Comstock Resources, Inc. (NYSE:CRK) Q1 2026 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q1 2026 Earnings Call Transcript May 6, 2026

Operator: Good day, and thank you for standing by. Welcome to Q1 2026 Comstock Resources, Inc. 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. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your first speaker today, Miles Jay Allison. Please go ahead.

Miles Jay Allison: Thank you, everyone. Thank you for joining us. Welcome to the Comstock Resources, Inc. 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 comstockresources.com and downloading the quarterly results presentation. There you will find a presentation titled First Quarter 2026 Results. I am Miles Jay Allison, chief executive officer of Comstock Resources, Inc. Here with me is Roland O. Burns, our president and chief financial officer, Daniel S. Harrison, our chief operating officer, and Ronald Eugene Mills, our VP of finance and investor relations. Please refer to slide two in our presentation and note that our discussions today will include forward looking statements within the meaning of securities laws.

While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If everyone would please go to slide three. On slide three, we summarize the highlights for the first quarter. Lower production, partially driven by production impact from significant winter weather in the first quarter, drove the lower financial results in the quarter compared to 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 returned to sales in the first quarter were very late in the quarter. Since our last update, we put six 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, 2026, 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 four. We are very excited about this development and what it means to have a large commercial customer in our backyard.

The project is part of Japan’s $550 billion investment commitment in the United States as part of the U.S.–Japanese trade deal. The U.S. and Japan would own the projects while NextEra Energy Resources will develop, build, and operate it. NextEra is actively developing the project, advancing site development, procurement, 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 gigawatts of natural gas fired generation capable of serving up to 5 gigawatts of large load demand. Comstock Resources, Inc. will provide the natural gas supply for the facility, which could reach almost 1 billion cubic feet per day by 2031.

We will now provide some more details on the financial results we reported yesterday. Roland?

Roland O. Burns: Alright. Thanks, Jay. On slide five, 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 are 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 six, we break down our natural gas price realizations in the quarter. The quarterly weighted average NYMEX settlement price averaged $4.96 in the first quarter, and the weighted average Henry Hub spot price was $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 that reference price. A significant disconnect existed during the quarter between the regional hub prices and NYMEX, which 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 seven, we detail our operating cost per Mcfe, and our EBITDAX per unit cost 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 cost 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 we recognized.

Overall, our EBITDAX margin in the quarter was 73%. On slide eight, we recap 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 net, horizontal Haynesville wells and six, or six net, Bossier wells for a total of 17 wells in the quarter, or 15.3 net wells. We turned 13 wells to sales, or 11.7 net wells, which had an overall average per well IP rate of 31 million cubic feet per day. Slide nine, we summarize our capitalization at the end of the first quarter. We ended the quarter with $350 million of borrowings outstanding under our upstream credit facility. Our upstream borrowing base is $2 billion, and our elected commitment under our facility is $1.5 billion.

In March 2026, we entered into a new $150 million midstream credit facility for Pinnacle Gas Services. At March 31, the midstream credit facility had $47 million outstanding. Our last twelve months leverage ratio was 2.9 times. At the end of the first quarter, we had almost $1.3 billion of liquidity. I will now turn it over to Dan to discuss our operations in the quarter.

Daniel S. Harrison: 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 874,868 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 within 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 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 operated inventory in the legacy Haynesville now consists of 955 gross locations, 740 net locations, which equates to an 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 four buckets. We have our short laterals less than 5,000 feet. We have our medium length laterals that are from 5,000 to 8,500 feet. Our long laterals between 8,500 to 10,000 feet. And our extra-long laterals are everything over 10,000 feet. So 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% in the Bossier. 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, and as of today, our average lateral length in 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 currently consists of 3,331 gross locations and 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 two-thirds of the inventory in the Bossier shale and one-third of the inventory in the Haynesville shale. And we also have our Western Haynesville inventory divided into the four separate groups by length, with our short laterals less than 5,000 feet, 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 do not have any short laterals today. We have 1,319 medium laterals, 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, it is an update to our new horseshoe development program. The horseshoe well design, of course, combines two separate and adjacent shorter laterals into a longer single lateral, which results in a much more efficient use of our capital. On average, we realized 35% savings in our drilling costs when we drill a 10,000-foot horseshoe well compared to two 5,000-foot sectional lateral wells. Our drilling inventory in our legacy Haynesville area now includes 114 horseshoe locations. The Camp Tech 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 in 2026.

