Participants

M. Jay Allison; Chairman of the Board, Chief Executive Officer; Comstock Resources Inc

Roland Burns; President, Chief Financial Officer, Secretary, Director; Comstock Resources Inc

Daniel Harrison; Chief Operating Officer; Comstock Resources Inc

Presentation

Operator

Good day and thank you for standing by. Welcome to the Q1 2025. Comstock Resources and it's conference call. (Operator Instructions) Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO, please go ahead.

M. Jay Allison

All right, thank you for the introduction. Welcome to the Comstock Resources first quarter of 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.commstockresources.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 investor 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 and 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 Johnson and his family owns 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 Elijah one.
Now as we review the first quarter of 2025 results today. I would like you to focus on what should be the holy grail that every ENP company is seeking to create long-term shareholder value. Drilling inventory is that holy grail.
For the past 5 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 Elijah one, which is our first well drilled in Freestone County. Now, the Elijah one, think about this, is 24.4 miles away from the closest producing Western Haynesville well and almost 50 miles away from our brother's producing well to the south in Robertson County.
The Elijah I 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 billion dollars to build and develop the 520,000 acres comprising our western Haynesville plague.
We turned the Elijah one 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 Boulsier 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 angel 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 EBITDA 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've turned over Roland to discuss financial results we reported yesterday. Roland.

Roland Burns

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 1st quarter were located in our legacy Haynesville area. In April, the Olajuwuan 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.
Even DAX 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 IMEX settlement price averaged $3.65 in the first quarter, and the average Henry have spot price averaged $4.27. 37% of our gas was sold in the spot market in the quarter, so the appropriate NIMex 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 IMEX 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 limited a very limited number of days that we had in the quarter and there was a lot of volatility around bases in the first quarter with the high spot prices.
In the first quarter we were also 54% hedge, which lowered our gas rela 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.
On slide 6, we detail our operating costs for MCFE and our EBA DAX margin. Our operating cost for MCFE averaged $0.83 in the first quarter, $0.11 higher than the 4th quarter rate.
Our EBITDAX margin improved to 60 to 76% in the first quarter as compared to 73% in the fourth quarter of last year. Our production and alarm 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.
Then our gathering costs were up $0.01 in the quarter and GNA costs were up $0.01 in the quarter. On slide 7, we recap our spending on our drilling and other development activity, and we spent a total of $250 million on development activities in the first quarter.
We drilled 4 or 3.9. Net horizontal painsel wells and 3 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.
Slide 8, we recap our, what our balance sheet looks 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 accrue 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, and now I'll turn it over to Dan to kind of discuss our drilling results in more detail.

