Comstock Resources Inc Q3 FY2025 Earnings Call

Good day, and thank you for standing by. Welcome to the Q3 2025 Comstock Resources Earnings Conference Call. 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.

All right. Again, I want to thank you for the introduction and thank 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. And 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 2 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 3. 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 moves 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 go to retire long-term debt. This was also a very efficient quarter in 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 averaged $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 3, 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 EBITDAX 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 3 new Western Haynesville wells online, increasing the number of wells turned to sales in 2025 in the Western Haynesville to 8 wells. Those 3 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. In 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 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 4, 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 inactive wells. On October 10, 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 the financial results reported today.

All right. Thanks, Jay. Slide 5, 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. EBITDAX 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 6 is the year-to-date results. Our production for the first 9 months has averaged 1.24 Bcfe per day. And with improved natural gas prices, our oil and gas sales in the first 9 months have increased 18% to $1.1 billion. EBITDAX for the first 9 months of 2025 was $802 million, and we generated $639 million of cash flow. We reported net income of $122 million for the first 9 months of 2025 or $0.41 per diluted share as compared to a net loss for the same period last year. On Slide 7, 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 8, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.77 in the third quarter, $0.03 lower than last quarter. Our EBITDAX margin was 74% in the third quarter, which is unchanged from last quarter. Lifting costs improved by $0.02 in the quarter. Production and ad valorem taxes were up by $0.01 and gathering and cash G&A costs improved by $0.01 in the third quarter. On Slide 9, 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 9 months of this year. In the first 9 months of this year, we've 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 3x and will continue to improve as you 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 are 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. I'll now turn it over to Dan to discuss the drilling results.

