Comstock Resources - Earnings Call - Q1 2025

Transcript

Operator (participant)

Today, 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. To ask a question during this session, you need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Jay Allison (Chairman and CEO)

All right. Thank you for the introduction. Welcome to the Comstock Resources first quarter 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, "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 Investor Relations. Please refer to slide two 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 in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

On slide three, we're going to summarize the highlights of the first quarter. 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. 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 Olajuwon, think about this, is 24.4 mi away from the closest producing Western Haynesville well and almost 50 mi away from our father's producing well to the south in Robertson County. The Olajuwon is further confirmation of our geologic work involving studying hundreds of well logs and 3D seismic to outline our new play. We have invested over $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 mitone 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 Bossier Shale. The geologic success has been matched by our drilling group, who figured out how to drill and complete some of the deepest and highest pressure horizontal shale 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 we reported yesterday. Roland.

Roland Burns (President and CFO)

All right. Thanks, Jay. On slide four, 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 five, 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 million on third-party gas marketing, which is mainly gas bought to fill our transport obligations. On slide six, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged 83 cents in the first quarter, 11 cents higher than the fourth quarter rate. Our EBITDAX margin improved to 76% in the first quarter as 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 cost versus variable. Our gathering costs were up 1 cent in the quarter, and G&A costs were up $0.01 in the quarter. On slide seven, we recap our spending on drilling and other development activity. 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 3 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. On slide eight, 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 29th 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. Now I'll turn it over to Dan to kind of discuss our drilling results in more detail.

Dan Harrison (COO)

Okay. Thanks, Roland. If you look over on slide nine, this is just an overview of our acreage footprint position in the Haynesville, Bossier Shale 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 Shale. 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. On slide 10 is our updated drilling inventory as of 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. In 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. 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 with 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 four 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 drilled today on the Western Haynesville acreage has a lateral length of 12,763 feet.

Just kind of summarizing on the long lateral activity, we now drilled 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 our 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 9,252 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 the earnings in February. The Olajuwon number 180 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 mi 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. 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 lengths 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 averaged 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 we've drilled to total depth through the end of the first quarter.

Since we split our initial well in the fourth quarter of 2021, 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, but 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 2022 averaged 281 feet per day, which has improved to the current average of 524 feet per day in the first quarter. Our record fastest well drilled at 741 feet per day.

Some of the primary factors behind the improved drilling performance include the shift to drilling more two well pads, our improvement in our casing designs, the utilization of the insulated drill pipe, and we've just had better down hole 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 costs 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 mid-year. Our pipe prices also started coming down late last year, and we expect to maintain these lower cost levels through mid-year 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. On 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 are turned to sales. 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. Contributing to this performance was drilling our record fastest well in the first quarter that we drilled to TD in 37 days. Since drilling our first wells in 2022, our drilling costs have now decreased by 34% into the first quarter. We did not have any wells in the Western Haynesville that were turned to sales in the first quarter. We continue to have superb execution from our frac crews, and the two well pads 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 frac fleets, which has also led to additional cost savings and less emissions.

All the exploratory capital we spent during the early timeframe 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 execution. Again, we 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 CO₂emissions decreased to 174,000 metric tons 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 tons 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 frac fleets eliminated 1 million gallons of diesel by utilizing natural gas, which offset approximately 2,000 metric tons of CO₂ equivalent. Our dual fuel drilling rigs eliminated 250,000 gallons of diesel utilizing natural gas, and this offset approximately 790 metric tons of CO₂ equivalent.

We've installed instrument air on 100% of our newly constructed production facilities, mitigating approximately 6,500 metric tons of CO₂ equivalent. Lastly, we announced yesterday a partnership with BKV Corporation to study the potential to develop carbon capture projects at our Bethel and Marquay natural gas treating facilities in the Western Haynesville. 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.

Jay Allison (Chairman and CEO)

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 sales 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 million 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. We expect to drill 25 or 20 net wells and turn 31 or 24.1 net wells to sales 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. 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.

Operator (participant)

Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again.

One moment while we compile the Q&A roster. Our first question comes from Derrick Whitfield from Texas Capital. Please go ahead.

Derrick Whitfield (Managing Director)

Good morning, thanks for your time. 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?

Dan Harrison (COO)

Yeah. So the well's 24 mi away from the nearest well we have. Probably all the way down to the other end of where we've drilled our wells, you can probably double that, probably almost, I'd say, 45 mi down into Robertson County.