Daniel Harrison

Okay, thanks Roland. If you look over on slide 9, this is just an overview of our acreage footprint position in the Hazel Boser Hill in East Texas and North Louisiana. We have now $1.1 million gross and 822,000 net acres that are perspective for commercial development of the Haysville and Bossier halls.
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 Haysville in 2020, we've grown our acreage-to-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 Haysville 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 hazel, we expect the Western Hazel to yield significantly more resource potential per section than our legacy Haynesville will. On slide 10 is our updated drilling inventory. That's the end of the 1st 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 then 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 ft 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 Haysville and the Bossier. The average lateral length now stands at 9,601 ft, which is basically unchanged from the end of last year.
The cemetery 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 lale that we drilled based on the wells that we have drilled and have reached total depth.
The average lateral links are shown separately for both our legacy Haynesville and our western Haynesville acreage areas. In the first quarter we drilled 3 wells to total depth in the legacy Haynesville, and these wells had an average lateral length of 12,903 ft.
The individual lengths ranged from 9,673 up to 15,0023 ft. The record longest lateral on our legacy, Haynesville Acres stands at 17,409 ft also in the first quarter we drilled 4 wells the total depth in the western Haynesville, and these wells had an average la length of 10,728 ft.
The individual lengths on those wells range from 9,100 ft up to 12,0045 ft. Our longest lateral drill to date on the western hazel acreage has a lateral length of 12,763 ft. I just kind of summarizing on the long lateral activity, we now drill 117 wells.
Laterals longer than 10,000 ft, and we have 44 wells that have laterals over 14,000 ft. On slide 12, this outlines the wells that have been turned to sales on our legacy Haysville 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 ft and the individual laterals range from 90 to 52 up to 17,409.
During the first quarter, the Wellsby turn to sales were more focused in the legacy Haynesville area compared to the 4th 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 3 of our 7 rigs currently drilling on our legacy Haynesville acreage. Slide 13 outlines the one well that we've turned to sales in our Western Haynesville acreage since we last reported earnings in in February. The Olajuwon number 18 well was turned to sales early last month.
This represents our first step out test to the northeast up in Freestone County. This well is located 24 miles away from our nearest producing well. The Olajuwan well was completed with a 10,306 ft lateral and the well was tested with an IP rate of $41 million cubic feet per day and so 4 of our 7 rigs are currently running on the Western Hinesville acreage.
14 highlights the average drilling days and the average footage drilled per day in our legacy Haynesville area. In the first quarter, we drilled 3 wells to total depth in the legacy Haynesville and we averaged 26 days to total depth. This is an increase of 3 days compared to the 4th quarter, but it's unchanged from the 20,244 year full year average of 26 drilling days.
The additional drilling days we experienced in the first quarter compared to the 4th quarter was due mainly to the longer lateral lengths. We drilled in the 1st quarter compared to the 4th quarter. I think the average la length was 2000 ft longer in Q1.
In the first quarter, we have 1,0027 ft 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 ft per day. Since 2017, our footage drill per day has increased by 51%.
The best well drill to date on our legacy Haynesville acre was averaged 1,461 ft per day, and we drilled it to TD in 14 days. So slide 15, this 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 the 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 dropping in to 59 days for the 2024 full year average. We averaged 55 drilling days for the 4 wells drilled the TD in the first quarter.
This 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 4th quarter. Most of the increase compared to the 4th quarter can be attributed to the lower efficiency of mostly single wells we drilled in the 1st quarter compared to the 2 well pads we drilled in the 4th quarter.
Also during the first quarter we drilled our fastest well to date in the western Haynesville at 37 drilling days. And this record well was drilled with a 12,0045 to lateral. So 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 of drill per day.
Our 1st 3 wells in 22 averaged 281 ft per day, which has improved to the current average of 524 ft per day in the first quarter a record fastest well drilled at 741 ft per day and some of the primary factors behind the improved drilling performance, includes the shift to drilling or 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 DNC 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 ft 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 term to sales date.
During the first quarter, we drilled 3 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. And as two of these three wells were drilled to TD, as two of the three wells were 15,000 ft lateral.
Also during the first quarter, we turned 11 wells to sales on our legacy Hinesville acreage. The first quarter completion costs came in at $855 a foot. This is just a 1% decrease compared to the 4th quarter. As we look ahead, we're anticipating our DMC cost on the legacy Haynesville acres will stay flat to slightly lower, for 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 3rd 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 and slide 17 is the summary of our decency costs through the first quarter for all the wells drilled in the western Haynesville.
For the western hazel, 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 cells. So during the 1st quarter we were able to carry forward the really great progress and the results we achieved during the 4th 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 fast as 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% in the first quarter. We did not have any wells in the Western Haynesville that were returned 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 time frame of our programs definitely allowed us to significantly expand our knowledge base of this area. We've zeroed in on a good well designed and, we continue to improve upon our job executions.
And again, we got 4 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 for 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 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 also said that approximately 2000 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 and lastly.
We announced yesterday a partnership with BKV Corporation to study the potential to develop carbon capture projects that our methyl and Mara, 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.

M. Jay Allison

All right, thank you, Dan. Thank you, Roland. If everyone please for a slide 19, we will summarize our outlook for 2025. In 2025 we're primarily focused on building our great assets in the Western Haynesville that will position us to benefit from the longer-term growth in natural gas demand. We currently have 4 operated rigs in Western Haynesville to continue to delineate the new play. We expect to drill 20 wells and turn 15 wells to sales in western Haynesville this year. We'll continue to build out our Western Avi 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 3 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 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 Angelville areas.
As Roland said, we have strong financial liquidity totaling almost a billion dollars.
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.

Question and Answer Session

Operator

Thank you. At this time, we will conduct a question and answer session. (Operator Instructions) Our first question comes from Derek Whitfield from Texas Capital. Please go ahead.

Good morning all and thanks for your time.

M. Jay Allison

Morning. Thank you. I have two.

Questions, and they're both related to the Western Haynesville, as you noted in your prepared remarks, Theologicon 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?

