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Good day. And thank you for standing by. Welcome to the Q1 2025 Comstock Resources Earnings Conference Call. At this time, all participants are in listen-only mode. After the speaker's presentation, there will be a question and answer session. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

All right. Thank you for the introduction. Welcome to the Comstock Resources Q1 2025 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 presentations. There you'll find a presentation entitled, quote, First Quarter 2025 Results. I am Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investment Relations. Please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meanings 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. On Slide 3, we're going to summarize the highlights of the first quarter. But before we start in the financial results, I'd like to make a few opening comments. First of all, most if not all of you know Jerry Jones and his family own 71% of Comstock. And, yes, he loves football and his Dallas Cowboys. But you need to know now that he's rediscovered his great love for basketball, especially players named Olajuwon. Now, as we review the first quarter 2025 results today, I would like you to focus on what should be the holy grail that every E&P company is seeking to create long-term shareholder value. Drilling inventory is that holy grail. For the past five years, we have chosen to pursue exploration to find our holy grail. Growing demand for natural gas for power generation, for AI, and for feedstock for LNG has created a need for our emerging natural gas play in the Western Haynesville. Today, we will talk about our latest successful well, the Olajuwon, which is our first well drilled in Freestone County. Now, the Elijah Olajuwon, think about this, is 24.4 miles away from the closest producing western Haynesville well and almost 50 miles away from our furthest producing well to the south in Robertson County. The Olajuwon is further confirmation of our geologic work involving studying hundreds of well logs in 3D seismic to outline our new play. We have invested over a $1 billion to build and develop the 520,000 net acres comprising our Western Haynesville play. We turned the Olajuwon to sales about a week ago with the initial production rate of 41 million cubic feet per day. This major step out represents another milestone achievement in our efforts to delineate the western Haynesville. Our acreage has the potential to have thousands of future drilling locations in multiple benches in Haynesville and Bolger shells. The geologic success has been matched by our drilling group. They figured out how to drill and complete some of the deepest and highest pressure horizontal shell wells in the world. They have also materially reduced the cost of the wells and continue to adjust our drilling and completion design to maximize performance and well returns. We also are capturing more of the value chain by developing our own midstream for the Western Haynesville assets. Now, moving on to the financial results for the first quarter. Higher natural gas prices in the first quarter drove much improved financial results in the quarter. Our natural gas and oil sales grew to $405 million. We generated $239 million of operating cash flow or $0.81 per diluted share. Adjusted EBITDAX for the quarter was $293 million, and we reported adjusted net income of $53.8 million or $0.18 per diluted share. We resumed completion activities in late 2024, allowing us to turn 14 or about 11.3 net operated wells to sales since our last update with an average per well initial production rate of about 25 million cubic feet per day. Now, I'll turn it over to Roland to discuss the financial results reported yesterday. Roland?

All right. Thanks, Jay. On Slide 4, we cover our first quarter financial results. Our production in the first quarter averaged 1.28 Bcfe per day, which is 17% lower than the first quarter of 2024, reflecting our decision last year to drop two rigs early and our deferral of completion activity last year into this year. All the wells turned to sales in the first quarter were located in our Legacy Haynesville area. In April, the Olajuwon well was turned to sales in the Western Haynesville. With the substantial improvement in natural gas prices, our oil and gas sales in the quarter increased 21% to $405 million. EBITDAX for the quarter was $293 million. We generated $239 million of cash flow in the first quarter. We reported adjusted net income of $54 million for the quarter, or $0.18 per share, as compared to a loss in the first quarter of 2024. Slide 5, we break down our natural gas price realizations in the quarter. The quarterly NYMEX settlement price averaged $3.65 in the first quarter, and the average Henry Hub spot price averaged $4.27. 37% of our gas was sold in the spot market in the quarter, so the appropriate NYMEX reference price was $3.88 for our production. Our realized gas price in the first quarter was $3.58, reflecting a $0.07 differential from the NYMEX price and about a $0.30 differential from the reference price for the quarter. The high spot prices we had in the quarter were really only for a very limited number of days that we had in the quarter, and there was a lot of volatility around basis in the first quarter with the high spot prices. In the first quarter, we were also 54% hedged, which lowered our gas realized price to $3.52 for the first quarter. Given this high volatility in gas prices we had in the quarter, we did lose $16 billion on third-party gas marketing, which is mainly gas bought to fill our transport obligations. In Slide 6, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.83 in the first quarter, $0.11 higher than the fourth quarter rate. Our EBITDAX margin improved to 76% in the first quarter, compared to 73% in the fourth quarter of last year. Our production and advertisement taxes were up about $0.04 from our fourth quarter rate, all really driven by the much-improved natural gas prices. Our lifting costs were up $0.05 in the quarter, mainly due to the lower production level we had in the quarter, and much of our base lifting costs are fixed costs versus variable. Then our gathering costs were up $0.01 in the quarter, and G&A costs were up $0.01 in the quarter. In Slide 7, we recap our spending on drilling and other development activity. And we spent a total of $250 million on development activities in the first quarter. We drilled four or 3.9 net horizontal Haynesville wells and three or three net Bossier wells. We turned 11 or 8.3 net operated wells to sales in the quarter, which had an average initial production rate of 23 million cubic feet per day. In Slide 8, we recap what our balance sheet looked like at the end of the first quarter. We ended the quarter with $510 million of borrowings outstanding at our credit facility, giving us $3.1 billion in total debt, including our outstanding senior notes. The increase in borrowings from year end is mainly due to working capital changes, as our drilling and completion activities were covered by operating cash flow in the quarter. When natural gas prices increase a lot, our actual collection of those really is out a couple of months from when we accrued the sales, so we'll see those working capital changes kind of turn around as the year progresses. We did just complete our spring borrowing base redetermination, and our borrowing base was reaffirmed on April 29 at $2 billion, and our elected commitment under the credit facility remains at $1.5 billion. With the improved natural gas prices that we're seeing for 2025 and a strong hedge position, we do expect our leverage ratio to continue to improve significantly as we report the 2025 financial results. At the end of the quarter, we had about $1 billion of liquidity. And now I'll turn it over to Dan to kind of discuss our drilling results in more detail.