On slide 14, there is a chart outlining our average lateral lengths drilled that are based on when the wells have been drilled to total depth. 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 five 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. To date, we have drilled 47 wells to total depth in the Western Haynesville, including 21 wells with laterals over 10,000 feet and seven wells with 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 a low 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 cubic feet per day up to a high of 41 million cubic feet per day, and the average IP was 31 million cubic feet per day. Five of our nine rigs are drilling on the legacy Haynesville acreage. Slide 16 outlines the six wells that we have turned to sales on our Western Haynesville acreage since the last call. These six wells had an average lateral length of 10,874 feet, with an average initial production rate of 29 million cubic feet per day, and we have four of our nine rigs 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 acreage, which represents a 3% increase versus 2025. Four of the wells drilled in the first quarter were our horseshoe wells, which do take a few extra days compared to our normal straight laterals. Slide 18 highlights our drilling progress in the Western Haynesville. During the first quarter, we drilled five 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 five wells drilled to total depth during the first quarter.

This is an increase of three days compared to the fourth quarter. You can see this is also reflected in the drilling speed of 478 feet per day during the first quarter, which is 4% lower than the fourth quarter. Aside from drilling issues we have, our quarter-to-quarter drilling performance in the Western 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 per 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 shorter average lateral length in the first quarter, a higher number of wells drilled, and more wells drilled in our East Texas area, which does require an additional casing string we use to isolate the localized over-pressured SWD zones in that area.

During the first quarter, we also turned eight of our benchmark long lateral wells to sales on our legacy Haynesville acreage. The first quarter completion cost came in at $652 per foot. This is a 9% decrease compared to the fourth quarter. This lower completion cost is due to a combination of using less horsepower, having higher frac efficiency, and with a slightly lower drill-out cost. We are currently running three full-time frac fleets. This is after we added our third frac fleet in January. We are adding a fourth frac fleet this month, and we are planning to maintain running four 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 are continuing to make good progress there.

As we accumulate more data and make further refinements, 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 for all our wells drilled in the Western Haynesville. During the first quarter, we drilled five wells to total depth in the Western Haynesville with an average lateral length of 10,356 feet. Our first quarter drilling cost averaged $1,534 per foot. This represents a 3% increase compared to the fourth quarter. During the first quarter, we also turned five wells to sales in the Western Haynesville that had an average lateral length of 11,177 feet. First quarter completion cost averaged $1,537 per foot, which is basically unchanged compared to the fourth quarter.

And 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 is much variability in the vertical depths and formation temperatures along with the lateral lengths. We are also implementing new performance initiatives that we expect will lead to further time savings and cost reductions. We have one of our existing Western Haynesville rigs being upgraded to a 10,000 PSI rating that is going to be available to us by late summer. With this upgrade, we will be able to increase our drilling speeds in both the vertical and horizontal hole sections, further reducing our cost. We also intend to test some new higher temperature 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 earlier that we 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. 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 and more predictable cost structure for our future wells.

I will now turn the call back over to Jay.

Miles Jay Allison: Alright, Dan. Thank you. Roland, thank you. If everyone would please turn to slide 21. I know we are dealing in a ninety-day capsule on this call. I understand that. But the Comstock Resources, Inc. story over the past five years has been defined by our quest to add substantial drilling opportunities in the Western Haynesville, not just the last ninety days of 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 five-year period. Overall, our leases have favorable terms supporting our development program. And as a result of that program, over five years, not the last ninety days, we now have 2,546 net locations identified on our acreage.

We have been joined by three 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 the 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. Now our relationship with NextEra, which goes back to 2015, combined with our ideal locations and the drilling results that Dan just talked about in the Western Haynesville, led to the 03/19/2026 announcement 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 in Anderson County, Texas.

So our current goals for the company, they are 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 are fantastic performing wells. Currently, three of our five 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 Resources, Inc. Third, 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 buildout 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 the power generation hub opportunities. By controlling our midstream, we will be able to keep our producing costs low and capture the future value by owning the infrastructure. Pinnacle Gas Services is now in a position to have its separate credit facility. We believe we are nearing the end of a very strong process finding an equity partner to allow us to continue to grow our midstream footprint and to take advantage of future opportunities to connect Western Haynesville to premium markets. And finally, number five, which is what much of this conversation has been on, optimize the drilling and completion of our wells in the Western 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, and were drilled and completed with different methods and tools as Dan has gone on about. We have 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 tremendous natural gas value and wealth in the future. Now I want to thank you for your time today. There will be questions, and we will turn it over to Ron if you want to call in and ask Ron questions.