Thank you, Roland. On Slide 11, you can see an overview of our current acreage in the Haynesville/Bossier Shale regions of East Texas and North Louisiana. We currently hold 1,055,386 gross and 797,440 net acres that are suitable for commercial development in these shales. On the left, you'll find our Western Haynesville acreage, which has expanded to over 530,000 net acres. On the right, we have 266,711 net acres in our legacy Haynesville area. We are currently producing from 27 gross or 26.9 net wells in the Western Haynesville, which is largely undeveloped in comparison to our legacy area. Due to the higher pay thickness and pressure in the Western Haynesville, we anticipate it will provide significantly more resource potential per section than our legacy Haynesville. Slide 12 outlines our new development approach utilizing the horseshoe lateral concept. This well design merges two shorter adjacent laterals into one longer lateral, leading to a more efficient use of capital. We achieve about 35% savings in drilling costs when drilling a 10,000-foot lateral horseshoe well compared to a 5,000-foot sectional lateral well. Our legacy Haynesville drilling inventory now includes 118 horseshoe locations. In the third quarter, we completed our second horseshoe well, the Roberts 2623 #1, which featured an 11,453-foot lateral and an initial production rate of 26 million cubic feet per day. Thus far this year, we've drilled one more horseshoe well, and we have another four currently in progress. We plan to drill a total of eight horseshoe wells this year, and ten in 2026. Slide 13 presents our updated drilling inventory in the legacy Haynesville area at the end of the third quarter, adjusted to exclude locations we are selling in the Shelby Trough. We now present our legacy Haynesville and Western Haynesville drilling locations separately. Our total operated inventory in the legacy Haynesville consists of 1,039 gross locations and 809 net locations, or about 78% working interest. Our non-operated inventory in the legacy Haynesville includes 873 gross and 108 net locations, representing a 12% average working interest. This inventory comprises short laterals under 5,000 feet, medium laterals between 5,000 and 8,500 feet, long laterals between 8,500 and 10,000 feet, and extra-long laterals 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 operated inventory is split 51% in Haynesville and 49% in Bossier. More than 80% of our gross operated inventory in the legacy Haynesville consists of laterals greater than 8,500 feet. The 118 horseshoe locations previously mentioned are all located in our legacy area. The average lateral length in our inventory has now increased to 9,961 feet, up 275 feet from the end of the second quarter, indicating we have decades of future drilling locations available based on our current activity levels. On Slide 14, we disclose our estimated drilling inventory in the Western Haynesville for the first time. Our total inventory here includes 3,332 gross and 2,559 net locations, translating to a working interest of about 77%. While our Western Haynesville acreage is not unitized, the net locations here are estimated. The inventory in Western Haynesville is more oriented towards the Bossier formation, with 36% in Haynesville and 64% in Bossier. Similar to our legacy Haynesville inventory, we categorize our Western Haynesville inventory into groups of short laterals under 5,000 feet, medium laterals between 5,000 and 8,500 feet, long laterals between 8,500 and 10,000 feet, and extra-long laterals over 10,000 feet. In the Western Haynesville, we have no short laterals, with 1,347 medium laterals, 642 long laterals, and 1,343 extra-long laterals, meaning roughly 60% of this gross operated inventory consists of laterals exceeding 8,500 feet. Slide 15 features a chart highlighting the average lateral lengths we drilled, based on wells that reached total depth. In the third quarter, we drilled 11 wells to total depth in the legacy Haynesville, averaging a lateral length of 12,593 feet, with individual lengths ranging from 4,968 feet to 15,466 feet. Our record-long lateral in the legacy Haynesville remains at 17,409 feet. In the third quarter, we drilled six wells to total depth in the Western Haynesville, which had an average lateral length of 10,158 feet, with lengths ranging from 7,809 feet to 12,710 feet. The longest lateral drilled so far in the Western Haynesville is 12,763 feet. To date, we have drilled 15 wells in the Western Haynesville with laterals longer than 10,000 feet, and six wells exceeding 12,000 feet. Slide 16 outlines the wells turned to sales in our legacy Haynesville this year. So far, we have turned 28 wells to sales in this area, with initial production rates ranging from 16 million to 37 million cubic feet a day, averaging 25 million cubic feet a day. The average lateral length was 11,919 feet, with individual wells ranging from 9,252 feet to 17,409 feet. To recap, four of our eight rigs are currently drilling in the legacy Haynesville. Slide 17 details the eight wells turned to sales in the Western Haynesville this year. Since our last earnings report, we’ve turned three additional wells to sales, averaging 8,566 feet in lateral length and an initial production rate of 32 million cubic feet per day. Four of our eight rigs are also working in the Western Haynesville. Slide 18 highlights the average drilling days and footage drilled per day in the legacy Haynesville for our benchmark long lateral wells, which exceed 8,500 feet. In the third quarter, we drilled ten benchmark long lateral wells to total depth in the legacy Haynesville, averaging 26 days to total depth, consistent with our performance over the last three quarters. In the third quarter, we drilled an average of 1,004 feet per day in the legacy Haynesville, a 4.5% increase from the second quarter of 2025 and a 2% increase compared to the full year average of 987 feet drilled per day in 2024. The best well drilled to date in the legacy Haynesville remains at 1,461 feet, completed in 14 days. Slide 19 reviews our drilling progress in the Western Haynesville, where we drilled six wells to total depth in the third quarter, totaling 35 wells drilled to date through the end of the quarter. We averaged 52 drilling days for the six wells in the third quarter, which is three days fewer than the second quarter and seven days shorter than our 2024 full year average of 59 days. Our fastest well remains at 37 days, drilled with a 12,045-foot lateral. Slide 20 summarizes our drilling and completion costs through the third quarter for benchmark long lateral wells in the legacy Haynesville area, reflecting costs for wells over 8,500 feet. In the third quarter, we drilled ten benchmark long lateral wells to total depth, with average drilling costs of $558 a foot, a 15% decrease compared to the second quarter. The second quarter had unusually high drilling costs due to challenges with over-pressurized zones. In the third quarter, we turned nine wells to sales in our legacy Haynesville area, with completion costs averaging $671 a foot, representing a 7% decrease from the previous quarter, driven by lower frac pricing and fuel costs, with all wells using a natural gas blended fuel, as well as longer laterals in the quarter. We currently have four rigs operating in our legacy Haynesville area. Slide 21 summarizes the drilling and completion costs through the end of the third quarter for the Western Haynesville. During the quarter, we drilled six wells to total depth with an average lateral length of 10,158 feet. The average drilling cost for the third quarter was $1,385 a foot, a 24% decrease compared to the second quarter, aligning more closely with our historical costs. The primary reason for lower drilling costs this quarter is the longer laterals, as the average lateral length in the second quarter was lower at 7,933 feet. We turned three wells to sales in the Western Haynesville this quarter, averaging 8,566 feet in lateral length. We did not turn any wells to sales in the first quarter this year. The average completion cost for the third quarter was $1,622 a foot, a 24% increase compared to the second quarter, primarily due to higher frac costs and the shorter average lateral length. There was also increased horsepower usage associated with fracking these deeper wells, necessitating higher frac gradients. To recap our activity levels, we have four rigs operating in the Western Haynesville and four rigs in the legacy Haynesville, alongside two dedicated frac fleets working across both areas. I will now hand it 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. We currently have 4 operated rigs drilling in the Western Haynesville to continue to delineate the 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 Marquez gas treating plant started operations in July, which more than doubled our gas treating capacity. In the legacy Haynesville, we are currently running 4 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 costs 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.

