Comstock Resources Q1 2026 Earnings Call - Western Haynesville Delineation Drives Long-Term Value Amid Production Miss

Operator: 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 speakers’ presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star 11 on your telephone. 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 Chief Executive Officer. Please go ahead.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: 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 titled 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 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 19th, 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 U.S. 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 fire generation capable of serving up to 5 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?

Charles Meade, Analyst, Johnson Rice0: 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 pre-tax $83 million mark-to-market unrealized gain related to our hedge book.

Excluding the mark-to-market gain, exploration expense, which is related to seismic that we’re shooting in our Western Haynesville play, and other non-recurring 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, 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 that reference price.

Significant disconnects existed during the quarter between the regional hub prices and NYMEX, kinda 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 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 cost are fixed. Our operating cost per Mcfe averaged $0.93 in the quarter, up $0.16 from the 4th 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. 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 at 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 2.9 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.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: Okay, thanks, Roland Burns. 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. 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.

Of course, with the higher pay thicknesses and the very high pressures we encounter 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 operating 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 5,000-8,500 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 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.

As of today, our average lateral length in the legacy Haynesville inventory has climbed up to 10,019 feet. 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 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 most of our Western Haynesville acreage has not yet been unitized. Our Western Haynesville inventory is more weighted to the Bossier formation, with nearly two-thirds of the inventory in the Bossier Shale and one-third of the inventory is in the Haynesville Shale.

We also have our Western Haynesville inventory divided into the 4 separate groups by length, with our short laterals less than 5,000, the medium laterals between 5,000 and 8,500 feet, the long laterals between 8,500 and 10,000 feet, and the extra long laterals over 10,000 feet. In our Western Haynesville gross operated inventory, we don’t have any short laterals today. We have 1,319 medium laterals. We have 646 long laterals and 1,366 extra long laterals. 60% of our Western Haynesville gross operated inventory has the laterals greater than 8,500 feet. On slide 13, this is 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 costs 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 Camp Tech 29149 number 2 was turned to sales in the first quarter with a 41 million cubic feet per day IP rate. We plan to drill a total of 16 Horseshoe wells total in 2026. On slide 14 is 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 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 number one H, reached total depth in mid-April, we have it scheduled for completion later this summer. To date, we have drilled 47 wells to total depth in the Western Haynesville. That includes 21 wells with laterals over 10,000 feet, 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. 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. The average IP was 31 million a day. Five 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. 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.

We have 4 of our 9 rigs 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. 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. 4 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 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, you know, 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.

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 string that we use to isolate the localized overpressure 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 frack efficiency and with a slightly lower drill-out cost. We’re currently running 3 full-time frack fleets. This is after we added our 3rd frack fleet in January. We are adding a 4th frack fleet this month, and we’re planning to maintain running 4 frack fleets through the end of the year. On the drilling side in the legacy Haynesville area, we have continued field testing, you know, with our rotary steerable drilling BHAs, and we’re really continuing to make good progress there. 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&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 cost averaged $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. 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 Haynesville 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 1 of our existing Western Haynesville rigs being upgraded to a 10,000 PSI rating that’s gonna 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 Haynesville area, we will be looking to deploy this technology into our Western Haynesville area. I also mentioned it earlier, but, you know, 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 down hole temperatures, more reliable motor performance from the downhole drilling assemblies, and longer motor life.

We plan to implement this new well design in more of our future wells. This, along with the other performance initiatives being undertaken, are gonna lead to significantly lower, more predictable cost structure for our future wells. I’ll now turn the call back over to Jay.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: All right, Dan, thank you. Roland, thank you. If everyone would please turn to slide 21. You know, I know we’re dealing in a 90-day capsule on this call. I understand that. 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. 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’ve 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 and 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. 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 fire power generation hub to be located where? In Anderson County, Texas. Our current goals for the company, they’re fivefold, and the fifth one you’ll really want to hear. Fivefold. Number 1, 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. 2, 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. 4, support the build-out of our midstream company, Pinnacle Gas Services. The formation of Pinnacle Gas Services by us in 2023 to gather and treat our natural gas in the Western Haynesville not only supports our drilling program, but also led to 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. 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. Finally, number 5, which is what much 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. 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. I want to thank you for your time today. There will be questions. We’ll turn it over to Ron if you want to call in and ask Ron questions. I also want to make one more comment. You know, as an initial founder or developer in the Legacy Haynesville in 2008, we learned from mistakes that were made there, that we did learn. We understand.