Okay, thanks, Roland. If you look over on Slide 9, this is just an overview of our acreage footprint position in the Haynesville and Bossier Shales in east Texas and north Louisiana. We have now 1.1 million gross and 822,000 net acres that are prospective for commercial development of the Haynesville and Bossier Shales. If you look over on the left, this is our emerging Western Haynesville acreage, and on the right is our Legacy Haynesville area. Since we began our leasing program in the western Haynesville in 2020, we've grown our acreage position to 520,000 net acres. We still have around 1,300 net locations to drill on our 302,000 net acres in the legacy Haynesville, which currently has 904 net-producing wells. Our Legacy Haynesville acreage is 48% developed for the Haynesville and 9% developed for the Bossier. In comparison, our Western Haynesville has only 19 net-producing wells and is virtually undeveloped compared to our legacy Haynesville. Given the higher pay thickness and the pressures we encounter in the western Haynesville, we expect the Western Haynesville to yield significantly more resource potential per section than our Legacy Haynesville well. On Slide 10 is our updated drilling inventory. That's the end of the first quarter. The total operated inventory now stands at 1,527 gross locations and 1,197 net locations. This equates to a 78% average working interest. And then our non-operated inventory, we have 1,114 gross locations and 138 net locations, which represents a 12% average working interest. The drilling inventory is split between the Haynesville and Bossier. And in our four categories, we now have gross operated inventory. We have 49 short laterals, 331 medium laterals, 569 long laterals, and 578 extra-long laterals. This gives us 75% of our laterals are now greater than 8,500 feet long. And the inventory is split evenly 50-50 between the Haynesville and the Bossier. The drilling inventory also includes our 113 horseshoe locations that we've identified, and these are also split 50-50 between the Haynesville and the Bossier. The average lateral length now stands at 9,601 feet, which is basically unchanged from the end of last year. This inventory provides us over 30 years of future drilling locations based on our current activity levels. On Slide 11 is a chart that outlines our average lateral length that we drilled based on the wells that we have drilled and have reached total depth. The average lateral lengths are shown separately for both our Legacy Haynesville and our Western Haynesville acreage areas. In the first quarter, we drilled three wells to total depth in the legacy Haynesville, and these wells had an average lateral length of 12,903 feet. The individual lengths ranged from 9,673 up to 15,023 feet. The record longest lateral on our Legacy Haynesville acreage stands at 17,409 feet. Also in the first quarter, we drilled 4 wells to total depth in the Western Haynesville, and these wells had an average lateral length of 10,728 feet. The individual lengths on those wells range from 9,100 feet up to 12,045 feet. Our longest lateral drill to date on the Western Haynesville acreage has a lateral length of 12,763 feet. Just kind of summarizing on the long lateral activity, we now drill 117 wells with laterals longer than 10,000 feet, and we have 44 wells that have laterals over 14,000 feet. On Slide 12, this outlines the wells that have been turned to sales on our Legacy Haynesville acreage since we last reported earnings. So far this year, we've turned 13 wells to sales on our Legacy Haynesville acreage. The individual IP rates range from 16 million a day up to 37 million a day, with an average IP rate of 24 million a day. The average lateral length was 12,367 feet, and the individual laterals ranged from 90 to 52 up to 17,409. During the first quarter, the wells we turned to sales were more focused in the Legacy Haynesville area compared to the fourth quarter, where our completions were focused in the Western Haynesville after we resumed our completion activity that followed the third quarter frac holiday. We do have three of our seven rigs currently drilling on our Legacy Haynesville acreage. Slide 13 outlines the one well that we've turned to sales on our Western Haynesville acreage since we last reported earnings in February. The Olajuwon 1H well was turned to sales early last month. This represents our first step-out test to the northeast up into Freestone County. This well is located 24 miles away from our nearest producing well. The Olajuwon well was completed with a 10,306-foot lateral, and the well was tested with an IP rate of 41 million cubic feet per day. So four of our seven rigs are currently running on the Western Haynesville acreage. Slide 14 highlights the average drilling days and the average footage drilled per day in our Legacy Haynesville area. In the first quarter, we drilled three wells to total depth in the legacy Haynesville, and we averaged 26 days to total depth. This is an increase of three days compared to the fourth quarter, but is unchanged from the 2024 full-year average of 26 drilling days. The additional drilling days we experienced in the first quarter compared to the fourth quarter was due mainly to the longer lateral inks. We drilled in the first quarter compared to the fourth quarter. I think the average lateral length was 2,000 feet longer in Q1. In the first quarter, we averaged 1,027 feet drilled per day, which represents a 1.5% improvement over the fourth quarter and a 12% improvement over the 2024 full-year average of 920 feet per day. Since 2017, our footage drilled per day has increased by 51%. The best well drilled to date on our Legacy Haynesville acreage was an average of 1,461 feet per day, and we drilled it to TD in 14 days. Slide 15 highlights the ongoing progress we've achieved in our drilling times in the Western Haynesville. During the first quarter, we drilled four wells to total depth in the western Haynesville to give us a total of 25 wells that we've drilled to total depth through the end of the first quarter. Since we sped our initial well in the fourth quarter of ‘21, we have seen significant and continuous improvement in our drilling times. Our first three wells were drilled in 2022, and we averaged 95 days to reach TD. This average dropped to 70 days in 2023 and dropped again to 59 days for the 2024 full-year average. We averaged 55 drilling days for the four wells drilled to TD in the first quarter. This is a decrease of four days compared to the 2024 full-year average of 59. That reflects an increase of six days compared to the fourth quarter. Most of the increase compared to the fourth quarter can be attributed to the lower efficiency of mostly single wells we drilled in the first quarter compared to the two well pads we drilled in the fourth quarter. Also, during the first quarter, we drilled our fastest well to date in the western Haynesville at 37 drilling days. This record well was drilled with a 12,045-foot lateral. This represents a 50% reduction compared to our first well that was drilled to TD in 74 days. This progress is also reflected in the average footage drilled per day. Our first three wells in 22 averaged 281 feet per day, which is improved to the current average of 524 feet per day in the first quarter. Our record fastest well drilled at 741 feet per day. And just some of the primary factors behind the improved drilling performance includes the shift of drilling over two well pads, our improvement in our casing designs, the utilization of the insulated drill pipe, and we've just had better downhole performance from our bottom hole assemblies as we continue to drill more wells. On Slide 16 is a summary of our D&C costs through the first quarter for our benchmark long lateral wells located on our legacy acreage. These represent all our wells that have laterals over 8,500 feet long. Our drilling costs are based on when the wells reach TD. This better aligns with when the drilling dollars are being spent, and our completion cost per foot continues to use the turn to sales date. During the first quarter, we drilled three wells to total depth. The first quarter drilling cost averaged $523 a foot. This is a 21% decrease compared to the fourth quarter. Most of this can be attributed to drilling longer laterals in the first quarter. As two of these three wells were drilled to TD, as two of the three wells were 15,000 foot laterals. Also during the first quarter, we turned 11 wells to sales on our Legacy Haynesville acreage. The first quarter completion cost came in at $855 a foot. This is just a 1% decrease compared to the fourth quarter. As we look ahead, we're anticipating our D&C costs on the Legacy Haynesville acreage will stay flat to slightly lower through at least midyear. Our pipe prices also started coming down late last year, and we expect to maintain these lower cost levels through midyear and into the third quarter. Our cost expectations in the back half of the year further out are a little more uncertain, just with the potential for the uptick in activity, coming from the higher gas prices and still some lingering potential impacts from the ongoing tariffs. We currently have three rigs running again on our Legacy Haynesville acreage. Slide 17 is the summary of our D&C costs through the first quarter for all the wells drilled in the Western Haynesville. For the Western Haynesville, our drilling costs are also based on when the wells reached TD. And then our completion costs are based on when the wells return to sales. So during the first quarter, we were able to carry forward the really great progress and the results we achieved during the fourth quarter of last year. During the first quarter, we drilled four wells to total depth in the Western Haynesville. The drilling cost averaged $1,374 a foot. This represents a 2% decrease compared to the fourth quarter. And contributing to this performance was drilling our record fastest well in the first quarter that we drilled the TD in 37 days. Since drilling our first wells in 2022, our drilling cost has now decreased by 34% into the first quarter. We did not have any wells in the Western Haynesville that returned to sales in the first quarter. We continue to have superb execution from our frack crews, and the two well paths have allowed us to be much more efficient with the crews. We've also started implementing the use of natural gas diesel blend to fuel our frack fleets, which has also led to additional cost savings and less emissions. All the exploratory capital we spent during the early time frame of our program has definitely allowed us to significantly expand our knowledge base of this area. We've zeroed in on a good well design, and we continue to improve upon our job executions. And again, we've got four rigs running in the Western Haynesville of our seven rigs. On Slide 18, we're going to highlight our continued improvement related to greenhouse gas and methane emissions. For 2024, we reported a greenhouse gas intensity of 2.5. This is kilograms of CO2 equivalent per BOE of production. This is a 28% improvement versus 2023 and 28% over the past two years. We reported a methane emission intensity rate of 0.039%. This is a 2.5% improvement versus 2023 and a 14% improvement over the last two years. We achieved those emissions despite our increased focus on the higher intensity Western Haynesville. On an absolute basis, our CO2 emissions decreased to 174,000 metric tonnes in 2024. This is down 44% from the 2023 levels and 39% over the last two years. In addition, our methane emissions decreased to 5,499 metric tonnes in 2024. This is down 3% from 2023 and down 11% over the last two years. We have deployed optical gas imaging and aircraft leak monitoring technology at 100% of our production sites, which has earned us the ability to certify our gas as responsibly sourced. Our natural gas and dual-fuel powered frack fleets eliminated 1 million gallons of diesel by utilizing natural gas, which offset approximately 2,000 metric tonnes of CO2 equivalent. Our dual-fuel drilling rigs eliminated 250,000 gallons of diesel utilizing natural gas, and this offset approximately 790 metric tonnes of CO2 equivalent. We've installed instrument error on 100% of our newly constructed production facilities, mitigating approximately 6,500 metric tonnes of CO2 equivalent. And lastly, we announced yesterday a partnership with BKV Corporation to study the potential to develop carbon capture projects at our Methylene Marquee natural gas treating facilities in the Western Haynesville. And these projects have the potential to significantly reduce our greenhouse gas emissions in the future. I'll now turn the call back over to Jay.