Our first question comes from Derrick Whitfield from Texas Capital.

I wanted to start with a broader question around 2026 and not to pin you guys down on any numbers, but really just want 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?

Yes. We've noticed a distinction between the legacy Haynesville and the Western Haynesville. In the legacy area, we've reached a peak in efficiency gains, especially since we introduced the horseshoe wells. We have been able to convert many of our shorter wells into longer ones, which has increased our efficiency. The horseshoe wells are performing very well for us. However, we are still on a learning curve in the Western Haynesville where we continue to seek efficiency improvements. We've made significant progress so far, and we have additional enhancements planned for implementation that should boost our efficiencies. The four rigs we have operating in the Western Haynesville are performing well, allowing us to gather valuable insights. We have made substantial improvements in our downhole performance, and we have more initiatives being developed that we believe will benefit us in 2026.

Derrick, 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 '08, 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.

From a capital efficiency perspective, we are holding some capital this year for the addition of the eighth rig, with production not expected to begin until the first or second quarter of next year. As you consider typical capital efficiency, this should lead to improved capital efficiency next year.

Great. And for my follow-up, I wanted to shift over to gas marketing. More specifically, I'd 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 power generation, you're arguably in a great position to benefit from both in terms of gas realizations.

Yes, that's a good observation, Derrick. I believe that owning our own midstream in the Western Haynesville will be a significant asset for us in the future. Instead of relying on other midstream companies and long-haul pipelines, we can create strong markets right there to sell directly to end users, becoming a reliable supplier. Many large users with new demand are looking to establish direct relationships with producers, and we've heard a lot about this in our industry. We're well positioned because we control the midstream infrastructure and are located in an area where the gas can support growth in Texas. Additionally, we're very close to the Port Arthur LNG for connection. Thus, I believe a crucial part of the future for natural gas lies in not only having the gas but also getting it directly to the end user.

Well, Derrick, 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 the 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 and a great footprint where we're located and maybe 6,000 of these acres are dedicated, the rest are undedicated. 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.

Our next question comes from Charles Meade from Johnson Rice.

Warm welcome. Jay, I want to ask you about the Shelby Trough sale. It seems to us that this is a fantastic outcome for you in terms of what the seller paid for those undeveloped locations. I would like to know how you would characterize it, how satisfied you are with those proceeds, and if there are any remaining assets in your portfolio that might attract interest from buyers 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 5 years. So if you look at other really good locations that might be for sale, I mean, I think it's a really smart buy by the buyer. I think we needed to pay down the debt on our balance sheet because we had incurred a lot of money as our investment in the Western Haynesville. And we look 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 derisk and kind of fortify our acreage position in 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 that we didn't need to be drilling them because we're drilling the Western Haynesville.

Thank you for sharing the count of locations in the Western Haynesville. I have a couple of questions regarding your assumptions and the dynamics of that area. It appears that your estimates on the number of zones and the spacing between them have been quite conservative. Could you share what the key assumptions are regarding the 2,500 to 2,600 number? Additionally, Dan mentioned in his remarks that the lack of unitized acreage may be limiting your ability to count locations. I assume this will be resolved over time, but could you incorporate that into your assumptions about the location count?