As far as the reservoir quality, the reservoir quality in the Olajuwon looks, I'd say, every bit as good as the ones we've drilled down in the core area. Looks really good. It is a Haynesville, not a Bossier. We got good thickness there. We did, of course, drill 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. We were not drilling totally blind up there, but the logs looked really good. That's why we targeted the Haynesville. Of course, the well results have supported what our expectations were. Looks really good. As far as the area up there, I mean, that's up on the northeast end of our footprint.

I mean, I think that kind of that I did not really figure the percentage of the acres, I think maybe is what you are asking, Derek, but a substantial chunk of our acreage up on the northeast end, yeah, looks, I would say, is definitely it puts it in play and greatly de-risked that entire area up there.

Jay Allison (Chairman and CEO)

One other comment, Derek. 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 mi away, and we did deepen it. Just like Dan said, the rock quality was exemplary.

Dan Harrison (COO)

We do, Derek. We have additional wells, obviously, that are on the drill schedule plan to further drill up in that area.

Derrick Whitfield (Managing Director)

Again, not to put a firm number, but I mean, it looks like eyeballing it's like 40%, 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?

Dan Harrison (COO)

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 TVD well up here where this well is located compared to the deepest ones we've drilled, between 18.5 and 19 at the very, very high end or deep end, however you want to look at it. This looks really stout. I mean, we couldn't be happier with it.

Jay Allison (Chairman and CEO)

If you look on a 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 acres for about 30 mi. If you look on the map, I mean, that's the broader part of our acreage position.

Derrick Whitfield (Managing Director)

That's great. As my follow-up, I want 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. 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?

Roland Burns (President and CFO)

Yeah. Derek, this is Roland. Yeah, that is the aim, and that's one of the reasons why we were excited about the partnership with BKV, who has already a proven track record here and has a very successful project in the Barnett Shale with their Barnett Zero project. We were impressed with that, impressed with their capabilities, and wanted to partner for them to be the lead there in developing a carbon capture and sequestration project for us there for our two plants. We think that makes our location about 100 mi from Dallas, 100 mi from Houston, the location next to gas storage, the vast gas resource we have in the Western Haynesville, then add a low carbon footprint to that.

It just makes it an ideal area, we think, for potential power generation facilities to support a data center in that area. That is all part of what we'd like to see. It is another piece in the puzzle that we're hoping to put together and develop that, but still a lot of work to do there.

Jay Allison (Chairman and CEO)

We had looked at Chris and his group at BKV. We'd been watching them before they went public and afterwards. We actually toured their injection well in the Barnett. That whole group is tier one. 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." We mutually said, "Let's go forward." If we can have zero emissions and BKV can do the carbon capture, then I think one they won and two we won. Just like Derek, your question, I think we'll be more attractive for exporting gas overseas with zero emissions. I think that's the next step.

Derrick Whitfield (Managing Director)

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

Operator (participant)

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

Kalei Akamai (Senior Equity Research Analyst)

Hey, good morning, guys. Jay, Roland, Dan. Look, I like basketball too, and the Rockets are still alive. I also got one on the Olajuwon step out here. 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? When you zoom out, look at the map, where do you plan to step out to next?

Dan Harrison (COO)

Good question. The next well we're going to spot up in this area is going to be in Q4. 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 and 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. You have to be ahead of these things on that side.

You cannot just get out here and start getting after it right off the bat because you have to wait on that part to get done. Like I said, Q4, we are going to drill a two well pad up here, actually pretty close to the Olajuwon, pretty nearby. It is close to the infrastructure again, like the Olajuwon was. Next year, we have more wells that will actually be fanning out much wider across that footprint up there. We have eight wells, somewhere on the order of eight wells planned for up in that area in 2026.

Kalei Akamai (Senior Equity Research Analyst)

Got it. I appreciate that. Next, I would 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 frac calendar, but at a seven rig pace, those two crews are probably fully booked. The contribution from those two new rigs, I think, would be ready by sometime before the end of the year. 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?

Roland Burns (President and CFO)

Yeah. We did recently add that seventh rig, Kalei, and that just went to work here in April. We do have that rig just on a well-to-well type short-term basis. I think that's kind of expected in our most of the production from adding rigs, that rig and any rigs that you could add at this point in the year.

It's not going to come on until next year. I mean, there's a really long cycle because we're going to want to drill multi-well pads. We're going to just put it into completion queue. There's really not activity level that we could add at this point in the year that would impact this year's production. We look ahead at 2026 and see a lot of increasing demand. We think it makes sense to add that rig here in April, like we kind of talked about the last call.