All right. Thank you, Dan. Thank you, Roland. If everyone please report to Slide 19, we will summarize our outlook for 2025. In 2025, we're primarily focused on building our great asset in the Western Haynesville that will position us to benefit from the longer-term growth in natural gas demand. We currently have four operated rigs in the Western Haynesville to continue to delineate the new play. We expect to drill 20 wells and turn 15 wells to cells in the Western Haynesville this year. We'll continue to build out our Western Haynesville midstream assets to keep up with the growing production from the area. Midstream expenditures are expected to be between $130 and $150 million. They will all be funded by our midstream partners. In the Legacy Haynesville, we're currently running three rigs, as Dan said, to build production back up by the end of the year. And we expect to drill 25 or 20 net wells and turn 31 or 24.1 net wells to cells in our Legacy Haynesville this year. We anticipate funding our drilling program out of operating cash flow depending upon natural gas prices and use. We continue to have the industry's lowest producing cost structure and expect drilling efficiencies to continue to drive down drilling and completion costs in 2025 in both the Western and Legacy Haynesville areas. As Roland said, we have strong financial liquidity totaling almost $1 billion. We have several slides that provide some specific guidance for the rest of the year. So, if you want to discuss that, please reach out to Ron Mills to discuss. We'll now turn the call back over to the operator to answer questions from analysts who follow the company.

