Thanks for the introduction, and I want to thank everybody for joining the call. It's always a highlight to report on what happened in the prior year and then kind of give you a visual for what we think tomorrow may look like and today is a day.

Welcome to the Comstock Resources fourth 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 Fourth Quarter 2025 Results. I have Jay Allison, Chief Executive Officer of Comstock, with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations.

Please refer to slide 2 in our presentation to note our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

If you'll turn on slide 3, we highlight our major 2025 accomplishments. We added three operated rigs to our operated program, with an additional rig coming in early 2026 to drive production growth in 2026 and 2027.

The additional production combined with an improved 2026 gas price outlook will substantially drive down the balance sheet leverage. In 2025, we drilled 52, or 44.2 net successful operated Haynesville-Bossier wells, with an average IP rate of 27 million cubic feet per day.

The 2025 drilling program replaced 229% of our 2025 production with 1 TCFE of drilling-related proved reserve additions, achieving an overall finding cost of a dollar two per Mcfe. We announced we were partnering with NextEra on a data center project in the western Haynesville.

NextEra plans to build new behind-the-meter power generation to support hyperscaler data center development with an initial capacity of 2 gigawatts with potential expansion up to 8 gigawatts. In the third and fourth quarters we completed $445 million of divestitures, which improved our balance sheet.

We completed the sale of the legacy Cotton Valley assets in September and the sale of the Shelby Trough assets in December. We recognized a pre-tax gain of $292 million on the divestitures.

The assets sold consisted of 1,084 producing wells with only 17 million cubic feet per day of net production. The sales proceeds were used to reduce debt and improve our leverage position.

Over the last two years Comstock has the highest total shareholder return of any public E&P company at 162%, almost twice the second highest company's total shareholder return. For the last two years Comstock was number one in total shareholder return among its public natural gas producers.

On slide 4 we summarize the highlights of the fourth quarter. Higher natural gas prices in the fourth quarter drove the improved financial results in the quarter compared to the fourth quarter of 2024.

Our natural gas and oil sales grew to $365 million. We generated $222 million of operating cash flow, or 75 cents per share.

Adjusted EBITDAx for the quarter was $277 million, and we reported adjusted net income of $46 million, or 16 cents per share. During the fourth quarter we put four new Western Haynesville wells online, increasing the number of wells turned to sales in 2025 in the Western Haynesville to 12 wells.

These four wells had an average lateral length of 8,399 feet and an average per well initial production rate of 29 million cubic feet per day. In our legacy Haynesville we turned 35 wells to sales in 2025 with an average lateral length of 11,738 feet and a per well initial production rate of 25 million cubic feet per day.

In December we closed on the sale of our Shelby Trough assets in East Texas for total net proceeds of $417 million, and net proceeds after selling expenses. We used the proceeds from the asset sale to reduce borrowings under our revolver.

Roland will provide some more details on financial results that we reported today. Roland.

Thanks, Jay. Slide 5 we cover the fourth quarter financial results.

Our production in the fourth quarter averaged 1.2 Bcfe per day and our oil and gas sales in the quarter increased 8% to $364 million in the fourth quarter this year despite the lower production number. EBITDAx for the quarter was $277 million and we generated $222 million of cash flow in the fourth quarter.

We reported a $281 million profit for the quarter, or 97 cents per share. Included in that number were some unusual items, including the pre-tax gain on the asset sales of $294 million, a $37 million mark-to-market unrealized gain on our hedge positions, and a $29 million impairment on our non-operated Eagle Ford shale acreage.

Excluding these items and exploration expense and the related income tax related to these items, we reported adjusted net income of $46 million for the quarter, or 16 cents per diluted share, the same as the adjusted net income in last year's fourth quarter. Slide 6 is the financial results for the full year 2025.

For the full year in 2025 our production averaged 1.2 Bcfe per day, which is 14% lower than production in 2024, but the improved natural gas prices we had in 2025 increased our oil and gas sales by 15% to $1.4 billion compared to 2024. EBITDAx for 2025 totaled $1.1 billion, and we generated $861 million of cash flow last year.

For the year we reported a $396 million profit, or $1.43 per share. That also includes the unusual items, including a pre-tax gain of $292 million on the 2025 property sales, a $62 million mark-to-market unrealized gain on the hedges, and that $29 million impairment.

Excluding these items and exploration expense and related income taxes, we reported adjusted net income of $160 million for 2025, or 54 cents per diluted share, compared to a net loss in 2024. On slide 7 we break down our natural gas price realizations.

The quarterly NYMEX settlement price in the quarter averaged $3.55 in the fourth quarter. The average Henry Hub spot price in the quarter averaged $3.69, approximately 4% above the NYMEX settlement price.

27% of our gas was sold in the spot market in the quarter, the appropriate NYMEX reference price for our production would have been $3.58. Our realized gas price during the fourth quarter averaged $3.29, reflecting a 26-cent basis differential compared to the NYMEX settlement price and a 29-cent differential compared to that reference price for the quarter.

Also in the fourth quarter, we were 57% hedged, which decreased our realized price to $3.27. Slide eight, we detail our operating costs per MCFE and our EBITDAx margin.

Our operating costs per MCFE averaged 77 cents in the fourth quarter, pretty much unchanged from the rate we had in the third quarter. Our EBITDAx margin was 77% in the fourth quarter, up 3% from the third quarter.

In the quarter, our lifting costs improved by one cent in the quarter, and our production and ad valorem taxes also decreased by three cents in the quarter. That was offset by increases in both our gathering costs and cash G&A costs, which both increased by two cents in the quarter.

Slide nine, we recap our spending on drilling and other development activity in 2025. We spent a total of $270 million on development activities just in the fourth quarter and $1.55 billion for the entire year in 2025.

