Comstock Resources, Inc. ($CRK)

Good day, and thank you for standing by. Welcome to Q1 2026 Comstock Resources, Incorporated earnings conference call. [Operator Instructions] 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. 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 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If everyone would please go to Slide 3. On Slide 3, 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 $0.66 per share. Adjusted EBITDAX for the quarter was $251 million, and we reported adjusted net income of $44 million or $0.15 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 6 new Western Haynesville wells online with an average per well initial production rate of 29 million cubic feet per day. In our legacy Haynesville, we turned 10 wells to sales 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 19, the United States Department of Commerce selected our Western Haynesville 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 4. 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, permitting and commercial structuring as they work toward definitive agreements with the U.S. 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-fired generation capable of serving up to 5 gigawatts 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 from the financial results we reported yesterday. Roland?

All right. Thanks, Jay. On Slide 5, we cover 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 $0.38 per share, but included in that number was a pretax $83 million mark-to-market unrealized gain related to our hedge book. So excluding the mark-to-market gain, exploration expense, which is related to seismic that we're shooting in our Western Haynesville play and other nonrecurring items and the related income tax effect of those items, we reported adjusted net income of $44 million or $0.15 per diluted share for the quarter. On Slide 6, 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 Hub spot price was at $4.90. 26% 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 $0.69 basis differential compared to the NYMEX settlement price and a $0.67 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 72% hedged, 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. On Slide 7, we detail our operating cost 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 cost per Mcfe averaged $0.93 in the quarter, up $0.16 from the fourth quarter rate. Both lifting costs and G&A were up $0.04, attributable to the lower production level. Production ad valorem taxes increased $0.03 due to the higher gas prices in the quarter. And our gathering costs were up $0.05, mainly due to some prior period adjustments that we recognized. Overall, our EBITDAX margin in the quarter was 73%. On Slide 8, we recap 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 Haynesville wells and 6 or 6 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 9, we summarize our capitalization at the end of the first quarter. We ended the quarter with $350 million of borrowings outstanding in our upstream credit facility. Our upstream borrowing base is $2 billion, and we -- and our elected 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 2.9x. At the end of the first quarter, we had almost $1.3 billion of 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 Haynesville 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 Haynesville and Bossier shales. On the left is our Western Haynesville 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 Haynesville area. We currently have 36 wells producing on our Western Haynesville acreage, which is relatively undeveloped compared to the legacy Haynesville area. And of course, with the higher pay thicknesses and the very high pressures we incur in the Western Haynesville versus the legacy core, we expect the Western Haynesville will yield significantly more resource potential per section than our legacy Haynesville. On Slide 11 is our current drilling inventory in our legacy Haynesville area at the end of the first quarter. Our operated inventory in the legacy Haynesville 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 Haynesville, we have 819 gross locations with 98 net locations, which is a 12% average working interest. Our drilling inventory, we split into 4 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 between 8,500 and 10,000 feet and our extra-long laterals are everything over 10,000 feet. Within our gross operated inventory in the legacy Haynesville, 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 Haynesville and 48% of our locations in the Bossier. Our legacy Haynesville inventory also includes 114 gross horseshoe locations with 53% of those being in the Haynesville 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 Haynesville 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 Haynesville. Our Western Haynesville inventory consists -- 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 Haynesville acreage has not yet been unitized. Our Western Haynesville inventory is more weighted to the Bossier formation with nearly 2/3 of the inventory in the Bossier shale and 1/3 of the inventory is in the Haynesville shale. And we also have our Western Haynesville inventory divided into the 4 separate groups by length, with our short laterals less than 5,000 and the medium laterals between 5,000 and 8,500 feet and the long laterals between 8,500 and 10,000 feet and the extra-long laterals over 10,000 feet. So in our Western Haynesville 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 Haynesville gross operated inventory has laterals greater than 8,500 feet. On Slide 13, just an update to our new horseshoe development program. The horseshoe well design, of course, combines the 2 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 cost when we drill a 10k horseshoe well compared to 2 5,000 foot sectional lateral wells. Our drilling inventory in our legacy Haynesville area now includes the 114 horseshoe locations. The Camptec 29-14-9#2 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 range from 8,497 feet up to 15,772 feet. Our longest lateral drilled to date on our legacy Haynesville acreage still stands at 17,409 feet. In the first quarter, we also drilled 5 wells to total depth in the Western Haynesville 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 Haynesville stood at 12,763 feet. As of last month, we have since exceeded that length in the Western Haynesville with a new record lateral length of approximately 14,800 feet. The well, which is the Dolly Jones RP #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 Haynesville. That includes 21 wells with laterals over 10,000 feet and 7 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 Haynesville acreage since 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 a day. And 5 of our 9 rigs are drilling on the legacy Haynesville acreage. Slide 16. This one outlines the 6 wells that we have turned to sales on our Western Haynesville acreage since the last call. So these 6 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 4 of our 9 rigs that are currently drilling on our Western Haynesville acreage. On Slide 17, this highlights the average drilling days and our average footage drilled per day in the legacy Haynesville 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 Haynesville area, and we averaged 26 days to TD. In the first quarter, we averaged 921 feet drilled per day in our legacy Haynesville 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 do take -- it takes a few extra days compared to our normal straight levels. Slide 18. This highlights our drilling progress in the Western Haynesville. During the first quarter, we drilled 5 wells to total depth in the Western Haynesville. 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 5 wells drilled to total depth during the first quarter. This is an increase of 3 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 Haynesville 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 Haynesville still stands at 37 days, and it was drilled with a 12,045-foot lateral. On Slide 19, this is a summary of our D&C cost through the first quarter for our benchmark long lateral wells that are located on our legacy Haynesville 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 sales. 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, we 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 strings that we use to isolate the localized overpressured SWD zones in that area. During the first quarter, we also turned 8 of our benchmark long lateral wells to sales on our legacy Haynesville 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 higher frac efficiency and with a slightly lower drill-out cost. We're currently running 3 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 4 frac fleets through the end of the year. On the drilling side in the legacy Haynesville 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 going to 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&C cost through the first quarter. This is for all our wells drilled in the Western Haynesville. During the first quarter, we drilled 5 wells to total depth in the Western Haynesville. This is with an average lateral length of 10,356 feet. Our first quarter drilling costs average $1,534 a foot. This represents a 3% increase compared to the fourth quarter. During the first quarter, we also turned 5 wells to sales in the Western Haynesville that had an average lateral length of 11,177 feet. And our first quarter completion costs averaged $1,537 a foot, which is basically unchanged compared to the fourth quarter. And then also to reiterate what was mentioned earlier, our drilling and completion performance in the Western Haynesville is greatly affected by where the wells are being drilled on the acreage as there's much variability in the vertical depth and formation temps along with the lateral lengths. And 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 Haynesville 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 the 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 Haynesville area, we will be looking to deploy this technology into our Western Haynesville area. I also mentioned it earlier, but we also drilled our record longest lateral to date in the Western Haynesville with a 14,800-foot lateral and the well surpassed our initial performance expectations. The well 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 going to lead to significantly lower, more predictable cost structure for our future wells. I'll now turn the call back over to Jay.

