Q2 2025 Comstock Resources Inc Earnings Call
Good day and thank you for standing by. Welcome to The Comstock resources. Second quarter 2025 earnings call.
At this time, all participants are in a listen-only mode.
After the speaker's presentation, there will be a question and answer session.
To ask a question during the session. You'll need to press star 1. 1 on your telephone. You will then hear an automated message advising. Your hand is raised.
To withdraw your question. Please press star 1 1 again.
Please be advised that today's conference is being recorded.
I'd now like to hand the conference over to Jay Allison, chairman and CEO. Please go ahead.
Oh, thank you.
Uh, welcome to the comp-toe resources, second 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.com stock resources.com
And downloading the quarterly results presentation there, you'll find a presentation entitled. Second quarter 2025 results, I have Jay, Allison, Chief Executive Officer of golf. 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 and a presentation is a note that our discussions today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations in such statements to be reasonable. There can be no assurance that such expectations will prove to be correct.
5 years ago.
We made the decision to lease acreage and to drill and exploratory. Well, in what. We now, call the Western Hayesville
Today, our Western Hayesville footprint has grown to nearly 525 net acres and we have now drilled 29 Wells for 24 of those currently producing 10 or producing from the Haynesville Shale in 14 from the buzzer shell.
700 ft to 12763.
63 ft. Since we have put the first well, online in 2022, we have made many changes to our Drilling and completion design for this area.
Both the Haynesville and Bossier Shales in this area are rich in organic content, very thick, and have high pressure this year. We have drilled two pilot holes, taking logs in the whole course to increase our knowledge about the best ways to complete the wells in the future to maximize the URS of the wells.
As we developed our vast acreage position, in the western Hayesville, we're also building out our own Midstream, to support it to that end. We just put our new gas, treating plant in operations, which increased our treating capacity by 400 million cubic feet per day.
And the second quarter, we turned 5 new Western Hazel Wells to sells these Wells, include the Elijah 1 to the North, and the BM to the South, which is 30 Mi away, both of these Wells appear to be some of the best we have ever. Ever drilled the second quarter, Wells were drilled and completed at an all-in cost of 2,647 for completed lateral foot, which is substantially less than the wells we completed in the last 3 years.
Over the last 3 years, we have decided not to engage in the m&a market to build drilling inventory, for the future. Instead we have put resources into amassing, the western hannes land position and de-risking this new play.
The path. We've chosen is not an easy 1 in a public company setting as future operating results are hard to predict and many of our actions are aimed at creating long-term value versus creating immediate short-term results that benefit the next quarter.
In order to protect our balance sheet, we pull back from drilling Wells, and our Legacy hands will area, which still accounts for over 80% of our production.
We now have 4 rigs working in our Legacy hanesville area which will allow us to stabilize production there. As we grow the Western hanesville so far this year, we have turned 21 Wells to sales with an average lateral length of 11,833 feet and a pearl. Well, initial production rate of 25 million cubic feet per day
As Dan will go over in a few minutes, we're excited about the Horseshoe Wells that we're adding to our drilling program that the added rig will focus on as Roland will cover in a few minutes. The second quarter for next results benefited from the improved natural. Gas price. We're seeing this year versus 2024, a natural gas, and oil cells, grew to 344 million, and we generated 210 million of operating cash flow or 71 cents per diluted share.
Our adjusted net income, for the quarter was 40 million or 13 cents per share.
We're also excited to announce that we're working with next year energy who leads the nation in the development of power, generation to explore the development of gas fired. Power generation assets near our growing Western hanesville area that can power potential data center customers that, we believe our location which is a 100 miles. From the Dallas Metroplex, is an ideal site with natural gas water, and electrical grid infrastructure resources, that could support data center development.
I will now turn it over to Roland to discuss the financial results for reported yesterday. Rowland.
Yeah. Thanks Jay.
On slide 4, we covered the second quarter, Financial results, our production in the second quarter average 1.23.
PCF per day, which was 14%, lower than the second quarter of 2025 reflecting our decision to drop rigs in early 2024 and our deferral of completion activity last year into this year.
With the improving and natural gas prices are oil, and gas sales in the quarter increased 24% to 344 million.
In the second quarter this year, despite the lower production.
Even tax for the quarter was 260 million and we generated 210 million of cash flow in the quarter.
As Jay said, we reported adjusted net income of 40 million dollars to the second quarter or 13 cents per diluted share compared to a loss in the second quarter of 2024.
Results for the first half of this year.
Production average 1.26 BCF per day in the first 6 Months of the Year 15 lower than the same period in 2024.
And our oil and gas sales in the first 6 months of this year, increased 22% to 749 million.
Even tax in the first 6, months was 553 million and we generated 449 million of cash flow.
For the first half of this year our, our adjusted net income.
Is 94 million.
Or 32 cents per diluted share as compared to a loss in the same period of 2024.
56 breaks down our natural gas, price realizations in the
The year and the quarter.
Our quarterly 9x settlement price for the second quarter.
Average $3.44.
however, the average Henry hub spot price
In the second quarter averaged a much lower $3.16. So 32% of our gas is sold in the spot Market.
So, the appropriate nimax kind of reference price for our for our activity was about $3.35.
For the second quarter.
I realized gas price for the second quarter was $3 and 2 cents, reflecting a
42 Cent basis, differential compared to the Nyx settlement price and a 33 Cent differential compared to the reference price.
We were 56% hedged in the second quarter so that improved our realized price to $36 and we earned a 4.4 million dollar profit from third, third party marketing activity, which improved our realized price to 310.
