Comstock (CRK) Q4 2025 Earnings Call Transcript

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Date

Feb. 12, 2026 at 11 a.m. ET

Call participants

• Chief Executive Officer — Jay Allison
• President & Chief Financial Officer — Roland O. Burns
• Chief Operating Officer — Daniel S. Harrison

Takeaways

• Revenue -- Oil and gas sales for the quarter totaled $364 million, an increase of 8% from the previous year’s fourth quarter, driven by higher natural gas prices despite lower production volume.
• Adjusted net income -- Adjusted net income for the quarter was $46 million, or $0.16 per diluted share, unchanged from the prior year’s fourth quarter.
• GAAP net income -- GAAP net income for the quarter was $281 million, or $0.97 per share, including a $294 million pretax gain on asset sales, a $37 million mark-to-market unrealized hedge gain, and a $29 million impairment charge.
• Operating cash flow -- Operating cash flow in the quarter reached $222 million, or $0.75 per share.
• EBITDAX -- Adjusted EBITDAX for the quarter was $277 million, with a margin of 77%, which was up 3% from the third quarter.
• Production -- Quarterly production averaged 1.2 Bcfe per day, 14% below the prior year, reflecting recent asset sales.
• Divestitures -- $445 million of asset sales completed in the second half, including the September Cotton Valley and December Shelby Trough transactions, reduced total producing wells by 1,084, but only 17 million cubic feet per day of net production was divested.
• Debt and liquidity -- Borrowings under the credit facility ended the quarter at $260 million, with total liquidity of nearly $1.3 billion, and an improved leverage ratio of 2.6x.
• Proved reserves -- Year-end proved reserves stood at 7.2 Tcfe (NYMEX pricing basis), an 8% increase excluding asset sales, with 1.1 Tcfe added from drilling, replacing 229% of annual production.
• Finding and development cost -- Finding cost for 2025 was $1.02 per Mcfe, up marginally from $1.00 per Mcfe in 2024.
• Drilling activity -- Fifty-two operated Haynesville/Bossier wells drilled in the year (44.2 net), averaging an initial production rate of 27 million cubic feet per day.
• Western Haynesville focus -- Four wells turned to sales in the Western Haynesville during the quarter averaged 8,399 feet of lateral length and 29 million cubic feet per day IP; the company drilled 39 wells to total depth in this area through year-end.
• Cost structure -- Operating cost per Mcfe averaged $0.77, flat versus the third quarter; overall drill-and-complete cost for legacy Haynesville long laterals was $1,347 per foot, down 11% from the prior year.
• Hedge impact -- 57% of gas volumes hedged in the fourth quarter, decreasing realized price to $3.27 per Mcf from a reference price of $3.58 per Mcf.
• Shareholder return -- Cumulative total shareholder return over two years was 162%, the highest among public E&P peers.
• Partnerships -- Announced joint venture with NextEra for a data center project in Western Haynesville, targeting 2 gigawatts of initial power generation, with potential to expand to 8 gigawatts.
• Midstream recapitalization -- Pinnacle Gas Services midstream subsidiary will be recapitalized by redeeming preferred units and selling equity, supported by a new credit facility, with these steps targeted for completion by midyear.
• Capital expenditure -- $1.06 billion spent on development activity in 2025, with focus shifting toward cost reductions through new drilling technologies and equipment upgrades in 2026.
• Guidance flexibility -- Management emphasized a flexible drilling budget, stating, "if gas prices disappoint, we have as many as four rigs that we could with short notice take out of action."

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Risks

• Production in 2025 declined 14% year over year due to asset divestitures.
• Fourth quarter drilling cost for legacy Haynesville long laterals increased by 22% sequentially, attributed to drilling complexity and shorter average lateral length.
• Western Haynesville drilling cost per foot increased 7.5% sequentially in the quarter as recent wells were deeper than previous periods.
• Management acknowledged, "we come in a little bit of negative in first quarter 2026, but then we make that up in the third and fourth quarter," indicating potential early-year volume headwinds.

Summary

Comstock Resources (NYSE:CRK) reported significant progress on its 2025 operational and financial initiatives, posting a sharp increase in oil and gas sales and adjusted EBITDAX driven by improved natural gas pricing. The company’s balance sheet benefited from $445 million in non-core asset divestitures, substantially enhancing liquidity and reducing leverage. Western Haynesville development accelerated, evidenced by higher initial well productivity, expanded drilling activity, and a new partnership with NextEra to create a data center energy hub. Operational efficiency initiatives led to an 11% year-over-year reduction in drilling and completion costs for legacy assets, although fourth quarter per-foot costs increased temporarily due to complex drilling conditions and shorter laterals. Management reiterated capital allocation flexibility and complete operational control, providing options to swiftly adjust rig count based on market conditions and supporting disciplined growth objectives.

