Affirm stock soars as Q1 earnings smash expectations, guidance lift
Comstock Resources Inc. reported better-than-expected financial results for Q3 2025, with earnings per share (EPS) of $0.09, surpassing the forecast of $0.0787. Revenue reached $449.85 million, exceeding expectations of $423.4 million. The stock reacted positively, closing 4.81% higher at $19.23, although it saw a 2.91% dip in pre-market trading.
Key Takeaways
- Comstock Resources posted a 14.36% EPS surprise and a 6.25% revenue surprise.
- The company expanded its operations in Western Haynesville, adding eight new wells.
- Natural gas demand is rising, driven by LNG exports and AI data centers.
- The stock closed higher post-earnings but showed pre-market caution.
Company Performance
Comstock Resources demonstrated robust performance in Q3 2025, with a 10% year-over-year increase in natural gas and oil sales, amounting to $335 million. The company continues to capitalize on the growing demand for natural gas, positioning itself as a key player in the energy sector.
Financial Highlights
- Revenue: $449.85 million, up from a forecast of $423.4 million
- Earnings per share: $0.09, exceeding the $0.0787 forecast
- Operating cash flow: $190 million
- Adjusted EBITDA: $249 million
- Adjusted net income: $28 million
Earnings vs. Forecast
Comstock Resources reported a 14.36% EPS surprise, with actual EPS at $0.09 compared to a forecast of $0.0787. Revenue also exceeded expectations by 6.25%, reaching $449.85 million against a projected $423.4 million.
Market Reaction
The stock closed 4.81% higher at $19.23 following the earnings announcement. Despite this, pre-market trading saw a 2.91% decline, reflecting mixed investor sentiment. The stock remains below its 52-week high of $31.174 but above its low of $11.415.
Outlook & Guidance
Looking forward, Comstock Resources plans to drill 19 wells and bring 13 to sales in Western Haynesville in 2025. The company anticipates continued growth in natural gas demand, driven by LNG and AI data centers.
Executive Commentary
CEO Jay Allison highlighted the strategic importance of natural gas, stating, "Natural gas has become the go-to energy source in the United States." He also emphasized the company’s liquidity, saying, "We have over $900 million liquidity, and that’s going to grow."
Risks and Challenges
- Market volatility could impact investor sentiment.
- The divestment of non-core assets might pose operational challenges.
- Potential supply chain disruptions could affect production timelines.
Q&A
During the Q&A session, analysts inquired about the potential expansion of Western Haynesville acreage and the company’s focus on strategic development. Management discussed the exploration of long-term industrial gas supply contracts and the retention of valuable acreage.
Full transcript - Comstock Resources Inc (CRK) Q3 2025:
Conference Operator: Good day, and thank you for standing by. Welcome to the Q3 2025 Comstock Resources earnings conference call. At this time, all participants are in listen-only mode. After the speaker’s presentation, there will be a question-and-answer session. To ask a question during this session, you need to press Star 11 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press Star 11 again. Please be advised that today’s conference is being recorded. I would now like to turn the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.
Jay Allison, Chairman and CEO, Comstock Resources: All right. Again, I want to thank you for the introduction and thank all those that are on the call. It’s been a really good morning. Welcome to the Comstock Resources Third Quarter 2025 Financial and Operating Results Conference Call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you’ll find a presentation entitled Third Quarter 2025 Results. I’m Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and CFO, Dan Harrison, our COO, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws.
While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you’ll flip over to slide three. As we start today, we are really excited to update our stakeholders on the company’s progress so far this year. Comstock and our bold move to create the Western extension of the Haynesville Shale have been the subject of several news stories recently as the interest in natural gas has never been greater. I don’t believe we have ever seen a brighter future for natural gas. Natural gas has become the go-to energy source in the United States, driven by the growth in LNG exports and the push to generate power for AI and data center development.
I noticed yesterday that LNG exports reached a record high of 18.7 Bcf, and the journal is full of articles on the impact of AI and data centers on future power demand. The Haynesville Shale is on the front line to deliver the gas supply to meet the growing demand. As one of the early pioneers in the Haynesville, we have focused our efforts over the last five years on being a leader in expanding the resource in the basin to be able to meet the new demand. The Western Haynesville story is more about utilizing advancements in technology than geologic prospecting, as the existence of the Haynesville and Bossier Shale in the area has been well known. Today, we’re giving you a preview of the future by providing our estimates of the vast inventory of drilling locations and our emerging play in the Western Haynesville.
We also announced the divestiture of some of our legacy Haynesville assets, which we will not need in the future as we shift more of our resources to the Western Haynesville. The sale allows us to improve our balance sheet as all of the proceeds will retire long-term debt. This was also a very efficient quarter, and our legacy Haynesville drilling program, fueled by the additional drilling rig we added at the beginning of the quarter. Our drilling and completion costs in our legacy Haynesville area average $1,229 per lateral foot. That is an industry-leading number in the basin. The activity we added last quarter will drive production growth next year into a growing demand market. On slide three, we summarize the highlights of the third quarter. Higher natural gas prices in the third quarter drove the improved financial results in the quarter compared to the third quarter of 2024.
Our natural gas and oil sales grew to $335 million. We generated $190 million of operating cash flow or $0.65 per diluted share. Adjusted EBITDA for the quarter was $249 million. And we reported adjusted net income of $28 million or $0.09 per diluted share. During the third quarter, we put three new Western Haynesville wells online, increasing the number of wells turned to sales in 2025 in Western Haynesville to eight wells. Those three wells had an average lateral length of 8,566 feet and an average per well initial production rate of 32 million cubic feet per day. And our legacy Haynesville, we’ve now turned 28 wells to sales to date in 2025 with an average lateral length of 11,919 feet and a per well initial production rate of 25 million cubic feet per day.