Daniel Harrison

Yeah, so we, the wells 24 miles away from the nearest well we have, probably, all the way down to the other end of where we drill the wells, you can probably double that, probably almost, I'd say 45.
Miles, down into Robertson County. So as far as the reservoir quality in the Olajuwan looks, I say every bit as good as the ones we drilled down in the core area looks really good. It's a, it is a Haynesville well, not a Bossier.
We've got good thickness there. And we did, of course, we drilled the Olajuwan in that area for a reason because we had some nearby well logs that had drilled through that section years ago that we're able to look at and we could, see the, 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, 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 and really figure the percentage of the acres, I think maybe is what you was asking, Derek, but A substantial chunk of our acreage up on the northeast end, yeah, looks, I'd say it definitely puts it in play and greatly de-risk that entire area up there.

M. Jay Allison

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 drill, but we deepened the well, the geological group that 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.

Daniel Harrison

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 eyeball and 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 delineating now across a position. I mean, is that a good kind of spitball if you will?

Daniel Harrison

Yeah, I'd say, I'd somewhat agree with that. We the depth of the well was probably maybe about 1,000 ft deeper. This was about a 17,500 ft TVVD well up here where this well is located compared to the deepest ones we drilled, 185, between 185 and 19 at the very high end or deep end, however you want to look at it. So, this looks really stout. I mean, we can be happier with it.

M. Jay Allison

But if you look on a map and you go, kind of east and west. You look where the large one well is, we probably have control of most of the acres for about 30 miles. So 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 BKB partnership and the value you see in this arrangement.
I mean from my 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 industrial client. Is that really the aim here?

Roland Burns

Yeah, Eric, this is rolling, yeah, that is the aim that's one of the reasons why we're excited about the partnership with BKV who, has already has a proven track record here, has a very successful project in the Barnet Shell with their Barnett Zero project.
So 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. So we think that makes the our location, about 100 miles from Dallas, 100 miles 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, just makes it an ideal area we think for potential power generation facilities to support a data center, in that area. So that's all part of what we'd like to see and so it's, another A piece in the puzzle that we're hoping to put together and develop that, but still a lot of work to do there.

M. Jay Allison

We had looked at Chris and his group at BKV. We've been watching them before they went public and afterwards, and we actually cured their injection of well and in the Barnet and that whole group, is tier one and we said, our Western angel is similar in size to what they're doing at the Barnet. 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 BKB can do the carbon capture, then I think one day one and two, we win. And 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.

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

Operator

Thank you. Our next question comes from Cali Akerman from Bank of America. Please go ahead.

Daniel Harrison

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 have expected a result in this area? And then when you zoom out, look at the map, where do you plan to step out to next?

Daniel Harrison

So good question. We have a The next well we're going to spot 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, it's just getting the midstream built out and getting ahead of where the locations are, being able to get them into the gathering system.
We obviously a lot of the midstream dollars we've spent have been down where we drilled all of the wells to date, so we, 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 got more wells that are actually be fanning out much wider across that footprint up there. We got eight wells somewhere on the order of 8 wells plans were 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 5 rig pace you have some white space in the frag calendar, but at a 7 rig pace those two crews are probably fully booked.
So the contribution from the 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 that the upper half of full year production guidance is still in play.

Roland Burns

Yeah, we did recently add that seventh rig. Kaylee with the and that just went to work here and, post here in April and so, and we do have that rigs just on a well to well type con short-term basis. So we so I think that's kind of expected in most of the production from adding, rigs, that rig and any rigs that we could, you 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 you know we're going to want to drill multi-well pads, we're going to, just to put it in the completion queue, there, there's really that activity level that we could add at this point in the year that would impact, this year's production. But yeah, we, we're looking at it 2026 and You see a lot of increasing demand and so we think it makes sense to add that rate here in April like we kind of talked about the last call.

Daniel Harrison

And we are still, 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 3rdfrack crew, but we pretty much can cover most of that still with the recount we got with two freight crews. Which, I'll just say our frac crews that we've got a really good, very efficient, so while we're able to do that.

Got it thanks guys.

M. Jay Allison

Thank you, Cali.

Operator

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

Good morning, Jay Roland Dan. I want to ask what. 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 that you guys were, I guess, chose this location or more confident is that you had some deep vertical well control there and I'm curious, I know that there was a lot of, there was historical vertical development in this area, but.
How many other places will having offset vertical well control, will that be the kind of the dominant variable on picking locations when you when you step out, or is that was that just kind of a onetime thing with the Elian? Wow.