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. We did learn, and we understand. The thing that we did not want to do in our 700,000-plus acres in the Western Haynesville, which might have unprecedented wealth because it has been a wealthy basin twenty, thirty years ago, is to make the mistakes that were made in the legacy starting in 2010. That is 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—but that is what we are doing to create the value where we already possess it. We will now open the call for questions.

Q&A Session

Operator: Thank you. At this time, we will conduct the question and answer session. Please limit to one question and one follow-up. To ask a question, you will need to press star 11 on your telephone, and wait for your name to be announced. To withdraw your question, please press star 11 again. Please standby 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: Hey. Good morning, guys. Thank you for having us on. I appreciate the—

Miles Jay Allison: Carlos? How are you? Thank you for headlining cash burn and slow pace of resource delineation risk investor patience. I love that headline. That is why I brought it up in my narrative, because I think that is exactly right. That is not a negative. It is a positive, but it is 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.

Carlos Escalante: No, sure. And I appreciate you saying that and giving an overview on how you feel about the long-term value proposition. So why do we not start there? If you do not mind, maybe you can expand on your initial thoughts. You are dealing with a tough gas tape, as are all your other peers. On your current plan, as you mentioned, it 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 has not been in line with or aligned with what you stated the quarter prior? If you can frame that for us, that would be tremendously helpful.

Miles Jay Allison: Well, Carlos, I think, number one—and this is hard, you know? It is 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 is so confusing. But if you look at our business plan, yes, we did miss production in the quarter by, you know, 13%, whatever the number is, and our CapEx was higher. Well, if you have our business plan, which is 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 do not have M&A, the only way you can increase production—there will be a time lapse.

You know, it may be 90 days, 120 days, but there will be a lapse because if you are trying to protect your balance sheet last year, and you lay down one, two, three, four rigs, you are going to lose that production a year later. So what happens is it is a day of reckoning. We laid down the rigs. We did not do M&A. We kept adding a couple two or three thousand acres every month to 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, you know, we did sell $445 million of assets that, in our business plan, were not important to us in the next fifteen years. But when you do that, then you pay down that debt. And then what happens? Well, you are 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 will put some positive headline out there about the biggest data center in the U.S. I do not see that out there from some of you. But yes, we missed production, and CapEx was up a little bit. But if you do not do M&A and you do not 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. Now the corner is hard. You know, the ninety days is hard because you have to actually spend money on those four new rigs. You have to have these horseshoe wells really work. You have to have Daniel S. 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 pounds apart from each other, much less 20 miles in the east–west direction. So I think, Carlos, we have turned the corner. Now maybe the second quarter, because we did add that fourth frac fleet, the dollars that we took last year, we paid down our debt, and we are not doing anything radical to destroy value in the Western Haynesville.

And 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, and we do not even have to have those four. So the plan works. And, you know, in the past, Carlos, you would say, well, you bought another 15,000, 20,000 acres. There is another $200–$300 million. It kind of hit us on the nose for the quarter. We do not plan on that. We do not see that out there. We do not see it. We see one or two thousand acres every month. If we could get more, we would get it, but it is not out there to be taken. So that is where I think we have crossed the bridge. What we are talking about now is a bridge we have crossed. It is a hard bridge to cross.

We crossed it. Now let us look at where the future is going.

Carlos Escalante: Sounds great to me, Jay. Appreciate the answer on that. My follow-up will be to you, Dan. Can you talk briefly about the Hutter Rodell IP? It looks like it underperformed the broad group and really the initial production rates of all the wells that you brought online, the average of all the wells you brought online, in the basin. 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 high-quality IP rates in the Western Haynesville?

Daniel S. Harrison: That is a good question. I will give you the really quick answer, and then I can give you a little bit more. The short answer is: when you make a lot of water during flowback, it is hard to get high IPs. Of the 36 wells that we have produced, we have seven of them that we have drilled “uphill.” The laterals go basically up instead of going down. Most of them go down dip quite a bit just due to the geology. But the Hutter Rodell is the furthest one by far as far as the TVD difference between the heel and the toe. It is nearly 1,400 feet from the heel to the toe. The main reason we did not get a good IP on this well was the well made a lot of water during flowback—all during flowback we were making really high water volumes.