In September, we divested of our non-strategic Cotton Valley wells in East Texas and North Louisiana for net proceeds of $15.2 million. We also recently entered into an agreement to divest of our Shelby Trough assets in East Texas for $430 million in cash, and that sale is expected to close in December. On the next slide, I will cover the divestitures in more detail. Slide four, visually you can see this. It summarizes our recent divestitures. In September, we sold our legacy Cotton Valley wells in East Texas, North Louisiana for net proceeds of $15.2 million. Our Cotton Valley properties, which we sold, included 880 or 770.9 net wells producing 7.9 million cubic feet per day net to our interest and another 46 or 27.3 net in active wells.
On October the 10th, we entered into an agreement to sell our Shelby Trough properties in Nacogdoches, San Augustine, and Sabine Counties for $430 million. These assets include 36,000 net acres with 155 or 74.5 net wells producing 9.3 million cubic feet per day net to our interest. The Shelby Trough sale is expected to close in December. I’ll now turn it over to Roland to discuss financial results for the report today. Roland.
Roland Burns, President and CFO, Comstock Resources: All right. Thanks, Jay. Slide five, we cover our third quarter financial results. Production in the third quarter averaged 1.22 BCFE a day, and our oil and gas sales in the quarter increased 10% from the third quarter of last year to $335 million. EBITDA in the quarter was $249 million, and we generated $190 million of cash flow during the quarter. We reported adjusted net income of $28 million for the third quarter or $0.09 per diluted share compared to a loss in the same period in 2024. Slide six is the year-to-date results. Our production for the first nine months has averaged 1.24 BCFE per day, and with improved natural gas prices, our oil and gas sales in the first nine months have increased 18% to $1.1 billion. EBITDA for the first nine months of 2024 was $802 million, and we generated $639 million of cash flow.
We reported net income of $122 million for the first nine months of 2024 or $0.41 per diluted share as compared to a net loss for the same period last year. On slide seven, we break down our natural gas price realizations. The quarterly NYMEX settlement gas price averaged $3.07 in the third quarter, and the average Henry Hub spot price averaged $3.03, which is slightly below the settlement price. 28% of our gas was sold in the spot market, and the balance was sold in the index market. So the appropriate reference price for our gas was $3.06. Our realized gas price during the third quarter averaged $2.75, reflecting a $0.32 basis differential compared to the NYMEX settlement price and a $0.31 differential compared to the reference price. In the third quarter, we were 57% hedged, which increased our realized gas price to $2.99.
We broke even from our third-party gas marketing in the third quarter. On slide eight, we detail our operating costs per Mcfe and our EBITDA margin. Our operating costs per Mcfe averaged $0.77 in the third quarter, $0.03 lower than last quarter. Our EBITDA margin was 74% in the third quarter, which is unchanged from last quarter. Lifting cost improved by $0.02 in the quarter. Production and ad valorem taxes were up by $0.01, and gathering and compression cost improved by $0.01 in the third quarter. On slide nine, we recap our spending on drilling and other development activity. We spent a total of $267 million on development activities in the third quarter and $785 million for the first nine months of this year.
In the first nine months of this year, we drilled 25 or 21.8 net horizontal Haynesville wells and 11 or 10 net Bossier wells for a total of 36 wells. We also turned 36 wells or 30.9 net operated wells to sales, which had an average initial production rate of 27 million cubic feet per day. Slide 10 recaps our capitalization at the end of the third quarter. We ended the quarter with $580 million of borrowings outstanding under our credit facility. Our borrowing base is at $2 billion under the credit facility, and the elected commitment is $1.5 billion. Our last 12 months’ leverage ratio has improved to three 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 third quarter, we had $239 million of liquidity.
The sale of our Shelby Trough assets that’s expected to close in December will improve the leverage ratio and enhance our liquidity since the cash flow that’s associated with the properties being sold was minimal. And I’ll turn it over to Dan to discuss the drilling results.
Dan Harrison, COO, Comstock Resources: Okay. Thanks, Roland. If you look on slide 11, this is an overview of our latest acreage footprint in the Haynesville Bossier Shale in East Texas and North Louisiana. We now have 1,055,386 gross and 797,440 net acres that are prospective for the commercial development of the Haynesville and Bossier Shales. Over on the left, this is our Western Haynesville acreage footprint, which we’ve now grown to over 530,000 net acres. On the right is our 266,711 net acres in our legacy Haynesville area. We have 27 gross or 26.9 net wells currently producing on our Western Haynesville acreage, which is virtually undeveloped compared to our legacy Haynesville area. Given the higher pay thickness and the higher pressures we encounter in the Western Haynesville, we expect the Western Haynesville will yield significantly more resource potential per section than our legacy Haynesville.
On slide 12, this outlines our new development plan utilizing the horseshoe lateral concept. The horseshoe well design concept combines the two separate and adjacent shorter laterals into a longer singular lateral, which results in a much more efficient use of capital. We realize approximately 35% savings in our drilling costs when we drill a 10K lateral horseshoe well compared to a 5,000-foot sectional lateral well. Our drilling inventory in our legacy Haynesville area now includes 118 horseshoe locations. During the third quarter, we completed our second horseshoe well to date, the Roberts 2623 number one. Had 11,453-foot lateral and a 26 million cubic feet per day IP rate. To date this year, we have drilled one additional horseshoe well, and we have another four horseshoe wells that are currently in progress.
We plan to drill a total of eight horseshoe wells this year, and we plan to drill 10 horseshoe wells in 2026. Slide 13 is our updated drilling inventory in our legacy Haynesville area at the end of the third quarter. This is adjusted to exclude the locations we’re selling in the Shelby Trough. This quarter, we’re now presenting our legacy Haynesville and our Western Haynesville drilling locations separately. Our total operated inventory in the legacy Haynesville consists of 1,039 gross locations, 809 net locations, which equates to a working interest of approximately 78%. Our non-operated inventory in the legacy Haynesville includes 873 gross locations, 108 net locations, and this represents a 12% average working interest.