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, 2009, 2010. 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. The way we do that, and I understand cash burn and slow pace of resource delineation is a little taxing, I get that.

That is what we’re doing to create the value that we already possess. Now with that, I’ll turn it over to ask questions.

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

Carlos Escalante, Analyst, Wolfe Research: Hey, good morning, guys. Thank you for having us on.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Hey, Carlos. Carlos.

Carlos Escalante, Analyst, Wolfe Research: How are you, Jay?

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Thank you for headlining cash burn and slow pace of resource delineation risk, investor patience. I love that headline.

Carlos Escalante, Analyst, Wolfe Research: Well-

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: 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. I just want you to know that, okay? Thank you for being honest and coming up with that headline. It helped me.

Carlos Escalante, Analyst, Wolfe Research: No, sure. I appreciate you saying that and giving us an overview on how you feel about the long-term value proposition. Why don’t we start there, if you don’t mind, maybe you can expand on your initial thoughts. You’re dealing with a tough gas tape as are all your other peers, that on your current plan, as you mentioned, may extend the period of that cash burn. 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?

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Right.

Carlos Escalante, Analyst, Wolfe Research: Frame that for us, that’d be tremendously helpful.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Carlos, I think, number 1, 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. 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 CapEx was higher. 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.

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 gonna lose that production a year later. 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 Haynesville, and most of that is the best of the best acreage. 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. When you do that, you pay down that debt, then what happens? Well, you’re going to have to lever up a little bit. 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 U.S. I don’t see that out there from some of you. Yes, we missed production, and CapEx was up a little bit.

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’s down. 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’s hard. You know, the 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 could be 90 miles apart from each other, much less 20 miles from us, on the east and west direction. I think, Carlos, we’ve turned the corner. Maybe the second quarter, because we did add that fourth frac fleet, you’ll see a little bit of hesitance in there. 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.

Like I said, the acreage that we have, if you keep the four rigs busy that we have right now in our Western Haynesville, every acre that we own will be HBP, every acre with those four rigs. We don’t even have to have those four. The plan works. You know, you in the past, Carlos, you’d say, "Well, you bought another 15,000, 20,000 acres. There’s another $20 million-$30 million. You kinda 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 one or two thousand acres every month. If we could get more, we’d get it. It’s not out there to be taken.

That’s where I think we have crossed the bridge, and what we’re talking about now is a bridge we’ve crossed, is a hard bridge to cross. We’ve crossed it. Let’s look at where the future’s going.

Carlos Escalante, Analyst, Wolfe Research: Sounds great to me, Jake. 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. Wondering if you can qualify for us what was the root cause? Was it completion design, geology? 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?

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: 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.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Give him the more.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: You know, 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. You know, the laterals go basically up instead of going down. Most of them, you know, go down quite a bit just due to the geology. 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. You know, 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.

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. 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. They were both Haynesville targets. They both drilled uphill. The Brown True Heart didn’t go as far uphill, but it also made a lot of water during flowback. We got a little bit better IP ’cause the water wasn’t quite as high.

Those are Of the 7 wells we’ve drilled uphill, those two wells, the Brown True Heart BB and the Hutto Rodell, are in our deeper pay. Those deeper TVDs, 17,500 to 18,500, 18,800 range. Both of those wells made a lot of water during flowback. We have drilled 5 wells up on our shallow acreage up in the 14,000 to 16,000, 16,000 to 17,000 TVD range that also went uphill. Not up 1,400 feet, but maybe up 600 or 700 feet from the hill to the toe. Those wells made a little more water during the initial part of flowback. By the time we released flowback, the water volumes were down.

That’s why I say I don’t know if I’m gonna hang my hat 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 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. It is a Bossier as opposed to these being two Haynesvilles.