Thank you. At this time, we will conduct the question-and-answer session. [Operator Instructions] Our first question comes from Derrick Whitfield from Texas Capital. Please go ahead.

Good morning, all, and thanks for your time.

Good morning. Thank you.

I have two questions, and they're both related to the Western Haynesville. As you've noted in your prepared remarks, the Olajuwon well is a material step out for you guys. Maybe perhaps for Dan, could you just directionally speak to reservoir quality there versus the wells you drilled to the south? And then quantitatively speak to the amount of your position you've now delineated following this well result?

Yeah, so the well is 24 miles away from the nearest well we have. Probably all the way down to the other end of where we drilled our wells, you can probably double that. Probably almost, I'd say, 45 miles down into Robertson County. So as far as the reservoir quality, the reservoir quality in the Olajuwon looks, I'd say, every bit as good as the ones we drilled down in the core area. It looks really good. It is a Haynesville well, not a Bossier. We've got good thickness there. And we did, of course we drilled the Olajuwon in that area for a reason. Because we had some nearby well logs that had drilled through that section years ago that we were able to look at, and we could see the reservoir quality. So we weren't drilling totally blind up there, but the logs looked really good. That's why we targeted the Haynesville. And, of course, the well results have supported what our expectations were. It looks really good. As far as the area up there, I mean, that's up on the northeast end of our footprint. And so, I mean, I think that kind of that -- I hadn't really figured the percentage of the acres. I think maybe as much as asking, Derrick, but a substantial chunk of our acreage up on the northeast end looks, I'd say is definitely puts it in play and greatly de-risked that entire area up there.

One other comment, Derrick. We were initially looking to drill a Bossier well. We thought the thickness of the Bossier would be a little thicker than what we drilled, but we deepened the well. The Geological Group thought we should go ahead and deepen that well since we were 24.4 miles away, and we did deepen it. And just like Dan said, the rock quality was exemplary.

And we do -- we have additional wells obviously, that are on the drill schedule plan to further drill up in that area.

And, again, not to put a firm number. But, I mean, it looks like eyeballing, it's like 40% to 50% of your position and arguably some of the riskier parts as it relates to being deeper that you've delineated now across your position. I mean, is that a good kind of spitball if you will?

Yeah, I'd say, yeah, I'd somewhat agree with that. The depth of the well was probably maybe about 1,000 foot deeper. This was about a 17,500 foot well. Up here where this well is located compared to the deepest ones we've drilled 18.5 -- between 18.5 and 19 at the very, very high end or deep end however you want to look at it. So, this looks really stout. I mean, we couldn't be happier with it.

If you look on the map and you go kind of east and west, and you look where the Olajuwon well is, we probably have control of most of the acreage for about 30 miles. That's the, if you look on the map, I mean, that's the broader part of our acreage position.

That's great. And then, as my follow-up, I wanted to see if you guys could speak to the structure of the BKV partnership and the value you see in this arrangement. I mean, from our view, the market appears to value lower carbon intensity power solutions based on the recent Chevron and ExxonMobil announcements. And again, while you guys aren't in the power business, I suppose there's a scenario where you could co-locate a CCGT on site and offer a lower CI power solution to a data center or industrial client. Is that really the aim here?

Yeah. Derek, this is Roland. Yeah, that is the aim. That's one of the reasons why we were excited about. The partnership with BKV, who has already has a proven track record here and has a very successful project in the Barnett Shell with their Barnett

We had looked at Chris and his group at BKV. We'd been watching them before they went public and afterwards. And we actually toured their injection well in the Barnett. And the whole group is Tier 1. And we said, our Western Haynesville is similar in size to what they're doing at the Barnett. They've already got a proven model. We like the people. They're really great people. So, we have mutually said, let's go forward. And, if we can have zero emissions and BKV can do the carbon capture, then I think one day, one, two, we win. And just like, Derrick, your question, I think we'll be more attractive for exporting gas overseas with zero emissions. I think that's the next step.