Slot 7, we detail our operating costs per mcfe and our Eva Dax margin.
Our operating costs per mcfe. Average 80 cents in the second quarter 3 cents lower than the first quarter rate and 4 cents, lower in the second quarter of 2024.
Our EBA tax margin was 74.
Percent in the second quarter compared to 76% in the first quarter.
Production at Aber taxes were down 1 set from the first quarter rate.
Due to lower natural gas prices, and our lifting cost improved by 2 cents in the quarter.
Gathering in GNA costs remained unchanged in the second quarter compared to the first quarter.
Slide 8, we recap our spending on Drilling and other development activity. We spent 268 million
uh, development activity, uh, in the second quarter. And for the first
For the first 6 months this year, we've now drilled 16 Wells or 14.5. Net Wells.
and uh, those are in that that Target the hanesville shell and then we we've also got another 3,
Gross Wells or 3, net Wells, that Target the B, the Boer shell for a total of 19 Wells.
Uh, drilled so far this year.
We turned 24, or 20.3 net operated Wells to sales, which had an average IP rate of 27 million cubic feet per day.
From slide 9 to be recap our what our balance sheet looks like at the end of the second quarter, we ended the quarter with 475 million of borrowing to outstanding under our credit facility, having paid down 35 million during the second quarter.
Our borrowing base is 2 billion dollars under the Crescent City and our the elected commitment.
Still is a 1.5 billion.
Our last 12 months, leverage ratio is improved to just to 3 times and will continue to improve as we get away from the 2024 results which are weighed down by low natural gas prices.
At the end of the second quarter, we had approximately 1.1 billion dollars of liquidity.
And I'll turn it over to Dan to discuss the drilling and operating results.
Okay. Uh, thanks Roland.
Slide 10.
Slides in here, just an overview of our latest.
Uh, Acres footprint in the hanesville Boer in East, Texas, and North Louisiana. Uh, we now have uh, 1,110 105,000. Uh, gross and 826,741 net Acres that our prospective for commercial development of the Hinesville and Bowser shells,
Uh, over on the left is our Western Hanes Western hanesville acreage footprint, which we have grown to nearly 5 2 5.
5,000 that Acres.
Virtually undeveloped compared to our Legacy hanesville area.
With the high pay thickness and pressures. We encounter in the western hanesville, we expect the Western Hansel will yield significantly more resource potential per section than our legacy homes for
On slide 11 uh outlines our new development plan utilizing the Horseshoe lateral concept.
The horsey. Well, design concept combines 2 separate and adjacent shorter, laterals into a longer single lateral, which results in a much more efficient, use of capital.
uh, we realized 35% savings and our drilling costs been drilling, a 10K lateral horseshoe
Well, compared to a 5,000 foot sectional lateral. Well,
Our drilling inventory in the Legacy Hinesville now includes 149 horseshoe locations.
Uh we completed our first horse you. Well, last year, the Sebastian 11 number 5
Uh, it had a 9,382 foot lateral.
And we had an IP rate of 31 million cubic feet per day.
Uh today this year we've drilled 2 additional horseshoe Wells uh and so for in 2025 we plan to drill a total of 9 of course, if you will, and we will drill 10 horsey wells in 2026.
And slide 12 is our updated drilling inventory. At the end of the second quarter,
Uh, our total operated inventory consists of 1,538 gross locations and 1,222 net locations, uh, which equates to a working interest of Approximately 80%.
Our non-operated inventory has 1,125 gross, locations, and and 137 net locations. And this represents an average 12% working interest.
Uh, the drilling inventory is split between the Hazel and Boer.
Uh are the only inventories comprised of short laterals less than 5,000 uh our medium laterals or between 25 and 8,500. Foot long, laterals between 8,500 foot 10,000 foot and our extra long laterals.
Uh, over 10,000 foot.
Our gross operated inventory. We have 42 short laterals,
318 medium laterals, 573 long laterals, and 6,005 extra long laterals.
The gross operated inventory is evenly split with 50% in the hanesville and 50% in the Boer.
uh, over 75% of the gross operated inventory, consists of larges, greater than 8,500, ft
Our drilling inventory, includes the 149 horseshoe locations, which are also split half and half between the Hansel and the Boer.
The average lateral length in the inventory is now up to 9686 Ft. Uh, this is up 85 ft from the end of the first quarter.
uh, so this inventory provides us with over 30 years of future, drilling locations based on our current activity level,
We'll fly at 13. Uh, as a chart outlining the average lateral length drilled. Uh, this is based on the wells that we have drilled to TD.
The average lateral links are shown separately for our Legacy. Hangs area and our Western hanesville area.
In the second quarter, we drilled 8 Wells to Total depth in the Legacy Hanceville.
And these had an average lateral length of 11,705 feet.
The individual levels. Ranged from 7,782 feet up to 15,190 Ft.
Uh, a record long lateral on our Legacy. Hanksville acord still stands at 17409 FT.
In the second quarter we drill 4 Wells to Total depth in the Western hanesville and these Wells had an average ladder length of 7,933 Ft.
The individual lengths range from 6,708. Ft up to 8836 Ft.
Our longest lateral drill. Today in the western, Hazel still stands it, uh, 12,763 ft.
Uh today we've drilled 122 Wells with laterals longer than 10,000 ft and we drilled 47 oil wells with laterals longer than 14,000 ft.
Slide, 14, outlines the wells that were turned to cells and our Legacy hanesville Acres this year.
Uh, so far for the year, we've turned 21 Wells to sales uh on our Legacy. Honeys the Lakers
The individual IPS for these Wells range from 16 million today, up to 37 million today.