Last year we drilled 36 or 29.6 net horizontal Haynesville Shale wells and another 16 or 14.6 net Bossier Shale wells for a total of 52 wells. We turned 47 of those wells to sales, or 40.3 net wells, and we had an average overall IP rate of 27 million cubic feet per day.

Slide 10, we recap our capitalization at the end of the fourth quarter. We ended the quarter with $260 million of borrowings outstanding under our credit facility after using the proceeds from the Shelby Trough sale to pay down the revolver.

Our borrowing base is currently at $2 billion under the credit facility, with an elective commitment of $1.5 billion. Our last 12 months leverage ratio has improved to 2.6 times and should continue to improve throughout 2026, given the growth we expect in EBITDAx.

At the end of the fourth quarter, we had almost $1.3 billion of liquidity. Slide 11, we recap our proved reserves at the end of 2025, which came in at 7.2 TCFE, based on reserves determined using year-end NYMEX market prices, adjusted for our differentials.

Proved reserves determined using year-end NYMEX prices were slightly higher than proved reserves determined under the SEC rules, and those reserves were 7 TCFE at year end. We were able to grow our reserves 8% in 2025, excluding the impact of the Cotton Valley and Shelby Trough asset sales, which totaled 419 BCFE.

2025 drilling additions of 1.1 TCF replaced 229% of our 2025 production of 450 BCFE. We spent $1.55 billion on our drilling program in 2025, giving us a total overall finding cost of $1.02 in 2025.

In addition to the proved reserves that we reported, we also have 1.9 TCFE of proved undeveloped reserves, which are not included in our proved reserves only because they're not expected to be drilled within the five-year rule as prescribed by SEC rules. We also have another 2.5 TCFE of 2P, or probable reserves, and an additional 7.7 TCFE of 3P, or possible reserves, for a total of 19.3 TCFE of reserves on a P3 basis.

This does not include a substantial amount of the reserve potential for much of our western Haynesville acreage, where we have only included 5.4 TCFE related to the Western Haynesville NRP3 reserve estimates. I'll now turn it over to Dan to discuss the drilling results we've had.

Thanks, Roland. On slide 12, this is an overview of just our latest acreage footprint for both the Haynesville and Bossier Shales in East Texas and North Louisiana.

We have 1,069,991 gross and 802,769 net acres that are prospective for commercial development of the Haynesville and Bossier Shales. If you look on the left, is our Western Haynesville acreage footprint, which we've now grown to over 535,000 net acres.

On the right is our 267,289 net acres in our legacy Haynesville area. We have 30 wells currently producing on our Western Haynesville acreage, which is relatively undeveloped compared to our legacy Haynesville, with a higher pay thickness and the pressures we encounter in the Western Haynesville, we'll expect the Western Haynesville will yield significantly more resource potential per section than the legacy Haynesville.

Slide 13 is our updated drilling inventory in our legacy Haynesville area at the end of '25. Our total operated inventory in the legacy Haynesville now consists of 1,009 gross locations and 785 net locations, and this equates to an average working interest of 78%.

On the non-operated inventory in the legacy Haynesville, we have 839 gross locations and 101 net locations, which comes out to a 12% average working interest. The drilling inventory is split into four buckets, comprised of short laterals, which are less than 5,000, the medium laterals between 5 and 8,500 feet, the long laterals between 8,500 and 10,000 feet, and our extra-long laterals for everything over 10,000 feet.

In our gross operated inventory in the legacy Haynesville, today we have 34 short laterals, 145 medium laterals, 397 long laterals, and 433 of the extra-long laterals. The gross operated inventory is evenly split with 50% in the Haynesville and 50% in the Bossier.

This sets up over 80% of our gross operated inventory in the legacy Haynesville with laterals greater than 8,500 feet. Our legacy Haynesville inventory also includes 115 gross Horseshoe locations, with close to a 50-50 split between the Haynesville and the Bossier.

The average length in our inventory has now climbed up to 10,077 feet, which is up 116 feet from the end of the third quarter. The inventory provides us with decades of future drilling locations based on our current activity levels.

Over on slide 14, we show our estimated drilling inventory in the Western Haynesville. Our Western Haynesville inventory consists of 3,343 gross locations and 2,561 net locations, equating to a working interest of approximately 77%.

The number of net locations is estimated since much of our Western Haynesville acreage has not yet been unitized. Our Western Haynesville inventory is more weighted to the Bossier formation.

We've got nearly two-thirds of our inventory in the Bossier and one-third of the inventory is in the Haynesville. With the same as our legacy Haynesville inventory, our Western Haynesville inventory is also divided into the four separate bucket lengths, with our short laterals less than 5,000 feet, our medium laterals between 5,000 and 8,500 feet, the long laterals between 8,500 and 10,000, and our extra-long laterals over 10,000.

In our Western Haynesville gross operated inventory, we don't have any current short laterals. We have 1,326 medium laterals.

We got 653 of the long laterals and 1,364 extra-long laterals. Approximately 60% of this gross operated inventory has laterals over 8,500 feet.

Now on slide 15 is a chart that outlines our average lateral length drilled based on the wells that have been drilled to total depth. The average lateral lengths are shown separately for both our legacy Haynesville and our Western Haynesville areas.

In the fourth quarter, we drilled 12 wells to total depth in the legacy Haynesville area, and these wells had an average lateral length of 11,381 feet. The individual lengths ranged from 9,304 feet up to 15,700 feet.

Our record long lateral in the legacy Haynesville area still stands at 17,409 feet. In the fourth quarter, we also drilled four wells to total depth in the Western Haynesville, and these wells had an average lateral length of 9,944 feet.

The individual lengths on these wells ranged from 9,355 feet up to 11,249 feet. Our longest lateral drilled to date in the Western Haynesville is 12,763 feet.

To date in the Western Haynesville, we have drilled 39 wells to total depth. This includes 16 wells with laterals over 10,000 feet and six wells with laterals over 12,000 feet.