All right. Dan, thank you. Roland, thank you. If everyone would please turn to Slide 21. I know we are dealing in a 90-day capsule on this call. I understand that. But the Comstock story over the past 5 years has been defined by our quest to add substantial drilling opportunities in the Western Haynesville, not just the last 90 days capsule. Over that period, we have leased or acquired drilling rights on 728,000 gross acres, comprised of approximately 30,000 individual leases over that 5-year period. Overall, our leases have favorable terms supporting our development program. And as a result of that program, over 5 years, not the last 90 days, we now have 2,546 net locations identified on our acreage. We have been joined by 3 other companies now who are actively drilling and working in the Western Haynesville Basin. The Haynesville shale 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, Louisiana. The arrival of the Western Haynesville 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 Haynesville, it led to the March 19, 2026 announcement of what? That the U.S. Department of Commerce selected our Western Haynesville site to host a new 5.2 gigawatt natural gas-fired power generation hub to be located where? In Anderson County, Texas. So our current goals for the company, they're fivefold, and the fifth one you'll really want to hear. Fivefold. Number one, enhance our legacy Haynesville 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, 3 of our 5 rigs deployed in our legacy Haynesville 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 Haynesville not only supports our drilling program, but also led the Power Generation Hub opportunities. By controlling our midstream, we'll be able to keep our producing cost 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 Haynesville to premium markets. And finally, number five, which is what most of this conversation has been on, optimize the drilling and completion of our wells in the Western Haynesville. 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 shale play. 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. I'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. As an initial founder or developer in the legacy Haynesville in 2008, we learned from mistakes that were made there, but 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 Haynesville, 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, '09, '10. That's 4 million acres in the legacy. We have about 800,000 acres that we think are in the Western Haynesville. 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.

