Comstock Resources, Inc.

Good day, and thank you for standing by. Welcome to the fourth quarter 2025 CompStock Resources, Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead.

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. So 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 am 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 two in our presentation to note our discussions today will include forward-looking statements within the meeting 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 turn on slide three, 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 Hainesville-Bozier wells with an average IP rate of 27 million cubic feet per day. The 2025 drilling program replaced 229% of our 2025 production with one TCFE of drilling-related approved reserve additions, achieving an overall finding cost of $1.02 per MCFE. We announced we were partnering with Nextera on a data center project in the Western Hainesville. 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 four, 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 Hainesville wells online, increasing the number of wells turned to sales in 2025 in the Western Hainesville to 12 wells. These four wells had a at 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 Hainesville, 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 in 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 five, we covered the fourth quarter financial results. Our production in the fourth quarter averaged 1.2 CCFE 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. EVA DAX 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 Fork shale acreage. Excluding these items and expiration 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 six 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. EVA DAX 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 expiration expense and related income taxes, we reported adjusted net income of $160 million for 2025, or 54 cents for diluted share. compared to net loss in 2024. On slide seven, 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, so 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 basis differential compared to the NYMEX settlement price and a 29 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 cost per MCFE and our EBITDAX margin. Our operating cost 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 cost 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 cost 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 $55 million for the entire year in 2025. Last year we drilled 36 or 29.6 net horizontal Hainesville shell wells and another 16 or 14.6 net Bossier shell 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 electric 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 EVA DAX. At the end of the fourth quarter, we had almost 1.3 billion of liquidity. Slot 11, we recap our approved reserves at the end of 2025, which came in at 7.2 TCFE, based on reserves determining year-end NYMEX market prices adjusted for our differentials. Proved reserves determined using year-end NOMICS 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 million on our drilling program in 2025, giving us the total overall finding cost of $1.02 in 2025. In addition to the approved reserves that we reported, we also have 1.9 TCFE approved undeveloped reserves, which are not included in our approved 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 or 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 Hainesville acreage, where we have only included 5.4 TCFE related to the western Hainesville NRP3 reserve estimates. I'll now turn it over to Dan to discuss the drilling results we've had.