I believe we took a conservative approach regarding well spacing and benches because we want to avoid starting with a high number and later reducing it. We feel confident that our view of the inventory is realistic. Regarding the working interest in our legacy Haynesville inventory, we are precise about every location and know our unit details and working interest accurately. However, in the Western Haynesville, the units are still being consolidated, so the exact working interest isn't fully established. So far, we've held a 100% working interest in most wells. We evaluated our acreage ownership and made broader assumptions that lack some precision, but I don’t think this discrepancy is significant; we're still within an acceptable margin of error in how we present the net figures.

Yes. And Charles, you 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 Roland 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 the asterisk that we've not unitized some of those locations. So that's a guesstimate.

Our next question comes from Kalei Akamine from Bank of America.

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 to 8,500 feet, but this is a large contiguous position. So my question is, what's stopping you from doing the land work to optimize the entire position around 10,000-foot laterals? And if that's possible, how long would that work take?

That's a great question. There are some areas where other operators have ownership that we've identified and decided to keep out of our units. We opted for shorter laterals, similar to the wells we completed and drilled recently, which were influenced by the acreage ownership. We've respected those boundaries, especially where we don't have contiguous land. Additionally, we've identified certain geological structures on seismic that we are avoiding for development. We've taken our geological analysis into account as well. It's still early, and we anticipate being able to optimize things over time. A lot will depend on how far we want to go, such as if we want to pursue 15,000-foot laterals, which I believe presents opportunities for future optimization. However, what we've presented is a solid overview of our current acreage. In the future, we could lease more acreage that would alter the configuration. We're always acquiring additional acreage as we arrange units, so there will be changes, but this provides a comprehensive look at what it might look like if we stopped leasing.

We added 5,000 acres since our last report. We continually clean up operations in the Western Haynesville, just as we do in our core areas. This estimate is quite conservative. We believe we have secured 90% of the real value in the Western Haynesville, and it might expand, which would be beneficial. We're optimistic about that potential. Given our control, size, and the well results we have, we feel confident about our position. We are committed to improving our operations. Eventually, we won't own all the wells, but until the right time, we'll drill the necessary lateral lengths to retain crucial information for future reference.

For my second question, I want to ask about the second train at the Marquez gas plant. That build looks like it's going to take you to about 1.3 Bs 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 Marquez 2 is online, perhaps in '27, where do you think the utilization rate will be at that time?

I’m not sure if we want to predict the utilization rate for the long term. Initially, we developed the plan for Pinnacle and how to support the development program. We recognized early on the need to establish a treating infrastructure capable of managing up to 2 billion of gross production over the next five to seven years. The second phase of Marquez was part of our original strategy. There’s also the potential for either expanding at Bethel or adding a third gas plant, but that would likely be further down the road. We need to stay proactive and ensure that we have the treating capacity ready well before we begin production, as it won't be a just-in-time setup since assembling that infrastructure takes 12 to 18 months. Currently, for Marquez Phase 2, we are in the process of ordering long lead time components and equipment. Our aim is to have everything in place to hopefully launch next summer.

And yes, I think the key answer to that is we have a lot of inventory, but we own our midstream, as Roland mentioned in the beginning comments, and we have an incredible financial partner with Quantum. And we look to see what our drilling inventory looks like. We 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. I think we're right there at the right time.

There are several other operators running rigs in the area, which will influence how we develop our operations, particularly regarding whether we can capture some of that gas. Much of this outcome remains uncertain for the future. However, there are additional activities in the region that we expect to benefit Pinnacle as we further develop the valuable asset in the Western Haynesville.

Our next question comes from Carlos Escalante from Wolfe Research.

I appreciate how the operator pronounced my name. I want to revisit one of your points, Jay. You mentioned the hope that the Western Haynesville footprint expands, and I commend you on your fine work. You’ve effectively set the foundation with nearly 30 TILs throughout the play, especially in the southern corridor of Leon and Robertson, with additional data suggesting potential acreage north of that. However, there has been recent leasing and M&A activity in the East and Southeast, particularly in Anderson and Houston. This leads me to wonder if you believe the core of the basin might actually be larger than anticipated, possibly extending into some of your previously drilled wells from this year. Additionally, I noticed you have a permitted well near Olajuwon, and I’d like to know when you plan to return to that area.