Same as wells in the core or no matter where we are at: if you are making a lot of water, it is just hard to get a high IP rate. So that is why we did not get a good IP rate on the well. We are still trying to triangulate and zero in on really whether it is more than just the geometry; it may be some geology involved. We did have our Brown TrueHeart BB well—it is about a mile away, but both were Haynesville targets. They both drilled uphill. The Brown TrueHeart did not go as far uphill, but it also made a lot of water during flowback. It got a little bit better IP because the water was not quite as high. Those two wells—the Brown TrueHeart BB and the Hutter Rodell—are in our deeper pay, those deeper TVDs, 17,500 to 18,500–18,800 range, and both of those wells made a lot of water during flowback.

Now we have drilled five wells up on our shallower acreage up in the 14,000 to 16,000–17,000 TVD range that also went uphill—not at 1,400 feet, but maybe up 600–700 feet from the heel to the toe. Those wells made a little more water during the initial part of flowback, but by the time we released flowback, the water volumes were down. So I am not going to 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 do not know if it is the sole reason. 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 is right there in line with those other two wells.

It is a Bossier as opposed to those being two Haynesvilles. We are going to have to see how that well responds to see if we can draw a conclusion that it is the geometry or if it is 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 is hard to get IPs. We probably had, out of the 36, three wells that made really high water volumes during flowback that greatly affected the IP rates.

Miles Jay Allison: And that is our platform.

Daniel S. Harrison: That is load water, that is not formation water. That is correct. We are drilling from one end to the other of the wells that we have tested so far—50 to 60 miles. That is like going from East Texas all the way down to the deep and active fault zone in Louisiana. That is a huge distance, and there is a lot of variability in what these wells are going to make and how much water they are going to make and how they will perform. Comparing the Western Haynesville to the core: in the core, we do not really have a lot of wells that go downhill or uphill—they are pretty much horizontally 85–95 degrees or maybe even a little flatter than that. In the Western Haynesville, it is different. We have a lot more dip that leads to these higher-angled wellbores.

Carlos Escalante: Understood. I will turn it back. Thank you, team.

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

Miles Jay Allison: That is a great question. If you look at all the dancing on the floor about AI, hyperscalers, all the things that are happening, and all the things that are not funded—you can consider that background noise. What has happened here is, if you have a hyperscaler in your office, most of them will say, I really like Texas. 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. But you have to have a location that works. If you can come out, like we have done in the Western Haynesville, and you are in a really great geographic location with a big footprint, the sky is the limit. The federal government comes in with an agreement with the Japanese.

The Japanese have committed this $550 billion. The federal government then will choose NextEra, and NextEra will choose where their site might be. It goes back to that 2015 relationship we have had with NextEra, and they said, we have done a lot of business in the past, we love the Western Haynesville, we have been out there; this is where we would like to have the data center and power hub. We do not own the surface. All we do, as far as dollars spent, is we provide the gas. The obligations to build and stuff like that—we do not have that. What we have is we provide them the gigawatts—the 5 gigawatts, the billion cubic feet per day, whatever it is. It may grow a lot higher than that—to fuel the turbines. So it is a really great event because it is at the United States government level, it is then at NextEra’s level, and it is our gas.

We are a natural gas company. So whatever the big package is for the benefits, which would be the profits—whatever they are—you just wait and open those up when everybody else has discussed what the terms will be and when you have your first power that is 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 what NextEra sees as a huge role for U.S. shale gas to power AI hyperscalers and data centers.

Charles Arthur Meade: Got it. Thank you, Jay, for that overview. And then if I could actually ask a follow-up about the Western Haynesville. I really like these maps—I am looking on page 16 where you give us the red dots on where your well results are. I am wondering if you could talk about the wells that are further up dip. If you could talk about what you are seeing as far as how the play changes. I am guessing you have probably lower D&C because it is less vertical depth, but what you are seeing with the productivity on those wells as you move up there also.

Miles Jay Allison: I am going to let Dan do that. I want to put a little asterisk on that, Charles. If you were to look at where we drilled in, you know, the Circle M in 2022—we produced it eight months in 2022, and then we started drilling in 2023, 2024, 2025. If you were to go where we have drilled several wells and you were to infill drill—when you could drill dozens and dozens, not hundreds of wells—then infill drill them, and you have gathering near there on that pad site, and you want to get costs down, you could do that. That is not part of our business plan either. That is why we went 40–50 miles to the north to drill that Elijah #1. We had seismic. We had well control—we have around a thousand penetrations in all this footprint we have—and then we have the seismic, and now we have cores.