Okay. Thanks, Roland. On slide 12, this is an overview of just our latest acreage footprint for both the Hainesville 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 Hainesville and Bossier shales. If you look on the left is our western Hainesville 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 Hainesville area. We have 30 wells currently producing on our western Hainesville acreage, which is relatively undeveloped compared to our legacy Hainesville. With the higher pay thickness and the pressures we encounter in the western Hainesville, we'll expect the western Hainesville will yield significantly more resource potential per section than the legacy Hainesville. Slide 13 is our updated drilling inventory in our legacy Hainesville area, the end of Our total operated inventory in the Legacy Hainesville 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 Hainesville, 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 Hainesville, 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 Hainesville and 50% in the Bossier. So this sets up over 80% of our gross operated inventory in the Legacy Hainesville with laterals greater than 8,500 feet. Our Legacy Hainesville inventory also includes 115 gross Horseshoe locations with close to a 50-50 split between the Hainesville 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 Hainesville. Our western Hainesville 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 Hainesville acreage has not yet been unitized. Our Western Hainesville inventory is more weighted to the Bossier formation. We got nearly two-thirds of our inventory in the Bossier and one-third of the inventory is in the Hainesville. With the same as our legacy Hainesville inventory, our Western Hainesville 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. So in our Western Hainesville gross operated inventory, we don't have any current short laterals. We have 1,326 medium laterals. We have 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 had been drilled to total depth. The average lateral lengths were shown separately for both our legacy Hainesville and our western Hainesville areas. In the fourth quarter, we drilled 12 wells to total depth in the legacy Hainesville 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. A record long lateral in the legacy Hainesville area still stands at 17,409 feet. In the fourth quarter, we also drilled four wells to total depth in the western Hainesville. And these wells had an average lateral length of 9,944 feet. The individual lengths on these wells range from 9,355 feet up to 11,249 feet. Our longest lateral drill to date in the Western Hainesville is 12,763 feet. And to date in the Western Hainesville, 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've turned to sales on our legacy Hainesville Acres 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 range 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 Hainesville acreage. Slide 17 outlines the 12 wells that we turned to sales on our western Hainesville acreage in 2025. Since we last reported earnings, we've had four additional wells that have been turned to cells. 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 are drilling on the western Hainesville Acres. On slide 18, This highlights the average drilling days and average footage drilled per day in the legacy Hainesville 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 Hainesville area and we averaged 27 days to total depth. In the fourth quarter, we averaged 893 feet drilled per day on our legacy Hainesville acreage, which this represents a 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 Vista No 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 levels. Slide 19 highlights our drilling progress in the western Hainesville. 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 Hainesville corridor. The corridor is mainly affected by our vertical depths, temperatures, and our lateral links. So 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 a thousand foot deeper vertically and hotter than the wells drilled in the third quarter while the average lateral lengths were similar. Our fastest well drilled at 8 in Western Hainesville still stands at 37 days and that well was drilled with a 12,045 foot lateral. On slide 20 is a summary of our DMC costs through the fourth quarter for our benchmark long lateral wells located on our legacy Hainesville acreage. The costs reflect all of our legacy area wells, again, that have the 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 cells. 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 reason mentioned on the efficiency slide where we had five wells within the Vista No 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 cells in the Legacy Hainesville. 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 cost 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 Hainesville. This additional frac fleet will be working full-time in our Legacy Hainesville 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 the Rotary Steerable Drilling Assembly in our Legacy Hainesville area. We've made great progress to date. As this technology becomes further refined for the high temperature environment in the Hainesville 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 D&C costs through the fourth quarter for all wells drilled in the western Hainesville. During the fourth quarter, we drilled four wells to total depth. with an average lateral length of 9,944 feet. The fourth quarter drilling cost averaged $1,489 a foot. This represents a 7.5% increase compared to the third quarter. Our drilling cost 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 hensel acreage. It had an average lateral length of 8,399 feet. The fourth quarter completion cost 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 we had lower horsepower usage in the fourth quarter. In addition to the earlier cost initiatives we have enacted in the Western Hazel, including the use of the insulated drill pipe, we are undertaking additional measures to further reduce our cost. We have recently arranged to have one of our existing Western Hazel 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 hull sections, significantly reducing our costs. Also, following up on the successful trial runs of the rotary stirruble drilling system in our legacy Hainesville area, we will be rolling out this system for trawls in our western Hainesville area in the near future. We believe the application of this technology to the hot hole environment of the western Hainesville, 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 track 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. And 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 Hainesville that will position Comstock to benefit from the longer-term growth in natural gas demand driven by LNG exports and build-out of power for data centers. We have four operated rigs drilling into Western Hainesville to continue to delineate the new plate. We expect to drill 19 wells and turn 24 wells to cells in 2026. We plan to have five operated rigs drilling and Legacy Hainesville 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 Hainesville later this year. We expect to commercialize our Western Hainesville 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 Hainesville midstream company, which is 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 Hainesville areas. And 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 Hainesville. 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 Hainesville. The Legacy Hainesville Play was discovered in 2008. It covers approximately four million acres and has produced about 48.5 TCF from 7,600 wells. We estimate the remaining recoverable reserves in the legacy Hainesville to be 75 TCF. Net to our working interest, we have about 14 TCF of reserves in our legacy Hainesville properties. The Western Hainesville Plate, 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 Hainesville could reach 99 TCF. Comstock would have almost 50 TCF net to the working interest we own in a play. As Dan Harrison said earlier, we have drilled 39 wells to date in the western Hainesville and have turned 30 of those to cells. In 2025, we turned one western Hainesville well to cells every month, along with three legacy Hainesville wells every month. This year, our activity level will increase as we expect to turn two western Hainesville wells per month and turn four legacy Hainesville wells per month to cells. 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 Hainesville, which is benefited by using thermal or insulated drill pipe, new purpose-built rigs, and new hot-hold MWD tools. Also drilling more wells on two-well paths and optimizing casing designs have contributed to improving our well cost. New initiatives to improving cost we're implementing in 2026, including applying rotary steerable drilling assembly technology that we're having great results in with our Legacy Hainesville horseshoe wells that we're currently drilling. We have learned from the development of Legacy Hainesville play that started in 2008 how this new Western Hainesville place should be developed to maximize its future value. We believe the Western Hainesville 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.

