look at all the dancing on the floor about, you know, AI, hyperscalers, all the things that have happened and all the things that are not funded. You can, that's background noise to us. What has happened here is if you have a hyperscaler in your office, you know, most of them will say, I really like Texas. It's a state that has a lot of natural gas and we need it to power the generation that the next tears of the world see. They like it. But you have to have a location that works, and so if you can come out, and like we've done with Western Anvil, and you're in a really great geographic location, there's a lot of people. You do own a big footprint, so the sky's the limit, as they say. What happens is, next year we'll say, okay, the federal government comes in with the agreement with the Japanese, and the Japanese will say, you know, we've committed this $550 billion, The federal government then will choose Nextera, and Nextera will choose where their basin might be. It goes back to that 2015 relationship we've had with Nextera, and they said, you know, we've done a lot of business in the past. We love the Western Ames. We've been out there. This is where we'd like to have the data center. So what happens is we don't own the surface All we do as far as dollars spent, Charles, is we provide the gas. In other words, obligations to build and stuff like that, we don't have that. What we have is we provide them the gigawatt, the five gigawatts, the billion, whatever it is. It may grow a lot higher than that to provide the data for the turbines. So it is a really great event because It's at the United States government level. It's then at an exteriors level, and it's our gas. We're a natural gas company. So whatever the big package is of the Christmas tree for the benefits, which would be the profits, whatever they are, you just wait and open those up when everybody else has discussed what the terms will be and when you have your first power that's needed. But it is unimaginable that that we would be the one that would have the acreage that we captured to have the upside and the mid-stream. You have to have the mid-stream to provide that gas to provide, you know, what NextEra sees as a huge role for U.S. shale gas to power AI hyperscalers and data centers.

Got it. Thank you, Jay, for that overview. And then if I could actually ask a follow-up about the Western Haines sale. I really like these, these maps. I'm looking at page 16 where you give us the red dots on where these, uh, where your, your recent well results are. And I'm wondering if you could talk about the wells that are, uh, it looks like you had two wells that are, that are further up dip. And, uh, if you could talk about, um, about what you're seeing as far as how the, how the play changes, I'm guessing you have probably lower DNC cause it's less vertical depth, but, uh, but what you're seeing with the productivity on those wells as you move up there also.

Yeah, and I'm going to let Dan do that. I want to put a little asterisk on that, Charles. If you were to look at where we drilled in, you know, the Circle M in 2022, we produced it eight months in 2022, and then we started drilling in 2345. If you were to go where we have drilled several wells and you were to infill drill wells, When you could drill dozens and dozens and dozens and dozens, not hundreds of wells, and infill drill them, and you've got gathering near there on that pad site, you want to get costs down, you could do that. That is not part of our business plan either. That's why we went 40, 50 miles to the north to drill that Elijah one, because we had seismic, we had well control. You know we have, I think, 1,000, maybe 100 penetrations in all this footprint we have. And then we have the seismic. And now we've got cores. But before we had the core, you know, we'd go north because the plan was, and that goes back to Carlos, you know, you're going to have enough patients to delineate this. Well, you know, in one year you jump 40, 50 miles to the north, that's pretty quick delineation. They never did that in a core, not with any control. So our goal is to keep those rigs busy. And 99% of the time is to continue to hold acreage not infill drill around existing known repeatable locations that's a different business plan uh so now with that i want dan to answer that question yeah so i'll definitely just just reiterate the last thing he said there we are all of these all the locations we're drilling for the whole acreage i'd say