Before we had the core, we would go north because the plan was—and that goes back to Carlos—you are going to have to have patience to delineate this. In one year, you jump 40–50 miles to the north. That is pretty quick delineation. They never did that in the core, not with any control. Our goal is to keep those rigs busy and, 99% of the time, to continue to hold acreage—not infill drill around existing known repeatable locations. It is a different business plan. Dan?

Daniel S. Harrison: I will definitely reiterate the last thing he said there. Of the locations we are drilling for the whole acreage, I would say more than nine out of every ten are to hold acreage. Those two dots you are looking at are actually two pads—the two Bumpers and two Pollard wells at that location. On each pad, we had a well to the north and a well to the south. One of the Bumpers goes north—the NMH goes north; the DHGJ goes to the south. Pollard PFG goes to the north, and the Pollard MBK goes to the south—holding acreage. After looking at well performance, we knew we were probably understimulating these wells. We needed to pump bigger fracs. All four of those wells were pumped with bigger fracs up in that area than what we had pumped on the offsets in that little area you are looking at.

All four wells look really good. I kind of spoke to two of those wells that went uphill when I was answering Carlos’ question earlier. We did not see big water volumes—maybe a little water in the first couple of days on flowback, but by the time we were off flowback and getting the well IP, they had pretty well dried up. They only go uphill there about 600–700 feet from the heel to the toe, and they look really good. All four of those we are really happy with. That is probably 14,000 to 16,500 TVD range on those wells—maybe the toe of the downdip wells closer to 17,000. It is less pressure, and they are cheaper to D&C. As a matter of fact, the record fastest, cheapest well to date—which we referenced as the record that we TD’d in 37 days—was a direct offset to one of those pads.

It is the Jennings pad—the Jennings LOR and the Jennings FSRA. The Jennings FSRA was right next to those wells. It was up dip. We drilled to TD in 37 days with some great motor runs. The EUR will be a little bit less just because you have less pressure and it is at a shallower depth, but we offset that with the faster drill and lower D&C cost.

Roland O. Burns: That is great color, Dan. Thank you.

Daniel S. Harrison: You bet. 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 Lee Whitfield: Good morning, all, and thanks for your time.

Miles Jay Allison: Morning, Derrick.

Derrick Lee Whitfield: Jay, I appreciate your bigger-picture comments to open up the call. Maybe, Dan, I wanted to start with you. As you think about 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 are successful as you think they will be?

Daniel S. Harrison: On rotary steerable, that is probably going to be deployed later in the Western Haynesville. We have had several runs so far in the legacy Haynesville. The system we are using—we probably started running it maybe five or six months ago—and we are still making some tweaks. It is a learning process. We have had some really fantastic runs to date with that rotary steerable tool. We have also had some that did not make it very far due to issues in the tool that they are getting tweaked. When they rolled out the same technology in the Permian Basin a few years ago, it took them 18–24 months to get this tool refined to where it was humming. It is not an overnight thing. The last basin these tools come to is the Haynesville due to the depths and temperatures.

We are super excited about the fantastic runs we have had, but we need to get more of those under our belt and with more consistency. Then we will roll it out into the Western Haynesville because that is a more difficult environment with temperatures. We have run several of them on each horseshoe well—super pleased with it. A lot of running room there. The 10k rig coming at the end of the summer—we are super excited. That is going to give us the ability to pump faster, more horsepower on bottom, better ROPs, knock some days off—pretty excited about that. Maybe the most exciting thing is this last well we drilled with big-hole laterals—8-1/2 inch bit size instead of 6-3/4. We needed a project that gave us the ability to drill a long lateral because you have to spend a lot more money before you ever get to the lateral—your casing strings up top have to be a whole size bigger, the casing has to be one size bigger.

Before you ever get to the lateral, you are in the red—you are a little more expensive. You have to have a longer lateral that you think you are going to drill faster to make up that and break even or come out even cheaper. We came out even cheaper than we expected. Our drill cost on that well was lower than any of the bars you see on slide 20 on our cost per foot—slightly lower. We also feel it is a little bit more predictable than what we have done in the slim hole, and we can slide and turn a little bit more effectively than we can in the slim hole. There are some intangible benefits that we think are going to help us. We just need to drill more of them. We are going to make some changes in the vertical to make that a little bit cheaper, but we are super excited about it.

We thought maybe we needed to drill 14,000–15,000 feet to have a breakeven versus the slim-hole laterals we have been drilling; we maybe only need to drill 11,000–12,000 feet for it to be cost-competitive with the slim holes.