The comments stem from Jerry Jones and his significant investment in the company, which allows us to think outside the box and take bold actions. Our focus has always been on natural gas, positioning us as leaders in the legacy Haynesville area. Jerry Jones pointed out a successful well, the Circle M well, which has performed well over the last five years. Moving forward, we are reviewing over five years of data, including seismic studies and the performance of the wells we've drilled or are currently drilling. We believe this encompasses about 90% of our true value. Aethon has indicated there are substantial wells available, and we have successfully tapped into several. They are a smart company that is indeed expanding into the Western Haynesville because the locations there are incredibly valuable. While mergers and acquisitions add to your portfolio, they don't necessarily create new locations, which remains a key concern for us. In response to an earlier question about inventory count, we are confident that we have about 2,500 to 2,600 net locations, a remarkable figure. We are continuously assessing whether to move east or south, as there are likely undiscovered valuable sites. We hope these sites are identified, as that would enhance the value of our acreage.

You inquired about a permitted well near the Olajuwon. We actually spudded a 2-well pad near the Olajuwon last week.

So it will be Bossier, one Haynesville.

Yes, we have one well, the Olajuwon, producing from the Haynesville. The new pad that we drilled last week will include an additional Haynesville well and our first test in the Bossier area.

Yes. And we're coring up in that area, too.

That's correct.

So the cores we've had, and we're coring there also.

That's great information, thank you. If I may quickly add a follow-up, Jay, you mentioned something earlier. I believe one of your Tilled wells this quarter, the two wells, are located near that area. We've observed their production curve to be quite impressive in terms of maintaining production levels. This well also shows strong initial production numbers. My question is, are you looking at any practices they are employing or considering any near-term collaboration that could benefit your operations, or have your efforts been more independent?

We have been working on some acreage swaps with them, allowing for longer lateral drilling on both our parts. However, I don't have any additional comments on that.

It's always beneficial when you see other operators handling things differently, as it's a great learning opportunity for a basin. The Western Haynesville hasn't experienced as much of this compared to the original Haynesville. However, with new operators entering the market, who were the first to start operations, I believe we will incrementally improve our understanding of how to effectively produce and drill the wells. Increased activity will lead to more learning, which will ultimately benefit all operators involved.

If you have 4 or 5 more new operators come in, I think everybody, particularly Comstock, the learning curve has shortened. I think that would be a great thing.

Yes. I think what you say 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 box, looking at the results, like we say, that's definitely going to help everybody.

Our next question comes from Kevin MacCurdy from Pickering Energy Partners.

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.

I think the 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 time frame we leased. And so I think that's how we look at it. I think the activity level of 4 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.

And I think you're going to see in 2026, more of our wells will continue to kind of push more in that normally northeastern 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 Shale, was that just driven by the asset sales? Or was there anything else that changed in those inventory numbers?

At one point, we included a small portion of the Western Haynesville based on the wells we drilled and other direct offsets that are part of our inventory. That’s why we decided to separate it out, as it wasn't significantly represented in the initial chart. Additionally, we accounted for the acreage we sold or are in the process of selling by removing those locations. We also continuously adjust our strategy since we often find ways to extend the laterals, especially as we notice an increase in the average lateral length. This is an ongoing process of optimization for us.

Our next question comes from Jacob Roberts from TPH & Co.

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 3 that came online last quarter and then the handful that are going to be coming online in the year.

We turned three wells to sales in the last quarter and have four new wells transitioning to sales in the fourth quarter. We've varied our approach somewhat but haven't taken any extremely conservative measures so far. We're analyzing the data from the cores and conducting detailed rate transient analysis. Essentially, it's indicating that a more conservative drawdown is the direction we should be taking. Looking ahead, we plan to shift towards a more conservative approach than our initial one.

Great. 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 in the river corridor area and along the Gulf Coast where new industrial plastic and fertilizer plants are being built. These facilities are competing with LNG feedstock gas. Customers have been reaching out and expressing interest in long-term supply deals, a shift from years ago when they preferred to purchase gas on the monthly market because it was readily available. Over time, we expect many of our market participants and other producers in the region to want to establish more direct sales to end users, allowing them to capture more value from the value chain and achieve better margins instead of letting midstream companies take a significant portion of those margins. Many of us are developing long-term plans in this direction, including ourselves.

Our next question comes from Phillips Johnston from Capital One.