More than nine out of every ten is the whole acreage. And so those two, what those two dots are, Charles, that's actually two pads right there. So those two dots, if you're looking at that slide, that represents those two bumpers and two pollard wells at that location. And so we drilled on each pad. We had a well to the north and a well to the south. So one of the bumpers goes north. The NMH goes north, the BHGJ goes to the south, the Pollard TFG goes to the north, and the Pollard MBK goes to the south, you know, holding acreage. So those we started after looking at just, you know, what we do constantly, right, looking at well performance. We knew we probably were under-stimulating these wells. We need to pump bigger fracts. All four of those wells were pumped with bigger fracks up in that area than what we had pumped on the offset wells in that little area there that you're looking at. All four wells look really good. Two of those wells that went uphill was kind of two of the wells when I was answering Carlos' question earlier. We may see a little water the first couple of days on flow back, but really we didn't see any Big water volumes, by the time we're off low back and getting the well IP'd, they had pretty well dried up. So they only go uphill there about 600 or 700 feet from the hill to the toe. But they look really good. All four of those, we're really happy with them. That's probably 14 to 16.5 TBD range on those wells. Maybe the toe of the down dip wells may be closer to 17. But it is less pressure. They are cheaper to D and C. As a matter of fact, the record fastest, cheapest well today, which we just referenced as the record well that we TD'd in 37 days, was the direct offset to one of those pads. The Jennings pad, the Jennings-Lore, the Jennings FSRA. Jennings FSRA was right next to those wells. It was up-dip. We drilled TD at 37 days. We just had some great motor runs. So, you know, the EUR will be a little bit less just because you got less pressure and it's at a shallower depth. But, you know, we offset that with the faster DNC calls, faster drill and lower DNC calls.

That is great color, Dan. Thank you.

Great question. Thank you.

Our next question comes from the line of Derek Whitfield from Texas Capital. Derek, your line is now open.

Good morning, all, and thanks for your time. Morning, Derek. Jay, I appreciate your kind of bigger picture comments to open up the call. Maybe, Dan, I wanted to start with you. Is As you think about really some of the new concepts that you guys are testing, you highlighted this quarter the use of rotary steerable drilling systems and your first well with a big hole design. Could you perhaps speak to what these developments could mean in cost if they're successful as you think they will be?

Well, I'll talk. So rotary steerable. That's going to probably be deployed later in the Western Hainesville. We've had several runs so far in the legacy Hainesville. The system that we're using, we probably started running it maybe five or six months ago, I want to say. We're still making some tweaks. It's a learning process. I'll tell you, we've had some really fantastic runs to date. that rotary steerable too we've also had some that didn't make it very far just due to just some issues in the tool that they're you know getting tweaked but uh you know i'll say when they rolled out the same technology in the permian basin a few years ago i mean it took them 18 months or two years to get this tool refined to where it was humming so it's not an overnight thing it's uh you know all of these tools that work well in other basins the last basin they come to to get you know to is the Hainesville just due to the depths and the temperatures. And so that's kind of where we're at. We are super excited about, you know, these, the fantastic runs that we've had, but we need to get more of those under our belt and we need to get them done with more consistency. And then we will roll it out into the Western Hainesville because that's just a much, you know, more difficult environment with temperatures. But, uh, a lot of, uh, you know, we, we've run several of them on these horseshoe whales. Just, uh, know super pleased with it so a lot of running room there i think you know the 10k rig that's coming at the end of the summer we're super excited that's just gonna give us we're gonna be able to pump faster uh just more horsepower on bottom better rop knock some days off so pretty excited about that and uh you know maybe the most exciting thing is this last well we drilled that was uh We drilled the big hole laterals, eight and a half inch bit size instead of a six and three quarter. But we had some expectations for it when we set out to drill it. We needed a project that gave us the ability to drill a long lateral, right? Because you've got to spend a lot more money before you ever get to the lateral because all your casing strings up top have to be a whole size bigger. The casing has to be one size bigger, right? before you ever get to the lateral, you're in the red basically, right? You're a little more expensive. So you have to have kind of a longer lateral that you think you're gonna drill faster to make up that to break even or come out even cheaper. And what we did was we came out even cheaper than what we expected. Our drill cost on that well was Basically lower than any of these bars you see on slide 20, you know, on our cost per foot. You know, slightly lower. So we feel also it's a little bit more predictable than what we've done in the swim hole. And, you know, we can slide and turn a little bit more effectively than we can in the swim hole. So there's some intangible benefits from that also that we think are going to help us. We just need to drill more of them, right? I mean, obviously, you need to get the proofs in the pudding. We've only done one. Looks really good. We're going to make some changes, hopefully, up in the vertical, kind of working on that. We think we'll make that a little bit cheaper there, but We're super excited about it. I mean, we thought maybe we need to drill 14 or 15,000 to have a break even versus the slim hole laterals we've been drilling when really we don't need to drill. We maybe only need to drill 11 or 12,000 foot for it to be cost competitive with the slim holes.