[Operator Instructions] Our first question comes from the line of Carlos Escalante from Wolfe Research.

I appreciate the...

Carlos? Carlos?

How are you, Jay?

Thank you for headlining cash burn and slow pace of resource delineation risk, investor patience. 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.

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 state as are all of your other peers, that on your current plan, as you mentioned, may extend the period of that cash burn. So how patient do you expect investors to be, acknowledging that there is 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 in the quarter prior. If maybe you can frame that for us, that would be tremendously helpful.

Well, Carlos, I think, number one -- and this is hard. 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 10%, 12%, 13%, whatever the number is, and our CapEx 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 will be a time lapse. It may be 90 days, 120 days, but there will be a lapse. Because if you're trying to protect your balance sheet last year and you lay down 1, 2, 3, 4 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 of 2,000 or 3,000 acres every month through our Western Haynesville, and most of that is the best of the best acreage, and we kept spending that money. Now in order to turn the cycle, 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 million, 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 U.S. 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 13%, 14%, 15% for the second quarter. I think, Carlos, we have turned the corner. And the corner is hard. You know that 90 days is hard because you have to actually spend money on those 4 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 Haynesville wells in both the Bossier and the Haynesville, and they can be 90 miles apart from each other, much less 20 miles from the east and west direction. So I think, Carlos, we've turned the corner. Now maybe the second quarter, because we did add that fourth frac fleet, 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 Haynesville. And like I said, the acreage that we have -- if you keep the 4 rigs busy that we have right now in our Western Haynesville, every acre that we own will be HBP, every acre with those 4 rigs. And we don't even have to have those 4. So the plan works. In the past, Carlos, you'd say, well, you bought another 15,000, 20,000 acres. It's another $20 million, $30 million. 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. And 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 crossed is a hard bridge to cross. We've crossed it now. Let's look at where the future is going.

Sounds great to me, Jay. I appreciate the answer on that. My follow-up will be to you, Dan. Can you talk briefly about the Hutto 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 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 Haynesville?

Yes. 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. So...

Give him the more.

So we've drilled -- of the 36 wells that we've got producing, we got 7 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. But this -- the Hutto Rodell is the furthest one by far as far as the TVD difference between the hill and the toe. I mean, it's nearly 1,400 feet from the hill to the toe. And so the main reason we didn't get a good IP on this well is this well made a lot of water during flowback. All during flowback, 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 triangulate and zero-in on really is it may be more than just the geometry. It may be some geology involved. We did have -- our Brown Trueheart BB well is, I'll say, next to it. It's about a mile away. But they were both Haynesville targets, they both drilled uphill. The Brown Trueheart didn't go as far uphill, but it also made a lot of water during flowback. We got a little bit better IP because the water wasn't quite as high. But those are -- of the 7 wells we drilled uphill, those 2 wells, the Brown Trueheart BB and the Hutto Rodell, are in our deeper pay, those deeper TVDs, 17.5 to 18.5, 18.8 range. And both of those wells made a lot of water during flowback. Now we have drilled 5 wells up on our shallower acreage up in the 14 to 16 to 17 TVD range that also went up hill, not at 1,400 foot, but maybe up 600 or 700 foot from the hill to the toe. 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 head 100% on the fact that they were drilled uphill for the high water volumes. 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 #1, not to be confused with the Dolly Jones #1 that I mentioned as our long lateral we just drilled. This is another Jones #1, but it's right there in line with those other 2 wells. And so it is a Bossier as opposed to these being 2 Haynesville. And so we're just going to 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 Haynesville 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 flowback, it's hard to get IPs. And we probably had -- out of the 36 -- we had 3 wells, I would say, out of those 36 that we made really high water volumes during flowback that greatly affected the IP rates.

And that's our frac water.

I mean that's load water. That's not formation water. That's correct. And this is across -- I mean, look, we're drilling 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 like going from East Texas all the way down to the deep Natchitoches fault zone in Louisiana. 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. So that's part of it. I'd say the other kind of comparing the Western Haynesville to the core, the core -- everything in the core -- we don't really have a lot of wells that go TVD-wise downhill or uphill. And they're all like pretty much horizontal, like maybe from 85 to 95 degrees or maybe even a little flatter than that. In the Western Haynesville, it's different. We got wells whether -- we're drilling the hold acreage is the reason we kind of drill some of these wells uphill, a 2-well pad, one goes south, it's going down dip, one goes north or northwest, I mean, that's going up dip. So -- but we have a lot more dip. We've got a lot more dip in the Western Haynesville that leads to these higher angled wellbores.