Thank you. As a reminder, to ask a question, please press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 again. In the interest of time, we ask that you please limit yourself to one question and one follow-up. Please stand by while we compile the Q&A roster. Our first question comes from Derek Whitfield with Texas Capital. Your line is open.

Good morning, guys, and thanks for your time. Thank you. Maybe to start with guidance, as that seems to be the focal point for investors, is it fair to say that the budget was put together in a slightly more constructive gas environment, and when it comes time to spend the capital, if the price isn't there, the capital won't be there either? And maybe just to build onto that guidance question, If we assume the capital program as outlined, I suspect the exit rate will be higher than what we anticipate today, given that legacy Hainful has faster cycle times, and there's likely some friction from 1Q that will bleed into Q2 as well. So maybe if you could offer any color on cadence of production, that would be helpful as well.

Yeah, sure, Derek. You know, it's been a – of course, gas prices have been all over the board, you know, since – Thanksgiving and then, you know, had a huge rally there. Then you had a fairly warm, you know, second half of December, first half of January. Then you had a cold second half of January. And so it's been a, you know, we've actually had two great index prices for January and February gas, you know, that are extraordinary. But obviously gas prices have been everywhere and that's not unexpected. We expected this to be a very volatile year for gas prices given the new demand that's coming on and the difficulty in trying to match supply to demand. And so weather has played a major role in and whether you know gas is considered you know undersupplied or oversupplied and probably will continue to play that role you know um you know throughout the year and obviously we have you know we did want to get um enough frac equipment and drilling rigs you know that we could execute a good program for 2026 in place and then running well you know we always run the equipment in the legacy haynesville before moving it to the western haynesville so so we put that in place, you know, for this year. But obviously if gas prices, you know, disappoint, you know, we have as many as four rigs that we could, with short notice, you know, take out of action. And the same thing with the frack crew. So I always have the ability to flex our drilling budget based on how things come out. But I think overall, you know, given we did sell a lot of properties, you know, finish out last year, you know, Sold some production. We do want to invest back in the properties, build the production levels up, and we think that's the best way to achieve the leverage goals we have will be really generate some higher EBITDAX. A lot of that will be more directed toward the second half of the year. Obviously, fairly noisy first quarter. month or so of this year, given the disruptions in January. And then some of that completion activity got pushed a little bit as we took down our freight crews during most of the winter storm. But generally, I think we have a very exciting year planned for 2026, we think.