Slide 16 outlines the 35 wells that we turned to sales on our legacy Haynesville acreage in 2025. This includes seven wells since our last earnings call.

The average lateral length was 11,738 feet, and the individual laterals ranged from a low of 4,968 feet up to a high of 17,409 feet. The individual IP rates on these wells ranged from 16 million cubic feet per day up to 37 million cubic feet per day, and our average IP was 25 million cubic feet per day.

Five of our nine rigs currently drilling are drilling on our legacy Haynesville acreage. Slide 17 outlines the 12 wells that we turned to sales on our Western Haynesville acreage in 2025.

Since we last reported earnings, we've had four additional wells that have been turned to sales. These four wells had an average lateral length of 8,399 feet and an average initial production rate of 29 million cubic feet per day.

Four of our nine rigs currently drilling are drilling on the Western Haynesville acreage. On slide 18, this highlights the average drilling days and average footage drilled per day in the legacy Haynesville area.

This is for our benchmark long lateral wells, which are greater than 8,500 feet long. In the fourth quarter, we drilled 12 of these benchmark long lateral wells to total depth in the legacy Haynesville area, and we averaged 27 days to total depth.

In the fourth quarter, we averaged 893 feet drilled per day on our legacy Haynesville acreage, which this represents an 11% decrease versus the third quarter of 2025. The primary reason for the lower drilling rate in the fourth quarter is that we had five of our 12 wells we drilled were located inside the Bistineau Gas Storage Field, and all five of these wells, it necessitates running an additional intermediate casing string on those wells.

We also drilled three horseshoe wells in the fourth quarter, and that naturally lowers our average drilling rate compared to our normal straight laterals. Slide 19 highlights our drilling progress in the Western Haynesville.

During the fourth quarter, we drilled four wells to total depth. This gives us a total of 39 wells drilled to total depth through the end of the year.

We averaged 54 days to TD for the four wells drilled during the quarter. This is an increase of two days compared to the third quarter.

This is also reflected in the drilling speed of 499 feet per day during the fourth quarter, which is 3% lower than the third quarter. Aside from any drilling issues we have, the drilling performance in the Western Haynesville quarter to quarter is mainly affected by our vertical depths, temperatures, and our lateral lengths.

Where the wells are being drilled has a big impact on our drilling performance quarter to quarter. This batch of wells drilled in the fourth quarter were nearly 1,000 feet deeper vertically and hotter than the wells drilled in the third quarter, while the average lateral lengths were similar.

Our fastest well drilled to date in the Western Haynesville still stands at 37 days, and that well was drilled with a 12,045-foot lateral. On slide 20 is a summary of our DNC costs through the fourth quarter for our benchmark long lateral wells located on our legacy Haynesville acreage.

The costs reflect all of our legacy area wells, again, that have laterals greater than 8,500 feet long. Our drilling costs are based on when the wells reach TD.

The completion costs are based on when the wells are turned to sales. During the fourth quarter, we drilled 12 of these benchmark long lateral wells to total depth.

The fourth quarter drilling cost averaged $681 a foot. This is a 22% increase compared to the third quarter.

The increase in the fourth quarter is the result of a shorter average lateral length and, for the same reasons mentioned on the efficiency slide, where we had five wells within the Bistineau Gas Storage Field with an additional intermediate casing string. We also drilled the three horseshoe wells in the fourth quarter.

During the fourth quarter, we also turned five of these benchmark long lateral wells to sales in the legacy Haynesville. The fourth quarter completion cost came in at $721 a foot.

This is a 7.5% increase compared to the third quarter. The higher completion costs in the fourth quarter is due to a combination of slightly lower frac efficiency coupled with we had a higher average drill-out cost in the fourth quarter.

Overall in 2025, we achieved a total drill and complete cost of $1,347 per foot, which is one of the lowest in the basin. This was 11% lower than our average cost of $1,510 per foot in 2024.

Last month, we added an additional frac fleet, and we're now running three full-time frac fleets in the legacy Haynesville. This additional frac fleet will be working full-time in our legacy Haynesville area along with the increase in the rig activity for that area.

On the subject of performance initiatives, in 2025, we began running trials with a rotary steerable drilling assembly in our legacy Haynesville area, and we've made great progress to date. As this technology becomes further refined for the high-temperature environment in the Haynesville Shell, we fully expect this technology to play a much larger role in our future drilling program and make a significant impact on further drilling cost reductions.

Slide 21 is a summary of our DNC costs through the fourth quarter for all wells drilled in the Western Haynesville. During the fourth quarter, we drilled four wells to total depth with an average lateral length of 9,944 feet.

The fourth quarter drilling costs averaged $1,489 a foot. This represents a seven-and-a-half-cent increase compared to the third quarter.

Our drilling costs was driven slightly higher in the fourth quarter as a result of the wells being slightly deeper and hotter than the wells drilled in the third quarter. During the fourth quarter, we also turned four wells to sales on our Western Haynesville acreage that had an average lateral length of 8,399 feet.

The fourth quarter completion costs averaged $1,542 a foot. This is a 5% decrease compared to the third quarter.

The lower completion cost was the result of us being able to obtain lower frac pricing along with having lower horsepower usage in the fourth quarter. In addition to the earlier cost initiatives we have enacted in the Western Haynesville, including the use of insulated drill pipe, we are undertaking additional measures to further reduce our costs.

We have recently arranged to have one of our existing Western Haynesville rigs upgraded to a 10,000 PSI pressure rating, and that will be available to us by late summer. With this upgrade, we'll be able to increase our drilling speeds in both the vertical and horizontal hole sections, significantly reducing our costs.

Also, following up on the successful trial runs of the rotary steerable drilling system in our legacy Haynesville area, we will be rolling out this system for trials in our Western Haynesville area in the near future. We believe the application of this technology to the hot hole environment of the Western Haynesville, along with insulated drill pipe, will lead to additional time savings and cost reductions.