Our next question comes from the line of Charles Meade from Johnson Rice.

Jay, I wanted to -- 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. It's -- you made a bunch of announcements about it. And -- but from my point of view, it looks like you're the -- I guess 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. 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 a great question. And I love your headlines, too. We slightly missed production, blah, blah, blah. That's good headline. I wish you would 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 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, 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 NextEras of the world see." And 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 the Western Haynesville, and you're in a really great geographic location, there's a lot of people. You do own a big footprint. So the sky is the limit as they say. What happens is NextEra will say okay. The federal government comes in with the agreement with the Japanese and say -- the Japanese will say, "We've committed this $550 billion." The federal government then will choose NextEra and NextEra will choose where their basin may be. It goes back to that 2015 relationship we've had with NextEra. And they said, "We've done a lot of business with you in the past. We love the Western Haynes. 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, the obligations to build and stuff like that, we don't have that. What we have is we provide them the gigawatt, the 5 gigawatts, the 1 billion, whatever it is. It may grow a lot higher than that to provide the data for the turbines. So it's a really great event because it's at the United States government level. It's then at NextEra's level, and it's our gas. We're a natural gas company. So whatever the big packages under the Christmas tree for the benefits, which will 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 we would be the one that would have the acreage that we captured to have the upside and the midstream. You have to have the midstream to provide that gas, to provide what NextEra sees as a huge role for U.S. shale gas to power AI hyperscalers and data centers.

Got it. And then if I could actually ask a follow-up about the Western Haynesville. I really like these maps. I'm looking at Page 16, where you give us the red dots on where these -- where your recent well results are. And I'm wondering if you could talk about the wells that are -- it looks like you had 2 wells that are further up dip. And if you could talk about what you're seeing as far as how the play changes. I'm guessing you have probably lower D&C because it's less vertical depth, but what you're seeing with the productivity on those wells as you move up dip also.

Yes. 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 the Circle M in 2022, we produced at 8 months in 2022 and then we started drilling in '23, '24, '25. If you were to go where we have drilled several wells and you were to infill drill, I mean, you could drill dozens and dozens and dozens, dozens, if not hundreds of wells and infill drill them and you've got gathering near there on that pad site. But you want to get cost 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. 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, we'd go north because the plan was -- and that goes back to Carlos. You're going to have enough patience to delineate this. Well, in 1 year, you jump 40, 50 miles to the north. That's pretty quick delineation. They never did that in the 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. So now with that, I want Dan to answer that question.

Yes. So I'll definitely just reiterate the last thing he said there. We are -- all of the -- all of the locations we're drilling for the hold acreage, I'd say more than 9 out of every 10 is the hold acreage. And so those 2 -- what those 2 dots are, Charles, that's actually 2 pads right there. So those 2 dots, if you're looking at that slide, that represents those 2 Bumpurs and 2 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 Bumpurs goes north, the NMH goes north, the DHGJ goes to the south, the Pollard TFG goes to the north and the Pollard MBK goes to the south holding acreage. So those -- we started after looking at just what we do constantly, right, looking at well performance. We knew we probably were understimulating these wells. We need to pump bigger fracs. So all 4 of those wells were pumped with bigger fracs up in that area than what we had pumped on the offset wells in that little area there that you're looking at. And so -- and all 4 wells look really good. And I kind of will speak -- 2 of those wells that went uphill was kind of 2 of the wells when I was answering Carlos' question earlier. We did not see -- we may see a little water in the first couple of days on flowback, but really we didn't see any big water volumes. By the time we're off flowback and getting the well IP-ed, 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 4 of those. We're really happy with them. That's probably 14 to 16.5 TVD 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&C. As a matter of fact, the record -- a record fastest, cheapest well today, which we just referenced as the record well that we TD-ed in 37 days was a direct offset to one of those pads. It was the Jennings pad, the Jennings Lower and the Jennings FSRA. The Jennings FSRA was right next to those wells. It was up dip. We drilled, TD-ed in 37 days. We just had some great motor runs. And so we -- the EUR will be a little bit less just because you got less pressure and it's at a shallower depth, but we offset that with the faster D&C cost -- faster drill and lower D&C cost.