And our average IP was 25 million a day.
8003 ft, and the individual lateral Springs from
9,252 feet up to 17,409 Ft.
And 4 of our 8 rigs that we have currently running are drilling on our Legacy hanesville acreage.
Slide 15 outlines the 5 wells that have been turned to cells on our Western Haynesville acreage this year.
Uh, we discussed it. The 24 Mile step out. Well, the Elijah Juan number 18, uh, during our last quarter's conference call.
Since we last reported underneath, we've turned 4 additional Wells to cells.
These 4 Wells had an average driver length of 11,044 Ft.
And an average, uh, initial production rate of 35 million cubic feet a day.
And 4 of our 8 rigs are uh, currently drilling on our Western High School acreage.
Slide, 16 highlights the average drilling days and our average footage. Drilled for today, in the Legacy Hanceville area,
Uh in the second quarter, we drilled 8 Wells to Total depth in the Legacy hanesville and we averaged 28 days to Total depth.
This is 2 days slower than than the prior quarter.
In the second quarter, we averaged 921 ft per day on our Legacy High School.
This is a 10% decrease versus the first quarter uh of 2025 and a 7%. Decrease versus our 2024 full year. Average of 987 ft drilled per day.
Now, the additional drilling days and the lower daily footage that we had drilled in the second quarter compared to the first quarter were really the result of 2 Wells and our East Texas area that experienced.
some drilling difficulties, uh, associated with some, uh,
highly overpressured, uh, swd zones.
The best well drill. Today, on our Legacy handle Legacy, Hazel acreage averaged 1,461 ft per day.
And we drilled that well to TD in 14 days.
Slide 17 highlights our drilling progress in the western Haynesville.
During the second quarter, we drilled four wells. The total depth was in the western Haynesville.
Uh, this now gives us a total of 29 Wells that we've drilled the total depth through the end of the second quarter.
Since we split our initial well in the fourth quarter of '21, we have seen significant improvement in our drilling times.
Our first 3 Wells drilled in 2022, averaged 95 days to reach TD. Our average yearly times dropped to 70 days and 2023 and dropped again to 59 days.
uh, for the full for the 2024 full year, average,
In the second quarter, we averaged 58 drilling days for the 4 wells that we drilled to total depth.
This is a decrease of 1 day compared to the 2024 full year. Average.
That reflects an increase of 3 days compared to the first quarter.
And the increase in the drilling days compared to the first quarter. Can really be attributed to to 2 things.
Uh the first 1 b, 1 of our wells in the second quarter had to be sidetracked up in the vertical due to a downhole motor that we had come apart.
And, secondly, All 4 of the wells are drilled in the second quarter. We're over 1500 foot deeper vertically than the wells. We drilled in the first quarter.
Uh, the additional drilling days in the second quarter is also a reflection that uh, with the lower foot is drilled per day.
Our fastest soil drill. Today in the western hisel, still stands 37 days and that well had a 12,045 foot lateral.
Slide 18 is a summary of our DNC costs through the second quarter, uh, for for our Benchmark, long lateral, Wells, uh, that are located in our Legacy Hanksville area.
uh these costs reflect all our Legacy area, Wells that had a laterals greater than 8,500 ft
The drilling costs are based on when the wells reached TD and our completion cost that we show here are based on when the wells are turned to cells.
So, during the second quarter, we drilled 7 of our, Mitch Mark long lateral Wells to Total depth.
The second quarter of drilling cost average is 696 a feet foot.
Which is a 33% increase compared to the first quarter.
Uh like I mentioned earlier on our second quarter, drilling efficiency, we incurred some additional drilling costs on a couple of our East Texas wells in the second quarter.
Uh, due to the drilling difficulties that were associated with the, you know, with the localized highly overpressured swd signs.
We also turned 8 Wells uh to sales on our Legacy High School acreage.
The second quarter completion cost came in at $724 a foot.
Uh, this represents a 15% decrease compared to the first quarter.
And the lower completion cost, uh, in the second quarter were partially driven by lower Frac cost, uh, that we had associated with lower fuel costs. And so, we did have more of our fraction. The second quarter, that utilized the higher percentage of natural gas, uh, for fuel.
We also experienced much better efficiency drilling out, Frac plugs in the second quarter.
Uh, we currently have the 4 R running on the Legacy Hanesville acreage. As we look ahead, we believe our DNC costs will remain relatively flat to slightly lower for the remainder of the year.
Slide 19 is a summary of our DNC costs through the second quarter for all the wells drilled in the western Hanceville, on our Western High School Acres.
Uh, during the second quarter, we drilled 4 wells to total depth.
Uh, these had an average lateral length of 7,933 feet.
The second quarter, drilling cost averaged 1,875. A foot.
Uh, which represents a 30 36% increase compared to the first quarter.
The dominant drivers for the higher joining cost. In the second quarter was the shorter laterals.
Our average lateral length. In the second quarter was 7,933 ft.
And this compares to an average lateral length of 10,728 Ft for the for the wells. We TD in the first quarter,
Uh we do plan on targeting much longer lateral uh in the western hanesville as we go forward.
Also 1 of our 4 Wells drilled during the second quarter had to be sidetracked in the vertical you know, downhill due to a motor that came apart.
During the second quarter, we also turned 6 Wells to sales on our Western Hills acreage that had an average lateral length of 10,445. Ft
Uh, we did not turn any Wells to cells in the first quarter.
So the second quarter completion cost average 1,355 a foot.
This is a 1% decrease compared to the fourth quarter of 2024.