And you know, Derek, going back to the question that Charles asked earlier, some of these are Bossier, some are Hainesville. So when Dan talks about a particular well, I mean, we may, 80 miles away, we may have another Hainesville, but it's not exactly the Hainesville that he's talking about today. In other words, they all are a little different, and that's why we saw a lot of value destroyed in the legacy Hainesville back in 08, 09, 10, 11. You know, not only were there too many rigs drilling it, they had leases that were expiring. So now you've got, and then you had gas prices, the natural gas prices collapsed. So we look at all of that, and I love the point that you said, the bigger picture concept, because it's like, you know, we're planting a bunch of these seeds around, and these trees are starting to grow up, but you can't do it too fast. Even we're in an unprecedented bull market opportunity, I think, headed our way for LNG and data centers. I think our timing is going to be perfect for that. Only because we're in the correct geographical location in America. That's the difference. But if you own the basin, and yeah, there's two or three other companies out there that they're drilling stuff, but they don't own what we own. So you have to treat it different. If it's valuable and precious, you have to treat it valuable and precious. And that's exactly what we're trying to tell everybody today. That may be the wrong type of candy in the candy store, and you don't like it. But that is what we are selling. And I will tell you, the board is 100% behind it. Management, the Jones family, almost every day, they're in it. They understand it. And we would like to go quicker, but you can't. You'll get in trouble if you go quicker. But I think it's kind of like what Carlos had asked, too. Well, I think we've turned that curve because it's production going down and capex going up that gives you indigestion. And I have it, too, and I know everybody does. But I think we've turned that curve on that. So production should go up. We should have really great growth in the rest of this year, particularly in the third and fourth quarter. And we did add that extra frac rig. I don't know. I just see big sunshine out there.

So, Derek, did I answer your question?

All good. And, Jay, I agree with you on NextEra. When you really think about that recent development and how meaningful and differentiated it is for you within the sector, just on the scale and the nearness of development, I agree that's a big development that probably is not getting enough headline or time this morning. I did want to get back to Dan, though, on another topic, because I think this is also important in evaluating the play. Clearly, the DNC optimization stuff you guys are working through now. But just, Dan, when you think about what you're seeing right now in restricted flow back testing to date, is that an optimization knob that you're likely to turn as you progress development in Western Hainesville?

Absolutely. I think we, I mean, I'll just sum it up. We need to be pumping bigger fracks, better stimulation. And with those bigger stimulations, the volume of rock that you're out there touching, you need to keep it all open. If you keep it all open, you're exposed to significant, significant reserves. And so to keep it open, you have to have that really conservative drawdown. And I'd say we're probably maybe even a slightly more conservative drawdown really this year going forward than where we were just in the last six months. If you, you know, you get the bigger EURs, you get the lot better PV10 values. And if you still can get them volumes within the first couple of years, you're really not going to affect your rate of return. I mean, it's going to be about the same number. So, you know, that's, that to me, that is the answer. Significant resource in the ground. I mean, you're talking, you know, just due to the thickness and the pressures in the big frays, you're, you're out there touching a lot of reserves and you have to keep those fracks open. What you created, you got to keep it open to extract that, you know, those volumes and that value. So the bigger fracks, the very conservative drawdown going forward.