• Cumulative two-year total shareholder return of 162% outperformed all public E&P peers, nearly doubling the next highest rival.
• Pinnacle Gas Services, the wholly owned midstream business, is set to transition to a self-funded, equity-driven structure by mid-2026, with a focus on serving both internal and third-party volumes.
• Data center opportunities are a strategic priority, with the NextEra joint venture potentially scaling power supply from 2 gigawatts to 8 gigawatts to meet hyperscale demand.
• The company maintains a large, undeveloped drilling inventory in both legacy and Western Haynesville, supporting growth ambitions for decades and reinforcing resilience against broader industry M&A dynamics.
• Core analysis data across Western Haynesville wells confirmed "no surprises to the downside," supporting resource estimates used in reserve bookings.
• First-year PDP decline rate moderated slightly from 40% by one or two percentage points compared with the previous year.

Industry glossary

• Haynesville Shale: A prolific natural gas-producing geologic formation primarily located in East Texas and North Louisiana.
• Bossier Shale: A natural gas-bearing formation often associated with and underlying the Haynesville Shale.
• IP rate: Initial production rate—measures the volume of oil or gas produced when a well is first brought online, often stated in cubic feet per day.
• PDP reserves: Proved developed producing reserves—volumes of hydrocarbons that can be recovered from existing wells and infrastructure.
• Pinnacle Gas Services: Comstock’s midstream subsidiary providing gas gathering, treating, and related services in its core operating areas.
• Horseshoe wells: Wells drilled with a U-shaped lateral, targeting additional productive zones inaccessible by straight laterals.
• Frac fleet: A set of hydraulic fracturing equipment deployed for well completion operations.
• Rotary steerable drilling assembly: Advanced drilling tool system providing continuous steering control, increasing drilling efficiency and wellbore quality, especially in challenging geology.
• EUR: Estimated ultimate recovery—total projected volume of hydrocarbons to be recovered from a well or field over its productive life.
• SEC five-year rule: Securities and Exchange Commission regulation restricting booking of proved undeveloped reserves to projects expected to be developed within five years.

Full Conference Call Transcript

If you will 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 27,000,000 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 $1.02 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 $445,000,000 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 have recognized a pretax gain of $292,000,000 on the divestitures. The assets sold consisted of 1,084 producing wells with only 17,000,000 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 total shareholder return along 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 results in the quarter compared to 2024.

Operator: Our natural gas and oil sales grew

Jay Allison: to $365,000,000. We generated $222,000,000 of operating cash flow or $0.75 per share. Adjusted EBITDAX for the quarter was $277,000,000 and we reported adjusted net income of $46,000,000 or $0.16 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 29,000,000 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 25,000,000 cubic feet per day.

In December, we closed on the sale of our Shelby Trough assets in East Texas for total net proceeds of $417,000,000 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?

Roland O. Burns: Thanks, Jay.

Jay Allison: Slide five, we cover the fourth quarter financial results.

Roland O. Burns: Our production in the fourth quarter averaged 1.2 Bcfe per day

Daniel S. Harrison: and our oil and gas sales in the quarter increased 8% to $364,000,000 in the fourth quarter this year despite the lower production number. EBITDAX for the quarter was $277,000,000. We generated $222,000,000 of cash flow in the fourth quarter. We reported a $281,000,000 profit for the quarter or $0.97 per share. Included in that number were some unusual items, including the pretax gain on the asset sales of $294,000,000, a $37,000,000 mark-to-market unrealized gain on our hedge positions, and a $29,000,000 impairment on our nonoperated 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 $46,000,000 for the quarter or $0.16 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. The improved natural gas prices we had in 2025 increased our oil and gas sales by 15% to $1,400,000,000 compared to 2024. EBITDAX for 2025 totaled $1,100,000,000 and we generated $861,000,000 of cash flow last year.

For the year, we reported a $396,000,000 profit or $1.43 per share. That also includes the unusual items, including a pretax gain of $292,000,000 on the 2025 property sales, a $62,000,000 mark-to-market unrealized gain on the hedges, and that $29,000,000 impairment. Excluding these items and exploration expense, related income taxes, we reported adjusted net income of $160,000,000 for 2025 or $0.54 per diluted share compared to a net loss 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.