Uh, our Frack Crews have continued ex execute with a very good efficiency.
And during the second quarter, all but one of our six wells that we turned to sales were fracked using a blended fuel of natural gas and diesel.
Uh, we do currently have uh 4 of our rigs running in the western Hanceville.
We also have 2, full-time, dedicated, Frac fleets.
And, uh, both of these fleets do have the ability to run, uh, off a blend of natural gas and Diesel.
So, well, now I'll turn the call back over to Jay. Hey, thank you Dan. Thank you. Roland. If you would, please refer to slide 20 where we summarize our outlook for 2025.
In 2025, we remain primarily focused on building our great asset in the Western Haynesville, which will position us to benefit from the longer-term growth in natural gas demand. We currently have 4 operating rigs filling in the Western Haynesville and continue to delineate the new play. We expect to drill 19 or 18.9 net wells and turn 13 net 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.
Our new Marche gas. Treating plant started operations this month. Which more than doubled, our gas treating capacity.
And the Legacy, HS? What we are currently running for reach the bill production backup for 2026. We expected real 32 or 24 net wells in turn 32 or 26.8 net wells to sales and the Legacy Haynesville this year.
Given the tremendous interest in acquiring properties. In the hanesville, we currently plan to the best certain non-core properties during 2025, which will allow us to accelerate deleveraging of our balance sheet. We continue to have the industry's lowest producing cost structure and expect drilling efficiencies to continue to work for driving down Drilling and completion, cost in 2025, and both the Western and Legacy handle areas with strong. Financial liquidity is rolling reported telling, almost 1.1 billion dollars,
All right, Liz. We can go and open up to Q&A.
As a reminder, if you'd like to ask a question at this time, please press star 1, 1 on your telephone and wait for your name, to be announced to withdraw your question. Please. Press star 1 1 again.
Our first question comes from a line of Carlos Escalante with Wolfe Research.
Hey, good morning team. Thank you for taking my question. Um, I guess I'll start out by asking a question on the on the western hensville for particularly on the step out to the Northwest, uh, which you point out in your map. Th this, well, seems to be a relative step out from your current PDP and it seems to us like it's another positive confirmation of initial Reservoir pressure, and, therefore productivity. Uh, now it, it also looks like through State data that, it's it, it might be a big seller. Well, and so I think we, we could, we should expect, um, some cooler water, all temperatures when you're doing those calls.
all that to say is uh, to to say if
You can perhaps walk us through what your key takeaways and learnings from Jillian, that specific area, have been. And obviously, what it means for your underlying capital, what the cost trend?
Well, and Dan, that's the Elijah 1 to the north, and you dropped down to the BME, and then to the left is the Jennings, and then the mill.
Yeah, that'd be correct. I think, cross—I think the... well, you're... when you say to the northwest, I think...
I think that's uh, if I'm just looking at the map here. I, that's probably our Jenny's. Well, we drilled a 2. Well, pad up there.
And uh, that will that's correct. Yes.
Yeah, that well was definitely shallower in the shallower part of the acreage compared to some of these other ones we drilled.
And you know Jay mentioned it earlier, you know and his opening remarks, you know, just the TVD depth ranges. And so that particular well,
Is the 4,000 or 14,000 foot book? End of those. You know, he gave you 14 to 19,000 to 200. That's the 14,000 foot TVD. Well.
Uh significantly. You know it's also our record fastest well that we drilled at 37 days to TD.
So it does make a big difference in where you're drilling on the acreage, on the number of drilling days and also the cost.
that well was uh also our cheapest you know, cheapest fastest
Uh significantly cheaper really so you know we've got a pretty good range here of depth temperatures drilling costs, you know, across the acreage. So um
yeah, just kind of point that out. It looks good. Some of the wells that were deeper hotter and uh so then you may talk about, you know, not having to took some of these walls up. So we have just due to the pressures on the initial Wells. We drilled of course are extremely high pressures.
Uh, everything that we flow up in in the core flows. You know, we just flow the wells, up the casing, we tube them up at a later date.
Uh, we didn't do that down here just because of the extremely high shut in pressure is Flowing pressures. Uh, we didn't want to be flowing at those kind of pressures up the production casing
Uh but when you get up in this area where these Jennings Wells are because they're they are shallower and we do have a little bit less pressure, we're comfortable flowing those up the casing.
we did run too but in those but, uh,
In the future Wells above. You know, we kind of are looking at a cut off a depth. Those are definitely above it. We'll flow those.
Those Wells or the wells in that depth, range up the casing in the future. And that'll, that'll drop or cost probably at least another
150 bucks a foot. So
I think had we not run tubing in that. Well, I think we'd have been looking at a sub $2,000 per foot well cost.
Well, I think another comment on the Elijah 1, you know. We we completed it a little different than we did the other Wells but we came down to the BM which is 30 miles away, really, about 33 miles away from me. Elijah the 1.
And we completed it the same way that we completed, the Elijah 1 and both of those is are reported. There's some of the 2 best worlds you've ever drilled. We did tweak the completions and I think that's the whole focus on the program. Is we we think we've captured our, you know, 525,000 net Acres. We've captured our Reserve pool now. What we're doing, which is what your question is, every 90 days. We're reporting on how we're tweaking this to de-risk it to create this tremendous value for what, for the natural gas is needed for LNG data, industrial demand, Etc.
Well, you may want to talk about that then, yeah, the man, the man. Well was also 1 that we tweaked them with j. J says, we tweaked the completions. We just tightened up our stage facing
A little bit, uh, was just gives us a little bit more intensity, you know, basically we're fracking and just over over a shorter distance.