Daniel Harrison

So we did, when you do your first step out, obviously you want to have as much control as possible. You don't, 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, get 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 were able, we wanted to get something fairly close to, kind of know for sure what the low quality was and that is how we picked the first one, but all the future wells obviously will be, 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 you need to drill those pilot holes and get some logs across them.

M. Jay Allison

Charles, go back to the circle him, that area we have the most well controls. That's why we drilled it where we drilled it and then we marched that 23 miles up to the north, northeast, to the Leon well, the DR and Ellis wells, and then to answer your question, we had, we thought we had better well control near the Elijah one, 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, etc. So, you have to go back and almost ask the question of why did you drill it. I mean, that was, 24.4 miles and even at the time we decided we wanted to drill it, we were probably 30 miles away from our closest producer, but the goal that 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 that the Elijah one 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. Other thing I think, Charles, is that even if you go back in February, we didn't really talk about the Elijah one. 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 tell you the truth about it. Whether it's, good, bad or ugly, and this happened to be great. So that that's how we go about it. And when we decided to do the live one gas is probably $1.90. I mean this was many months ago we elected to go ahead and drill this well.

God, that is, that's a helpful elaboration, Jay, and then perhaps following up on that idea of derisking 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.
So I wonder is that the 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 a northwesterly, updip direction?

M. Jay Allison

Well, when we started 5 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 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 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 unleashed.
So you go and you you aggressively get prudently, grab what is unleashed and then if you can add HPP acreage, which most of that is to the west. So 80+% of our acreage is HPP, but we didn't add that HPP acreage. It was March of last year, we added 185,000 acres.
It was probably first quarter, we had another 62,000 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 play.
So we have focused our most part of drilling the whole acreage, and then we'll deviate over and drill some of the HPP acreage. Now, we will, we've had one pilot, well, cos, 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 Derek has, what is the rock quality? Well, we're going to know that with the course.

Daniel Harrison

That is helpful detail.

M. Jay Allison

Thank you, Jake. Sir, thank you.

Operator

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

M. Jay Allison

Good morning.

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 sidecar of that, is there an internal view to take a more method optical approach to growth and target high skill digits or low double digits at the end of the decade?

M. Jay Allison

I think if you have, all of this except like 6,000 acres is un dedicated. So I think you have to look at that and say, well, we're going to probably connect 15 or 20 new wells to cells and then as Dan mentioned earlier, when Derek or maybe Cali 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 other question was asked 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 of course 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 the Pinnacle ga 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 BKB and the carbon capture, we're going to be far more attractive, for companies that will look to approach us and we've 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? Is it, is this real? Do you really need this gas? And we looked in the world's largest electric utility this week said that US 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 Woodsides and now so you can probably have two BCF by 20,209 or 230 current permitted LNG projects for about 17 B. So this is a great question. Where are you going to get that gas? We think that Appalachians could strain, you'll get a bee or so. I think the par you don't drill there for gas.
This is this core area while we worked really hard and fought hard to de-risk this stuff to deliver it to you when we need to. So that, that's, we're always going to protect the balance sheet, but we're going to de-risk this thing and take risk, to de-risk it just like the Elijah one.

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

Daniel Harrison

Well, so the flow rate on the Olajuwan 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 don't, why we're not spreading another well until the end of this year and, really mostly into next year.
So no, I mean the well will look looks as good as everything else we have. We're going to flow it the same as the other wells we have, and I mean we don't have any constraints on the midstream side.

Excellent, appreciate the time.

M. Jay Allison

Thank you, great questions.

Operator

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.
Morning. It's, so considering that 2025 is a an HDP 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 slash appraisal wells, I think that I, to conclude the question, it would be tremendously helpful to understand and parse out the general geography of where these HDP wells are and their underlying impact to the perception of those well results as we move through the next 24 months.

Roland Burns

Yeah, I mean, we still want to focus on when we drill a well in the western Hainesville and holding acreage, and 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. Yeah, that and this, the proximity and availability of midstream and acreage or, 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 Hainesville, not to the Haynesville.