On the completion side, we're also investing to upgrade one of our existing frac fleets to a 20,000 PSI rating, along with the frac stacks, which will lead to improved frac stimulations as well as making it easier for us to execute larger and more aggressive stimulation treatments. All of these initiatives together are going to lead to a substantially lower cost structure for future wells while enhancing the well performance.

By substantially lower, we believe we'll be able to cut drill times by two weeks and reduce our drilling costs by another $300 a foot on top of our earlier cost reductions we've made to date. With that said, I will now turn the call back over to Jay.

Thank you, Dan and Roland. Thank you.

If you would, please refer to slide 22, where we will summarize our outlook for 2026. In 2026, we will continue to be focused on building out our great asset in the Western Haynesville that will position Comstock to benefit from the longer-term growth in natural gas demand driven by LNG exports and buildout of power for data centers.

We have four operated rigs drilling in the Western Haynesville to continue to delineate the new play. We expect to drill 19 wells and turn 24 wells to sales in 2026.

We plan to have five operated rigs drilling in legacy Haynesville to support production growth in 2026 and 2027. We expect to drill 47 wells and turn 48 wells to sales in 2026.

One of those rigs may move to the Western Haynesville later this year. We expect to commercialize our Western Haynesville data center project in 2026, where we have partnered with NextEra, which is the nation's largest developer of power.

We're also working to recapitalize our Western Haynesville midstream company, which Pinnacle Gas Services. In 2026, we plan to put in a new bank credit facility and redeem the preferred units held by our partner to be funded by selling equity in Pinnacle.

We continue to have the industry's lowest producing cost structure and are striving to create additional drilling efficiencies to drive down our drilling and completion costs in 2026 in both the Western and Legacy Haynesville areas. Lastly, we continue to have strong financial liquidity of $1.3 billion, which was recently built up by our successful 2025 property sales.

In 2020, we started leasing in the Western Haynesville. Today, after several acquisitions and direct leasing with over 100 land men, we now own 20,000 leases covering 535,000 net acres in our Western Haynesville.

The Legacy Haynesville play was discovered in 2008. It covers approximately 4 million acres and has produced about 48.5 TCF from 7,600 wells.

We estimate the remaining recoverable reserves in the Legacy Haynesville to be 75 TCF. Net to our working interest, we have about 14 TCF of reserves in our Legacy Haynesville properties.

The Western Haynesville play that we drilled our first well and turned to sales in 2022 covers approximately 800,000 acres and has produced 300 BCF from only 36 wells. We estimated recoverable reserves in the Western Haynesville could reach 99 TCF.

Comstock would have almost 50 TCF net to the working interest we own in the play. As Dan Harrison said earlier, we have drilled 39 wells to date in the Western Haynesville and have turned 30 of those to sales.

In 2025, we turned one Western Haynesville well to sales every month along with three Legacy Haynesville wells every month. This year, our activity level will increase as we expect to turn two Western Haynesville wells per month and turn four Legacy Haynesville wells per month to sales in 2026.

Our Pinnacle Gas Service midstream company we own is also a success, which services our new play. We're excited about the progress we're making reducing well costs in the Western Haynesville, which has been achieved by using thermal or insulated drill pipe, new purpose-built rigs, and new hot hole MWD tools.

Also drilling more wells on two-well pads and optimizing casing designs have contributed to improving our well cost. New initiatives to improving cost we are implementing in 2026, including applying rotary steerable drilling assembly technology that we're having great results in with our legacy Haynesville Horseshoe wells that we're currently drilling.

We have learned from the development of legacy Haynesville play that started in 2008 how this new Western Haynesville play should be developed to maximize its future value. We believe the Western Haynesville Basin is needed to supply the natural gas for growing industrial demand, LNG demand, as well as to generate power for data centers.

Thank you for your time today. The next slides provide guidance for 2026, which Ron can discuss with you directly if you have questions.

For the rest of the call, we'll take questions from analysts who follow the company. I'll turn it back over.

We're developing it based upon how the legacy was developed, and some of that value was not captured because of what was happening during '08, '09, '10, '11. As we look at that and we look at NextEra, and NextEra we've been partners with for 10 years, they come in and say, We do think you have a really great place, and we want to collaborate with you.

I think we were taking those next steps hand in hand with them, or we wouldn't be discussing it. You start out with two gigawatts, and then they said at their analyst meeting that they would like to ratchet up to eight gigawatts if that's where the demand is.

I think the demand will be there, and I think we can provide them everything they need, particularly because we do own our midstream. Most of these companies don't own their midstream.

That's why they have to deal with midstream companies that have upstream companies' gas. We're trying to capture both of it.

Hey, good morning, guys, Jay, Roland, Dan. Thank you so much for taking my question.

Maybe this first question is for Roland. This question is on Pinnacle Gas Services.

In your remarks you mentioned addressing the preferred equity at that entity, wondering how we should think about the cost of doing that, and if you plan to backfill the funding with bank debt, how should we think about the size of that facility and whether it's sufficient to execute on the scope of your midstream ambitions?

That's a good question. We have kind of put in place a plan to kind of recapitalize Pinnacle now that it's ready to make the next step as it's got a really great future ahead of it, starting to generate much more significant EBITDA, which probably people aren't really expecting because it just hasn't had it in the past.

It's ready to move on from the development capital that our partners put in, and they've given us an opportunity to redeem them. That's the plan we put in place, including a new credit facility.

We also have an initiative here that we're going to sell just common equity in the midstream company, and that's how we plan to eliminate the preferred equity that has a dividend that's pretty expensive, and so now that cash flow that before was mainly going out of the company to our partner will be available to fund its capex and also have its own low-cost credit facility now that it has the credit metrics to deserve that. We expect a lot of that.

Hopefully our goal is to have a lot of that in place by May of this year.

That

is a positive move for our midstream. In other words, it was birthed.