Uh, the manual was also in a well in uh, you know in our
Shower Acres, kind of similar to the Jennings. The production looks looks fantastic on it. Uh,
It's only been on for probably.
A couple of months now. But, uh, you know, low DNC costs. Good results. We've had J Major, so we've had the Elijah 1, the BMY, and the men are really the three that we've probably...
tweaked the most on the completions with the tighter States spacing and we we've been well is 38 million a day IP at a shallower depth. Yeah. And looking at our just even though they haven't been on Long when we look at the initial production rates and we look at the pressure decline just over that little short period. Those those 3 Wells do or 3 of our best looking Wells.
Terrific. Very helpful callers, guys. Um,
I guess, taking a step back now, and looking at it from a more General perspective.
um,
Considering that you you started the year out guiding for 17 pills in the western Hillsville. Um and you know, due to unforeseen issues we're down to 13. What are the ramifications of this to your, uh, 2027 Target of hvp? All your leases through 7 Wells? Is that, is that pushed to the right? Um, and also
1, big question. What? What is the what is the Run rate for sales in the western handle? Yeah, go ahead.
Uh, I mean, I'm not I don't know the number right off the top of my head, but I'm going to say it's not a big, it's really not a big mover. I mean, we've got obviously our drilling speeds are getting faster so that's pulling Wells forward.
uh we have the 1 well that has the you know, the Midstream issue that we're waiting to get it connected and then uh,
Of course we've drilled we've drilled 2 pilot holes. Also, uh, you know, so that that's uh, that pushes the dates back a little bit. But overall, in general, like you asked in the general sense,
It's not really pushing. It's not really pushing any of these wheels back. No, I think that's that's more of a function of
These wells could have come on in December, and now they're forecast to be January. You're talking about a month or so of delay, right? As far as how they fall this year. Yeah, correct. Which could change again, you know, based on...
Midstream issues, a little bit more Randomness in that as far as you know, if if some of them are going to be delayed. But
You know, overall, our drilling times—I mean, you know, in the greater sense and over a longer term—our drilling times are what's really going to drive those cadence of those numbers.
Our next question comes from.
Good morning Allen. Thanks for your time.
Morning.
So uh similarly kind of taking a step back and looking at the Western Hansel, more holistically you guys have had considerable expiration and donation. Success and have drastically improved. The commerciality of the plate with limited missteps to date uh to be clear again for the benefit of investors, the increase in capital, allocation to the legacy, hanesville is in no way an indication of change in relative value of the western hanesville and was part of a broader initiative to return the Legacy play to maintenance levels of spending and a more constructive cast environment.
Do I have that part, right? Yes. That you know what? I didn't even think about that. When you brought that up, I mean, we
To 3, then the predictability of our growth is not there. So you've got to go ahead and add another rig and then the in the core, which is the Legacy in order just to offset some of the risk that you may have and delays that you may have as why we uh, de-risk this giant footprint in the western hanesville so Derek in no way at all. Uh, does it imply that we, we pulled anything back as far as the attitude about the Western Angel at at all. But that is a great question but I it never even came into my mind ever. I mean, like ever and I would add that uh, it more reflects the the fact that, you know, Drilling and completion costs are down. And yeah, we can add this rig and stay in our original budget. Um, and it, and availability of those Services is, is with the lower oil prices.
And and also reflects, you know, kind of our decision to sell some non-core properties, you know. And so this is uh you know getting kind of
Uh, prepared to, you know, replace you know, that production, you know and and it it also reflects kind of the excitement about the Horseshoe Wells and the ability to kind of add a lot of those to the schedule, you know what you're going to be in the Legacy hanesville. So it kind of it's probably more reflects opportunity that we see and and those areas versus you know, any
Any doubts about, you know, putting the capitol on the western Haynesville, you know? Yeah, I would say, again, 50% of our gas is head for 25, same in 26. That's the risk adjustment. Uh, We've added a lot of horseshoe Wells 149. And we said, okay, we want to increase our budget in 2025. If we add this rig to drill Wells and mainly, it's to drill a horseshoe Wells. And you saw the economics are incredible. So those are all new in the last year that 149 of the list. So we just had, why don't we? Why don't we soften up the development of the western Angel because it it it's like we said it's it's expiration exploitation but but we're going to, we're scattered out, we're drilling 80 miles to the North and South in 2030 miles to the east and west, because we're so comfortable with with what we think. We're finding and what we've found and at the same time, you know, when, when the
Geological group says, we need to core some wells. Well, that does cause some time and money. We said, okay, well let's pour all those Wells and then you know, we we plan on really drilling 1 more pilot hole in it near the Elijah 1, maybe this year. So you work that in the numbers too, and that gives you a little bit more time to tie geologically everything together. But no, no, no. We've, we've, we've, we've if anything, we have never ever been more encouraged about what we're sitting on, uh, in the western hand.
Will period. And and you know as I was talking to the Joneses today, you know, he said you need to broadcast for sure. We're not ever uh right now in the Civil future even thinking about issuing Equity to grow this stuff at all a period. In other words, that'd be another question that might be out there. Uh, we we are we're we're going to divest some non-core assets. We're going to use those dollars to pay down our debt. We'll deliver that way for a while and then we'll let Dan and the group drill and complete these Western Angel Wells with the big land, grab Derek, uh, being behind us. Now we do have probably 25,000 or 30 million budgeted for land in 2025. Some of that's in the core. Some of it's just a clean up in the western as well. But but that that's where we're going and it is a different story but it's it's such an incredible story. So great question.