Roland Burns

That is the Westernville, right? That, yeah, legacy Haynesville we have don't have any acreage to drill the hole, but, so that's very, price driven and takeaway is there are areas that the takeaway is more difficult than the legacy.
Haynesville, there are different costs of the transporting 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 our, with the rig we just added and drill and the legacy of 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, are you, would you be concerned at all, if Permitting around the Permian, even though you rightly point out, Jay, those walls 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 premium 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?

Roland Burns

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 for that's, coming from LNG and other power generation. So that, that's going to be a big contributor. So it's, 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.

M. Jay Allison

Yeah, we do expect that growth. Thank you, gentlemen.

Operator

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, it'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 hazel 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 there's no way to for people to outside to know the timing of when those are brought on. And so the tills in the 2nd quarter look to be more second half weighted. That's why the production is really you're starting to see the production, the sequential production growth return in both the 3rd and the 4th quarter.
And then if you, 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 would look pretty similar to the 1st and 2nd where the 3rd will be a lower number of tills and the 4th will be a higher number of tills.

Okay perfect thanks.

When they come on during the quarter.

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

Roland Burns

No, we, 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. So yeah, we don't see any big capital investment by ComStot.

Excellent. Thanks all.

M. Jay Allison

Thanks Phil.

Operator

Thank you. Our next question comes from Greta Dreft 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 you realize in Q125 going forward this year and into next.

Daniel Harrison

So in the legacy Haynesville, yeah, we're, 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 ft for Q1.
We're our longest 1, 17,000. We still have several 15,000, 14, 15,000 footers 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 to 13,000 ft average 1 length. So I don't think you're going to see us continually like keep climbing higher than that.

Roland Burns

The positive is that 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 lateral.
Well, yeah, our averages should be a little bit better because we won't have the really short ones to weigh it down, right?

Daniel Harrison

And most of the horseshoe wells we'll be drilling, they're going to be, they're 9,500 ft and we've got a few of them are going to be a little bit longer than that. But, as far as just the average, I think is what you were asking about doing in 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 DNC cost. 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.

Daniel Harrison

Yeah, I think that's a really good question, and I think the answer is yes, compared to, if we, 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, freight 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 region freight cruise, I think where you'll probably get a more meaningful percentage drop and vendor costs there and also hopefully on our pipe prices, depending on what happens with the tariffs.

Got it appreciate it thank you.

Operator

Thank you. Our next question comes from Noelle Parks from Tui Brothers Investment Research. Please go ahead.

Hi, good morning. I just have a couple. Looks like a pretty exciting quarter in terms of the lodging one well and everything going on. I guess I did want to ask about A maybe just overall. So you know 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 formally 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 as just not workable.

Daniel Harrison

Yeah, I think we, 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 see, 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. And when you're 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 and 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.

Daniel Harrison

Well, there, we've, so we, one thing I always kind of just, preach around here is obviously consistency. We've had some great results, we obviously keep we just want to be very repeatable and predictable, to be able to deliver that and some of that and, 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 drilling the la, I mean, obviously we 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 stream streamline the downsize our sizes a little bit and we just got a lot better at picking where our casing points are.
So, bottom hole assemblies, just as we've drilled more wells and got more data on how the motors are performing, which motors perform better, basically how to, tweak the designs on the motors for the temperature we just delivered better runs with that.

M. Jay Allison

You know what, we looked at the 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 in well. I said, okay, so you had to progress, day to day to day, just like our relationship with you, and you have to handicap people and say, Tuy does this, Compto does that, etc. Etc.
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 got to say, well, is that seismic real? Are those logs real? Is that core real? Can you really, how do you frac 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 it is a, this is a team sport of Comstock.
You got to have a big backer saying, I want to own something big and you got to have some breaks where you get this HPP 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, then you got to have some people join the team for financing like quantum. And then you have to get the gathering and then you got all this stuff and then you, once you get a little bit comfortable in one area, you got to jump out 24 miles somewhere else because it is a very hard fought road.
I don't think anybody when gas is 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.

Operator

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

M. Jay Allison

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 ALL255 people here at Comstock, we relish and we're thankful for the incredible opportunity to unlock what we see is this tremendous wealth.
What we love the chance, that everybody's given us. It was almost 7.5 years ago when Jerry Jones's family started supporting and investing in the company and ultimately, they own 71% of the company, but they asked 3 questions at that time.
This is 7.5 years ago, what is 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 feed salt 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 come a long way in 7.5 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.

Operator

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