That's great. Thanks. I'll turn it back to the operator.

Thank you. Our next question comes from Kalei Akamine from Bank of America. Please go ahead.

Hey, good morning, guys, Jay, Roland, Dan. Look, I like basketball, too, and the Rockets are still alive. So, I also got one on the Olajuwon step out here. I think I have to imagine that given the success that you've seen at the Olajuwon, that you're anxious to test other parts of the position. When do you think we should expect another result in this area? And then when you zoom out and look at the map, where do you plan to step out to next?

So, good question. We have the next well we're going to spud up in this area is going to be in Q4. And part of that, how fast we can actually step out up in this area as we have it is just getting the midstream built out and getting ahead of where the locations are, being able to get them into the gathering system. Obviously, a lot of the midstream dollars we've spent have been down where we've drilled all of the wells to date. So, you have to be ahead of these things on that side. So, you can't just get out here and start getting after it right off the bat because you have to wait on that part to get done. But we do -- like I said, Q4, we're going to drill a two-well pad up here, actually pretty close to the Olajuwon, pretty nearby, close to the infrastructure again like the Olajuwon was. And then next year, we've got more wells that will actually be fanning out much wider across that footprint up there. We've got eight wells, somewhere on the order of eight wells planned for up in that area in 2026.

Got it. I appreciate that. Next, I'd like to pick up on the comment that you made about picking up a spot rig later this year. I imagine that at a five-rig pace, you had some white space in the frag calendar. But at a seven-rig pace, those two crews are probably fully booked. So, the contribution from those two new rigs, I think, would be ready by sometime before the end of the year. So, the question is, if you do pick up that spot crew, does that suggest that the upper half of full-year production guidance is still in play?

Yeah, we did recently add that seventh rig, Kalei, and that just went to work here in April. And we do have that rig just on a well-to-well type short-term basis. So, I think that's kind of expected. Most of the production from adding rigs, that rig and any rigs that we could add at this point in the year, it's not going to come on until next year. There's a really long cycle because we know we're going to want to drill multi-well paths. We're going to just put it in the completion queue. There's really not an activity level that we could add at this point in the year that would impact this year's production. But, yeah, we look ahead at 2026 and see a lot of increasing demand. And so we think it makes sense to add that rig here in April like we kind of talked about the last call.

And we still have two frack crews pretty much running full-time throughout the year. There may be a spot, maybe very infrequent, though that we have to pick up a spot third frack crew, but we pretty much could cover most of that still with the rig count we got with two frack crews, which I'll just say our frack crews that we got are really good, very efficient, so that's why we're able to do that.

Got it. Thanks, guys.

Thank you, Kalie.

Thank you. Our next question comes from Charles Meade from Johnson Rice. Please go ahead.

Good morning, Jay, Roland, and Dan.

Hello, Charles.

I want to ask one more question about the Olajuwon. Dan, I think you mentioned in your prepared comments that one of the reasons that you guys were, I guess, chose this location or were more confident in it is that you had some deep vertical well control there. I'm curious. I know that there was a lot of historical vertical development in this area, but how many other places, will having offset vertical well control? Will that be kind of the dominant variable on picking locations when you step out, or was that just kind of a one-time thing with the Olajuwon well?

So, we did -- when you do your first step out, obviously, you want to have as much control as possible. If you don't -- if you get away from the areas where you have well control, that's where we have to drill a pilot hole and log it and get that -- see what that section looks like. So, we did kind of know generally where we wanted to drill up here, but with the vertical well control we did have. We wanted to get something fairly close to kind of know for sure what the log quality was. And that is how we picked the first one. But all the future wells, obviously will spread out. And in some places we will be drilling, we will need to drill some pilot holes. As we get further away from those control points, just to control your risk, you need to drill those pilot holes and get some logs across them.

Charles, go back to the Circle M, that area we have the most well control, so that's why we drilled it where we drilled it, and then we marched that 23 miles up to the northeast, to the Leon well, the DeOrnellas wells. And then to answer your question, we thought we had better well control near the Olajuwon, so it's kind of a mirror image of the Circle M. We had 3D, we had well control, we didn't see a lot of static in the 3D lines, et cetera. So, you have to go back and almost ask the question, why did you drill it? I mean, that was 24.4 miles. Even at the time we decided we wanted to drill it, we were probably 30 miles away from our closest producer. But the goal, and we keep telling you and the world is, we do trust our geological department, we trust the operations department. And we really want to de-risk this 520,000 acre footprint as quickly yet as prudently as possible. And we did take a chance that the Olajuwon would be a great well. We didn't know that, but I do think that the results are transformational. We're glad we can report it. Another thing I think, Charles, is that even if you go back in February, we didn't really talk about the Olajuwon. We did some road shows. We didn't tout something. We said we're drilling a well. You almost had to go find that well. And once we could report it, then we'd tell you the truth about it, whether it's good, bad, or ugly. And this happened to be great. So that's how we go about it. And when we decided to do the Olajuwon, gas was probably $1.90. I mean, this was many, many months ago we elected to go ahead and drill this well.