We’re just gonna have to see how that well responds, you know, 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. You know, a little bit of geology in that answer, too. The short answer is, when you make a lot of water during flowback, it’s hard to get IPs. We’ve probably had out of the 36, we’ve had 3 wells, I would say, out of those 36, that we made really high water volumes during flowback that, you know, greatly affected the IP rates.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: That’s our frack water.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: That’s load water. That’s not formation water. That’s correct. This is across, you know, 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, 50-60 miles. That’s like going from East Texas all the way down to the deep Natchitoches Fault Zone in Louisiana. That is a, that is a huge distance, and there’s a lot of variability in what these wells are gonna make and perform and how much water they’re gonna make. You know, 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 TBD-wise downhill or uphill.

They’re all, like, pretty much horizontal, like maybe from, you know, 85 to 95 degrees or maybe even a little flatter than that. In the Western Haynesville, it’s different. You know, we got wells whether, you know, we’re drilling to hold acreage is the reason we kind of drill some of these wells uphill. 2 well pad, one goes south, it’s going down dip, one goes north or northwest, that means it’s going up dip. But we have a lot more dip. We got a lot more dip in the Western Haynesville that leads to these, you know, higher angled wellbores.

Carlos Escalante, Analyst, Wolfe Research: Understood. I’ll turn it back. Thank you, team.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Great question. Thank you.

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

Charles Meade, Analyst, Johnson Rice: Good morning, Jay, Dan, Roland, Ron, and all the other Comstock people on the call.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Morning.

Charles Meade, Analyst, Johnson Rice: Jay, I wanted to, forgive me if this is kind of a basic question, I wondered if you could just give us the whole picture from your point of view on this Texas power generation hub. It’s, you know, you’ve made a bunch of announcements about it and, you know. From my point of view, it looks like you are, you’re the, I guess you’re the surface owner for where this site is gonna be. At least I think that seems to be the case. You’re going to supply gas to the power gen facility. I guess that’s not finalized.

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.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Well, I think that’s a great question. You know, I love your headlines too. You know, we slightly missed production, blah, blah. That’s a 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, 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, it is a state that has a lot of natural gas, and we need it to power the generation that the NextEras of the world see. They like it. You have to have a location that works. 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’s the limit, as they say.

What happens is, NextEra will say, "Okay," the federal government comes in with the agreement with the Japanese and said. The Japanese will say, "You know, we’ve committed this $550 billion." The federal government then will choose NextEra. NextEra will choose where their basin might be. It goes back to that 2015 relationship we have with NextEra. They said, "You know, we’ve done a lot of business with you in the past. We love the Western Haynesville. We’ve been out there. This is where we’d like to have the data center." What happens is, we don’t own the surface. All we do as far as $ 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 gigawatts, the 5 gigawatts, the billion, whatever it is, it may grow a lot higher than that, to provide the data for the turbines. It is a really great event because it’s at the U.S. government level, it’s then at NextEra’s level, and it’s our gas. You know, we’re a natural gas company. Whatever the big package is 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 know, when you have your first power, that’s needed.

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, you know, what NextEra sees as a huge role for U.S. shale gas to power AI hyperscalers and data centers.

Charles Meade, Analyst, Johnson Rice: Got it. Thank you, Jay, for that overview. 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 your recent well results are. I’m wondering if you could talk about the wells that It looks like you had two wells that are further up dip. 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.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Yeah. I’m gonna let Dan do that. I wanna 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 8 months in 2022, and then we started drilling in 2023, 2024, 2025. If you were to go where we have drilled several wells and you were to infill drill, well, you could drill dozens and dozens and dozens and dozens, if not hundreds of wells and infill drill them, and you’ve got gathering of near there on that pad site. You wanna 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 1, because we had seismic, we had well control.

You know, we have 1,000, maybe 100 penetrations in all this footprint we have. Then we have the seismic, and now we’ve got cores. Before we had the core, you know, we’d go north because the plan was, that goes back to Carlos, you know, are you gonna have enough patience 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. 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. Now with that, I want Dan to answer that question.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: I’ll definitely just reiterate the last thing he said there. All of the locations we’re drilling are to hold acreage. I’d say more than 9 out of every 10 is to hold acreage. Those two dots are, Charles, that’s actually two pads right there. Those two dots, if you’re looking at that slide, that represents those two Bumpurs and two Pollard wells at that location. We drilled on each pad, we had a well to the north and a well to the south. One of the Bumpurs 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.