Hey, Derek, you know, we put boots on the ground. If Dan and, you know, a couple of the other top tier people in the drilling group, Two weeks ago they went to Germany, boots on the ground at the Baker plant. In other words, look and see it, touch it, what do we do and how can we tweak it to make it better, quicker, faster? But we take them there. In other words, if they're offering to teach you and to show you what we need to be doing maybe, and they're going to spend their own money developing what we need, then we go there. So I think it's important, whether it's Carlos, Charles, Derek, everybody that asks these questions, we love them over here. We're giving you our best. And it comes out in a word. It comes out in emotion. It comes out in what we do for 38 years. We give you our best. And we don't tell a weird story. This is a story that's a hard story. It's the greatest story, though. And again, On the equity side, every share is precious. We create it like it's precious.

Perfect. Maybe just one more just for the benefit of investors. I know many are thinking about it, but just philosophically on guidance. When you guys provide guidance, should we think of that as a P50 with a little bit of risking, so call it P45, P55 range? I know you guys are giving your best on the guidance and what you think you can execute against, but just would love any color that you could share on that.

I mean, we give you our best guess based on what the expectations are from a drilling and completion timeframe, Derek.

I don't know what else to say about more than that.

I think it's, I'd say the Western Hinesville, you know, we've got the Legacy versus the Western Hinesville. The legacy's probably been a little bit more predictable today in Western Hainesville, but I think with the more conservative drawdown, the beer frags, the more conservative drawdown, it's going to make guiding the Western Hainesville volumes more predictable, I think, than looking forward than looking backwards.

Yeah, and pure volume in the Western Hainesville will take out some of the lumpiness.

All makes sense. Thanks for your time, guys.

Great questions. Thank you, Derek. Thank you.

Our next question comes from the line of Leo Mariani from Roth. Leo, your line is now open.

Hey, guys. I wanted to kind of turn to the funding side a bit here. So obviously you guys secured the Pinnacle credit facility here, which you mentioned briefly. It looks like that you guys are consolidating that. It is on your balance sheet. Wanted to get a sense, is that debt recourse to Comstock there? And then just additionally, you've spoken about other financing needed at the Pinnacle level. I know you're attempting to take Quantum out, which I guess supposedly pays them. So is there additional equity as well that you're looking to raise at the Pinnacle level, or do you think you're going to be good with this credit facility for the near future?

That's a good question, Leo. We are running a process to raise equity in Pinnacle. and hopefully can report on that at the next conference call. That's going very well. It's a great opportunity to bring in more of a common equity partner versus the preferred equity partner we have with Quantum. So we have that opportunity to not only redeem the preferred units, which have a big distribution on them, and bring in a common equity partner, Partner, which will, you know, and I think we'll raise a little extra equity to help pay down some of the, you know, add a little equity to Pinnacle along with the credit facility. So, you know, it is at a, the way the midstream is being built out, it's obviously you have to build everything before, you know, and be ready for the wells and do everything way ahead of the volumes. And so, you know, we're, we have done that and spent a lot of, you know, capital heavy up front. With our second train being put in, it'll be operational this summer. Once that's done, we'll have a lot of treating capacity. We'll really just be spending money on going out and hooking up the wells as we go forward. The capex will be a little bit lower as you go forward in Pinnacle. Then the volumes, I'll show up for that off in the future. That's the nature of the midstream operator. But I think we're hoping that the process, like I said, Jay said it's going well. We'll have that resolved soon. And we think that should maybe even highlight the value that the midstream company will have. I think it will start to have a lot more visibility of the number. And, yes, it is all consolidated now. as we have the majority interest and have full control of the entity, and it is in a separate credit structure. So the upstream has its complete structure that includes the bonds and the credit facility, and the midstream has just the credit facility and two separate credit structures, and there's no recourse between the two with each other.

All right. I think that the quantum was a partner for a while. Perfect, perfect, perfect. And then the way their funds work is that, you know, if we can pay them off, which we will, and get a longer-term equity owner, years and years and years of investments to grow the gathering and we control it, that's the next step. And it's been pent-up demand, as I've told you, and we should see good results in that in the near future.