That's a helpful elaboration, Jay. And then perhaps following up on that idea of de-risking more of the position. It looks to me, I'm not looking at any kind of contours or anything, but it looks to me that if you look at the wells you've drilled and the permits that you have. It's mostly along that, what looks like that kind of southwest-northeast strike axis. And so I'm wondering, is that in fact the case? And if it is, when or what's the right time to push it -- push the de-risking kind of in a northwesterly up-dip direction?

Well, when we started five years ago, you have a blank sheet of paper like you're in kindergarten. You've got a sheet of paper. There's nothing on it. And then all of a sudden we look and say, well, maybe we should drill this Circle M well. Now, all that acreage that you see that we present, we didn't own any of that. And we said, okay, let's drill the Circle M. Well, as you progress, it's almost quarter-by-quarter, year-by-year, we're able to buy the big position from Legacy Reserve, which had Pinnacle. Well, we didn't know if the Pinnacle plant in that 145-mile high-pressure pipeline, whether it was located at the right spot. But we did know that the logs that we had showed that on the, there was a boundary kind of on the east side. And we did, with our hundreds of land men, we did find out that that was unleased. So you go and you aggressively, yet prudently, grab what is unleased. And then if you can add HPP to acreage, which most of that is to the west. So 80%-plus of our acreage is HPP, but we didn't add that HPP acreage. It was March of last year we added 185,000 net acres. It was probably first quarter we had another 62,000 net acres. So the acreage that you're seeing to the west, most of that's HPP. So we've said over and over, we've got to drill about 70 wells to hold acreage that we leased in this 520,000 net acre plate. So we have focused most part of drilling to hold acreage, and then we'll deviate over and drill some of the HPP acreage. Now, we will, we've had one pilot well core, and we've got a second one that we're working on right now. So as we go through 2025, 2026, we would like to have a core of our own on all four corners of the footprint and a few in the middle. And that will tell you the answer to the question that Derrick asked, what is the rock quality? Well, we're going to know that with the cores.

That is helpful detail. Thank you, Jay.

Sir, thank you.

Thank you. Our next question comes from Jacob Roberts from TPH & Company. Please go ahead.

Good morning.

Good morning.

Maybe a bit of a macro question, but if we see gas prices cooperate to the end of the decade, how many rigs do you envision the western Haynesville being able to support over that time frame? And maybe as a side card of that, is there an internal view to take a more method -- a more methodological approach to growth and target high single digits or low double digits to the end of the decade?

I think if you have -- all of this except like 6000 acres is undedicated. So I think you have to look at that and say, well, we're going to we're going to probably connect 15 or 20 new wells to sales. And then, as Dan mentioned earlier, when Derrick or maybe Kelly asked the question of how many more wells you can drill around a large one. Fortunately, we have an incredible partner in Pinnacle with Quantum. So we do control a budget for our gathering. And then the question was asked about how about the data centers, et cetera. I think we'll be able to control it. We will never have to drill a well that we shouldn't be drilling. We'll never oversupply the market because, of course, we have to drill wells. I think you will see us very prudently develop this and de-risk all four corners in the middle of it with the Pinnacle Gas Services, which makes our wells far more economic. And I think that'll serve data centers. I think you're going to see, we're 100 miles away from Dallas, 100 miles away from Houston. We're where you should have a data center. And I think with BKV and the carbon capture, we're going to be far more attractive for companies that will look to approach us. And we're already in discussions with them to create the data center, which goes back to this power demand. I think we're going to be able to fulfill our share of the power demand. And you look and you say, well, is it real? You always say, where's Waldo [ph]? Is this real? Do you really need this gas? And we looked in the world's largest electric utility this week, said that U.S. power demand will probably grow by 450 gigawatts at 71 Bcf of gas, which is what? That's 75 gigawatts with gas fire. That's 12 Bcf of new gas that's needed. You've got Woodside announced it can probably have 2 Bcf by 2029 or ‘30. Current permitted LNG projects are about 17 B. So this is a great question. Where are you going to get that gas? We think that Appalachia is constrained. You'll get 1 B or so. I think the permit, you don't drill there for gas. This is this core area why we work really hard and fought hard to de-risk this stuff, to deliver it to you when we need to. So we're always going to protect the balance sheet, but we're going to de-risk this thing and take risks to de-risk it just like the Olajuwon.

Great. I appreciate the answer. The second question kind of circling back to Freestone and some of the comments you all made about timing it perhaps with the midstream build out as we progress in the Q4 and the 2026. Is there anything we should be thinking about on the Olajuwon in terms of flow rate versus the IP rate or if that dynamic will apply to any other wells planned for this year?

The flow rate on the Olajuwon, we're flowing it basically the same type curves that we've got set up for all the wells back to the core. I don't think anything on the midstream side is going to constrain us on the ability to flow them how we want to flow them. We just need to be able to get the midstream in place to be able to drill these, which is why we're not splitting another well up there until the end of this year and really mostly into next year. The well looks as good as everything else we have. We're going to flow it the same as the other wells we have. We don't have any constraints on the midstream side.

Excellent. Appreciate the time.

Thank you. Great questions.

Thank you. Our next question comes from Carlos Escalante from Wolf Research. Please go ahead.

Hey, good morning, gentlemen. Thank you for taking my question.

Good morning.