Twenty-seven percent 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, reflected a $0.26 basis differential compared to the NYMEX settlement price and a $0.29 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 detailed our operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.77 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 $0.01 in the quarter, and our production and ad valorem taxes also decreased by $0.03 in the quarter. That was offset by increases in both our gathering cost and cash G&A cost, which both increased by $0.02 in the quarter.

Operator: Slide nine, we recap our spending on drilling and other development activity.

Daniel S. Harrison: You know, in 2025, we spent a total of $270,000,000 on development activities just in the fourth quarter and $1,055,000,000 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 27,000,000 cubic feet per day. Slide 10, we recap our capitalization at the end of the fourth quarter. We ended the quarter with $260,000,000 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 $2,000,000,000 under the credit facility and with a committed amount of $1,500,000,000. Our last twelve 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 $1,300,000,000 of liquidity. Slide 11, we recap our proved reserves at year-end 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 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 $1,055,000,000 on our drilling program in 2025, giving us the 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 are 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 will now turn it over to Dan to discuss the drilling results we have had.

Operator: Okay. Yeah. Thanks, Roland. On Slide 12, this is an overview of just our latest acreage footprint, you know, 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 have now grown over 535,000 net acres

Jay Allison: On the right is our 267,289 net acres in our legacy Haynesville area.

Operator: We have 30 wells currently producing on our Western Haynesville acreage.

Jay Allison: Which is

Operator: relatively undeveloped compared to our legacy Haynesville. With a higher pay thickness and the pressures we encounter in the Western Haynesville, we will expect the Western Haynesville will yield significantly more resource potential per section than the legacy Haynesville.

Jay Allison: Slide 13 is our updated drilling inventory and our

Operator: legacy Haynesville area, the '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 nonoperated inventory in the legacy Haynesville, we have 839 gross locations and 101 net locations, which comes out to a 12% average working interest.

Jay Allison: Drilling inventory is split into four buckets comprised of

Operator: short laterals, which are less than 5,000; the medium laterals between 5,000 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. So 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.

Jay Allison: The inventory provides us with decades of future drilling locations based on our current activity levels. Over on Slide 14, we show

Operator: 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.

Jay Allison: Our Western Haynesville inventory is more weighted to the Bossier formation. We have nearly two-thirds of our inventory in the Bossier and one-third of the inventory is in the Haynesville.

Operator: 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 8,500 and 10,000 feet, the long laterals between 8,500 and 10,000, and our extra long laterals over 10,000.

Jay Allison: So in our Western Haynesville gross operated inventory, we do not have any current short laterals. We have 1,326 medium laterals.

Operator: 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

Jay Allison: The average lateral lengths were shown separately for both

Operator: legacy Haynesville and our Western Haynesville areas. In the fourth quarter, we drilled 12 wells to total depth in the legacy Haynesville area. 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 Haynesville area still stands 17,409 feet.

Jay Allison: In the fourth quarter, we also drilled

Operator: 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 range from 9,355 feet up to 11,249 feet. Our longest lateral drilled to date in the Western Haynesville is 12,763 feet. And today in Western Haynesville, we have drilled 39 wells to total depth. This includes six wells with laterals over 10,000 feet and six wells with laterals over 12,000 feet. Slide 16 outlines the 35 wells that we have turned to sales

Jay Allison: on our legacy Haynesville acreage in 2025.

Operator: 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 16,000,000 cubic feet per day up to 37,000,000 cubic feet per day, and our average IP was 25,000,000 cubic feet per day.

Jay Allison: 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.

Operator: Since we last reported earnings, we have had four additional wells that have been turned to sales.

Jay Allison: These four wells had an average lateral length of 8,399 feet.

Operator: And an average initial production rate of 29,000,000 cubic feet per day. Four of our nine rigs currently drilling are drilling on the Western Haynesville acreage.

Jay Allison: 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.

Operator: In the legacy Haynesville area, and we averaged 27 days to total depth

Jay Allison: In the fourth quarter, we averaged 893 feet drilled per day on our

Operator: Haynesville acreage.

Jay Allison: Which represents an 11% decrease versus the 2025. The primary reason for the lower drilling rate in the fourth quarter is that we had five of our 12 wells we drilled that were

Operator: located inside the Visonia Gas Storage Field, and all five of these wells necessitate running an additional intermediate casing string on those wells. We also drilled three horseshoe wells in the fourth quarter, and that

Jay Allison: lowers our average drilling rate compared to our normal straight wells.