Okay, that was very thorough, guys. I really appreciate all that additional color. Just wanted to jump back to the, you know, Anderson, you know, county five gigawatt, you know, facility here. Could you probably at least maybe a little bit more color in terms of where we are these days on the commercial negotiations for gas supply? Is this still a bit of a competitive process? Are they talking to kind of multiple parties or have they just kind of honed in on Comstock at this point in time and Can you give us a sense of like, maybe I don't know where the talks are these days, but is there any kind of high-level indication of how that gas could be priced?

No, we don't make any comments on that, Leo. That's a much bigger question than you're asking, so we don't comment on that.

Yeah, I would only add, though, that you can see this in Nextera's comments, you know, that our agreement is that we are the gas supplier, so it's not, but we are, that's All the negotiations involved a lot of parties, and so that's what's ongoing. So we think that's a process that Nextera is controlling. But, you know, they were clear in their earnings call, you know, that the gas is coming from Comstock. So that's not something to debate.

Yep. Great question. Nobody has the answer. It's disclosable now.

Understood. Thank you, guys.

Thank you. Our next question comes from the line of Jacob Roberts from TPH and Company. Jacob, your line is now open. Good morning.

Good morning. Maybe starting on Q1 realizations, I understand there's a lot of moving pieces and maybe a bit of a one-time event, but just curious if you could speak to any key takeaways from the quarter in terms of how you think about marketing in the future.

Yeah, I think in the Q1, you know, it was a very volatile quarter for gas, you know, both spot prices and the first of the month prices had huge variability. You had very unusual February where the NYMEX price got set very high at the last minute and then spot prices were, you know, almost 50% of that, you know, almost immediately, you know, when the month even opened up. So you had a very strange quarter. And then we're also kind of impacted by, you know, some production that had to be shut in, you know, during the storm event. And then also the delays that got created and with a lot of wells that were going to come on, you know, several week delays in wells that didn't get to come on because you couldn't, you know, we had to shut down the frack equipment, couldn't move drilling rigs, et cetera, you know, because of the bad road conditions, especially in Louisiana. So just a lot of noise there. We think that was especially in the Hainesville, but we don't think that's a real something to really take forward and you get back to a more normal gas market. We tend to try to have about 75% of our gas nominated to sell on a first-of-month basis and 25 in the spot to allow us to adjust if there's a well down or just to do wells coming on and that's kind of our philosophy you know and that kind of matches you know we have about 55 plus percent of our gas hedge so we want to have that that those hedges are really tied to that first of the month so you don't want to tie those to the to the spot prices so I think our philosophy would be similar I think you know We would have been maybe better served in the first quarter if we just had more production available in the spot market. We probably could have realized a lot better price. I think having not much gas to make up the first of the month commitments probably hurt us some on the realization during the time you had high gas prices.

I appreciate the response. Jay, your comments are well taken in terms of trying to develop this asset the right way. And I'm going to circle back to the Western Hainesville. Our investor conversations remain focused on the state data coming out of the basin. And what we're seeing is a step down in cumulative production over six or 12 months in the 24 and 2025 vintages. And I think that's mirrored to some extent by the IPs you guys present today. um in these decks so within the context of the optimization and trying to get this right can you walk us through internally what you're seeing on on the most recent eurs and how those compare to the earliest wells that might have been in that three to three and a half bcfe per 1000 foot range well i'd say you know the earliest wells that we drilled in the play were the first six or so were in robertson county

And what we've seen, if we just basically were to shut down today and just measure everything on the 36 wells that we got producing, the best wells have been the wells over in Robertson County, if you just compare them to the ones in Leon. We just have one producing today way up on the northeast end, 50, 60 miles away, the Olajuwon. And it's a really good well up there also, but by and large, on average, The best wells to date have been those in Robertson County. We've got good, thick-paid rock qualities there. And I'm going to go back and say 15 years ago, somewhere in there, and Canada came out here and drilled the very first two shell wells, and they drilled them in that area. And we pulled those wells harder in the beginning. So... You know, those are the early wells. When you look at 22 and 23 are those wells. And then as you get into 24, 25, you're in the stuff that moved over into Leon. I mean, still good wells. It's just, you know, we're going to have that variability across the footprint.