Good morning. So considering that 2025 is an HBP-driven program, so to speak. If I jump forward to 2026, what is your underlying assumption for that year's program in terms of capital allocation in between HBP-exclusive wells versus delineator-slash-appraisal wells? I think that to conclude the question, it would be tremendously helpful to understand and parse out the general geography of where these HBP wells are and their underlying impact to the perception of those well results as we move through the next 24 months.

Yeah. We still want to focus on when we drill a well in the Western Haynesville into holding acreage. Remember, we have that 70 wells or so to hold this acreage that we leased versus the acreage we acquired that's held by the shallow production. So, that will always be a big priority over anything else. And the proximity and availability of midstream and acreage are for the next -- '25, ‘26 to both be similar. Those will be the main drivers to where they drill these wells.

Yeah. Thank you, Roland. I maybe should have clarified that. I was asking specifically about the Western Haynesville not to --

That is the Western Haynesville, right?

Yes.

I would say Legacy Haynesville, we don't have any acreage to drill to hold, so that's very price-driven, and takeaways. There are areas that the takeaway is more difficult in the Legacy Haynesville. There are different costs of the transport in the Legacy Haynesville, so we take that into account. But generally, we fill in the Legacy Haynesville locations. And since we haven't been that active there, we're actually able to go back into some of our higher-performing areas with the rig we just added and drill in the Legacy Haynesville around that since we've created a lot of space about letting production kind of fall in that area.

Yeah. Thank you, Roland. Appreciate it. My second question is, turning to the macro real quick, and perhaps using one of the prior questions as a segue, would you be concerned at all if permitting around the Permian, even though you rightly point out, Jay, those wells are drilled for the oil, but unfortunately have a ton of associated gas. Simply, they don't have the necessary takeaway capacity to the necessary demand center. So, would you all be concerned, or what do you view that Permian gas if there was an outlay for that gas from additional permitting at the government level that would take more of that molecule towards the Gulf Coast or the general demand area? Is that something that you're thinking about or concerned about at all?

I think that's all expected as far as the -- I mean, obviously, the Permian gas supply has to grow in order to fill the big demand pool that's coming from LNG and other power generation. So, yeah, that's going to be a big contributor. So, we do think that the weak oil prices today kind of stall a lot of the interest in drilling those wells since they are drilled mainly for oil prices.

Yeah, we do expect big growth.

Thank you, gentlemen.

Thank you. Our next question comes from Phillips Johnston from Capital One. Please go ahead.

Hey, thanks, and congrats. I wanted to ask you about the quarterly shape of your tills and just assess your confidence in achieving the large ramp-up in production in the second half of the year that your midpoint of the guidance implies. It looks like you brought on 11 tills in Q1 and are planning 12 to 14 or so in the second quarter. So, combined for the first half, that's about half the 46 wells or so for the year. So, the till cadence seems fairly rateable by quarter. I'm just trying to reconcile that with the fairly flat production level in the first half and then sort of the large ramp-up in the second half. Is that mainly a function of the timing of when those 12 to 14 tills occur here in the second quarter, or is it sort of a larger mix of Western Haynesville tills in the second half or some sort of a combination of those factors?

It's a combination of the both. I mean, the problem that till-related production models have is there's no way for people outside to know the timing of when those are brought on. And so, the tills in the second quarter look to be more second-half weighted. That's why you're starting to see the sequential production growth return in both the third and the fourth quarter. And then, it's just a function of the types of wells that we're drilling and that we are completing, at which time the third and fourth quarters, like you said, will be a similar amount of total tills as the first half, but the profile will look pretty similar to the first and second, where the third will be a lower number of tills and the fourth will be a higher number of tills --

Okay, perfect. Thanks, Ron.

And they come on during the quarter.

Yeah, okay. Appreciate that. And then obviously, it's pretty early days regarding the BKV agreement. I'm sure a lot of details need to be hammered out, and there's tax credits to consider and whatnot. But looking out in the future, would you guys expect any incremental costs incurred by Comstock or any sort of net capital outlays funded by Comstock?

No. Our partnership is basically they will get the tax credits, and they will make the capital outlays. And then we'll participate by receiving -- they'll purchase the CO2 from us. There will be a reduction in our operating costs, net-net. So, yeah, we don't see any big capital investment by Comstock.

Excellent. Thanks, Ron.

Thanks, Phil.

Thank you. Our next question comes from Greta Drefke from Goldman Sachs. Please go ahead.

Good morning, and thank you for taking my questions. My first one is on your lateral links. You've seen pretty consistently continued improvements across operations, particularly in the Legacy Haynesville. How much further upside do you see the laterals on a sustainable basis, and how would you characterize the applicability of these lateral links do you realize, in 1Q’25 going forward this year and into next?

So, in the Legacy Haynesville, yeah, we've gotten actually pretty long where we're at today. I don't see us getting a whole lot longer than this on average. I mean, we were at what -- just under 13,000 feet for Q1. Our longest from 17,000, we still have several 15,000 -- 14,000, 15,000 critters in our inventory. But when you just look at the mix of what we're going to be drilling as we go forward on the schedule. We're just getting pretty flat up there around that 12,000 to 13,000 foot average lateral length. So, I don't think you're going to see us continually, like, keep climbing higher than that.

The positive is, though, we will not have to drill a lot of the very short laterals for reasons because of the U-turn and horseshoe wells are now kind of replacing those. So, where we had those scattered in the drilling programs, and even last year, in the first part of the year, we had short laterals. Yeah, our averages should be a little bit better because we won't have the really short ones to weigh it down.