Our next question comes from the line of Derrick Whitfield from Texas Capital.

Jay, I appreciate your kind of bigger picture comments to open up the call. Maybe, Dan, I wanted to start with you. 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, so that's going to probably be deployed later in the Western Haynesville. We are -- we've had several runs so far in the legacy Haynesville. The system that we're using, we probably started running it maybe 5 or 6 months ago, I want to say, and we're still making some tweaks. It's a learning process. But I'll tell you, we've had some really fantastic -- I mean, really fantastic runs to date with 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 getting tweaked. But 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 2 years to get this tool refined to where it was humming. So it's not an overnight thing. It's -- all of these tools that work well in other basins, the last basin they come to, to get -- is the Haynesville just due to the depths and the temperatures? And so that's kind of where we're at. We are super excited about 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 Haynesville because that's just a much more difficult environment with temperatures. But a lot of -- we've run several of them on these horseshoe wells. Just super pleased with it. So a lot of running room there. I think the 10-K rig that's coming at the end of the summer, we're super excited. That's just going to give us -- we're going to be able to pump faster, just more horsepower on bottom, better ROPs, knock some days off. So pretty excited about that. And maybe the most exciting thing is this last well we drilled that was -- we drilled the big hole laterals, 8.5-inch bit size instead of the 6.75. 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 got to spend a lot more money before you ever get to the lateral because you got all your casing strings up top that have to be a whole size bigger. The casing has to be one size bigger, right? So 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 going to drill faster to make up that to breakeven or come out even cheaper. And what we did was we came out even cheaper than what we expected. So we -- our drill cost on that well was basically lower than any of these bars you see on Slide 20 on our cost per foot, slightly lower. So we feel also -- it's a little bit more predictable than what we've done in the slim hole. And we can slide and turn a little bit more effectively than we can in the slim 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. It 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 14,000 or 15,000 to have a breakeven versus the slim hole laterals we've been drilling on early. We don't need to drill. We maybe only need to drill 11,000 or 12,000 foot for it to be cost competitive with the slim hole.

Derek, going back to the question that Charles asked earlier, some of these are Bossier, some are Haynesville. So when Dan talks about a particular well -- I mean, we may -- 80 miles away, we may have another Haynesville, but it's not exactly the Haynesville 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 Haynesville back in '08, '09, '10, '11. Not only was there too many rigs drilling, they had leases that were expiring. So now you've got -- and then you had gas prices and natural gas prices collapse. So if we look at all of that -- and I love the point that you said, the bigger picture concept, because it's like 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 there's just the 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. Now that may be, yes, 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 of 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. So I don't know. I just see the 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 D&C optimization stuff you guys are working through now. But just, Dan, when you think about what you're seeing right now on restricted flowback testing to date, is that an optimization now that you're likely to turn as you progress development in Western Haynesville?

I mean absolutely. I think we -- I mean, I'll just sum it up. We need to be pumping bigger fracs, 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 at slightly more conservative drawdown really this year going forward than where we were just in the last 6 months. If you get the bigger EURs, you get a lot better PV-10 values. And if you still can get that 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 that -- to me, that is the answer, significant resource in the ground. I mean you're talking -- just due to the thickness and the pressures. In the big fracs, you're out there touching a lot of reserves and you have to keep those fracs open. What you created, you got to keep it open to extract that -- those volumes and that value. So the bigger fracs, very conservative drawdown going forward.

Derek, we put boots on the ground. Dan and a couple of the other top-tier people in the drilling group, 2 weeks ago, they went to Germany. They had boots on the ground at the Baker plant. In other words, look and see it, touch it, what are we doing, 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 an 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 -- it's a hard story. It's the greatest story, though. So -- and again, on the equity side, every share is precious. We treat it like it's precious.

Perfect. Maybe just one more just for the benefit of investors because I know that 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 time frame, Derek. I don't know what else to say about more than that.

I think it's -- I'd say the Western Haynesville -- we've got the legacy versus the Western Haynesville. The legacy has probably been a little bit more predictable to date than the Western Haynesville. But I think with the more conservative drawdown -- the bigger fracs, the more conservative drawdown is going to make the -- guiding the Western Haynesville volumes more predictable, I think, than looking forward than looking backwards.