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 fracs. 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. All 4 wells look really good. I kinda will speak, 2 of those wells that went uphill was kinda 2 of the wells I was when I was answering Carlos’s question earlier.

Charles Meade, Analyst, Johnson Rice: Right.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: We may see a little water the first 2 days on flowback, really, we didn’t see any big water volumes. You know, by the time we were off flowback and getting the well IP’d, you know, they had pretty well dried up. They only go uphill there about 600 or 700 feet from the hill to the toe. They look really good. All 4 of those. We’re really happy with them. That’s probably 14 to 16,500 TVD range on those wells. Maybe the toe of the down dip wells may be closer to 17, it is less pressure. They are cheaper to D&C.

Matter of fact, the record, our record fastest, cheapest well to date, which, you know, we just references the record well that we TD’d in 37 days, was the direct offset to one of those pads. It was the Jennings pad, the Jennings Lower, the Jennings FSRA. The Jennings FSRA was right next to those wells. It was up dip. TD’d at 37 days. Just had some great motor runs. You know, the EUR will be a little bit less just because you got less pressure and it’s at a shallower depth. You know, we offset that with the faster D&C costs. Faster drill and lower D&C costs.

Charles Meade, Analyst, Johnson Rice: That is great color, Dan. Thank you.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Great, great question. Thank you.

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

Derrick Whitfield, Analyst, Texas Capital: Good morning, all, and thanks for your time.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Morning, Derrick. 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?

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: Well, I’ll talk. rotary steerable, so you know, that’s gonna probably be deployed later in the Western Haynesville. We’ve had several runs so far in the legacy Haynesville. The system that we’re using, we probably started running it maybe five or six months ago, I wanna say. We’re still making some tweaks. You know, it’s a learning process. I 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, you know, getting tweaked.

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 2 years to get this tool refined to where it was humming. It’s not an overnight thing. It’s, you know, all of these tools that work well in other basins, the last basin they come to get, you know, to is the Haynesville, just due to the depths and the temperatures. That’s kinda where we’re at. We’re super excited about, you know, the fantastic runs that we’ve had. We need to get more of those under our belt, and we need to get them done with more consistency. Then we will roll it out into the Western Haynesville because that’s just a much, you know, more difficult environment with temperatures.

A lot of, you know, we’ve run several of them on these Horseshoe wells. Just, you know, super pleased with it. 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. We’re gonna be able to pump faster, just more horsepower on bottom, better ROP, knock some days off, pretty excited about that. You know, maybe the most exciting thing is this last well we drilled that was, we drilled the big hole laterals, 8.5 inch, you know, bit size instead of a 6.75 inch. We, 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? You gotta spend a lot more money before you ever get to the lateral because you got all your casing strings up top. They have to be a whole size bigger. The casing has to be 1 size bigger, right? Before you ever get to the lateral, you’re, you know, you’re in the red basically, right? You’re a little more expensive. You have to have, you know, 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. 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.

we feel also, it’s a little bit more predictable than what we’ve done in the slim hole. you know, we can slide and turn a little bit more effectively than we can in the slim hole. there’s some intangible benefits from that also that we think are gonna help us. We just need to drill more of them, right? I mean, obviously, you need to get, you know, the proofs in the pudding. We’ve only done one. Looks really good. we’re gonna make some changes hopefully up in the vertical, kinda 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 needed to drill 14,000 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 11,000 or 12,000 foot for it to be cost, you know, competitive with the slim holes.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: You know, Derrick, going back to the question that Charles Meade asked earlier, you know, some of these are Bossier, some are Haynesville. 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 2008, 2009, 2010, 2011. You know, not only were there too many rigs drilling it, they had leases that were expiring. Then you had gas prices, the natural gas prices collapsed.