Understood and and makes complete sense. And as my follow-up, I want to see if you could offer some perspective on what you're seeing in the western Hanceville. That's leaning you down. The path of testing, restricted, check management. I know it's been part of a broader optimization process in all plays, but I imagine there's a specific reason as to why you guys are approaching that in the second, half of my testing perspective based on whether it's your data or competitive data but some data
but well, it's a good question and so we are, you know,
1 of the things we knew kind of early on coming into this play was obviously it's deep and it's hot and just if you look at the the acreage up in the core of the plate, you know, you can see that when you get into the deeper parts of the core,
You know, you need to probably be a little bit more disciplined on how you draw the wells down. So, down here, we're at the very, you know,
Um, you know, pressure dependent parm. What we've seen on the wells is that uh, we we and we float our wells in a lot of different ways. We got Wells, kind of all the way across the board. Trying to kind of see what works.
and what we see is if, you know, a little bit a little bit uh,
more of a decline in year 1 just basically choking them back which is part of the reason our production is low is this was just self-imposed, you know we've
Got more aggressive at choking, the Well's back trying to maintain a real disciplined draw down.
And so, uh, that's that's uh, you know, in the results we see. And when we model it out and we do look at competitor Wells, you know, the state data,
Leads you to think that you should get a little better eurs you know if you flow them at basically more conservative rates and I do believe that you just got to find the right balance. You know as far as when you're when you're modeling the economics for return and pay out versus you know, the long-term value in the PV 10s and that's that's just what we're working through right now. And I think Eric, that's 1 reason we came up with an adjusted the production. In other words, we said whatever. We see every 90 days. We're going to tell you when to tell you and then we're going to adjust it accordingly. Um, and that's just what it's telling us to do. And it's like then said,
If you can, if you can uh uh choke it back a little bit more and have a much higher, you are in the IRL, looks fantastic, and the payout looks good Etc. Uh and you've got this inventory on 2 on 525,000 Eighty Acres and that's how we want to manage it. It it is managing like like we said
It's taken care of today, but it's also managing for long term.
Our next question comes from Clay Akamine with Bank of America.
Hey, good morning guys. Jay rolling my first question. Good morning. I I want to ask you about the non-core sales effort here. Can you talk a little bit about how you think about sizing a sale i.e.? I, I would imagine that you'd want to keep that because that's gas torque and if gas prices go up, then that's your pathway to deleveraging. And then on top of that, are there any metrics that you can point to to help us understand the value of the locations in this market?
Yeah, it's a good question. I mean, I I think that we are looking to There's an opportunity, I think in this market and in our base and you know to you know we're before I think the last several years until this year you know, basically the market was really around selling PDP and you know if out there those are the type buyers that dominated the the acquisition space and it's changed a lot.
This year, there's a lot of interest in our basin.
Um, and new players coming in. Um,
that are uh very interested in drilling locations and you know with a higher gas price, you know, some
Some uh, lower.
Lower return, projects, and the hanesville now become very attractive and and make a lot of money for for folks. So,
So, you know, we have a very, a deep inventory and the Legacy hanesville and some of what we just, you know, in our particular, uh, circumstance for the next 10 years, we just can't get to any of that. And uh, so selling off some of that inventory that we view that we would not develop, you know, anytime soon, you know, can add a lot of
Npv value to the company because we'd create value out of it. So yeah, I think we're focused on more of that and really selling a lot of, uh, you know, production or, you know, approved producing reserves. Well, and remember, as we, uh, de-risked the Western heels. We we had inventory. In other words, if we thought that we wouldn't potentially be adding material inventory. In the western Angel, we wouldn't be be looking at divesting anything in our Legacy, but if you look at the Legacy and you say you have 30 40 Years of of inventory, uh, and the market tells you that there's a demand uh for some drilling inventory. Uh and they went and we went, if we sell them they buy then we should take a hard look at it if it makes coms stock a much better company.
And it locked somebody else into the area, mainly for LNG demand.
Got it. I appreciate that. For my second question, I'm hoping that you can talk about your core in the program and what you're attempting to learn here. Our base case for the Western Haynesville is basically 3,000 locations across 3 fairways, each with a different number of drilling horizons. Does that kind of align with how you guys see it, and will this program help confirm that case?
We have, uh, of course, there's 2 reasons to drill, drill pilot holes out here for us, we sum and we've got, we've got kind of some tentative plans on where we want to drill. Our pilot holes across the entire footprint footprint. Right now those will probably move around a little bit for various reasons but uh,
you know, we eat in some areas, we just need to drill a pilot hole just to get the logs just because we don't have any kind of well control, and
And that area. And we need it to be able to steer our lateral and know you know where we're Landing it in the zone.
And then, uh, you know, secondary reason is, you know, basically to cut cores and you know, and do all of that science work, uh, get our, you know, toc's and, you know, basically let that help you back into kind of what a an original gas in place. Number looks like and also to basically just get all of the mechanical properties and maybe we can, maybe it'll help us make some tweaks to our um, you know, to our completions.
Now, I would comment that, uh, remember 80% of the western Hays will HPP. And some of the cores that we would probably drill would, would be in the HPP to acreage. Now. The first ones will be, you know, in the acreage that we need to drill to continue to hold. But even if you look at the Elijah 1, you've got a really good company. Uh, that's that's a Japanese company that's shoulder. Well, they're they're completing their will now. I believe with, uh, with the same track crew, we use to complete our wells, but we would still like the core
Well, close to that, Elijah. And we do have a 3D shoot in that area. That's the only area that we think we need to have a little bit more seismic work done. So we've implemented that program, too. So this is proactive work. Now, it costs money to do that, and that is all in our budget, too. And that goes back to, you know, we didn't grow through M&A.