Miles Jay Allison: And, Derrick, 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, we may be 80 miles away with another Haynesville, but it is not exactly the Haynesville that he is talking about today. They all are a little different, and that is why we saw a lot of value destroyed in the legacy Haynesville back in 2008–2011. Not only were there too many rigs drilling it, they had leases that were expiring, and then you had natural gas prices collapse. We look at all of that, and I love the point that you said the bigger-picture concept. We are planting a bunch of these seeds, and these trees are starting to grow up, but you cannot do it too fast.

Even though we are in an unprecedented bull market opportunity headed our way for LNG and data centers, I think our timing is going to be perfect for that, only because we are in the correct geographical location in America. That is the difference. If you own the basin—and yes, there are other companies out there drilling stuff, but they do not own what we own—you have to treat it differently. If it is valuable and precious, you have to treat it valuable and precious. That is exactly what we are trying to tell everybody today. Now, that may be the wrong type of candy in the candy store, and you do not like it. But that is what we are selling, and I will tell you the board is 100% behind it. Management and the Jones family—almost every day—they are in it.

They understand it. We would like to go quicker, but you cannot. You will get in trouble if you go quicker. I think, like Carlos asked too, we have turned that curve because it is production going down and CapEx going up that gives you indigestion. I have it too, and I know everybody does. But I think we have turned the 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. We did add that extra frac fleet. I see big sunshine out there.

Daniel S. Harrison: Derrick, did I answer your question?

Derrick Lee Whitfield: 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 is a big development that probably is not getting enough headline or time this morning. I did want to get back to Dan on another topic because I think this is also important in evaluating the play. Clearly, D&C optimization stuff you guys are working through now. But when you think about what you are seeing right now on restricted flowback testing to date, is that an optimization now that you are likely to turn as you progress development in Western Haynesville?

Daniel S. Harrison: Absolutely. We need to be pumping bigger fracs—better stimulation. With those bigger stimulations, the volume of rock that you are out there touching, you need to keep it all open. If you keep it all open, you are exposed to significant reserves. To keep it open, you have to have that really conservative drawdown. I would say we are probably even slightly more conservative on drawdown going forward this year than where we were in the last six months. If you get the bigger EURs, you get a lot better PV-10 values. If you still can get the volumes within the first couple of years, you are really not going to affect your rate of return—it is going to be about the same number. That is the answer. Significant resource in the ground—just due to the thickness and the pressures—you are out there touching a lot of reserves, and you have to keep those fracs open.

What you created, you have to keep open to extract those volumes and that value. So: bigger fracs, very conservative drawdown going forward.

Miles Jay Allison: And, Derrick, we put boots on the ground. Dan and other top-tier people in the drilling group—two weeks ago they went to Germany. They put boots on the ground at the Baker plant. Look and see it, touch it—how can we tweak it to make it better, quicker, faster? If they are offering to teach you and to show you what we need, and they are going to spend their own money developing what we need, then we go there. Whether it is Carlos, Charles, Derrick—all the questions—we love them. We are giving you our best. It comes out in words, in emotion, in what we have done for thirty-eight years. We give you our best, and we do not tell a weird story. This is a hard story. It is the greatest story, though. On the equity side, every share is precious. We treat it like it is precious.

Derrick Lee Whitfield: Perfect. Maybe just one more for the benefit of investors because many are thinking about it. Philosophically on guidance, when you provide guidance, should we think of that as a P50 with a little bit of risking—call it P45–P55 range? You guys are giving your best on the guidance and what you think you can execute against, but would love any color you could share on that.

Daniel S. Harrison: We give you our best guess based on what the expectations are from a drilling and completion timeframe. I would say the legacy has been a little bit more predictable to date than Western Haynesville. But with the bigger fracs and the more conservative drawdown, it is going to make guiding the Western Haynesville volumes more predictable looking forward than looking backward.

Miles Jay Allison: And pure volume—the Western Haynesville will take out some of the lumpiness.

Derrick Lee Whitfield: All makes sense. Thanks for your time, guys.

Miles Jay Allison: Great questions. Thank you, Derrick.

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

Leo Mariani: Hey, wanted to 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 are consolidating that. It is on your balance sheet. Wanted to get a sense: is that debt recourse to Comstock Resources, Inc. there? And then additionally, you have spoken about other financing needed at the Pinnacle level. I know you are attempting to take Quantum out, which I guess supposedly pays them. So is there additional equity as well that you are looking to raise at the Pinnacle level, or do you think you are going to be good with this credit facility for the near future?

Roland O. Burns: That is a good question, Leo. Yeah. We are running a process…