I appreciate the time, guys. Thank you. Thank you.

Our next question comes from the line of Paul Diamond from Citi. Paul, your line is now open.

Thank you. Good morning, all. Thanks for taking the call. I just want to touch base on the development of Western Haynesville. Can you remind us of the kind of the timeframe and the cadence towards full unitization there? Is it still kind of that late 27 period or do we see any movement?

In terms of HBP? Yeah, in terms of what everything's HPP'd.

Yeah, I think you keep, again, we add acreage every month, but if you look at the model we have today, you keep the four rigs busy this year, next year, part of the, even maybe by the middle of 28, you've got it all HPP'd. That's a pretty good guess on that. I mean, I think the real question is you have to drill wells you don't want to drill in the time frame. You don't want to drill them. The answer is no. You know, we had two rigs several years ago. We're going to add a third. We didn't add the third because gas prices were low. We came in later last year and added four, and that didn't impact, you know, holding the acreage that we've leased. So I think the real question is, With the rigs that we have now, or even if you reduce them by rig, I'll just take the negative. Could we hold all the acreage that we've now leased? The answer is yes.

Got it. Understood.

And then just speaking on that kind of a downside here, can you talk a bit about the optionality and your operational cadence in coming quarters? is what would cause a shift in the current strategy, you know, five rigs in western Hainesville, four rigs in the core, and those four fleets across the acreage?

So what's the question now?

What would change the current strategy?

Yeah, would we reduce rigs or, you know, add rigs? I think that ultimately we're looking to see the best time to move one of the legacy Hainesville rigs to the western Hainesville. So it's still, Decided on that that's probably but I think that the current cadence is probably Is the plan that we could be running yet? Consistently even maybe in the next year But we'll look for the opportunity to add there Add another move one of the rigs to the Western Hainesville.

It's kind of the biggest decision we have to make I think yeah I think Paul's a recount is nine member five and a core for the Western angel that recount is that we see it today is static and I mean, like Roland said, I think all the rigs we have, all nine of them except one, Dan, you can correct me, is capable of moving over to the Western Angle. That's correct. So if we needed to, you know, we could move a rig from the core over to the Western Angle. But I think the nine is good. I think that accomplishes every goal we have in 26 and 27. It meets, you know, any contracts that we had to provide gas. We have a takeaway for that. We have the rigs deployed for that. We have the frack crews committed for that. So I think that works good.

Yeah. And the only other thing I'll add to that is just, you know, as far as the cadence, I think four is good. And we also have, you know, all of these, still these things that we're learning. You know, we got the 10K rig upgrade coming. We got some high temp motors we're going to be testing at the end of the year. We've got this big hole that looks really good that we're, We're trying to get some more of those in the mix. So, you know, that cadence with rigs is, you know, just we want to learn some more of these things before we add rigs to the Western High School.

Got it. Understood. Appreciate the time. I'll leave it there. Thank you, Paul.

Our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Noel, your line is now open.

Hi, good morning. Hey, how you doing? Just trying to sort of triangulate some of what you were talking about. You need to be able to demonstrate that you can keep the formation open after the threat. So if I'm understanding right, Is part of that just your protocol for chokes, or is also, for instance, propent part of that? And is there going to be a need for considerable exploration on that front, or I'm sorry, experimentation on that front going forward?

You know, I think most of it is the drawdown. All fracture systems naturally close over time as you produce them. large cumulative amount of gas. That's just the natural progression. You know, you see a little bit more of it in the deeper formations versus something that's really shallow. But, you know, you can mitigate that larger volumes of sand, higher concentrations of sand, you know, the viscosity of the fluid you're fracking with as far as creating a little bit more width of the fracture when you put that sand in there. All of those things contribute, but I think the greater lever is how fast you draw them down. Like we stated, we want to get exposed to a large volume of rock because the resource is so huge, and then we want to be very conservative on how fast we pull it back out.