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. 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 gonna be perfect for that, only because we’re in the correct, you know, geographical location in America. That’s the difference. If you own the basin, and yeah, there’s 50 other companies out there that they’re drilling stuff, but they don’t own what we own. 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. I will tell you, the board is 100% behind it, management. The Jones family, almost every day, they’re in it, they understand it. We would like to go quicker, but you can’t. You’ll get in trouble if you go quicker. I think it’s kind of like what Carlos had asked too. I think we’ve turned that curve because it’s production going down and CapEx going up that gives you indigestion.

I have it too, and I know everybody does. I think we’ve turned that curve on that. Production should go up. We should have really great growth in the rest of this year, you know, particularly in the third and fourth quarter. We did add that extra frac rig. I don’t know, I just see big sunshine out there.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: Derrick, did I answer your question?

Derrick Whitfield, Analyst, Texas Capital: All good. 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 wanna 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. Just, Dan, when you think about what you’re seeing right now in restricted flowback testing to date, is that an optimization knob that you’re likely to turn as you progress development in Western Haynesville?

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: I mean, absolutely. I think we I mean, I’ll just sum it up. We need to be pumping bigger fracs, better stimulation. 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 reserves. To keep it open, you have to have that really conservative drawdown. I’d say we’re probably, you know, maybe even a slightly more conservative drawdown really this year going forward than where we were just in the last 6 months. You know, you get the bigger EURs, you get a lot better PV-10 values. If you still can get them volumes within the 1st 2 years, you’re really not gonna affect your rate of return.

I mean, it’s gonna be about the same number. You know, 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 fracs, you’re out there touching a lot of reserves, and you have to keep those fracs open. What you created, you gotta keep it open to extract that, you know, those volumes and that value. The bigger fracs, the very conservative drawdown going forward.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Hey, Derrick Whitfield, you know, we put boots on the ground. If Daniel S. Harrison and, you know, a couple of the other top tier people in the drilling group, 2 weeks ago, they went to Germany. They boots on the ground at the Baker plant. In other words, look and see it, touch it. What do we do, how can we tweak it to make it better, quicker, faster? You know, we take them there. In other words, you if they’re offering to teach you and to show you what we need to be doing maybe, and they’re gonna spend their own money developing what we need, then we go there. I think it’s important, whether it’s Carlos Escalante, Charles Meade, Derrick Whitfield, everybody that asks these questions, we love them over here.

We’ve given you our best. 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. Again, on the equity side, every share is precious. We treat it like it’s precious.

Derrick Whitfield, Analyst, Texas Capital: Terrific. Maybe just one more just for the benefit of investors, because I know many are thinking about it. Just philosophically on guidance, when you guys provide guidance, should we think of that as a P 50 with a little bit of risking, so call it P 45, P 55 range? I know you guys are giving your best on the guidance on what you think you can execute against, but just would love any color that you could share on that.

Charles Meade, Analyst, Johnson Rice1: I mean, we give you our best guess based on what the expectations are from a drilling and completion timeframe, Derrick. I don’t know what else to say about more than that.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: I think it’s, I’d say the Western Haynesville, you know, we got the Legacy versus the Western Haynesville. The Legacy’s probably been a little bit more predictable to date than Western Haynesville. I think with the more conservative drawdown, the bigger fracs, the more conservative drawdown, it’s gonna make the guiding the Western Haynesville volumes, more predictable, I think, than, you know, looking forward than looking backwards.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Yeah, sheer volume in the Western Haynesville will take out some of the lumpiness.

Derrick Whitfield, Analyst, Texas Capital: All makes sense. Thanks for your time, guys.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Great questions. Thank you, Derrick Whitfield.

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

Leo Mariani, Analyst, Roth: Hey guys, wanted to, kind of turn to the funding side a bit here. 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? 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. Is there additional equity as well that you’re looking to raise at the Pinnacle level? You think you’re gonna be good with this credit facility for the near future?