Operator: Slide 19 highlights our drilling progress in the Western Haynesville.

Jay Allison: 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.

Operator: 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 fourth quarter, which is 3% lower than the third quarter. Aside from any drilling issues, the drilling performance in the Western Haynesville quarter to quarter is mainly

Jay Allison: affected by our vertical depths, temperatures, our lateral lengths. So where the wells are being drilled has a big impact on our drilling performance quarter to quarter.

Daniel S. Harrison: This batch of wells drilled in the fourth quarter were

Jay Allison: 1,000 feet deeper vertically and hotter than the wells drilled in the third quarter while the average lateral lengths were similar.

Daniel S. Harrison: On Slide 20,

Operator: is a summary of our D&C costs through the fourth quarter.

Jay Allison: 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.

Operator: 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.

Jay Allison: The increase in the fourth quarter is the result of a shorter average lateral length

Operator: and for the same reason mentioned on the efficiency slide, where we had five wells within the Visonia 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

Jay Allison: in the fourth quarter is due to a combination of slightly lower frac efficiency,

Operator: coupled with we had a higher average drill-out cost in the fourth quarter.

Jay Allison: Overall, in 2025, we achieved the total drill-and-complete cost of $1,347 per foot, which is one of the lowest in the basin.

Operator: This was 11% lower than our average cost of $1,510 per foot in 2024.

Jay Allison: Last month, we added an additional frac fleet, and we are now running three full-time frac fleets in the legacy Haynesville. This additional frac fleet will be working full time in our

Operator: 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 the rotary steerable drilling assembly in our legacy Haynesville area. We have made great progress to date. As this technology becomes further refined for the high-temperature environment in the Haynesville Shale, we fully expect this

Jay Allison: technology to play a much larger role

Operator: in our future drilling program and make a significant impact on further drilling cost reductions. Slide 21 is the summary of our D&C costs through the fourth quarter for all wells drilled in the Western Haynesville,

Jay Allison: During the fourth quarter, we drilled four wells to total depth, with an average lateral length of 9,944 feet.

Operator: 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 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.

Jay Allison: The fourth quarter completion cost averaged $1,542 a foot.

Operator: 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 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 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 Haynesville rigs upgraded to a 10,000 PSI pressure rating.

Jay Allison: And that will be available to us by late summer.

Operator: With this upgrade, we will be able to increase our drilling speeds in both the vertical and horizontal hole sections, significantly reducing our cost. 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 are also investing to upgrade one of our existing frac fleets to a 20,000 PSI rating.

Jay Allison: Along with the frac stacks, which will lead to improved frac stimulations as

Operator: 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 will be able to cut drill times by two weeks and reduce our drilling cost by another $300 a foot on top of our earlier cost reductions we have made to date.

Jay Allison: 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 build out 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 at 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 are also working to recapitalize our Western Haynesville midstream, 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 cost in 2026 in both the Western and legacy Haynesville areas. And lastly, we continue to have strong financial liquidity of $1,300,000,000, 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 landmen, we now own 20,000 leases covering 535,000 net acres in our Western Haynesville. The legacy Haynesville play, which was discovered in 2008, covers approximately 4,000,000 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 estimate 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 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 Services midstream company we own is also a success which services our new play. We are excited about the progress we are making reducing well cost 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 include applying rotary steerable drilling assembly technology that we are having great results with in our legacy Haynesville horseshoe wells that we are 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 slide provides guidance for 2026, which Ron can discuss with you directly.

For the rest of the call, we will take questions from analysts who follow the company.

Daniel S. Harrison: I will turn it back over.

Jay Allison: Thank you.

Operator: As a reminder, to ask a question, please press *11 on your telephone. Wait for your name to be announced. In the interest of time, we ask that you please limit yourself to one question and one follow-up. Our first question comes from Derrick Lee Whitfield with Texas Capital. Your line is open.

Derrick Lee Whitfield: Good morning, guys, and thanks for your time. Thank you. Maybe to start with guidance because that seems to be the focal point

Daniel S. Harrison: for investors.

Derrick Lee Whitfield: Is it fair to say that the budget was put together in a

Daniel S. Harrison: more constructive gas environment? And when it comes time to spend the capital,

Derrick Lee Whitfield: if the price is not there, the capital will not be there either. And maybe just to build onto that,

Roland O. Burns: 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 Haynesville has faster cycle times, and there is likely some friction from 1Q that will bleed into Q2 as well. Maybe if you could offer any color on cadence of production, that would be helpful as well.