We had 145 miles of high-pressure line, we had the Bethel plant, and then as it progressed, we added Marquez. Then now it's progressed where we have a giant foothold in the Western Haynesville, and we want the Pinnacle system to mature as we add rigs and production.

Remember, some of this gas will go to serve the data center demand, much less the LNG that we service right now.

Thank you for that, guys. Just to follow that up, have you already fielded interest on the potential equity sell down?

Then can you kind of talk about the timing rationale for the Marquez expansion? Is that being motivated by the NextEra data center project timing, in which case utilization of that plant doesn't increase until the data center project is online?

With the Marquez plant, we think the next train will be operational sometime this summer. Again, as a midstream provider, you've got to have these assets up available before the production's there, otherwise, it's holding up things.

Also with the other potential operators in the area, we thought it was a great opportunity for us to have ample treating, then we can really also pick up third-party business for Pinnacle, as now we have several operators in the area and want to be positioned to continue to capture that market. A lot of that capital for midstream company all has to come way ahead of when you actually get your revenue, and then you have a long period of collecting fees after that.

By this summer, about the time we kind of probably finish the recapitalization, kind of a lot of our heavy capex will be behind us, and I think you'll see the entity well positioned to fund itself and still keep a low leverage profile with its own credit facility. And

I think the audience that will look at the Pinnacle system as an equity investor, I think what they'll do is they'll dig a little deeper into what we are showing in the Western Haynesville, and I think the more they dig, the more they like is our opinion. We'll find out.

Hey, good morning, guys. Good morning.

Thank you for having me on today. This one is perhaps for Dan.

Dan, it might be a little bit unfair because you had a tremendous program for the Western Haynesville throughout the year, but if I may cherry-pick one of your latest wells, the Brown Trueheart BB, that well looks like the IP rate basis slightly underperformed the broader group. Now I think it's normal for you to assume that you'll have a laggard on any given program for the year, but it is in close proximity to another well that had underperformed in the past, the Miles well.

I'm just wondering if you can perhaps provide your perspective on anything that you might be seeing on the rock quality, or perhaps any kind of water handling issues, something that maybe qualifies this specific area where these two wells are, which is, I suppose, closer to the heart of your position on the basin.

If you look on the acreage map, it is the furthest one as we've kind of fanned out and drilled more to the northeast. It's not the far northeast end where the Alligator one, but the farthest northeast of that trend of wells we've drilled.

It was a two-well pad. We drilled the well up dip and down dip.

This well was drilled up dip, and actually we drilled four wells kind of right there in that same spot, two two-well pads, and just because of the geology. If you're drilling south, you're going down dip, and if you're drilling north, you're going up dip.

This well, I think it's basically just because the well was making a lot of water during flowback, and when we see wells that make a lot of water during flowback, it's more difficult just to get a good IP rate, even though the wells are still really good, and that's what happened on this well. The down dip well just right there off the same pad.

We IP'd it at 30 million a day, and this one was 22. The only difference between the two wells was this one was making more water during the flowback period.

Thank you. That's very helpful.

Then my follow-up, this one's for you, Jay and Roland. The M&A market in the Haynesville last year was pretty hot, and you saw deals that implied pretty high dollars per location across the board.

That was with lower quality acreage. I think that I can say that objectively speaking.

I wonder what your views are on the recent trend coming into the year on M&A activity. When you see the second largest operator taken out, do you and the team feel compelled to keep business as usual, or does it prompt you to feel compelled to participate on it?

I think, Carlos, I think we're just me. Again, this goes back to five and a half years.

This goes back to probably July 2020, when we first looked at the Western Haynesville. I believe we're sitting on some of the most valuable gas in the world.

The reason I believe that is where the LNG facilities are being built, and have been built, and are being built, and that the U.S. is the largest exporter of gas in the world.

It's only going to get bigger and bigger and bigger. As the Cheniere's, et cetera, et cetera, they're all adding.

Their venture globals are adding. The data centers are adding.

I think, to answer your question, our business plan is to show what our Western Haynesville might be. The way we do that is we talk about rotary and durable innovations.

We talk about hot hole tools. We talk about the different rigs to drill the wells.

We talk about efficiency. The holy grail for an upstream company, which is M&A's or upstream, it's your quality drilling locations.

I think we have that not only in our core, but our core you wouldn't buy that, but you would buy that to Western Haynesville area. Because I don't know of any company our size, or remotely our size, that has 2,561 locations that are almost all of that's undeveloped.

Our goal, and Jerry Jones is the master plan behind this that's let us think out of the box and act out of the box, it is to make sure our balance sheet is strong, make sure our liquidity is strong, make sure that we report to you every 90 days, all the good and the bad. If we needed to add a rig, which I think that's the only negative truly in the call, is we added a rig.

That's $150 to $70 million. That's what we use per rig per year.

That is to what? It's to continue to shore up our legacy and then add to the Western Haynesville performance.

We're not looking for inventory. They are looking for inventory.

We're looking to develop what we own now. We've got a great amount of gas.

That, and always, you always want to be the beauty queen. It's like the Olympics.

We don't want a silver or a bronze medal. That'd be great to be up there.

That'd be great. If you're going to go out there, you're going to go for the gold.

Lindsey Vonn was five inches away from maybe having a gold or where she was, but she was dead aimed to get the gold because she won it a dozen times. That's exactly what we hope you know that we've been doing for decade after decade at Comstock.

We've never deviated from who we are. We've kept our same name.

We've kept true. The Jerry Jones of the world came in and said, I'm behind you.

I want to go with you. Let's develop this.

What? We'll see where the value comes.

We'll see where it comes from.

Good morning, Jay. Roland, and Dan, and to the rest of the Comstock team there.

Dan, in response to the earlier question about the Brown True Heart BB, I wanted to ask one more question based on your response there. Can you tell whether the water you're producing there, is that completion water, or is that formation water?