Our drilling inventory is comprised of short laterals, less than 5,000 feet; medium laterals, 2,500 to 8,500 feet; our long laterals between 8,500 and 10,000 feet; and our extra long laterals for all the wells over 10,000 feet. In our gross operated inventory in the legacy Haynesville, we have 36 short laterals, 157 medium laterals, 425 long laterals, and 421 extra long laterals. Our gross operated inventory is split 51% in the Haynesville and 49% in the Bossier. Over 80% of our gross operated inventory in the legacy Haynesville consists of laterals which are greater than 8,500 feet. The 118 horseshoe locations mentioned on the previous. Slides are all in our legacy area. The average lateral length on inventory is now up to 9,961 feet. This is up 275 feet from the end of the second quarter.
So our inventory provides us with decades of future drilling locations based on our current activity levels. On slide 14, we show our estimated drilling inventory in the Western Haynesville. This represents the first time we’ve disclosed our Western Haynesville inventory. And our total inventory in the Western Haynesville consists of 3,332 gross locations and 2,559 net locations. This equates to a working interest of about 77%. As much of our Western Haynesville acreage is not unitized, the net locations here are estimated. In the Western Haynesville, the inventory is more weighted to the Bossier formation. With 36% of the inventory in the Haynesville and 64% of the inventory in the Bossier.
The same as our legacy Haynesville inventory, our Western Haynesville inventory is broken down into groups of short laterals less than 5,000 feet, our medium laterals between 5,000 and 8,500 feet, our long laterals between 8,500 and 10,000 feet, and our extra long laterals over 10,000 feet. In our Western Haynesville, in the gross operated inventory, we assume we have no short laterals. We have 1,347 medium laterals, 642 long laterals, and 1,343 extra long laterals. So approximately 60% of this gross operated inventory in the Western Haynesville consists of the laterals greater than 8,500 feet. On slide 15 is a chart outlining our average lateral lengths that we’ve drilled. This is based on wells that have reached total depth. The average lateral lengths are shown separately for both our legacy Haynesville and Western Haynesville areas.
In the third quarter, we drilled 11 wells to total depth in the legacy Haynesville, and these had an average lateral length of 12,593 feet. The individual lengths ranged from 4,968 feet up to 15,466 feet. Our record long lateral in our legacy Haynesville area still stands at 17,409 feet. In the third quarter, we drilled six wells to total depth in the Western Haynesville, and these wells had an average lateral length of 10,158 feet. The individual lengths here range from 7,809 feet up to 12,710 feet. Our longest lateral drilled to date in the Western Haynesville still stands at 12,763 feet. To date in the Western Haynesville, we have drilled 15 wells with laterals longer than 10,000 feet, and we have drilled six wells with laterals over 12,000 feet. Slide 16 outlines the wells that were turned to sales on our legacy Haynesville acreage this year.
So far this year, we’ve turned 28 wells to sales in our legacy Haynesville area. The individual IP rates on these wells range from 16 million a day up to 37 million cubic feet a day. And the average was 25 million cubic feet a day. The average lateral length was 11,919 feet, with the individual wells ranging from 9,252 feet up to 17,409 feet. Just to recap, four of our eight rigs are drilling on our legacy Haynesville acreage. Slide 17 outlines the eight wells that we have turned to sales in the Western Haynesville this year. Since we last reported our earnings, we have turned three additional wells to sales. These three wells had an average lateral length of 8,566 feet and an average initial production rate of 32 million cubic feet per day. And four of our eight rigs are drilling on our Western Haynesville acreage.
Slide 18 highlights the average drilling days and the average footage drilled per day in the legacy Haynesville area for our benchmark long lateral wells. These are our wells that are greater than 8,500 feet long. In the third quarter, we drilled 10 benchmark long lateral wells to total depth in the legacy Haynesville. And these wells averaged 26 days to total depth. We’ve averaged 26 days consistently for the last three quarters. In the third quarter, we averaged 1,004 feet drilled per day on our legacy Haynesville acreage. This is a 4.5% increase versus the second quarter of 2025. And a 2% increase versus the 2024 full year average of 987 feet drilled per day. The best well drilled to date in the legacy Haynesville still stands at 1,461 feet, which was drilled to TD in 14 days. Slide 19. This highlights our drilling progress in the Western Haynesville.
During the third quarter, we drilled six wells to total depth in the Western Haynesville. We now have a total of 35 wells that we have drilled to total depth through the end of the quarter. We averaged 52 drilling days for the six wells drilled to total depth in the third quarter. This represents a decrease of three days compared to the second quarter and a decrease of seven days compared to our 2024 full year average of 59 days. Our fastest well drilled to date still stands at the 37-day mark, and that was drilled with a 12,045-foot lateral. Over on slide 20 is a summary of our D&C costs through the third quarter for our benchmark long lateral wells located on our legacy Haynesville acreage. These costs reflect all legacy area wells drilled with laterals greater than 8,500 feet long.
The drilling costs are based on when the wells reach TD. And the completion costs are based on when the wells are turned to sales. During the third quarter, we drilled 10 of our benchmark long lateral wells to total depth. The third quarter drilling cost averaged $558 a foot. This is a 15% decrease compared to the second quarter. We had an abnormally high drilling cost in the second quarter due to drilling difficulties that were associated with some highly overpressured SWD zones. And during the third quarter, we turned nine wells to sales on our legacy Haynesville acreage. The third quarter completion cost came in at $671 a foot. This represents a 7% decrease compared to the second quarter.
These lower completion costs are due to a combination of we had lower frac pricing, lower fuel costs with all of our wells using a natural gas blended fuel, and also the longer laterals in the third quarter. Just we got four rigs running that are running on our legacy Haynesville acreage. Slide 21 is a summary of the D&C costs through the end of the third quarter for the wells drilled in the Western Haynesville. During the quarter, we drilled six wells to total depth with an average lateral length of 10,158 feet. The third quarter drilling cost averaged $1,385/foot. This represents a 24% decrease compared to the second quarter, but is more in line with our previous quarters. The primary factor for the lower drilling costs in the third quarter is the longer laterals. Our average lateral length in the second quarter was very low at 7,933 feet.