Daniel S. Harrison: Yeah. Sure, Derrick. You know, it has been, you know, first, gas prices have been all over the board since Thanksgiving and then had a huge rally there, then you had a fairly warm December, January, then you had a cold second half of January. And so it has been a, you know, we have actually had two great index prices for January and February gas that are extraordinary. But, obviously, gas prices have been everywhere, and that is not unexpected. We expected this to be a very volatile year for gas prices given the new demand that is coming on and the difficulty in trying to match supply to demand.

And so weather has played a major role in whether gas is considered undersupplied or oversupplied and probably will continue to play that role throughout the year. And, obviously, we have, you know, we did want to get enough frac equipment and drilling rigs that we could execute a good program for 2026 in place and then running well. We always run the equipment in the legacy Haynesville before moving it to the Western Haynesville. So we put that in place for this year. But, obviously, if gas prices disappoint, we have as many as four rigs that we could with short notice take out of action. And the same thing with the frac crew.

So we always have the ability to flex our drilling budget based on how things come out. But I think overall, given we did sell a lot of properties to finish out last year, sold some production, we did want to invest back in the properties, build the production levels up, and we think that is the best way to get 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, you know, noisy,

Roland O. Burns: first

Daniel S. Harrison: 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 frac crews during most of the winter storm. But, generally, I think we have a very exciting year planned for 2026, we think.

Jay Allison: Well, Derrick, it is very flexible. If we want to get rid of one, two, or three of our drilling rigs, we could on notice, probably four to five-day notice. It is very, very flexible. We have quality drilling contractors. We have a quality group of fracking companies. And as Dan has said, I think we are going to get better and better and better on our drilling completion times in Western Haynesville. In 2025, as the year went along, we ended up with four rigs in the Western Haynesville. So if you look at 2026, I think it will 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 3%, 4%, 5% growth every year, and we were negative 14% last year. So we come in a little bit of negative in first quarter 2026, but then we make that up in the third and fourth quarter. And if you do look at this gas demand, we believe on a yearly basis, the demand is going to grow about 3 Bcf every year between now to 2030. That is 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 did not give up a lot of production—now we gave up a little bit—and we paid down our borrowing base or our credit facility, we do have a little bit more flexibility to lean into 2026 earlier. And that is what we are doing. I look at these, all these E&P companies, they really are searching for tomorrow's drilling inventory. And you really to a question is, what does your tomorrow look like? Well, most of these are looking for tomorrow's drilling inventory. They are searching across the globe.

Look at the Wall Street Journal yesterday. They are 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, Derrick, that is exactly where we are. We are just trying to manage this potential 50 Tcfe of upside in Western Haynesville, again, on the decades to come, to bring that to fruition to show everybody what we are trying to do. Our tomorrow, we are looking at today. So we are just trying to de-risk it and deliver it.

Roland O. Burns: Great, Jay. And I will 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 2 gigawatts you hope to commercialize in 2026 to the 8 gigawatts it could be? And then how should we think about the price and or cost advantage of selling to NextEra versus traditional marketing?

Jay Allison: Well, my, I think my comment with that, without getting into granularity, 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 is good to be in Texas now. You always have to be in an area where there are people to hire. If you build 8 gigawatts, you might be building a city of 20,000 people. So you have to have location, but you have to have water. You want water.

If you look where we are, we are 100 miles from Dallas, 100 miles from Houston, and you have to have an airport where you get in and out, in and out. So all we have done is we said, we have untapped what we call the basin. I think we control a new basin, not some acreage in the legacy area, but we control a basin is how we look at it. That is how we are developing it. And we were developing it based upon how the legacy was developed and some of that value was not captured because of what was happening during 2008/2009/2010/2011.

So as we look at that and we look at NextEra—and NextEra, we have been partners with for ten 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 are taking those next steps hand in hand with them, or we would not be discussing it. But you start out with 2 gigawatts, and then they said at their analyst meeting that they would like to ratchet up to 8 gigawatts if that is 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 do not own their midstream. That is why they have to deal with midstream companies that have upstream companies’ gas. So we are trying to capture both of it.

Operator: Thank you. Our next question comes from

Roland Eugene Mills: Khoi

Operator: Akamine 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. 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 is sufficient to on the scope of your midterm ambitions?