Jay Allison (Chairman and CEO)

We still have two frac 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 frac crew, but we pretty much could cover most of that still with the rig count we got with two frac crews, which I'll just say our frac crews that we got are really good, very efficient. It is why we're able to do that.

Kalei Akamai (Senior Equity Research Analyst)

Got it. Thanks, guys.

Jay Allison (Chairman and CEO)

Thank you, Kalei.

Operator (participant)

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

Charles Meade (Research Analyst)

Good morning, Jay, Roland, Dan.

Jay Allison (Chairman and CEO)

Hello, Charles.

Charles Meade (Research Analyst)

I want to ask one more question about the Olajuwon. And Dan, I think you mentioned in your prepared comments that one of the reasons that you guys were, I guess, chose this location or 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?

Dan Harrison (COO)

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.

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. That is how we picked the first one. All the future wells, obviously, will spread out. 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.

Jay Allison (Chairman and CEO)

You know, Charles, go back to the Circle M. That area we had the most well control, so that's why we drilled it where we drilled it. We marched that 23 mi up to the north-northeast to the Leon well, the Deornellis wells.

To answer your question, we thought we had better well control near the Olajuwon. It is kind of a mirror image of the Circle M. We had 3D. We had well control. We did not see a lot of static in the 3D lines, etc. You have to go back and almost ask the question, "Why did you drill it?" I mean, that was 24.4 mi. Even at the time we decided we wanted to drill it, we were probably 30 mi away from our closest producer. The goal that we keep telling you and the world is we do trust our geological department. We trust the operations department. We really want to de-risk this 520,000 net acre footprint as quickly yet as prudently as possible. We did take a chance that the Olajuwon would be a great well. We did not know that.

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. Once we could report it, we tell you the truth about it, whether it's good, bad, or ugly. This happened to be great. That's how we go about it. When we decided to do the Olajuwon, gas was probably $1.90. I mean, this was many, many, many, many, many months ago. We elected to go ahead and drill this well.

Charles Meade (Research Analyst)

God, that's a helpful elaboration, Jay.

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 what looks like that kind of southwest and northeast strike axis. I'm wondering, is that in fact the case? If it is, when or what's the right time to push the de-risking kind of in the northwesterly updip direction?

Jay Allison (Chairman and CEO)

When we started five years ago, you have a blank sheet of paper like you're in kindergarten. You got a sheet of paper. There's nothing on it.

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. We said, "Okay, let's drill the Circle M." 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. We didn't know the Pinnacle plant in that 145 mi high-pressure pipeline, whether it was located at the right spot. We did know that the logs that we had showed that there was a boundary kind of on the east side. We did, with our hundreds of landmen, find out that that was unleashed. You go and you aggressively, yet prudently, grab what is unleashed.

If you can add HBP acreage, which most of that is to the west. 80+% of our acreage is HBP, but we did not add that HBP acreage. It was March of last year. We added 185,000 net acres. It was probably first quarter, we added another 62,000 net acres. The acreage that you are seeing to the west, most of that is HBP. We have said over and over, we have to drill about 70 wells to hold acreage that we leased in this 520,000 net acre play. We have focused our most part of drilling to hold acreage. We will deviate over and drill some of the HBP acreage. We have had one pilot well, core, and we have a second one that we are working on right now.

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. That will tell you the answer to the question that Derrick asked, "What is the rock quality?" We're going to know that with the cores.

Charles Meade (Research Analyst)

That is helpful detail. Thank you, Jay.

Jay Allison (Chairman and CEO)

Yes, sir. Thank you.

Operator (participant)

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

Jacob Roberts (Director)

Good morning.

Jay Allison (Chairman and CEO)

Morning.

Jacob Roberts (Director)

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 timeframe?

Maybe as a side card of that, is there an internal view to take a more methodological approach to growth and target high single digits or low double digits through the end of the decade?

Jay Allison (Chairman and CEO)

I think if you have all of this except like 6,000 acres is undedicated. I think you have to look at that and say, "We're going to probably connect 15 or 20 new wells to sales." As Dan mentioned earlier, when Derek or maybe Kaley asked the question of how many more wells you're going to drill around Olajuwon, fortunately, we have an incredible partner in Pinnacle with Quantum. We do control a budget for our gathering. The other question was asked, "How about AI? How about the data centers, etc.?" I think that 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, quote, "You 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 Pinnacle Gas Services, which makes our wells far more economic. I think that'll serve data centers. I think you're going to see we're 100 mi away from Dallas, 100 mi away from Houston. We're where you should have a data center. I think with BKV and the carbon capture, we're going to be far more attractive for companies that will look to approach us. We've already been 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.