Yes. And pure volume in the Western Haynesville will take out some of the lumpiness.

Our next question comes from the line of Leo Mariani from ROTH.

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. I 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 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 that we hope we 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, which will -- and I think we'll raise a little extra equity to help pay down some of the -- add a little equity to Pinnacle along with the credit facility. So it isn't a -- the way the midstream is being built out, it's -- obviously, you have to build everything before and be ready for the wells and do everything way ahead of the volumes. And so we're -- we have done that and spent a lot of capital heavy upfront with our second frame being put in. It will be operational this summer. Once that's done, we'll be -- have a lot of treating capacity and we'll really just be spending money on going out and picking up the wells as we go forward. So the CapEx will be a little bit lower as you go forward in Pinnacle. And then the volumes will show up for that off in the future. That's the nature of the midstream operator. But I think that 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 in the number. And yes, it is all consolidated as we have the majority interest and have full control of the entity. And it is in a separate credit structure. So it's -- the upstream has its complete structure that includes the bonds and the credit facility and the midstream has just the credit facility and 2 separate credit structures, and there's no recourse between the 2 with each other.

Leo, I think that Quantum was a perfect partner for a while, perfect, perfect, perfect. And then the way their funds work is that 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 there'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 Anderson County 5-gigawatt facility here. Could you provide a little bit more color in terms of where we are these days on the commercial negotiations for gas supply? Is it still a bit of a competitive process? Are they talking to kind of multiple parties? Or are 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?

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.

I would only add, though, that if you can see this in NextEra's comments that our agreement is that we are the gas supplier. So it's not -- but we are -- 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 they were clear in their earnings call that the gas was coming from Comstock. So that's not something to debate.

Yes. Great question. Nobody has the answer disclosable now.

Our next question comes from the line of Jacob Roberts from TPH & Company.

Maybe starting on Q1 realizations. I understand there's a lot of moving pieces and maybe a bit of a onetime 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.

Yes, I think the -- and the Q1, it was a very volatile quarter for gas, both spot prices and the first of month prices have huge variability. We had very unusual February, where the NYMEX price got set very high at the last minute and then spot prices were almost 50% of that almost immediately when the month even opened up. So you had a very strange quarter. You had a -- and then we're also kind of impacted by some production that had to be shut in during the storm event, and then also the delays that got created with a lot of wells that were going to come on. Several week delays in wells that didn't get to come on because you couldn't -- we had to shut down the frac equipment, couldn't move drilling rigs, et cetera, because of the bad road conditions, especially in Louisiana. So just a lot of noise there. I don't -- we think that was especially in the Haynesville and -- but we don't think that's a real -- something to really take forward. And you could 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 month basis and 25% in the spot to allow us to adjust if there's a well down or just the new wells coming on. And that's kind of our philosophy. And that kind of matches -- we have about 55-plus percent of our gas hedged. So we want to have that -- those hedges are really tied to that first of the month. So you don't want to tie those to the spot prices. So I think our philosophy will be similar. I think we would have been maybe better served in the first quarter if we just had more production available on 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 commitment probably hurt us 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 Haynesville. 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 6 or 12 months in the '24 and 2025 vintages. And I think that's mirrored to some extent by the IP you guys present 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 the most recent EURs and how those compare to the earliest wells that might have been in that 3 to 3.5 Bcfe per 1,000 foot range?

Well, I'd say the earliest wells that we drilled in the play with the first 6 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 had one producing to date way up on the Northeast end, 50, 60 miles away, the Eljah one. And it's really a good well up there also. But by and large, on average, the better -- the best wells to date have been those in Robertson County. We've got good thick pay rock qualities there. And I'm going to go back and say 15 years ago, somewhere in there, Encana came out here to drill the very first 2 shale wells and they drilled them in that area. So we -- and we pulled those wells harder in the beginning. So 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. Just we're going to have that variability across the footprint.

Our next question comes from the line of Paul Diamond from Citi.

I just want to touch base on -- yes, let's talk about the development of Western Haynesville. Can you remind us of the kind of the time frame and the cadence towards full utilization there? Is it still kind of that late '27 period? Or do you see any movement?

In terms of HBP, Paul?

Yes, in terms of what the realization -- HBP.