Compared to an average lateral length of 10,158 feet in the third quarter. During the quarter, we also turned three wells to sales on our Western Haynesville acreage. These had an average lateral length of 8,566 feet. We didn’t turn for this year. We didn’t turn any wells to sales in the first quarter. The third quarter completion cost averaged $1,622/foot. This is a 24% increase compared to the second quarter. And the higher completion cost was primarily due to the higher frac costs we had on the wells and to a lesser extent the shorter average lateral length. We did have some higher than normal horsepower usage associated with frac in these wells, which were considerably deeper than our average Western Haynesville well. And we observed some higher frac gradients at these deeper depths. To kind of recap our activity levels.
We’ve got four rigs running in the Western Haynesville. And we got four rigs running on our legacy Haynesville acreage. We also have two full-time dedicated frac fleets that we are running between both our legacy Haynesville area and our Western Haynesville areas. And I’ll turn the call back over to Jay. All right. Great job, Dan and Roland. Please refer to slide 22 where we summarize our outlook for 2025. In 2025, we remain primarily focused on building our great asset in Western Haynesville that will position us to benefit from the longer-term growth in natural gas demand. And we currently have four operated rigs drilling in Western Haynesville to continue to delineate the new play. We expect to drill 19 wells and turn 13 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 Marquette Gas Treating Plant started operations in July, which more than doubled our gas treating capacity. In the legacy Haynesville, we’re currently running four rigs to build production back up in 2026. We expect to drill 33 or 25.6 net wells and turn 35 or 28.2 net wells to sales in the legacy Haynesville this year. We continue to have the industry’s lowest producing cost structure and expect drilling efficiencies to continue to work toward driving down drilling and completion cost in 2025 in both the Western and legacy Haynesville areas. As Roland stated earlier, we have strong financial liquidity totaling more than $900 million, which will be enhanced with proceeds from the Shelby Trough divestiture, which is expected to close in December 2025.
If you have any specific questions on guidance for the rest of the year, please feel free to reach out to Ron Mills. Ron. Antoine, we can turn it over to Q&A. Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while I compile the Q&A roster. Our first question comes from Derek Whitfield from Texas Capital. Please go ahead. Good morning, Alan. Thanks for your time. Morning.
Wanted to start with a broader question around 2026 and not to pin you guys down on any numbers, but really just wanted to think about it from the standpoint of the higher level of activity you’re carrying into 2026 and the operational efficiencies you’ve gained in both the Western Haynesville and legacy Haynesville. Could you speak to the broader capital efficiency gains you’d expect as you enter the year? Yeah, I’d say. If you kind of—they’re kind of two different animals, the legacy Haynesville versus the Western Haynesville. I mean, the efficiency gains in the legacy area, we’ve pretty much—we’re kind of up at the top of the curve there. I think we’ve picked up a lot, obviously, since we’ve added the horseshoe wells. As far as just being able to convert a lot of our shorter wells to longer wells, I think we’ve seen more efficiency there.
The horseshoe wells are going great for us. Really, the efficiency gains that we’re still looking to pick up and have been still up on the learning curve is in the Western Haynesville. We’ve got a lot of—we’ve had a lot of improvements we’ve made to date. We still got a few other things kind of coming down the pike that we’re going to be—we’re going to be looking at implementing in the Western Haynesville to help our efficiencies there. But I think the four rigs that we got running in the Western Haynesville’s is a good activity level for us. We’re able to learn a lot from it. We’ve made a lot of improvements in our downhole performance. And like I said, we just got a few things.
In the mill that are kind of turning that are going to help us out, we think, in this next year, in 2026. Derek, you commented that we’ve had solid Western Haynesville well results. And I’d just like to comment on Dan. The very first Haynesville well we ever drilled back in 2008, Dan was involved with it. So for 17 years, he’s touched every Bossier or Haynesville well we’ve drilled, either be in the core or in the Western Haynesville. So he has complete authority to derisk and optimize the cost on the new Western Haynesville play that’s important. And just from a capital efficiency standpoint, we are carrying some capital this year for the addition of that eighth rig with no production really showing up until sometime in the first or second quarter of next year.
So when you think about your typical capital efficiency, that should drive improved capital efficiency next year. Great. And for my follow-up, I wanted to shift over to gas marketing. More specifically, I love your perspective on how you see gas on gas competition unfolding along the Gulf Coast. As you think about your supply advantage of being able to deliver gas into Sabine Pass and the competing demand opportunities between LNG and PowerGen, you’re arguably in a great position to benefit from both in terms of gas realizations. Yeah, that’s a good observation, Derek.
Yeah, I think that especially owning our own midstream in the Western Haynesville is going to be really a huge asset for us in the future as we’re able to kind of, instead of having to go through other midstream companies and long-haul pipelines, we can create great markets right there that we can directly sell to end users and become a very reliable supplier. And I think that’s what a lot of these large users with new demand are looking to establish direct relationships with the producers. And you’ve heard a lot of that about that in our industry. So I think we’re well positioned there, given that we control the infrastructure, the midstream, and obviously a great location where the gas can support all the growth in Texas. And then with the Port Arthur LNG, very close to being able to connect to that.
So yeah, I think that’s a big part of the future for natural gas, is not only having the natural gas, but being able to get it directly to the end user. Well, Derek, I think if you look at location, location, location, I mean, 100 miles from Dallas and the same distance from Houston. And really close to LNG corridor. You’re perfectly situated for both AI data centers and LNG. So you couldn’t be in a better area. And then the fact that this is not an exploration play, it’s really a development play for the geology that was there. So it’s been a very, very, very active oil and gas region for 30-plus years. So for us to just deepen these wells with the new technology in a great footprint where we’re located. And on maybe 6,000 of these acres are dedicated, the remainder dedicated.