Could it be related to the azimuth of that well and whether you're toe-up versus toe-down? What's your thought process there?

That's a really good question. We've had several wells in the core that will make high water in the very beginning.

When we do make high water in the beginning, it's just hard to get a good IP rate until that water comes off. I don't know of any really shell well that I can remember that we've made formation water.

There is no formation water. It's all load water coming back from what you fracked.

Not on the Brown Trueheart, but in other areas in the past, there's been discussions when we've had high water about did the frack orientation change along the wellbore. Instead of being perpendicular to the lateral from the toe to the heel, due to some regional local stresses, maybe those fracks turned more closer to being parallel with the wellbore than being perpendicular.

That will definitely lead to a well that makes more water. Now, that's possible on the Brown Trueheart.

We don't think that's what's happening on the Brown Trueheart. I think this is probably the second well.

We've only had a few wells that have drilled up dip. This well was drilled up dip.

It could be that, or it could be a geometry thing, just how much they make from flowback when you drill uphill versus drilling downhill. Like I said, this was a two-well pad.

We had the down-dip well IP'd at over 30 million a day, and this one, we IP'd it at 22 million a day while it was making a lot higher water rate. We could have got a higher IP rate than that, but we'd have been pulling a lot more water too, and obviously that's not good for the well.

You fight gravity. You drill up dip, and you're 1,000 foot shorter than the Brown True Heart W number one.

You're 1,000 foot shorter, you're up dip, and you fight gravity. Water was going to flow down.

We IP'd the Brown Trueheart at 22 and the other one at 32.

All these wells where we have an instance where the water's high up front, what happens is it comes down over time, but it's after you've IP'd the well and you're off of flowback, the water eventually dries up and it comes down, and you still end up with the similar EUR that you got on the other wells that are down dip.

Right, that's all really interesting color, and thank you for that. Jay, I want to go back and ask a bigger picture question about the 1.1 T's that you added with your drilling program this year.

That's a big number. I guess we'll get some more detail when we see your K, but I wondered if you could just maybe give us a little preview and tell us how much of that is PDP adds, how much of it was PUDs, and I think three quarters of your wells in '25 were legacy, a quarter were Western Haynesville.

What's the ratio of those reserve adds, whether legacy versus Western Haynesville?

I don't know if we have all those exact stats for you, Ron. I probably have to work on that for you.

Basically, there was definitely some good growth in the PDP reserves, but you also had kind of a situational change here. We've added additional drilling rigs.

Basically, in the next five years, we've got more ability to have proved undeveloped reserves in our reserve report. Also, we sold some inventory, which got to be replaced by new projects.

There's still a lot of reserves that could easily be proved undeveloped reserves that we could put on the books, except for we just cannot develop those in a five-year period, which is that arbitrary SEC rule. A lot of it's just extensions.

Of course, obviously, we're able to book in the Western Haynesville as we had some new wells, we can have offsets to those. It's a combination of all those things.

I think that got back to a normal growing kind of drilling program going forward versus a contracting program that you had last year, the last couple years, where we were pulling in activity because of low gas prices.

Remember in 2024, our finding costs were $1.25, 2025 they're $1.02. Went up two cents, but I think there were probably better adds this year than in '24.

And

those numbers that we provided were all using the NYMEX reserves because they were fairly comparable in price between the end of last year and the end of this year. That isn't reserves that got put back on the books because of improvement in gas prices.

That you would see in our SEC reserves, which had a tremendous amount of additions because a lot of reserves left the SEC case came back. Those are true.

That number, the 1.1 T's, is true additions that are related to drilling activity, not to prices moving around.

Hi. Yes, you got Leo Mariani here from Roth.

Wanted to just touch base a little bit more on the Pinnacle deal here. Wanted to just kind of get a sense from you folks.

It looks like you're trying to replace Quantum as a capital partner here. Can you basically just give us a little bit more color on where you are in the process?

Has that just kind of recently started? I heard you earlier talk about trying to get something accomplished this summer, and does that mean that in the near term Quantum's not going to be contributing any capital for the next several months and you guys need to kind of find that new partner before seeing some of that capital get kind of offset?

Just a little bit more color on that would be great.

We just have an opportunity to replace Quantum, and we're going to do that, yeah. We just started this process, we can't give you a lot of details yet because it just started, but it's an opportunity to replace a preferred kind of capital structure that Pinnacle has now with a common capital structure, so much more equity-like, and then allow the cash flow to be used at Pinnacle and not have the large kind of preferred distribution going out.

Business as usual until all that happens. I think the credit facility, though, we will be putting in soon.

That was the natural part of the business plan of Pinnacle was to have that, and it was provided for originally, but we were waiting till it grew up and had the credit stats to deserve that, which it has now. We'll probably have that in place first and then hopefully complete an equity sale that will allow us to do the full redemption this summer.

No, that's helpful. Then just with respect to Pinnacle, I presume there's probably no debt on that entity right now at the moment?

Then just additionally, do you expect Pinnacle to be free cash flow positive, maybe that year or something like that? Can you just give us any color in terms of where it is in its kind of life cycle from a cash flow perspective?

Sure. I think it becomes really free cash flow positive in the second half of this year.

Putting in the treating plants is a really large capital expenditure that it's had. As we get to that with Marquez train two coming in, we'll have over a BCF a day of treating capacity.

We'll be well positioned to where we'll only be just spending money on well connections. That's really when it becomes much more cash flow positive.

Also, the credit facility will be more than adequate, we think, with its cash flow to fund its capital in the future. The need for the capital infusions like Quantum made last year shouldn't be there.

It made those before it had a revenue stream; now it has one.

Hey, great. Thank you for taking my question.

I wanted to ask again about the production trajectory throughout the year. I know you won't have any turnarounds in the first quarter, but with less downtime, do you expect second quarter to kind of resemble more where you ended the year?

Do you care to put out kind of an exit rate for production, assuming that you run the nine rigs this year?