Well, Derek, it's very flexible. If we wanted to get rid of one, two, or three of our drilling rigs, we could on notice. given probably 45-day notice. It's very, very flexible. We've got quality drilling contractors. We've got quality group of fracking companies. And as Dan has said, I think we're going to get better and better and better on our drilling completion times in Western Hainesville. In 2025, you know, as the year went along, we ended up with the four rigs in the Western Hainesville. So if you look at 2026, I think it'll be a lot more predictable what the outcome can be and particularly a lot of these wells will be drilled on two well pads and i think these costs are going to go down and what we do focus on is you need to have three four five percent uh you know uh growth every year and we were negative 14 last year so we come in a little bit of negative in uh first and second quarter 26 but then we make that up in the third and fourth quarter and and if you do look at this natural gas demand we you know we believe on a yearly basis, the demand's going to grow about 3 BCF every year between now through 2030. And that's just based upon LNG facilities and data centers that are being built. That has nothing to do with FIDs. So we want to lean into that. And a way to lean into that is if we have sold an asset and we didn't give up a lot of production or we gave up a little bit and we paid down our borrowing base, our credit facility, We do have a little bit more flexibility to lean into 2026 earlier. And that is what we're doing. I look at these, all these E&P companies, they really are searching for tomorrow's drilling inventory. And you're really asking the question is, what's your tomorrow look like? Well, most of these are looking for tomorrow's drilling inventory. They're searching across the globe. Look at the Wall Street Journal yesterday. They're across the globe. So if you really are a pure natural gas company in the U.S. and you want to be near where the majority of the demand for LNG is located as well as where these investments for AI data centers are being made. And Derek, that's exactly where we are. So we're just trying to manage this potential 50 TCFE of upside in a western anvil in the decades to come to bring that to fruition to show everybody what we are trying to do. Our tomorrow, we're looking at today. So we're just trying to de-risk it and deliver it.

Great, Jay. And I'll maybe lean in just there on kind of the tomorrow, particularly with AI demand along the Gulf Coast. With respect to Nextera, do you have a view on how the JV will scale from the two gigawatts you hope to commercialize in 2026? to the eight gigawatts it could be. And how should we think about the price and or cost advantage of selling to Nextera versus traditional marketing?

Well, yeah, I think my comment with that, you know, without getting in the gray area is if you listen to what most of the hyperscalers would tell you, I think they would like to be in Texas if they could. I think regulatory-wise, it's good to be in Texas. Now, you have to be in an area where there's people to hire. If you build eight gigawatts, you might be building a city of 20,000 people, so you gotta have location, but you have to have water. So you want water? If you look at where we are, we're 100 miles from Dallas, 100 miles from Houston, and you have to have an airport where you can get in and out, in and out. So all we've done is we said we have untapped, what we call the basin. You know, I think we control a new basin, not some acreage in the legacy area, but we control a basin. That's how we look at it. That's how we're developing it. And 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. So 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. And I think we were taking those next steps hand in hand with them, or we wouldn't be discussing it. But 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. So we're trying to capture both of it.

Thank you. Our next question comes from Kalei Akamai. With Bank of America, your line is open.

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. I'm wondering how we should think about the cost of doing that. And if you plan to backfill the funding with BankTet, how should we think about the size of that facility and whether it's sufficient to execute on the scope of your midstream ambitions?

Yeah, that's a good question. Yeah, we've 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 EBITDAX, which probably people aren't really expecting because it just hasn't had it in the past. But 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 And so that's the plan we're putting 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 is you know, will be able to be available to fund its CapEx and also have its own low-cost credit facility now that it is, you know, it has the credit metrics to deserve that. So we expect a lot of that. Hopefully our goal is to have a lot of that in place, you know, by May of this year.

I'll tell you this is a positive move for our midstream. In other words, it was birthed You know, we had 145 miles of high-pressure line. We had the Bethel plant. And then as it progressed, we added Marquet. And then now it's progressed where we have a giant foothold in the western Angle. And we want the pinnacle system to mature as we add rigs and production. And 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 pull that up, have you already fielded interest on the potential equity sell-down? And then can you kind of talk about the timing rationale for the marquee 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?

Yeah, with the marquee plant, which is being, you know, we think it's, you know, next trade will be operational sometime this summer. Again, you know, as a, you know, As a midstream provider, you've got to have these assets 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 so 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. So 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. And so 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 that 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, you know, they'll dig a little deeper into what we are showing in the Western Hainesville. And I think that the more they dig, the more they like is our opinion. So we'll find out.

Thank you. Our next question comes from Carlos Escalante with Wolf Research. Your line is open.