You look and you say, "Is it real?" You always say, "Where's Waldo? Is this real? Do you really need this gas?" We looked, and the world's largest electric utility this week said that U.S. power demand will probably grow by 450 gigawatts. That's 71 Bcf of gas, which is what? That's 75 gigawatts with gas fired. That's 12 Bcf of new gas that's needed. You got Woodside's announced they can probably have 2 Bcf by 2029 or 2030. Current permitted LNG projects are about 17 B. This is a great question. Where are you going to get that gas? We think the Appalachia is good to sprain. You'll get a B or so. I think the Permian, you don't drill there for gas.

This is this core area why we've worked really hard and fought hard to de-risk this stuff, to deliver it to you when we need to. We are always going to protect the balance sheet, but we are going to de-risk this thing and take risk to de-risk it just like the Olajuwon.

Jacob Roberts (Director)

Great. I appreciate the answer. My second question, kind of circling back to Freestone and some of the comments y'all made about timing it perhaps with the midstream buildout as we progress in the Q4 into 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?

Dan Harrison (COO)

The flow rate on the Olajuwon is, I mean, we're flowing at 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 spreading another well up there until the end of this year and really mostly into next year. No, I mean, the well looks as good as everything else we have. We're going to flow it the same as the other wells we have. I mean, we don't have any constraints on the midstream side.

Jacob Roberts (Director)

Excellent. Appreciate the time.

Jay Allison (Chairman and CEO)

Thank you. Great questions.

Operator (participant)

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

Carlos Escalante (Senior Associate)

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

Jay Allison (Chairman and CEO)

Morning.

Carlos Escalante (Senior Associate)

Morning. Considering that 2025 is an HBP-driven program, so to speak, if I jump forward to 2026, what is y'all's underlying assumption for that year's program in terms of capital allocation in between HBP-exclusive wells versus delineator/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.

Roland Burns (President and CFO)

Yeah. I mean, 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. That will always be a big priority over anything else. Yeah. That 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.

Carlos Escalante (Senior Associate)

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

Roland Burns (President and CFO)

That is the Western Haynesville. Right.

Carlos Escalante (Senior Associate)

Yeah.

Roland Burns (President and CFO)

Yeah. Obviously, Legacy Haynesville, we don't have any acreage to drill the hole. That is very price-driven. Takeaway is there are areas that the takeaway is more difficult in the Legacy Haynesville. There are different costs of the transport in the Legacy Haynesville.

We take that into account. Generally, we fill in the Legacy Haynesville locations. Since we have not been that active there, we are 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 have created a lot of space by letting production kind of fall in that area.

Carlos Escalante (Senior Associate)

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 do not have the necessary takeaway capacity to the necessary demand centers?

Would y'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 at all?

Roland Burns (President and CFO)

I think that's all expected as far as the, I mean, obviously, the Permian gas supply has to grow in order to fuel the big demand pool that's coming from LNG and other power generation. That's going to be a big contributor. 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.

Dan Harrison (COO)

Yeah. We do expect that growth.

Carlos Escalante (Senior Associate)

Thank you, gentlemen.

Operator (participant)

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

Please go ahead.

Phillips Johnston (Senior E and P Analyst)

Hey, thanks. And congrats. 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. Looks like you brought on 11 tills in Q1 and are planning 12-14 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 ratable 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 12tills-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?

Roland Burns (President and CFO)

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 the production is really you're starting to see the sequential production growth return in both the third and the fourth quarter.

It is just a function of the types of wells that we are 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.

Phillips Johnston (Senior E and P Analyst)

Okay. Perfect. Thanks.

Roland Burns (President and CFO)

On when they come on during the quarter.

Phillips Johnston (Senior E and P Analyst)

Yeah. Okay. Appreciate that. It is pretty early days regarding the BKV agreement. I am sure a lot of details need to be hammered out, and there are tax credits to consider and whatnot. 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?

Dan Harrison (COO)

No. Yeah.

Our partnership is basically they will get the tax credits, and they will make the capital outlays, and then we'll participate by receiving some—they'll purchase the CO₂ from us. There will be a reduction in our operating cost net-net. Yeah, we don't see any big capital investment by Comstock.