We put out the guidance that we like to put out. Exit rates are interesting, but they're also so dependent on timing that a well could come online a week later and be in January versus December.

Given that our capital program, big wells, and they come on in usually groups of two to three. The timing of their production is really critical to one day's production.

I think generally...

I think what I would add to that is we'll see quite significant growth over the course of the year just based on our well completion schedule. We only have five wells turning to sales here in the first quarter.

That means over the remainder of the year we have 65-plus wells coming online. Those are pretty evenly spread between the quarters, with a little bit more in the second quarter than in the third.

That would point towards a strong kind of fourth quarter rate. Historically, what we had said on the eight-rig program that we could by the fourth quarter get back to kind of the first half of '24-type levels.

With the ninth rig, I think that remains intact, if not a little bit higher. Remember, adding a rig now, we're not going to really start to see any impact from that until very late in the year, sometime in the fourth quarter.

The addition of that rig is really going to have a much greater impact on the production profile in '27 than it will this year. It's just the capital lag versus production.

Thank you. I appreciate that.

I think that helps. As a follow-up, I wanted to ask on lateral lengths in the Western Haynesville.

It looks like they were a little lower this quarter and that might have affected the per-foot costs. Do you have any color on what the lateral lengths will look like going forward in 2026?

Have you guys kind of decided on what the long-term goal should be for lateral lengths in that play?

I will say the long-term goal is obviously to be longer. A lot of our sticks are controlled by the geology, and you're dead on.

When we have an average short lateral length in any one quarter, it definitely leads to a higher cost. Like I said, we've got six that we've drilled over 12,000 foot long, but we've got several that are on the short end.

I think the shortest one's about 7,800 feet that we've done to date. We do have here in the very near future, we're going to be targeting our first 15,000-foot lateral, and we think we're going to be successful there.

I think the upside is definitely going to be longer than where we've been if you look backwards on average lateral length. As long as we're in areas where we don't have to stop short and due to a fault or something of that nature, we will definitely be longer in the future.

I think the rotary steerable that we've gotten that's been working good for us in the core that we're going to deploy down here, and the 10K rig upgrade, we got just the one rig we're upgrading right now. Those things are going to definitely help us get longer on the laterals.

Good morning.

Morning.

We don't want to belabor the point, and I appreciate the color on the Brown Trueheart, but just taking a step back and looking at slide 17 compared to the equivalent in last year's Q4 deck, the lateral-adjusted IP rate on average has moderately come down year on year. I'm just wondering if you could talk a little bit about this dynamic, and then maybe if you could remind us what EUR you're expecting or underwriting across the Western Haynesville at the moment.

We have made an effort to basically control our drawdowns a lot more than we did in the very beginning. All these wells can be IP'd at what we want to be IP'd at.

We like to get them up to about a 30-, 35 million-day range and IP them there, but all of these wells are capable of IPing at over 40 million a day if we want to, but we don't want to pull the wells that hard. I wouldn't read a lot into that, just the IP rate on a length-adjusted basis, because I think that's part of what you're seeing there is just how we're flowing the wells back.

I think as we fan out across the acreage, we're going to see a little bit different performance in different areas. We still have some of the acreage that we haven't drilled on yet.

We're going to be drilling more wells this year up on the northeast end by the Alligator, and I think all the offset wells to that one up there will resemble that well, which had a good IP, could have been a lot better IP. I think that's going to ebb and flow.

I wouldn't read a lot into that as far as any kind of a trend.

Another question that I think you should ask is, what are we seeing from our cores, and where are our cores? Dan can follow up with that too.

We've drilled four pilot holes to date. We've cored three of those.

All of the cores look great. No surprises to the downside on any of the core work that we've done.

Fully supports the resource estimates that we've had in place. We are taking the learnings from the cores along with the logs and trying to get a little bit better at where we want to target putting the laterals.

That obviously makes a big difference on how good the wells are going to be, where they're landed. In the very beginning, we talked in several of the calls, we had a laser focus to get costs down.

We did. We used insulated drill pipe.

We got our motor runs a little more efficient, a little bit longer, but we were also not trying to keep the laterals exactly maybe where we wanted them. We let them wander just a little bit, just keep our drilling speeds up.

As we look back on some of these, we probably need to put a little bit more emphasis on keeping the laterals landed kind of closer to where we want them and not forsake that maybe to drill a lot faster. That's just day to day.

That's just a balance for us, where we want the well to be and how fast we're trying to drill the well. And

the cores tell us now really where we should land these laterals, we didn't have that data before.

That's right. We've got one core.

We just cored a well up on the northeast end of the field by the Alligator that the rig's on now, and our other two cores are back down towards the other end where the bulk of all the wells have been drilled.

I appreciate that. Jay, I appreciate the free question.

Maybe staying on the productivity side of things, looking at the state data on the legacy side of the basin, and I know there's various factors that might have impacted production or production reporting last year, but it looks like there's a step down in productivity in 2025 vintages. At a high level, could you comment on your views around the Louisiana productivity per foot in 2025 and maybe where you see that heading into 2026 and 2027?

I think if you just look across the entire area up there, there's obviously been some small amount of degradation as the basin's been filled in. There's been obviously thousands and thousands of wells drilled.

Everybody drills where they think their best areas and their best wells are first, and then they kind of start kind of working down their inventory mix from there. Plus, as the gas prices pick up, I think you see more people starting to drill in maybe even some of the lower-type curve areas at the higher pricing when those become a lot more economic.

On our side, I think we'll see maybe a little bit movement back in the other direction now that we're drilling a lot more of these Horseshoe wells, because a lot of our stranded short laterals were in our better-type curve areas. Once we kind of went the Horseshoe route, and they've been looking great for us, we've got ten of those TD to date, going really good, and the performance on those has been better just because they're in the better-type curve areas.