That’s why we say. We’re around a big bright light bulb. And then people are calling because of the inventory, which inventory is the Holy Grail. I mean, that’s why you see people expanding to look at this play. It is the Holy Grail. You got to have inventory. Thanks for your comments. I’ll turn it back to the operator. Thank you. One more for our next question. Our next question comes from Charles Arthur Meade from Johnson Rice & Company. Please go ahead. Good morning, Jay. To you and your whole team there. Hello, Charles. Thank you for the warm welcome. Jay, I want to ask you about the Shelby Trough sale. It looks to us like that’s really a great outcome for you guys as far as what the seller paid for those undeveloped locations.
So I wanted to see how you would characterize it, how happy you were with those proceeds, and then ask if there’s anything left in your portfolio that could fit that same appetite for people who are willing to pay for those undeveloped locations. Well, first of all, Charles, I think it’s a total win-win for everybody. I mean, we are really a unicorn out there because we have so much inventory. As we just announced, we almost have 2,600 locations net in the Western Haynesville. That’s a big gift that we’ve been working on for five years. So if you look at other really good locations that might be for sale, I mean, I think there’s a really smart buy by the buyer.
I think we needed to pay down the debt on our balance sheet because we’d incurred a lot of money as our investment in the Western Haynesville. And we looked at that. We trimmed some of the vertical wells, those 900 or so vertical wells. We sold those early on. So we are always looking as we de-risk and kind of fortify our acreage position, Western Haynesville. Is there anything else we can do? And that is to adjust the balance sheet because we need to get our leverage lower. So I was pleased with how both of those transactions came about. And again, we always look to see, Charles, as you well know, what can we do as a company position where we think we are to become a stronger company in the light of AI data center demand and LNG demand. That’s the only thing we do.
And I think everybody won in the trade. Great locations. And we didn’t need to be drilling them because we’re drilling the Western Haynesville. Got it. And then the follow-up, following on that same thread, I want to say thank you for sharing this Western Haynesville location count. And I just want to ask a couple of questions around your assumptions and the dynamics there. Just using the kind of back-of-the-envelope math, it looks like you guys have been pretty conservative in your assumptions on number of zones and spacing across zones. But I wonder if you could share what the, if you’d be willing to share what the important assumptions are in that, I think, the 2,500-2,600 number.
And also, I think Dan alluded to this in his prepared remarks that perhaps because not a lot of the acreage is unitized yet, that that’s actually preventing you from counting locations. And my assumption is that would get worked out over time. But maybe you can fold that into the assumptions on the location count. I’m sure. And I think we tried to be conservative on how we looked at well spacing and benches in the play because you obviously don’t want to start out at a high number and bring it down. But we think they’re very, it’s a very realistic view of the inventory. The comment that was made about the working interest in our legacy Haynesville inventory, I mean, every single location there is pretty exact. We know the exact, we know what unit it’s in. We know our working interest with precision.
In the Western Haynesville, those units are being put together still. So the exact working interest in the units is not 100% known. So far, most of the wells, we’ve had 100% working interest in. So we just looked at our acreage ownership and just made some rougher assumptions there. So it just doesn’t have the level of precision, but I don’t think it’s a significant. I think we’re within the margin of error as far as looking at how we present the net numbers. Yeah. And Charles, we always discount it back. You say, "Here’s what you could have. Here’s kind of a high, low number." And then you discount it back and say, "Okay. What is a number that we can throw out right now. That we think with some bookends on we have a chance of achieving?" And like I said, you don’t want to be aggressive.
And then all of a sudden, you have a few less, and you’re a loser. So we want to throw that out and just say, again, with an asterisk that we’ve not unitized some of those locations. So that’s a guesstimate. Got it. That is great detail. Thank you. Yeah. Great questions. Thank you. Our next question comes from Kelly Chen from Bank of America. Please go ahead. Hey. Good morning, guys. Jay, Roland. Good morning. I want to start on the Western Haynesville disclosure. And maybe first off, I think putting your expectations in print really shows your conviction in the asset. For my question, I want to follow up on the unitization comment. You’ve got some short laterals in that table, 5,000-8,500 feet. But this is a large contiguous position.
So my question is, what’s stopping you from doing the landwork to optimize the entire position around 10,000-foot laterals? And if that’s possible, how long would that work take? Yeah, that’s a great question too. But I think there are some areas where there’s some ownership, where there’s some other operators that we’ve already kind of identified that we’re keeping out of our units. So we’ve chosen those. Shorter laterals. Just like the wells we completed this quarter and drilled last quarter, a lot of that was defined by kind of the acreage ownership. And so we’ve honored that where we don’t have it completely contiguous. So I think—and then there’s obviously geologic structures that we have identified on seismic that we are avoiding and not wanting to develop around. And so we’ve honored a lot of our geologic work too in those assumptions. But it’s still early on.
You’ll be able to probably optimize that over time. And then a lot will depend on how long do you really want to go? Do you want to go to 15,000-foot laterals? And some of that is, I think there’s room to optimize in the future. But I think this was a really good view of how we see the acreage we currently own. Now, we could also lease additional acreage that will change the configuration in the future. And I’m sure that will happen. We’re always picking up additional acreage as we put units together. So there’ll be moving parts. But I do feel like this was a pretty thorough look at if we stopped leasing, what it could look like now. And Kelly, you noticed we added 5,000 acres from the last time we reported.
So we do cleanup stuff all the time in the Western Haynesville, just like we do in the Core. This is a pretty safe, conservative number. We think that we have leased 90% of what we think the real value is in the Western Haynesville. Now, maybe that’s expanded, and that’ll be a good thing. We hope it does expand. But based upon the control that we have and the size that we have and the well results we have, I think that we’re in pretty good shape there. But we keep trying to make it better. And at some point in time, we won’t own 100% of all the wells. But until that time is right, we’ll kind of drill the lateral lengths that we need to keep the information that we need to keep kind of in our back pocket right now. Thank you for that, guys.