Charles Meade, Analyst, Johnson Rice0: That’s a good question, Leo. You know, we are running a process, excuse me, to raise equity in Pinnacle. That we hopefully can report on that at the next conference call. That’s going very well. It’s a great opportunity, you know, to bring in more of a common equity partner versus the preferred equity partner we have with Quantum. We have that opportunity to not only redeem the preferred units, which, you know, have a big distribution on them, and bring in a common equity partner, which will, you know. 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.

you know, it is at a The way the midstream’s 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. you know, we’re we have done that and spent a lot of it’s, you know, capital heavy up front with our second train being put in. It’ll be operational this summer. You know, once once that’s done, you know, we’ll be have a lot of treating capacity, and we’ll really just be spending money on, you know, going out and hooking up the wells, you know, as we go forward. The CapEx will be a little bit lower as you go forward in Pinnacle.

Then the volumes will, you know, show up for that, you know, off in the future. That’s the nature of the midstream operator. I think we’re hoping that the process, you know, like I said, Jay said, it’s going well. We’ll have that resolved, you know, soon, and we think that should maybe even highlight the value that the midstream company will have. You know, I think it’ll start to have a lot more visibility in the number. Yes, it is all consolidated as we have the majority interest and have full control of the entity. It is in a separate credit structure.

It’s the upstream has its complete structure that includes the bonds and the credit facility, and the midstream has just the credit facility in two separate credit structures. There’s no recourse between the two with each other.

Leo Mariani, Analyst, Roth: All right. That was very thorough.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Leo, I’d say that the Quantum was a partner for a while. Perfect. 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 investments, to grow the gathering and we control it, that’s the next step. It’s been pent up demand, as I’ve told you, and we should see good results in that in the near future.

Leo Mariani, Analyst, Roth: 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 5 gigawatt, you know, facility here. Could you provide 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? Can you give us a sense of like, is 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?

Charles Meade, Analyst, Johnson Rice0: Well-

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: No, we don’t make any comments on that, Leo.

Charles Meade, Analyst, Johnson Rice0: Yeah.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: That’s a much bigger question than you’re asking. We don’t comment on that.

Charles Meade, Analyst, Johnson Rice0: Yeah. We add though that, and you can see this in NextEra’s comments, you know, that, you know, our agreement is that, you know, we are the gas supplier, so it’s not. We are, you know, that all the negotiations involve a lot of parties. That’s what’s ongoing. We think that’s, you know, that’s a process that NextEra is controlling, you know, they were clear in their earnings call, you know, that the gas is coming from Comstock. That’s not something to debate.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Yep. Great question. Nobody has the answer that’s disclosable now.

Leo Mariani, Analyst, Roth: Understood. Thank you, guys.

Operator: Thank you. Our next question comes from the line of Jacob Roberts from TPH & Co.. Jacob, your line is now open.

Jacob Roberts, Analyst, TPH & Co.: Morning.

Charles Meade, Analyst, Johnson Rice0: Morning.

Jacob Roberts, Analyst, TPH & Co.: Maybe starting on Q1 realization. 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.

Charles Meade, Analyst, Johnson Rice0: Yeah, yeah, I think the in the Q1, it was a very volatile quarter for gas. 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 almost 50% of that almost immediately when the month even opened up. You had a very strange quarter. We’re also kind of impacted by some production that had to be shut in during the storm event.

The delays that got created, and with a lot of wells that were going to come on, you have 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. Just a lot of noise there. We think that was especially in the Haynesville. We don’t think that’s a real something to really take forward. You get back to a more normal gas market.

You know, we tend to try to have about 75% of our gas, you know, nominated to sell on a first-of-the-month basis and 25 in the spot to allow us to adjust, you know, if there’s a well down or adjust to new wells coming on. That’s kind of our philosophy, you know. That kind of matches, you know, we have about 55+% of our gas hedged, so we wanna have those hedges are really tied to that first of the month, so you don’t want to tie those to the, you know, spot prices. I think our philosophy would be similar. I think, you know, we would’ve been maybe better served in the first quarter if we just had more production available on the spot market.

We probably could’ve realized a lot better price. You know, I think having, not much gas to make up the first-of-the-month commitments, you know, probably hurt us some on the realization during the time you had high gas prices.

Jacob Roberts, Analyst, TPH & Co.: 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 2024 and 2025 vintages. I think that’s mirrored to some extent by the IPs you guys present in these decks. 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?