We're growing, we we we own our asset base. We're just de-risking it, improves it up. And then as you do that to your first question, if there's something over in the Legacy that you want drill for a long time, that's good. Uh, and you can get top dollar for it and both the buyer and the seller win. Then we should be shuffling that around too and to protect our balance sheet. That's exactly what we're doing.
Our next question comes from Philips. Johnston with capital 1.
Hey, thanks for the time. Uh, wanted to ask a follow-up question, on the non-core asset sale um program.
Can you maybe just give us a sense of what sort of order of magnitude we're talking about in terms of potential proceeds? And also, would you expect any sort of tax leakage on the sales?
No, we really don't go into the details on what the device would look like. Yeah, yeah, I think next quarter, hopefully, we'll be able to kind of provide that, you know, so we have an ongoing process, and so we just don't think that's helpful to the process. Um, okay, we don't believe on the tax side, though, that there's any significant, um, you know, tax liability. Matter of fact, the passage of the...
The 1, big beautiful. Bill is, is very, uh, supportive of of, especially our situation and the ability to use uh, you know, have future deductions for things like interest Etc, but that's actually going to be a, a real positive benefit I think on, on, on, on our tax rates, uh, going forward and especially the third quarter when that was adopted making make, you know, make an adjustments to that. But I think that we see that at all very positive and
And, uh, probably, you know, reducing the future tax liability that we might have seen before the bill was passed.
Okay good. Um,
And then your implied capex guidance for the second half of the year is relatively flat versus the first half of the year.
Yeah, that's despite your red count. Going to 8 here in the back, half of the year from 7 in Q2 and something a little less and 7 on average in Q1. And despite, I guess, the outlook for...
32 wells drilled in the second half versus 19 in the first half. So what gives you guys confidence that CapEx won't increase in the second half of the year?
You know, if you look at where we're at really today and just in the second quarter, versus end of the last year, you know, our DNC costs are down probably on the order of 10% or so. In that neighborhood, a lot of that is the pipe prices. You know, we started seeing significant savings and our pipe prices mainly, in the first quarter, we got a little bit in the fourth quarter.
Uh, so you know, as long as those, you know, hopefully the tariff is used, don't send that the other way. But, you know, as long as that continues, that's a big piece of that.
You know, on vendor costs, just the costs are down a little bit. I think some of that may be, you know, the...
the, uh, slow down in the Parian with the lower oil prices and, uh, you know, just the fact that the rigs haven't really
Just exploded and taken off on the gas side. So, you know, we just see it across all the services.
there's also the Cadence of completions and so, you know it was a, you know, when that actually occurs and what period, you know, is also a big factor more so than when the wells are really
so I think that's actually probably a little bit less activity from, um,
You know, completion activity in the second half of the year, right? It was in the first budget.
Our next question comes from Charles Meade, with Johnson rice.
Good morning, J. Rolling, Dan, and the whole team at Comstock Resources Inc.
hello, Charles
Uh, Jay, I believe you have have talked in the past that you guys uh on on the Elijah want. Pickings well, that you guys had a little bit of a a different completion design there. And um I I I wonder if you could give us an update on how that uh how that well is performing with that different completion design. And if you've used that sort of design,
Subsequently, in any of these more recent wells.
Hey, Charles, uh, yes, we have the Elijah 1 was the first well, that we made the tweak on. And basically, we just went from 150 foot to 100 foot stages.
Uh, you know, we see on a lot of these wells, especially the deeper ones in this range.
We are typically not quite at our frac design rate when we start out. And so, just to basically address that, we decided to go to later stages.
And we basically carried it out for the entire lateral on the Elijah 1. We wanted that to be, you know, we didn't want to have a mixed bag along the lateral, how we completed it. So the entire lateral was completed with 100-foot stages.
we've done uh really 2 other Wells since then the the men 1/8 and the bail Meijer
And I think it is making a difference; it's early. We've only had the Elijah 1 on for about 3.5 months.
But, uh, it's still flowing. It's just a hair under, you know, the 27 million starting rate that we set it on, and the pressure dropped today looks really, really good. So we're very encouraged by it. I think we'll be going more in that direction.
Got it. Thank you for that that detail and then uh, Rowland on the, uh, I I get that. Yeah, for, for, for good reasons, you, you're little reticent to talk about the the vesture program. But I'm, I'm curious when I look at your acreage map to me.
The the most obvious, uh, sale.
For comps like you you guys being really, you know, deep in inventory, with the rest of the industry, at least in the Haynesville, really short on inventory, it would be in that, that Angelina River trend. Is that, is that a reasonable inference? Or is that, uh,
Is that not the direction you're going?
No, that's a reasonable. I think for Einstein? That's a good guess, right? Yeah. That's that's the reason look, you know, and it's you can also it's in the area that, you know, we just haven't been active in.
um,
So, yeah, yeah. And hopefully, we'll have a good view of that in our next report.
Yeah, I kind of really hoping that that really lets us, you know, accelerate our deleveraging goals this year while still being able to invest in, you know, the end of Western Haynesville.
Our next question comes from Null Parks with Brothers Investment Research.
Now, you may be on mute.
Our next question comes from Paul diamond with City.
Uh, thank you. Good morning. Thanks for taking the call. Um, just wanted to touch a bit on the Horseshoe well program. I know you guys have talked about 10 this year, 10. Next, just want to get an understanding of how, um,
is what we could. Cause you to move off that. Like, if you started to see better results, would you lean in, uh, worse results? Could you be out just kind of how to think about your, you know, how about the strategy there?