For my second question, I want to ask about the second train at the Marquette Gas Treating Plant. That build looks like it’s going to take you to about 1.3 Bcf/d from 900 million cubic feet. So that’s quite the scale. My question is, was this part of the original scope of the JV deal with Quantum? And then can you talk about the capacity utilization at those plants? What is it today? And once Marquette 2 is online, perhaps in 2027, where do you think the utilization rate will be at that time? I don’t know if we want to forecast the utilization rate. That’s getting way out there. But we are. We originally put together the plan for Pinnacle, the Pinnacle Gas Services, and how to service the development program. I mean. Obviously, we saw. And we’ve commented this a long time ago.
That we saw trying to create a treating infrastructure to handle up to 2 Bs of gross production over the next five, six, seven years. So I think this is the second phase of Marquette. It was the next step that was in our original plan. And then there’s another. Either debating on an expansion at Bethel or a third gas plant will probably be something way off next in the future. But we do have to keep ahead. We obviously have to provide for the treating way ahead of when we’re going to actually produce it. It’s not going to be a just-in-time kind of delivery, obviously, because it takes a good 12 to 18 months to put those together.
So yeah, right now on Marquette 2, phase two, we’ve got a lot of long lead time components and equipment that are being manufactured that we have to go out and order. And so that’s kind of the big process going on now for something that we can hopefully open up next summer would be our goal for that. And yes, I think the key answer to that is we have a lot of inventory. But we own our midstream, as Roland mentioned during the beginning comments. And we have an incredible financial partner with Quantum. And we look to see what our drilling inventory looks like. We look to see what our performance looks like. We see what our acreage addition looks like. And then based upon all that, we control the gathering.
And as far as the takeaway and the demand, as we said 45 minutes ago, it has never, ever looked brighter out there for what the world needs, not just America. The world needs in the form of natural gas. And I think we’re right there at the right time. Are there additional other operators? There are a couple of other operators which are running rigs in the area. And so a lot of that will. How we actually build out will also depend on do we end up picking up some of that gas or not. And so that’s all. A lot of that is to kind of remain to be seen in the future. But there’s other activity in the area that hopefully we kind of see come into Pinnacle over time too as we build out that great asset that underlies the Western Haynesville.
Guys, I appreciate all that, Keller. Thank you. Thank you. Our next question comes from Carlos Escalante from Wolfe Research. Please go ahead. Thank you. I love the way the operator said my name. Escalante. Good morning, Jay, Roland, and Dan. I want to go back to one of your comments, Jay. You said hopefully the Western Haynesville, the footprint that you guys have at least expands. And nice wordplay, by the way. But look, you’ve done a great job at establishing the core with just under 30 wells across the play, especially in that southern corridor across Leon and Robertson. With what is incremental data proving up acreage to the north of that as well. However, you’ve seen recent leasing and M&A activity flow into the east and southeast, particularly in Anderson and Houston.
So I wonder, when you see that, do you think the core—do you think there’s likelihood that the core of the basin could actually be much larger and it extends into potentially some of your other wells that you drilled earlier this year? So in part, it begs the question, if I may, along the same lines, if you look at—it looks like you have a permitted well near Olajuwon. If maybe you can touch on when you plan to go back to this area as well. Thank you. Well, yeah, the comment should be because of Jerry Jones and because of his big and plus dollar investment in the company, we could literally think and not only think, Carlos, we could act out of the box.
And because of the fact that we’ve always been leaning toward natural gas, I mean, and we’re one of the front runners in the core of the legacy Haynesville area. Jerry Jones said, "Here’s a well. We showed it. We could drill it. And that’s a Circle M well." That, over the last five years, has proved to be successful. So as we move to the call we have today over five years. And looking at the seismic 2D, 3D, looking at the wellbore penetrations, looking at the performance of the 30, 40 wells we’ve either drilled, completed, or drilling. What we look at, we say, "We’re very comfortable that this is probably 90% of the real value." Now as you look at Aethon, Aethon says, "There are monster wells out there." I love that they say that. And we’ve hit a bunch of them. But that’s a credible company.
Mitsui to come in. They’re smart. Management’s smart. They’re money-smart. They come in. Expand is they’re doing what their name says, expanding. Their name says expanding. And they’re expanding into the Western Haynesville. Because why? As I said earlier, the locations are the Holy Grail. I mean, you can do M&A, M&A, M&A, but that doesn’t add any new locations on planet Earth. It gives you more under your umbrella. But we’ve tried to address the problem. And the problem is, can you really add new inventory? And that’s where the prior question was asked, "What’s your inventory count?" And I think we’re pretty accurate on 2,500, 2,600 net locations. That’s an incredible number. 2,600 locations. Incredible number. So we are always looking, Carlos, to see, "Do you go east? Do you go south? Do you go?" Everybody is always doing that. And you know what?
There’s going to be some gems out there. And I hope they are found. Because all that does is make our acreage more valuable, in our opinion. And I’ll add. You asked about a permitted well up by the Olajuwon. We do. We actually did spud. We got a two-well pad that’s up there near the Olajuwon, and that pad was spud last week. So it’ll be one Bossier, one Haynesville? Yeah, we got one. The Olajuwon is producing from the Haynesville. And the new pad that we spud last week would be an additional Haynesville well and a Bossier test, our first Bossier test up there. Yeah. And we’re coring up in that area too. That’s correct. So that’s important. At the cores we’ve had, and we’re coring there also. That’s terrific, Carlos. I appreciate that.
And real quick, if I can sneak in my follow-up, you mentioned Aethon, Jay, and if I may, I think one of your drilled wells this quarter, well, two wells, the McCullough wells, are nearby that area. We’ve seen their type curve to be quite outstanding in terms of production plateau. And obviously, this well is very strong in terms of initial production. So I guess my question is, is there anything that. You’re looking at in terms of what they’re doing or. Any kind of. Near-term collaboration. That you guys can potentially benefit from in terms of what you do, or. Has it been more. A separate effort from that standpoint? Well, yeah, we’ve done some are in the process of some acreage swaps with them so they can drill longer laterals.