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, and we do expect a sizable gain on that transaction because we acquired that acreage back at the Covey Park acquisition, and it wasn't a significant part of the value that got allocated in. So, there is a considerable tax gain that we anticipate. You'll see some of that in the 10-Q when we file it later today. We believe we have many tax attributes that we can utilize, and we don't see any real cash tax impact from that.

Okay. Sounds good. Then a question for Dan. It's really a follow-up on Carlos’ and Kevin's questions. It sounds like the 2-well pad near Olajuwon has 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 have more wells planned in that area. I can't recall the exact number right now, but we really like that region. The Olajuwon well is performing extremely well, and we are very pleased with it. Our next step on this 2-well pad is to test the Bossier formation, which is thicker in that area. We want to accurately assess the Bossier before deciding how to further develop that section. I would estimate that we have around 5 or 6 wells planned in that area for next year, approximately around that general location.

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

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 like 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?

Yes. We've been analyzing this because a significant portion of the cost for treatment comes from the facilities we build. Once these facilities are in place, the operating costs can be quite low, but the initial capital must be recovered. A lot of costs come from this capital investment. If you own the facility, you won’t have recurring recovery costs once you’ve recouped your investment. However, if a third party operates it, they will keep charging based on demand, and those costs will not decrease unless demand in the area drops. We are making long-term investments now that we believe will benefit us greatly in the future. These investments will help us maintain our industry-leading low-cost structure, which is why we are excited about our accomplishments and our partnerships that are supporting this growth without putting too much strain on the company.

Great. And this is kind of a housekeeping item, but I did take sort of a quick look at the gathering and transportation expense line, and it looks like it might have been down sequentially a bit in the quarter. And I just wonder if I had that right and if there are any drivers behind that?

Yes, it decreased sequentially. It was just over $41 million in the second quarter and just under $40 million in the third quarter. This was partly due to lower volumes sequentially. On a GTC per unit basis, it was $0.36 compared to $0.37 last quarter. So that change is really driven by volumes.

Yes. I would say that's correctly right.

Our next question comes from Paul Diamond from Citi.

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 any activity over time, where do you think it would come from, one or the other?

We'd like to maintain the four operating rigs in the Western Haynesville because it's important strategically to hold all the acreage, and this pace allows for a comfortable program. We usually adjust our activity in the legacy area where there are no acreage concerns, based on supply-demand outlook and pricing. Similar to last year, we have been very flexible in the legacy area. We aim to steadily increase activity in the Western Haynesville as we develop that asset. So, we are very reactive on the legacy side, while we prefer a more consistent approach in the Western Haynesville to continue developing and retaining that asset.

Got it. Makes perfect sense. And now you guys have given the inventory assumptions in the Western Haynesville acreage. Can you talk about any progression you see on Drilling & Completion still tracking towards about $30 million per well on 10,000-foot basis? I guess where do you guys see that going through time? What your target longer term?

I believe we will definitely see costs continue to decline. There is a significant range depending on the drilling location in terms of the drilling and completion cost. Our lowest cost achieved so far is around $2,100 per foot for shallower wells. For deeper wells, assuming around a 10,000-foot lateral, costs are estimated at about $3,000 per foot or slightly higher. The final cost will depend on the specific areas and the rigs used when we report each quarter. However, we are confident that costs will keep decreasing. We have already made substantial reductions, and while the rate of decrease may slow over time, we anticipate new initiatives that will help us further reduce days in the drilling process.

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

Thank you all for listening for over an hour. November 4, 2025, will be a significant day for the company when we can inform our stakeholders and financial partners about our substantial expansion in the Western Haynesville region. We have been acquiring 530,000 net acres in that area. As of today, we proudly report over $900 million in liquidity, which we expect to increase. Kim mentioned that we have 2,559 locations in the Western Haynesville available from the very beginning, along with 917 legacy locations. This gives us ample inventory; we are not pursuing inventory or mergers and acquisitions. Our management team has been a leader in the Haynesville/Bossier shale since 2008, with Dan Harrison overseeing operations from day one. Additionally, we are attentive to managing our balance sheet through certain divestitures that we’ve already executed, reflecting our commitment to prudent financial stewardship. Thank you for your trust in our company; we are dedicated to delivering quality work every day. Thank you for the call.

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