Right. And most of the horseshoe wells we'll be drilling, they're going to be, they're 9,500 foot, and we've got a few of them going to be a little bit longer than that. But as far as just the average, I think is what you were asking about going into the future, I think we're probably getting close to a plateau point.

Got it. I appreciate that color there. And then my second question is just on D&C costs. Do you think that there could be some meaningful pricing concessions on rigs or crews as we head towards 2026, just given the broader, more macro uncertainty, especially potentially also the implications from the oil macro more idiosyncratically?

Yeah, I think that's a really good question. And I think the answer is yes. Compared to -- if you would ask that question on the last call, obviously we're more optimistic we'll see some price concessions just with what we're seeing with the oil strip and where the activity may be headed in the Permian. And I think we'll see that across the board on all services, rigs, frack crews. I mean, obviously we got some of our rigs are turned up, but I think we'll see it on a lot of those smaller services beyond rigs and frack crews, I think where you'll probably get a more meaningful percentage drop in vendor costs there and also, hopefully on our pipe prices depending on what happens with the tariffs.

Got it. I appreciate it. Thank you.

Thank you.

Our next question comes from Noel Parks from Tuohy Brothers Investment Research. Please go ahead.

Hi. Good morning. Just have a couple. Looks like a pretty exciting quarter in terms of a Olajuwon well and everything going on. I guess I did want to ask about maybe just overall. So it used to be that before the shale era, rock that was too tight was off the table. And I'm just wondering, do you see there being plays now where formerly the thinking was, well, it's too deep and too hot that now could be available sort of to make a second wave in shale, given what you've demonstrated you've been able to do in areas that a lot of pretty much everyone dismissed is just not workable.

Yeah, I think we've obviously, I think, made some big inroads and I think a lot of people are looking at what we're doing and what we've been able to achieve with the depths and the temperatures. I don't think there would have been a lot of takers on trying to have a commercial development with these conditions just not too long ago. And I think with the price environment where it's headed over the next two years and the LNG demand, I can certainly see some people looking a little bit deeper than what they would have just a year ago.

Right, right. And you were talking about also the great improvement you had in just the drilling time on the Western Haynesville. And you listed using more pads, the drill pipe, but you also mentioned specifically casing design improvements and use of bottom hole assemblies. So I just wonder if you could just talk a little bit more about some details on the influence of those.

Well -- we've, so one thing I always kind of just preach around here is obviously consistency. We've had some great results and we obviously keep -- we just want to be very repeatable and predictable to be able to deliver that. And some of that then comes with time and practice. Practice just as you keep drilling wells, you keep getting better. The insulated drill pipe is basically shaved days off of drilling the lateral. I mean, obviously where we're deep and got a lot of high temperatures, our motors and MWD tools on bottom obviously things don't perform well when you put a lot of heat on them. So insulated drill pipe cools those temperatures down a little bit. It makes our motors and our tools just last longer. You don't have to make as many trips when you're drilling the lateral. So that's how you shave off days there. Casing designs, we've just basically been able to streamline downsize our sizes a little bit and just got a lot better at picking where our casing points are. So, bottom hole assemblies, just as we've drilled more wells and gotten more data on how the motors are performing, which motors perform better and basically how to tweak the designs on the motors for the temperature. We've just delivered better runs with that.

We looked at geology 30 years ago and said we thought the rocks were there. And then when the Joneses came in, he said I like to drill this Circle M well. I said, okay. So, you have to progress, progress, progress day to day to day, just like our relationship with you. And you have to handicap people and say, Tuohy does this, Comstock does that, et cetera, et cetera. And then you have to perform. You have to perform and you have to get in the game. And then once you get in the game, you've got to say, well, is that seismic real? Are those logs real? Is that core real? Can you really, how do you track these wells? And look at the performance. Our in-house reservoir group, they have to look at how hard do you draw these wells down? But this is a team sport of Comstock. You've got to have a big backer saying, I want to own something big. And you've got to have some breaks where you get this HPP acreage. You've got to know how much you have to spend in order to hold all that acreage. Like Roland said, we're going to drill our 70 wells. Then you've got to have some people join the team for financing, like Quantum. And then you have to get the gathering. And then you've got all this stuff. And then once you get a little bit comfortable in one area, you've got to jump out 24 miles somewhere else. Because it is a very hard-fought road. I don't think anybody, when gas was at a 30-year low except for COVID, was eager to jump in and drill the wells that we were drilling, which are some of the hardest in the world, when we drilled them last year. Nobody. We pushed the reset button on how to add inventory. We pursued exploration. That's what we did.

Great. Thanks a lot.

Thank you. This concludes the question-and-answer session. I will now turn it back over to Jay Allison for final remarks.

All right. Again, I want to thank all of you that are still here listening. And we respect your time. I want you to know that all 255 people here at Comstock, we relish and we're thankful for the incredible opportunity to unlock what we see as this tremendous wealth. We love the chance that everybody has given us. It was almost seven and a half years ago when Jerry Jones' family started supporting and investing in the company. And ultimately, they own 71% of the company, but they asked three questions at that time. This is seven and a half years ago, what does your drilling inventory look like? If you drill a well, can you turn it to sales immediately? And if LNG really materializes, can you use that natural gas as feedstock gas? Well, those same three questions is what we asked ourselves today over and over and over for this whole conference call. So we've really, really come a long way in the seven and a half years. But we want to thank you that are our equity owners, financial backers, and all the service companies we depend upon to create this value chain. Thank you.