We can drill some longer laterals in areas that we want to drill and they want to drill. But I don’t have any other comments on that, Dan, on McCullough, etc., versus Aethon. I mean. It’s always very, when you have other operators doing things differently, it’s always great learning for a basin. So that’s one thing that the Western Haynesville hasn’t had near as much of as the original Haynesville had. But as we have some other operators, and they were the first one out there. And so it’s going to be, I think, very incremental to us learning how to properly produce the wells and drill the wells. The more activity, the more learning, it’s going to be better for all the operators. Yeah. If four or five more new operators come in, I think everybody, particularly Comstock, the learning curve is shortened.
I think it’d be a great thing. Yeah. I think what you see is all the operators, obviously, they all kind of do something a little bit different: bigger fracs, smaller fracs. How they draw their wells down. What kind of casing design. Bigger hole laterals, slimmer hole laterals. So all of those things, I think when you get more of that in the pot and start looking at the results. Like we say, that’s definitely going to help everybody. Thank you, fellas. Thank you for having me on. Thanks, Carlos. Thank you. To ask a question, please press star 11 on your telephone and wait for your name to be announced. In the interest of time, we ask that you please ask one question and one follow-up. Our next question comes from Kevin McCurdy from Pickering Energy Partners. Please go ahead. Hey, good morning. Thanks for taking my question.
I know you haven’t put out a 2026 guide yet, but is there any color you can provide on how you plan to prosecute the Western Haynesville next year? I’m looking for any thoughts on holding acreage versus development. The size of the pads you might drill, and lateral lengths, as well as I think you kind of touched on where you might be drilling, but any more color on that would be helpful too. Well, I think that, yeah, 90% of the plan is going to be holding acreage, as we said. We still have a lot of term acreage that we lease. In the play. And so that’s a big part of where we want to drill the wells. So it’s going to be following. Where we lease, the timeframe we leased. And. So I think that’s how we look at it.
I think, yeah, the activity level of four rigs that we have operating. Is sufficient to kind of accomplish all that and not have to. Worry about losing any acreage that we don’t drill that we want to drill. Yeah. And I think you’re going to see in 2026, more of our wells will continue to kind of push more in that. Northern, eastern direction along the trend of where the acreage is. Great. Appreciate that detail. And then just a question on slide 13 and 14 on your inventory. Just to confirm, were the changes in the legacy Haynesville and Bossier share, was that just. Driven by the. Asset sales, or was there anything else that changed in those inventory numbers?
Well, one time we had some of the Western Haynesville in there, probably a small amount that was based on just the wells we drilled and the direct offsets, etc., that you obviously have. In the inventory. And so that’s why we kind of chose to break it out. It really wasn’t really represented much in the original chart. So you had that, plus you had, obviously, we had the. Acreage that we sold. Or in the process of selling that we also removed those locations. And then there’s always continued recalibration as wells we find a way to make the laterals longer, typically, is kind of you could see that the feet continues to get larger. Average foot of that lateral. So that’s always a process that we continue to optimize. Thank you for taking my question. Thank you. Our next question comes from Jacob Roberts from TPH&Co.
Please go ahead. Good morning. Morning. I wanted to circle back to a Q2 item. One of the things that was discussed was some experimentation on choke management in the Western Haynesville. And I understand that we probably don’t have enough data to make a final call, but I’m just wondering if you could talk about maybe the varying methodologies you’ve applied to the three that came online last quarter and then the handful that are going to be coming online to end the year. Yeah. We got the three that we turned to sales in the last quarter. We’ve got four new wells that are turning to sales here in the fourth quarter. We have had some we have varied it a little bit. I’d say we haven’t done anything that’s been extremely conservative to date.
We’re taking some of the information from the cores, and we’re still doing a lot of detailed rate transient analysis. And basically, I think it’s telling us, obviously, the more conservative drawdown is what we need to be following. And I think for the future, we’re still looking to transition more into that probably more conservative approach from where we started at. Great. Thank you. Jay, earlier you mentioned AI data centers, that type of stuff, as well as LNG demand, which have both been hugely topical. But recently, we saw one of your peers sign a sizable industrial contract at a premium to NYMEX over in Louisiana. Curious if you could talk about that market, how you see it evolving, and maybe Comstock’s willingness to participate in industrial agreements moving forward. Sure.
That’s a great market, especially along the River Corridor area and areas along the Gulf Coast where there are new industrial plastic plants, etc., that are being built, fertilizer plants. And they’re competing, obviously, with the LNG feedstock gas. So those customers have been reaching out and interested in long-term supply deals where years ago they were never interested in that. They would just go get gas in the monthly market, it was easy to get. So I think you do see I think over time we see a lot of our market and our other producers in the area wanting to establish having more direct sales to end users, capturing more of the value, the value chain, and better margins versus having the midstream companies take off a lot of that margin. And so a lot of us are working on long-term plans like that, as we are too.
Great. Appreciate the time, guys. Thank you. Thank you. Our next question comes from Philip Johnston from Capital One. Please go ahead. Hello, Phillip. Hey, thanks for the time, and congrats on the asset sales. My first question is really just a housekeeping question for Roland on the Shelby Trough sale. Would you expect any tax leakage on the gross proceeds? That’s a good question. No, we really have lots of tax attributes to actually that—yeah. And we do expect a fairly sizable gain on that transaction because of. We acquired that acreage way back with the Covey Park acquisition. And it wasn’t a big part of that value that got allocated then. So there is a pretty sizable bookend tax gain that we expect. You’ll kind of see some of that in the 10-Q when we file it later today. But we think we have a lot of.
Tax attributes that we’ll just be able to utilize. And so we don’t see any cash. Tax impact of that. Okay. Sounds good. Then a question for Dan, and it’s really a follow-up on Carlos and Kevin’s questions. It sounds like the two-well pad near Olajuwon is kicked off, which is good to hear. Can you maybe just give us a guesstimate of how many wells up in that northern step-out area might be considered for next year, or what percentage of the total might be up in that area? Good question. We do have more wells planned for up in the area up there. The number. Escapes me off the top of my head, but. We do really like that area up there. The Olajuwon is performing extremely well. Super happy with it.