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: 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. What we’ve seen, if we just basically were to shut down today and just, you know, measure everything on the 36 wells that we got producing, you know, the best wells have been the wells over in Robertson County, if you just compare them to the ones in Leon. We just have 1 producing, you know, to date, way up on the northeast end, you know, 50, 60 miles away, the Elijah 1. It’s a really good well up there also. You know, by and large, on average, the best wells to date have been those that in Robertson County. We’ve got good, thick pay, rock qualities there, you know.

I’m gonna go back and say 15 years ago, somewhere in there, you know, Encana came out here and drilled the very first two shale wells, and they drilled them, you know, in that area. You know, we pulled those wells harder in the beginning. You know, those are the early wells. When you look at 22 and 23 are those wells. 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 gonna have that variability across the footprint.

Jacob Roberts, Analyst, TPH & Co.: All right. I appreciate the time, guys. Thank you.

Operator: Thank you. Our next question comes from the line of Paul Diamond from Citigroup. Paul, your line is now open.

Paul Diamond, Analyst, Citigroup: Thank you. Good morning, all. Thanks for taking the call. I just wanted to touch base on, you guys talked about 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 2027 period, or do we see any movement?

Charles Meade, Analyst, Johnson Rice0: In terms of HBP, Paul?

Paul Diamond, Analyst, Citigroup: Yeah, in terms of whatever they HBP.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: Yeah. I think you keep. Again, we add acreage every month. You know, if you look at the model we have today, you keep the four rigs busy this year, next year, part of the, or even the, maybe the, by the middle of 2028, you’ve got it all HBP’d. That’s if. That’s a pretty good guess on that. I mean, I think the real question is, do you have to drill wells you don’t wanna drill in the timeframe you don’t wanna drill them? The answer is no. You know, we’ve had two rigs several years ago. We’re gonna add a third. We didn’t add the third ’cause gas prices were low.

We came in later last year and added 4, and that didn’t impact, you know, holding the acreage that we’ve leased. I think the real question is with the rigs that we have now, or even if you reduce them by rig, I just take the negative, could we hold all the acreage that we’ve now leased? The answer is yes.

Paul Diamond, Analyst, Citigroup: Mm-hmm. Got it. Understood. Just speaking on that, kind of the downside here. Can you talk a bit about the optionality on your operational cadence in coming quarters? Is what would cause a shift in the current strategy of, you know, 5 rigs in Western Haynesville, 4 rigs in the core, and those 4 fleets across the acreage?

Charles Meade, Analyst, Johnson Rice0: What’s the question, though?

Paul Diamond, Analyst, Citigroup: What would change the current strategy?

Charles Meade, Analyst, Johnson Rice0: Yeah. If we will we, yeah, 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 Haynesville rigs to the Western Haynesville. We’re still deciding on that. That’s probably I think the current cadence is probably the plan that we will be running, you know, consistently even maybe into next year. We’ll look for the opportunity to add the Move one of the rigs to the Western Haynesville. It’s kind of the biggest decision we have to make, I think.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Yeah, 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 static. Like Roland said, I think all the rigs we have, all 9 of them except 1, Dan, you correct me, is capable of moving over to the Western Haynesville.

Charles Meade, Analyst, Johnson Rice0: That’s correct.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: We if we needed to, you know, we could move a rig from the core over to the Western Haynesville. I think the 9 is good. I think that accomplishes every goal we have in 2026 and 2027. 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 frac crews committed for that. I think that works good.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: Yeah. 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. We got the 10K rig upgrade coming. We got some high temp motors we’re gonna be testing end of the year. We’ve got this big hole that looks really good that we’re trying to get some more of those in the mix. That cadence with rigs is just we wanna learn some more of these things before we add rigs to the Western Haynesville.

Paul Diamond, Analyst, Citigroup: Got it. Understood. Appreciate the time. I’ll leave it there.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: Thank you, Paul.

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

Noel Parks, Analyst, Tuohy Brothers Investment Research: Hi, good morning.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: Hello, Noel.