Yes, that HBP -- again, we add acreage every month. But if you look at the model we have today, you keep the 4 rigs busy this year and next year, part of the -- even the -- maybe by the middle of '28, you've got it all HBP. 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. If you don't want to drill them, the answer is no. We had 2 rigs several years ago. We're going to add a third. We didn't have the third because gas prices were low. We came in later last year and added 4. And that didn't impact 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 a 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 the downside here, can you talk a bit about the optionality in your operational cadence in coming quarters? I guess what would cause a shift in the current strategy of 5 rigs in Western Haynesville, 4 rigs in the core and those 4 fleets across the acreage?

So what's the question now?

What would change the current strategy?

Yes, we reduce rigs or add rigs. I think that ultimately we're looking to see the best time to move one of the legacy Haynesville core rigs to the Western Haynesville. So we're still deciding on that. That's probably -- but I think the current cadence is probably -- is the plan that we could be running consistently even maybe into next year. But we'll look for the opportunity to add another -- moving one of the rigs to the Western Haynesville is kind of the biggest decision we have to make, I think.

Yes. I think, Paul, the rig count is 9. Remember, 5 in the core, 4 in the Western Haynesville. That rig count is, as we see it today, is static. I mean it's -- and like Roland said, I think all the rigs we have, all 9 of them except one -- Dan, you can correct me -- is capable of moving over to the Western Haynesville.

That's correct.

So if we needed to, we could move a rig from the core over to the Western Haynesville. But I think the 9 is good. I think that it accomplishes every goal we have in '26 and '27. It meets any contracts that we had to provide gas. We have a takeaway for that. We have the rigs deployed for that. We have the frac crews committed for that. So I think that works good.

Yes. And the only other thing I'll add to that is just as far as the cadence, I think 4 is good. And we also have all of these -- still these things that we're learning. We got the 10-K rig upgrade coming. We've got some high temp motors we're going to be testing 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 that cadence with rigs is just -- we want to learn some more of these things before we add rigs to the Western Haynesville.

Our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research.

Just trying to sort of triangulate some of what you're talking about, that you need to be able to demonstrate that you can keep the formation open after the frac. So if I'm understanding right, is part of that just your protocol for chokes? Or is also, for instance, proppant 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?

I think most of it is the drawdown. All fracture systems naturally close over time as you produce some large cumulative amount of gas. That's just the natural progression. You see a little bit more of it in the deeper formations versus something that's really shallow. But you can mitigate that. Larger volumes of sand, higher concentrations of sand, 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 one is the -- the greater lever is how fast you draw them down. So like we've stated, we need to -- 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. And you were mentioning Robertson County as the home of some of the early wells. And I know this is sort of like a -- 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 core to the play and maybe with an eye towards 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 Elijah one. We got several more there -- that's where we drilled the Dolly Johns 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 acreage so far that we don't like. There's just a little bit of variability, but it all looks good.

Yes. And we think that more of the results -- the wells have been done -- drilled differently, different landing zones. They've been drawn down differently. And I think the very early wells in Robertson County were drawn down pretty hard. So they did produce a lot of gas upfront. We think that the more restrictive choke in Leon and other counties are going to still yield very attractive EURs on the nature of the 3.5 Bcf per 1,000. But we can't pull them as hard. And so I think the data just looks different. But we still see very strong recoveries from the wells. It's really -- you've seen other -- the other operators have had some wells that have obviously going to exceed 4 and 5 Bcf per 1,000. So there's a lot of -- and a lot of it is, how do you want -- if you want to pull out gas out really quickly, you're going to get a lower EUR. If you're going to manage the choke 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. But I don't think that overall it really means that, 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 -- the Elijah one is going to be a well that has a very high EUR than 3.5 plus for sure. And I think we probably -- early wells probably understimulated them. We think looking at all the data that's -- and so now the better frac design is -- I think is going to contribute to better recovery from the wells.

I think how prolific this is. We have over 1,000 penetrations where we have seen what the molecules look like, what the Haynesville, Bossier look like in 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. We like -- that is 80 miles away from where we drilled our first well. I mean, if I put you in a pair of tennis shoes to go 80 miles, it would take you 2, 3 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, and we're not going to ruin the basin that we control like happened in the legacy back in 2008, '09, '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 proppant to use. They didn't have midstream. All of those things we have avoided in the basin that we call the Western Haynesville.

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 Jones 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 NextEras that we have and the banks that we have backing us and then the growth with LNG with Golden Pass and Cheniere, 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 will 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.