Great. Thanks. You were mentioning Robertson County as the home of some of the early wells, and And I know this is sort of like a big sort of decision point that I imagine it's way too early for you to really have the data for. But, I mean, do you have some sense of how far you might be from sort of designating a chord as a play and maybe with an eye towards, you know, beginning – or heading towards sort of like a manufacturing mode on a more contained part of the play?

I mean, it's all been very productive. I would hesitate to say that we know enough to say where the core of the play is. We still got a lot of acreage left to drill. We've only got one well that's producing up on the northeast end up there, the Olajuwon. We got several more there.

Sure.

That's where we drilled the Dolly Jones at 14,800-foot lateral that we're going to complete later this summer. So we need to get a lot more of those in the door. But, I mean, so far, let me just say, there's not any of this sacred so far that we don't like. You know, there's just a little bit of variability, but it all looks good.

Yeah, and we think that, you know, more of the results – The wells have been drilled differently, different landing zones. They've been drawn down differently, and I think the very early wells in Roberson County were drawn down pretty hard, so they did produce a lot of gas up front. We think that the more restrictive choke in Leon and other counties are going to still yield very attractive EURs on the nature of 3.5 Bs per 1,000. But, you know, we can't pull them as hard. So I think the data just looks different. But, you know, we still see very strong recoveries from the wells. It's really, you've seen the other operators have had some wells that have, you know, obviously going to exceed four and five BCF per thousand. So there's a lot of, and a lot of it is how do you want, you know, if you want to pull gas out really quickly, you're going to get a lower EUR if you're going to manage the choke, you know, properly, you're going to get a higher EUR. So that's kind of the balance that we're learning. And I think the very early wells, we think we pulled them too hard. And some of them can handle it better. Some of them couldn't, you know. That's right. But I don't think that overall it really means that, you know, that's the only area that has those kind of EURs. I mean, I think we're going to get a great, we're going to get a very high, you know, And I think we probably, early wells probably under-stimulated them. We think, you know, looking at all the data that's, and so now the better frack design is, I think, is going to contribute to better recovery.

I'll tell you how prolific this is. We have over a thousand penetrations where we have seen what the molecules look like, what the Hainesville-Boger look like, and all of our You know, all of our footprint, the 740,000 gross acres, whatever. If you look at a competitor to the northeast, I mean, they have 75,000 net acres. They've drilled a well. They said, we like what we've seen. That is 80 miles away from where we drilled our first well. I mean, if I put you in a pair of tennis shoes, go 80 miles, it takes you two or three days to get there. That's how far away this is. That's how massive this play is. That's how thick some of this is. So that's why we say we're at the very beginning of this. We're not going to ruin the basin that we control like happened in the legacy back in 2008, 9, 10. Too many wells. They didn't know how to drill them and complete them. They couldn't go long enough laterals. They didn't know what kind of propping to use. They didn't have midstream. All of those things we have avoided in the basin that we call the Western Angle.

Great. Thanks for the perspective. This concludes the question and answer session.

I would now like to turn it back to Jay Allison for closing remarks.

First of all, you've been with us for an hour 20, an hour 30. So I mean, I hope that you can tell how compassionate we are about giving you the truth and about telling you where we are in this big play. I want to always thank you. for taking a look at the business plan. I always want to remind you that whether it's the Joneses or the board or the management, we are really of one mind and we try to do what is just and right for everybody. Whether it's a bondholder or an equity owner, it doesn't matter. We really try to stay strong and do our work. We do see that Comstock is a great story for LNG. It's a great story for power generation, the data center play, and it's a great story with the bounty of inventory that we have. And if you can check the boxes with the pinnacles that we have and the next years that we have and the banks that we have backing us, And then the growth with LNG, with Golden Pass and Chenier, Venture Global, et cetera, et cetera, we look to be teed up to have a big win on the scoreboard. So if you just stay with us and keep asking questions, it'll make us better, and we're thankful for that. So thanks for your time.

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