Like I said, it's been a natural degradation, I think just for the whole basin-wide, in how the laterals are drilled. I'd say next year, flat kind of to this past year where we are.

If you can add a rig and drill 115 gross Horseshoe wells, 50-50 Haynesville-Bossier, which we'll drill 16, I think, this year, but let's say you use that rig and you say, well, I'm just going to drill Horseshoe wells. Remember, like Dan said, those are 2.1 BS per thousand.

Those are really, really good locations, except they were shorter laterals. Now all of a sudden you kind of jump-start that and you bring it to the front with a rig, and it makes economic sense to do that.

That's one reason we found a rig and added it earlier on.

Thank you. Good morning all.

Thanks for taking the call. You have talked a lot about the divestiture over the last few years between Western Haynesville and the core, and then some of the non-core asset sales.

I guess, is there anything on the horizon that would kind of shift more of the legacy core into that, I guess, non-core category in which you'd be potentially looking to monetize? Or were the deals towards the end of last year more one-offs?

We don't have any current plans to divest any properties. We obviously react to people coming to us or react to activity in the area.

There's no planned divestitures for 2026.

We look at that, and Shelby was kind of dangling out there, and we had inbound calls, and we looked to see when we might drill that, and then if we could monetize it, what we would do with the dollars. Particularly, we would have never sold that had we not been adding inventory in the Western Haynesville.

That also proves that we trust what we've been de-risking in the Western Haynesville.

Understood, appreciate the clarity. Then you guys talked a bit about other improvements in the capital spending, whether it's rotary steering, high-pressure apparatus, or other type of efficiency rates.

Can you talk a bit about in the Western Haynesville how you see that deployment timing shaking out? Is this relatively linear through 26, or is it back half into 27-type weighted?

When do you expect some of those tangible cost savings to flow through?

That's a good question. All the operators in the core, I'd just say really this rotary steerable started, the vendors have been putting R&D dollars into the rotary steerable systems for the Haynesville.

They're used extensively in all the other basins because they're lower temperature, not really in the Western Haynesville till, say, the last half of '25. We've had probably ten runs to date with that system so far and, really made good progress.

The vendors, they're tweaking their tools. As far as deploying it to the Western Haynesville, I'm going to say, sometime here within the next three months we'll be making our first run in the Western Haynesville.

We do plan to make several runs in the Western Haynesville over this year. As far as the full cost savings, I think we'll get pretty immediate cost savings when we get that first 10K rig in place late this summer.

The rotary steerable, I think, will be a little bit more of a gradual increase as far as the realized savings on that system. Hopefully this, I think this two weeks, by this time next year, we can be achieving this two weeks reduction in drill times from where we're at today on average.

We've got, like I said, the vendors are super interested, they're putting a lot of money into R&D for these tools. All the operators are trying to, they're running the tools in the core.

We've looked at all the numbers and it's very doable in the Western Haynesville. I think once we see some success early on in the Western Haynesville, we'll be pushing to get the temperature rating on that tool even higher.

I think, that may be maybe deeper into next year as far as having, say, a 392-degree-rated rotary steerable tool. Like I said, if we just can repeat

in the first half of our Western Haynesville laterals with what we've seen in the core, we're going to definitely cut off a lot of days.

Hey, thanks for the time. Just a couple of follow-up questions about the year-end reserve report.

First, what is the average EUR per thousand foot assumed by Lee Keeling in the Western Haynesville? Then you maybe talk about how that compares to the legacy Haynesville.

Our reserves are audited by Netherland, Sewell, Phillips. Yeah.

The Western Haynesville basically, I think the overall average reserve EURs are probably, they do range from anywhere from 3 Bs per thousand foot of lateral to 4 Bs per thousand foot of lateral. It's kind of a range.

I think that only the ones that really have a long performance have that really higher one. I think generally three and a half is a good average for the Western Haynesville.

Sounds good. Yeah.

Sorry about that. I forgot it was Netherland, Sewell.

Just one more on the reserve report. What's sort of the implied next 12-month PDP decline rate in your report, and how does that maybe compare to the decline rate in your year-end '24 report?

It's actually come down a little bit. It's from 40%.

It's down like 1 or 2%. Part of that is a function of it was expected to start to come down as we have a greater percentage of our production in the Western Haynesville, and we're starting to see that.

It's just a small piece of the overall reserve, so that first-year PDP decline will improve over time, not all at once.

The only thing I would tell you is that I think there is concern about U.S. shale maturity.

I think there is a little bit of spirit about wildcatting now, because you've got to have inventory. If you just look at these numbers, and the legacy Haynesville, which is 4 million acres, has produced 48.5 Ts from 7,600 wells, and we think Comstock is exposed to 50 Ts, well, that's more than has been produced from the legacy Haynesville.

That's why when you ask Dan the question about are the service companies trying to figure out how we can drill and complete these wells quicker, faster, cost savings? Absolutely yes.

Because they have a lot of work built in for decades if they can do that, and they're spending their own money doing it. They not only believe what we're doing, we believe what we're doing, and the thousand penetrations that we have from north, south, east, west that triggered this whole play shows that we probably have great belief in its accuracy.

We are thankful or fortunate that we captured that footprint. I think that goes back to toggling.

As I visit with Jerry, he will toggle stuff. Do you have X amount of landmen leasing acreage?

You toggle it. What do we do in the Western Haynesville?

Do you add two more rigs in 2024? No, because gas prices are low, you do it in 2025.

Kind of like what Dan is doing with these rotary steerables. You accelerate it and go into the Western Haynesville.

Then if the opportunity comes where we should divest something in the core that we won't drill for years, but somebody else would drill now, and you can both win, you toggle that. That is what we've been doing, and that's what we will do for all the equity stakeholders and the bondholders and the banks and everybody else that believes in us.

I can tell you that we work really hard. We're going to try to give you good news when it's there, and if something's not there, we'll always tell you the truth.

It's a pretty good world we live in. Thank you.