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 Hensville throughout the year. But if I may cherry pick up one of your late as well as the Brown True Heart B.B., That well looks like the IP rate basis slightly underperformed the broader group. And 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. So I'm just wondering if you can perhaps provide your perspective on anything that you might be seeing on the raw quality or perhaps any kind of water handling issues Something that, you know, maybe qualifies this specific area where this two wells are, which is, I suppose, closer to the heart of your position on the basin.

Yeah, so the Brown-Streer heart well was, that's, if you look on the acreage map, it is the furthest one that we've, as we've kind of fanned out and drilled more to the northeast, it's kind of on that Not the far northeast end where the Olajuwon, but the farthest northeast of that trend of wells we've drilled. It was a two-well pad. We drilled the well up-depth and down-depth. This well was drilled up-depth. And actually, we drilled four wells kind of right there in that same spot, two well pads. And just because of the geology, if you're drilling south, you're going down-depth. And if you're drilling north, you're going up-depth. So this well, I think it's... Basically, it's 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. And the only difference between the two wells was this one was making more water during the flowback period.

Thank you. That's very helpful. And 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. And that was with lower quality acreage. I think that I can say that objectively speaking. So I wonder what your views are on the recent trend coming into the year on M&A activity. And 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?

You know, I think, Carlos, I think we're just me. And again, this goes back to five and a half years. This goes back to probably July of 2020 when we first looked at the Western Angle. I believe we're setting on some of the most valuable gas in the world. And the reason I believe that is where the LNG facilities are being built and have been built and are being built. And that, you know, the U.S. is the largest exporter of gas in the world. It's only going to get bigger and bigger and bigger. As you know, I mean, the Schneers, et cetera, et cetera, they're all adding. The Venture Globals are adding. The data centers are adding. So I think to answer your question, our business plan is to show what our Western Hainesville might be. And the way we do that is we talk about, you know, rotary steerable 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&As or upstream, it's your quality drilling locations. And I think we have that not only in our core, but our core you wouldn't buy that, but you would buy that at the Western Hainesville 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 undedicated. So 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, and if we needed to add a rig, which I think that's the only negative truly in the call as we added a rig that's $150 to $70 million as we use per rig per year. But that is to what? It's to continue to shore up our legacy and then add to the Western Hainesville performance. You know, we're not looking for inventories. They are looking for inventories. We're looking to develop what we own now, and we've got a great amount of gas. And always, you know, you always want to be the beauty queen. It's like the Olympics. You know, we don't want a silver or a bronze medal. That'd be great to be up there. That'd be great. But if you're going to go out there, you're going to go for the gold. You know, 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 he 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. And the Jerry Jones of the world came in and said, I'm behind you. I want to go with you. Let's develop this. And you know what? We'll see where the value comes. We'll see where it comes from.

Thank you. Our next question comes from Charles Mead with Johnson Rice. Your line is open.

Good morning, Jay, Roland, Dan, and to the rest of the Comstock team there. Dan, in response to the earlier question about the brown two-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? And could it be related to the azimuth of that well and whether you're toe up versus toe down? Is there any, you know, what's your thought process there?

Well, that's a really good question. You know, I don't think anytime these, you know, we've had several wells in the core, you know, that will make high water in the very beginning and When we do make high water in the beginning, it's just hard to get a good eye pre-grate until that water comes off. But 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, you know, from what you fracked. And there have, not on the brown true heart, but, you know, In other areas in the past, there's been discussions when we've had high water about did the frac orientation change along the wellbore. Instead of being perpendicular to the lateral from the toe to the hill, due to some regional local stresses, maybe those fracs turned more closer to being parallel with the wellbore than being perpendicular. And that will definitely lead to a well that makes more water. That's possible on the Brown True Heart. We don't think that's what's happening on the Brown True Heart. 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. And we, you know, it could be that or it could be a geometry thing. Just, you know, how much they might come flow back when you drill uphill versus drilling downhill. Like I said, this was a two well pad. We had the downhill, the down dip, Well, IP'd at, you know, over $30 million a day, and this one, you know, 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 would have been pulling a lot more water, too, and obviously that's not good for the well.