So our next step is on this two-well pad is to test the Bossier, which is much thicker. Up there. So we want to get a good read on the Bossier, and then. We’ll kind of. Kind of go from there as far as how we’re going to develop out that. Bench in that area. But we do have. I’m going to say. Five, six wells kind of planned up in that area for next year. Kind of just around that general area. Yep. Okay. Perfect. Thank you. Thank you. Our next question comes from Noel Parks from Tuohy Brothers Investment Research. Please go ahead. Hi. Good morning. Morning. I just had a couple—hey, how you doing? You did touch a bit on it, but with the new treatment capacity you have, the new plant coming online. Have you talked much about sort of the. Economics of. It?
Sort of the in-house economics versus the third-party opportunity while you’re kind of in the ramp-up mode? Yeah. I think that’s been something we’ve been studying, obviously, because we don’t—a large part of. Your cost for treating is really. All the facilities you build. And then once you build them, if you can utilize them, your actual operating costs can be very, very, very, very low. Just the actual operating cost associated with it. But you have to recover the capital. So that’s kind of where a lot of the costs are. So obviously, if you own it yourself, you can recover it. You don’t have to. Keep recovering it. If you allow a third party to provide it, then they’re going to continue to charge whatever they can for that area based on. Demand for their services in the area. And that cost will never go down unless.
There’s just no demand for services in the area. So I think. So these are long-term investments we’re making now, but I think they’re really going to really pay off in the future. For us. To continue to preserve our already industry-leading low-cost structure. So that’s why we’re real excited about what we’re able to accomplish out there and be able to do it without too big of a strain on the company with our partnership there that’s funding it. Great. Thanks. And. This is kind of a housekeeping item, but I did take sort of a quick look at. The. Gathering transportation expense line, and it looked like it might have been down sequentially a bit in. The quarter. And I just wonder if I had that right and if there were any drivers behind that. Yeah. It was down sequentially.
It was just over $41 million in the second quarter. It was just under $40 million in the third quarter. But part of that is driven by we had lower volumes sequentially as well. So you look at it on a GTC per unit basis. It was 36 cents just versus 37 last quarter. So that’s driven by volumes. Yeah. I would say that’s probably correct, right? Okay. Okay. Great. Thanks a lot. Thank you. Thank you. Our next question comes from Paul Diamond from Citigroup. Please go ahead. Good morning, y’all. Thanks for taking the call. Just wanted to touch quickly on kind of your activity allocation between Western Haynesville and the legacy acreage. Currently split 50/50. If you guys were to add or drop. Any activity over time, where do you think it would come from, one or the other?
Well, I think we’d like to keep the four operating rigs in the Western Haynesville just. Because of the strategically, in order to hold all the acreage, that’s a pace that makes that a comfortable program. And so I think it would obviously reflect in the legacy area where there’s no. Acreage considerations there, and you’re kind of basing that on what’s the. Supply-demand outlook, what’s the price. So. Obviously, just like last year, we flexed very heavily in the legacy area. And we hope to continue just to steadily add activity to the Western Haynesville as we build that up. So they’re kind of on two different kind of—I think we’re very reactive on the legacy side to. The situation, and then we want to be more. Steady on the Western Haynesville in order to continue to develop that asset and retain that asset. Got it. Makes perfect sense.
And now that you guys have given the inventory assumptions of the Western Haynesville acreage, can you talk about any progression you see on D&C? Still tracking towards about $30 million per well on a 10,000-foot basis. I guess, where do you guys see that going through time? What’s your target longer term? I think we’re going to definitely see the cost continue to come down. There’s a pretty good spread depending on where you’re drilling at on the acreage as far as. What that D&C cost is. Our low end that we’ve achieved so far is about $21,000 a foot for the stuff that’s a little bit shallower TVD. And then the $30 million mark or. Assuming like a 10K lateral, $3,000 a foot or a little bit higher than that.
If you go all the way to the other end to the far deeper stuff, probably just a little bit over that. So. As far as any quarter when we’re reporting, it just depends on where those rigs have been and what the TVD areas we’re drilling in as far as what the cost comes out to. But we’re definitely going to see the cost continue to go down. I think. We’ve gotten a big chunk of it down already. And as. Naturally go in time, I think the rate at which the costs come down probably slow a little bit. But we still see. I mentioned it earlier. We still got a few things kind of coming down the pike that we’re going to be trying. We think that’s going to help us. Continue to shave days off. Understood. Makes perfect sense. I’ll leave it there. Thanks. Thank you.
This concludes the question and answer session. I will now turn it back over to Jay Allison for closing remarks. Perfect. I want to thank everybody for listening for over an hour. And November the 4th of 2025 is a great day for the company when we can tell the stakeholders, which is you. And our financial backers, which is you. That we’ve added. This giant footprint in the Western Haynesville. So the debt that we have, that is the Western Haynesville. Acreage that we have been buying. It’s 530,000 net acres. But we can report on a day like today, we have over $900 million liquidity, and that’s going to grow. We can report that we have 2,559 Western Haynesville locations at the very beginning of time. And then the legacy. Locations are 917. So we have a lot of inventory. We’re not chasing.
Inventory or we’re not chasing M&A. And that the management here has been pioneered the Haynesville-Bossier Shale going back to 2008, 17 years. So. The man that’s in charge of operations has been here. The very first day we ever looked at the Haynesville-Bossier, which is Dan Harrison. And then you look at managing the balance sheet, the couple of divestitures that we will make and have made, that just tells you that we’re watching our balance sheet, which the major stockholder and everybody else wants us to do that. So I just want to thank you for believing in the company, and we’ll give you a good day’s work every day. So thank you for the call. Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.
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