Still in some of our better-type curved areas.
You know, then, uh, just our regular straight wheels that we're drawing. So that's one big thing that we like about them. We've drilled three to eight; we just need our third one here, probably just last week. We've had zero problems drilling them. Uh, you know, I've said before,
Add maybe 2 days to, you know, a 10,000-foot straight. Well, just add 2 days to bend it around and make it a horseshoe.
Uh, just zero issues, drilling zero issues. Completing that first one, we'll complete these next ones here.
You know, probably in the next over this next quarter. But, um,
So really, you know, there's nothing we don't like about them right now.
Understood. Appreciate the clarity and just do a quick follow-up. So you just announced the uh, you have the next hair agreement. Um, just want to get an understanding of how you guys are thinking about potential, you know, scales structures duration timing. If any of that is kind of on the books yet or is it still just an agreement to kind of look and do it together?
Well, you know, we've had we've done business for the next year for at least 10 years and, uh, we've got a big footprint and most of our Western Angels Undead and it is a 100 miles away from both Houston and the Dallas Metroplex. So you know you if we can collaborate, which we've done is, you know, in agreement with the largest natural gas plate in the United States.
Make sure, you know, it does bring experience in power generation development and operating natural gas power generation facilities. And what we think is an area, uh, that will need some data centers. So, uh, we've been working with them for months and months, and months. And we just have a, let's just see if we can't. Uh, we can't can't go forward on this so we don't go into any more details about customers. Uh, but we do think that we have a really good site for data center, uh, near the Western heel area.
And I don't think we could pick a better partner.
Our next question comes from. Jacob Roberts with tutor biggering, hold.
Good morning.
Morning morning.
That relative capital allocation has changed given the development of the western Haynesville over the last 18 months.
But it's, it's real early for us still to be, you know, talking about our 26th activity. Which we haven't announced yet, but, uh, the, uh, you know, but, but I think that, you know, we really like the, the, uh, where the company is now with the balance program and both the Legacy and the Western hanesville and, you know, we'll be, you know, reaping the benefit of the, you know, higher production, you know, from the money we're spending this year because it takes almost, you know, 9 months, really to get production. When you kind of add a rig line,
And so yeah, I don't think we'll see any case where, you know, we'd be out spending. So obviously we would adjust, you know, activity level.
Um,
but yeah, we're very uh, bullish about
About 2026, we are looking for the company. Um, you know.
Both plays. So, you know, but, you know, we'll we'll be setting our our budget later this year. It's usually late, you know, late in the fall.
When we gauge our activity, we have a lot of flexibility and...
And how we do that activity, especially in the, you know, the, the obviously, the core where we have a lot of, uh, Well to Well rig contracts so that, you know, we always have the ability to flex activity based on the Outlook that we see. But, you know,
We're still very, uh, very bullish about 2026, and what you see in the futures market and the demand, we know that's coming on. And, you know, even with our direct,
Talks about uh providing long-term Supply to some of the really large users. You know, a lot of that is starting to crank it crank into 26.
Okay, thank you. And, and I, I wanted to Circle back to some of the, the choke Management in the western Hanceville. I'm, I'm just trying to understand in terms of of trying to different things or experimenting, different ways. How should we be thinking about the timeline on that? Well Data before you're able to make a decision as to what the optimal approach is? Um, is it, you know, you, you choke now and it's 14 months later that you're able to say this was good or bad. Uh, just just kind of any color around. That would be great.
Well, that's a really good question on the timeline because it is, it's, it is, uh, it is a longer time line because you, you definitely can't get quick answers. We float them, several different ways. We've been really aggressive on some, uh, more of the wells of late. You know, we've been uh, been very proactive as far as starting to choke them back and and basically bring the rates back down a little bit.
Uh, just based on early modeling stuff we've done, you know, we're definitely expecting a little bit better ERs with the conservative drawdown.
Uh, we haven't gotten it done yet. It's really conservative, you know? That's probably the next test that we're kind of looking at here in the near future.
411 at, uh, you know, a months of lower rate, straight out of the gate. And, uh,
And as far as the timeline to get that data, you know, I mean it's you you're probably talking uh a minimum of a year to get an idea, what it's going to do and you know maybe even 18 months to 2 years to really start dialing in on a you know, an exact answer.
But you you have your daily, you have your feedback of the the draw Downs as you produce, but that's giving you Clues, I guess I'm or you're on the right path. Yeah. And there has been some other industry, you know, uh, operators out there that have drilled a few Wells that have some State data out there that's in our data set and we're looking at. So,
Um, you know, I think we're on the way to getting there, but, uh, you know, you do kind of have to wait and let them play out a little bit. See where they're headed?
That concludes today's question-and-answer session. I'd like to turn the call back to J. Ellison for closing remarks.
Again, thank you for your hour plus time. I, I want to conclude it in that 1 week. We I think the Joneses in particular, but all of us.
We want to protect the balance sheet. That's number 1, number 1, number 1. And then, you know, I think that we can deliver this non-core asset sale. If it's a if it's a win-win for us and for the and for the buyer and we'll use those proceeds to deliver.
Organically, not with M&A. And when this LNG demand keeps growing and growing and growing, as other companies have said, the hands will need to supply most of that growth. And we want to be a big part of that. So, again, thank you for your patience. We always try to be very transparent with you about where we're going, and we'll report again in 90 days. Thank you.
This concludes today's conference call, thank you for participating. You may now disconnect