Well, and you fight gravity. You drill up dip, and you're 1,000 foot shorter than the brown true or W number one. You're 1,000 foot shorter, you're up dip, and you fight gravity. Water is going to flow down. So we IP'd the brown true heart at 22 and the other one at 32.

And 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 the flow back, 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 1.1Ts that you added with your drilling program this year. That's a big number. And I guess we'll get some more detail when we see your K, but I wonder if you could just maybe give us a little preview and tell us how much of that is PDP ads, how much of it was PUDs, and I think three-quarters of your wells in 25 were PUDs. Legacy, a quarter were Western Hainesville. But what's the ratio of those reserve ads, whether Legacy versus Western Hainesville?

Yeah, I don't know if we have all those exact stats for you. Ron, probably have to work on that for you. But basically, you know, there was definitely some good growth in the PDP reserves. But you also had, you know, kind of a situational change here. You know, you're looking at – you're coming off of – 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. We've got a lot of reserves that could easily be proved undeveloped reserves that we could put on the books, except for we cannot develop those in a five-year period, which is that arbitrary SEC rule. So a lot of it is just extensions. Of course, obviously, we're able to book into Western Hainesville as we had some new wells, so we can have offsets to those. So 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 of years where we were pulling in activity because of low gas prices.

Remember in 2024, our finding costs were $1. 2025, they're $1.02. Went up two cents, but I think there were probably better ads this year than in 24.

And those numbers that we provided, we're all on the using the NYMEX reserves because they were fairly comparable in price between the end of last year and the end of this year. So that isn't reserves that got put back on the books because of, you know, improvement in gas prices. That you would see in our SEC reserves, which had tremendous amount of additions because a lot of reserves left the SEC case, came back. Those are true, you know, that number – the 1.1 T's as true additions that are related to drilling activity, not to prices moving around.

Thank you. Our next question comes from Phu Pham with Roth Capital Partners. Your line is open.

Yeah, hi. I actually got Leo Mariani here from Roth. I wanted to just touch base a little bit more on the Pinnacle deal here. So I wanted to just kind of get a sense from you folks. It looks like you're trying to replace, you know, Quantum, you know, as a capital, you know, 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, you know, this summer. And does that mean that in the near term, Quantum's not going to be completing or sort of 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 code on that would be great.

Yeah, no, we just have an opportunity to replace Quantum, and we're going to do that. And we just started this process, so we can't give you a lot of details yet because it just started. But it's an opportunity to replace the 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. So 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 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, and we'll probably have that in place first and then hopefully complete an equity sale to allow us to do the full redemption this summer.

Okay, I know that's helpful. And then just with respect to Pinnacle, I presume there's probably no debt on that entity right now at the moment. And then just additionally, do you expect Pinnacle to be, you know, free cash flow positive? Maybe that, you know, next year or something like that? Can you just give us any color in terms of where it is and 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. The first half is kind of this last, you know, putting in the treating plants is a really large capital expenditures that it's had. So, As we get to that, with Markay Train 2 coming in, we'll have over a BCF a day of treating capacity. So we'll be well positioned to where we'll only be just spending money on well connections. So 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. So, you know, the need for the capital infusions like Quantum made last year, you know, shouldn't be there. And so it's just because it's made those before it had a revenue stream, now it has one.

Thank you. Our next question comes from Kevin McCurdy with Pickering Energy Partners, your line is open.

Hey, great. Thank you for taking my question. I wanted to ask you about the production trajectory throughout the year. I know you won't have any turning lines in the first quarter, but with less downtime, do you expect second quarter to kind of resemble more where you ended the year? And do you care to put out kind of an exit rate for production, assuming that you run the non-rigs this year?

Well, we put out the guidance that we like to put out, you know, so we don't really, you know, exit rates are so, you know, they're interesting, but they're also so dependent on timing that, you know, a well could come online, you know, a week later and be in, you know, January versus December. So given that, you know, our capital program, big wells, you know, and they come on in usually groups of two to three. So, you know, the timing of their production is really critical to one day's production.