Phillips Johnston (Senior E and P Analyst)

Excellent. Thanks, Roland.

Roland Burns (President and CFO)

Thanks, Phil.

Operator (participant)

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

Greta Drefke (Equity Research Associate)

Good morning, and thank you for taking my questions. My first one is on your lateral lengths. 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? How would you characterize the applicability of these lateral lengths you realized in 1Q 2025 going forward this year and into next?

Roland Burns (President and CFO)

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 was 17,000. We still have several 15,000, 14, 15 thousand footers in our inventory. 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 foot-13,000 foot average lateral length. I don't think you're going to see us continually keep climbing higher than that.

Dan Harrison (COO)

The positive is that we will not have to drill a lot of the very short laterals for reasons because the U-turn and horseshoe wells are now kind of replacing those.

Where we had those scattered in the drilling programs, and even last year in the first part of the year, we had short laterals, our averages should be a little bit better because we will not have the really short ones to weigh it down.

Roland Burns (President and CFO)

Right. Most of the horseshoe wells we will be drilling, they are going to be 9,500 foot, and we have a few of them going to be a little bit longer than that. As far as just the average, I think, is what you were asking about going in the future, I think we are probably getting close to a plateau point.

Greta Drefke (Equity Research Associate)

Got it. I appreciate that color there. 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?

Roland Burns (President and CFO)

Yeah. I think that's a really good question. 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. 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 the smaller services beyond rigs and frack crews.

I think we'll probably get a more meaningful percentage drop in vendor costs there. Also, hopefully, on our pipe prices, depending on what happens with the tariffs.

Greta Drefke (Equity Research Associate)

Got it. Appreciate it. Thank you.

Roland Burns (President and CFO)

Thank you.

Operator (participant)

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

Noel Parks (Managing Director of Energy Research)

Hi. Good morning. Just have a couple. Looks like a pretty exciting quarter in terms of the lodge and one well and everything going on. I guess I did want to ask about maybe just overall. It used to be that before the shale era, rock that was too tight was off the table.

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 pretty much everyone dismissed as just not workable?

Dan Harrison (COO)

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.

I think with the price environment where it is 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.

Noel Parks (Managing Director of Energy Research)

Right. Right. When 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. I just wonder if you could just talk a little bit more about some details on the influence of those.

Dan Harrison (COO)

One thing I always kind of just preach around here is obviously consistency. We have had some great results. We obviously keep, we just want to be very repeatable and predictable to be able to deliver that.

Some of that comes with time and practice. Practice just as you keep drilling wells, you keep getting better. The insulated drill pipe has basically shaved days off 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. The insulated drill pipe cools those temperatures down a little bit. It makes our motors and our tools just last longer. You don't have as many trips when you're drilling the lateral. That's how you shave off days there. Casing designs, we've just basically been able to streamline and downsize our sizes a little bit, and we've just got a lot better at picking where our casing points are.

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.

Noel Parks (Managing Director of Energy Research)

Thank you. Yeah.

Jay Allison (Chairman and CEO)

We looked at geology 30 years ago and said, "We thought the rocks were there." And when the geologist came in, he said, "I'd like to drill this Circle M well." I said, "Okay." You had to progress, progress, progress day to day to day, just like our relationship with you. You have to handicap people and say, "Toy does this, Comstock does that," etc., etc. You have to perform. You have to perform, and you have to get in the game. Once you get in the game, you got to say, "Is that seismic real?

Are those logs real? Is that core real? Can you really how do you frack these wells? Look at the performance. Our in-house reservoir group, they have to look at how hard do you draw these wells down. This is a team sport of Comstock. You got to have a big backer saying, "I want to own something big." You got to have some breaks where you get this HBP acreage. You 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." You got to have some people join the team for financing like Quantum. You have to get the gathering. You got all this stuff.

Once you get a little bit comfortable in one area, you got to jump out 24 mi somewhere else because it is a very hard-fought road. I do not 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 is what we did.

Noel Parks (Managing Director of Energy Research)

Great. Thanks a lot.

Operator (participant)

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

Jay Allison (Chairman and CEO)

All right. Again, I want to thank all of you that are still here listening. 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's given us. It was almost seven and a half years ago when Jerry Jones and his family started supporting and investing in the company. Ultimately, they own 71% of the company. 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? If LNG really materializes, can you use that natural gas as feedstock gas? Those same three questions are what we ask ourselves today over and over and over for this whole conference call.

We have really, really come a long way in the seven and a half years. 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.

Operator (participant)

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