Noel Parks, Analyst, Tuohy Brothers Investment Research: You know, just Hey, how you doing? Just trying to sort of triangulate some of what you were talking about just, you know, you need to be able to demonstrate that you can keep the formation open after the frac. If I’m understanding right, is part of that just your protocol for chokes, or is also, for instance, proppant part of that? Is there gonna be a need for, you know, considerable exploration on that front? Or, I’m sorry, experimentation on that front going forward?

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: You know, I think most of it is the drawdown. You know, all fracture systems naturally close over time as you know, you produce some large.

Noel Parks, Analyst, Tuohy Brothers Investment Research: Sure

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: 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. 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, I think the greater lever is how fast you draw them down. you know, like we’ve stated, we wanna get exposed to a large volume of rock because the resource is so huge, and then we wanna be very conservative on how fast we pull it back out.

Noel Parks, Analyst, Tuohy Brothers Investment Research: Great. Thanks. You know, you were mentioning Robertson County as, you know, the home of some of the early wells. 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. 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, you know, beginning or heading towards sort of like a manufacturing mode on a more contained part of the play?

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: 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 1. We got several more there.

Noel Parks, Analyst, Tuohy Brothers Investment Research: Sure.

Dan Harrison, Chief Operating Officer, Comstock Resources Incorporated: That’s where we drilled the Dolly Jones at 14,800 foot lateral we’re gonna complete later this summer. We need to get a lot more of those in the door. So far, let me just say, there’s not any of this acreage so far that we don’t like. You know, there’s just a little bit of variability, but it all looks good.

Charles Meade, Analyst, Johnson Rice0: Yeah. We think that, you know, more of the results, you know, the wells have been drilled differently, different landing zones. They’ve been drawn down differently. I think the very early wells in Robertson 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 gonna still yield, you know, very attractive EURs on the nature of the 3.5 Bcf per thousand. You know, we can’t pull them as hard. I think the data just looks different. You know, we still see, you know, very strong recoveries from the wells.

It’s really you’ve seen other, the other operators have had some wells that have, you know, obviously gonna exceed 4 and 5 Bcf per thousand. There’s a lot of, and a lot of it is how do you want, you know, if you wanna pull every gas out really quickly, you’re gonna get a lower EUR. If you’re going to manage the choke, you know, properly, you’re gonna get a higher EUR. That’s kind of the balance that we’re learning. I think the very early wells, we think we pulled them too hard. Some of them can handle it better, some of them couldn’t, you know.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: That’s right.

Charles Meade, Analyst, Johnson Rice0: I don’t think that overall it really means that, you know, that’s the only area that has that, those kind of EURs. I mean, I think we’re gonna get, you know, a very high You know, the Elijah well is gonna be a well that has a very high EUR than 3.5 plus for sure. I think we probably early wells probably under-stimulated them. We think, you know, looking at all the data that’s. Now the better frack design, I think is gonna contribute to better recovery.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: I’ll tell you how prolific this is. We have over 1,000 penetrations where we’ve 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 a competitor to the northeast, 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. If I put you in a pair of tennis shoes, go 80 miles, it takes 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.

That’s why we say we’re at the very beginning of this. We’re not gonna ruin the basin that we control like happened in the Legacy, back in 2008, 2009, 2010. 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.

Charles Meade, Analyst, Johnson Rice0: Great. Thanks for the perspective.

Operator: This concludes the question and answer session. I would now like to turn it back to Jay Allison for closing remarks.

Jay Allison, Chairman and Chief Executive Officer, Comstock Resources Incorporated: First of all, you’ve been with us for 1 hour 20, 1 hour 30. I, 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 wanna always thank you for taking a look at the business plan. I always wanna remind you that whether it’s the Joneses or the board or the management, we all really have one mind, and we try to do what is just and right for everybody. Whether it’s a bond holder, an equity owner, it doesn’t matter. We, 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. If you can check the boxes, with the pinnacles that we have and the next tiers 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. If you just stay with us, and keep asking questions, it’ll make us better, and we’re thankful for that. Thank you for your time.

Operator: Thank you for your participation in today’s conference. This does conclude the program, and you may now disconnect.