Yeah, 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, you know, 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. And so, you know, 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 links in the western Hainesville. 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 links will look like going forward in 2026, and have you guys kind of decided on what the long-term goal should be for lateral links in that play?

Well, I will say the long-term goal is obviously to be longer. You know, 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. And we've got, you know, like I said, we've got six that we've drilled over 12,000 foot long, but we also have, you know, we've got several that are, you know, on the short end. I think the shortest one's about 7,800 foot that we've done to date. But we do have here in the very near future, we're going to be drilling towards our first, you know, targeting our first 15,000 foot lateral. And we have, we think we're going to be successful there. So I think the upside is definitely going to be longer than where we've been if you look backwards on the average lateral length. So, you know, as long as the geology, we're in areas where we don't have to stop short due to a fault. you know, or something that's of that nature, we will definitely be longer in the future. I think the rotary stirruble, you know, 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, you know, we got just the one rig we're upgrading right now. Those things are going to definitely help us get longer on the laterals.

Thank you. Our next question comes from Jacob Roberts with TPH & Co. Your line is open.

Good morning. Morning. I don't want to belabor the point, and I appreciate the color on the brown true heart, 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. So 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 Hainesville at the moment.

So as far as, you know, we have made an effort to, you know, have basically control our drawdowns a lot more than we did in the very beginning. We're not looking, you know, all these wells can be IP'd at what we want them to be IP'd at. We like to get them up to about, you know, 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. So 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. But I think as we fan out across the acreage, we're going to see a little bit different performance in different areas. And so 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 Olajuwon. And, you know, I think all the offset wells to that one up there will resemble that well, which had, you know, a good IP, could have been a lot better IP. So 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.

Well, another question that I think you should ask is, what are we seeing from our cores, and where are our cores? And Dan, you know, can follow up to that too.

Yeah, so we've taken – We've cored, we've drilled four pilot holes today. We've cored three of those. All of the cores look great. I mean, 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 on several of the calls. We had a laser focus to get costs down. We did. We used the 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 to keep our drilling speeds up. And 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. So that's just the... 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.

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 Elijah one that the rig's on now. Our other two cores are back down towards the other end where the bulk of all the wells have been drilled.

I appreciate that. And 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 porting 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 in 26 and 27?

I think in the core, you know, I think if you just look across the entire area up there, all operators, I mean, there's obviously been some you know, small amount of degradation as the basin's been filled in. I mean, there's been obviously thousands and thousands of wells drilled. You know, everybody drills where they think their best areas and their best wells are first, and, you know, 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, you know, at the higher pricing when those become a lot more economic. I think we will see 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 horsey wells because a lot of the horsey wells were from a lot of our stranded short laterals were in our better type curve areas. So once we kind of went the horsey route and they've been looking great for us, we've drilled, we've got 10 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 area. So, like I said, it's been a natural degradation, I think, just for the whole basin, basin-wide, on how the laterals are drilled. So, you know, I'd say, you know, next year, you know, flat kind of to this past year where we are.

Well, if you can add a rig and drill, you know, 115 gross horseshoe wells, 50-50, Hainesville, Bossier, which you, you know, will 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 two 2.1 bees per thousand. Those are really, really good locations, except they were shorter laterals. So now all of a sudden you kind of jumpstart that and you bring it to the front with a rig, and it makes economic sense to do that. So that's one reason we found a rig and added it earlier on.

Thank you. Our next question comes from Paul Diamond with Citi. Your line is open.

Thank you. Good morning, all. Thanks for taking the call. I just wanted to touch base on, you guys have talked a lot about the delineation over the last few years between Western Hainesville 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 these the deals towards the end of last year more one-offs?

Yeah, we don't have any current plans to invest in any properties. But, you know, we obviously react to, you know, people coming to us or react to activity in the areas, though. But there's no planned divestitures for 2026.

Yeah, we look at that. And Shelby was kind of dangling out there, and we had, you know, we had inbound calls at And we look to see where we might drill that. And then if we could monetize it, you know, what we would do with the dollars. Particularly, we would have never sold that had we not been adding inventory in the western Hainesville. But that also proves that we trust what we're de-risking in the western Hainesville.

Understood. Appreciate the clarity. And then just talk a bit about the other improvements in the capital spending, whether it's rotary steering, high-pressure apparatus, or other type of efficiency routes. Can you talk a bit about in the western Hainesville, how you see that deployment timing shaking out? Is this relatively linear through 26, or is it back half into 27 type weight? When do you expect some of those tangible cost savings to flow through?

Yeah, that's a good question. So, you know, all the operators in the core, I'd just say really this rotary steerable started, you know, the vendors have been putting R&D dollars into the rotary steerable systems for the Hainesville. They're used extensively in all the other basins because they're lower temperature, not really in the western Hainesville till, say, the last, you know, the last half of 25 years. We've had probably 10 runs to date with that system so far and really made good progress. The vendors, they're tweaking their tools and as far as deploying it to the Western Hainesville, I'm gonna say sometime here within the next three months, we'll be making our first run in the Western Hainesville. We're gonna make, we do plan to make several runs in the Western Hainesville over this year. As far as the full cost savings, I think we'll get, you know, 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. But, you know, hopefully this, I think, this two weeks, by this time next year, you know, we can be achieving this two weeks reduction in drill times from where we're at today on average. So, I mean, we've got, like I said, the vendors are Super interested to put a lot of money in the R&D for these tools. All the operators are trying to, you know, they're running the tools in the core. So, you know, we've looked at all the numbers and, you know, it's very doable in the western Hainesville. And I think once we, you know, see some success early on in the western Hainesville, we'll be pushing to get the temperature rating on that tool even higher. And I think, you know, That may be maybe deeper into next year as far as having a, you know, say a 392-degree rated rotary steerable tool. But, you know, like I said, if we just can repeat in the first half of our western Hainesville laterals with what we've seen in the core, we're going to definitely cut off a lot of days.

Thank you. And our final question comes from Phillips Johnson with Capital One. Your line is open.

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 1,000 foot assumed by Lee Keeling and the Western Hainesville? And then you maybe talk about how that compares to the legacy Hainesville.

Yeah, I'm not sure why you referenced Lee Keeling. Our reserves are allotted by Netherlands, Sewell, Leo. Phillips. I mean Phillips, yeah. So the Western Hainesville basically, I think – The overall average reserve EURs are probably, they do range from anywhere from three bees per thousand foot of lateral to four bees per thousand foot of lateral, kind of a range. I think that only the ones that really have a long performance have that really higher one. But I think generally, three and a half is a good average for the Western Hainesville.

Okay. Sounds good. Yeah. Sorry about that. I forgot it was another one. So 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's a function of was expected to start to come down as we have a greater percentage of our production in the Western Hainesville, 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.

Thank you. This concludes the question and answer session. I would now like to turn it back to Jay Allison for closing remarks.

Yeah, 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. And if you, you know, if you just look at these numbers and the Legacy Hainesville, which is 4 million acres, has produced 48.5 tees from 7,600 wells, and we think Comstock is exposed to 50 tees, well, that's more than has been produced from the Legacy Hainesville. That's why when you asked 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. Yeah, 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. So 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 a great belief and it's accurate. So we are thankful or fortunate that we captured that footprint. And I think that goes back to toggling. You know, as I visit with Jerry, he will toggle stuff. Do you have X amount of landmine leasing acreage? You toggle it. What do we do in the western hand? Do you add two more rigs in 2024? No, because gas prices are low. So you do it in 2025. You know, kind of like what Dan is doing with these road resturables. You accelerate it. and going to the Western Hainesville. And 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. So 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. And 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.

Thank you. This concludes today's conference call. Thanks for participating. You may now disconnect.