Daniel S. Harrison: Yeah. That is a good question. We have kind of put in place a plan to recapitalize Pinnacle now that it is ready to make the next step as it has got a really great future ahead of it, starting to generate much more significant EBITDAX, which probably people are not really expecting because it just has not had it in the past. But it is ready to move on from the development capital that our partners put in, and they have given us an opportunity to redeem them. And so that is the plan we put in place, including the new credit facility.

We also have an initiative here that we are going to sell common equity in the midstream company, and that is how we plan to eliminate the preferred equity that has a dividend that is pretty

Roland O. Burns: expensive.

Daniel S. Harrison: And so now that cash flow that before was mainly going out of the company to our partner will be able to be available to fund its CapEx, also have its own low-cost credit facility now that 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 by May.

Jay Allison: Rolling to all that. Positive move

Jay Allison: 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 more K. And then now it has 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. And remember, some of these gas will go to serve the data center demand, 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? Then can you kind of talk about the timing rationale for the Marquet expansion?

Operator: Is that being motivated by the NextEra data center project timing? In which case utilization of that plant does not increase until the data center project is online?

Daniel S. Harrison: Yeah. With the Marquet plant, which is being, we think it is going to be operational sometime this summer. Again, as a midstream provider, you have to have these assets up before the production there. Otherwise, it is holding up things. So 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 probably finish the recapitalization, a lot of our heavy CapEx will be behind us. And I think you will see the entity well positioned to fund itself and still keep a low leverage profile with its own credit facility.

Jay Allison: And I think the audience that will look at the Pinnacle system as an equity investor, I think what they will do is they will 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. So we will find out.

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

Roland O. Burns: Good morning. Thank you for having me on today. This one is perhaps for Dan.

Operator: Dan,

Daniel S. Harrison: might be a little bit unfair because you had a tremendous

Roland O. Burns: program for the Western Haynesville throughout the year. But if I cherry pick one of your latest wells, the Brown TrueHeart B, that well looks like it, the IP rate basis, slightly underperformed the broader group. And I know it is normal for you to assume that you will 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 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.

Jay Allison: Yeah. So

Operator: Brown TrueHeart well was, if you look

Jay Allison: on the acreage map, it is the furthest one that we have, as we have kind of fanned out and drilled more to the northeast, it is kind of on that

Operator: not the far northeast end where the Elijah One, but the farthest northeast of that trend of wells we have 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-well pads. And just because of the geology, if you are drilling south, you are going down dip, and if you are drilling north, you are going up dip. So this well, I think it is basically, it is 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 is more difficult just to get a good IP rate even though the wells are still really good. And that is what happened on this well. The downdip well, right off the same pad, we IPed it at 30,000,000 a day, and this one was 22. Only difference between the two wells was this one was making more water during the flowback period. Thank you. That is very helpful.

Roland O. Burns: And then my follow-up, this one is for you, Jay, and Roland.

Jay Allison: The

Roland O. Burns: M&A market in the Haynesville last year was pretty hot, and you saw

Operator: deals that implied pretty high dollars per location across the board.

Roland O. Burns: 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?

Jay Allison: You know, I think, Carlos, I think we are just me. And, 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 are sitting 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 the U.S. is the largest exporter of our gas in the world. It is only going to get bigger and bigger and bigger. As you know, I mean, the Chenieres, etcetera, etcetera, they are all adding. Their venture doubles are adding.

The data centers are adding. So I think to answer your question, our business plan is to show what our Western Haynesville might be. And the way we do that is we talk about 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 is your quality drilling locations. And I think we have that not only in our core, but our core, you would not buy that, but you would buy that at the Western Haynesville area.

Because I do not know of any company our size or remotely our size that has 2,561 locations that are almost all of that undedicated. So our goal—and Jerry Jones is the master plan behind this—is to 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 to all the good and the bad. And if we needed to add a rig, which I think that is the only negative, truly, in the call is we added a rig. That is $150,000,000 to $170,000,000 as we use per rig per year.

But that is to what? It is to continue to shore up our legacy and then add to the Western Haynesville performance. We are not looking for inventory. They are looking for inventory. We are looking to develop what we own now, and we have got a great amount of gas. So that, and always, you always want to be the beauty queen. It is like the Olympics. We do not want a silver or

Daniel S. Harrison: or a bronze medal. That would be great to be up there. That would be great.

Jay Allison: But if you are going to go out there, you are 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 is exactly what we hope that we have been doing for decade after decade at Comstock. We have never deviated from who we are. We have kept our same name. We have kept true, and the Jerry Jones of the world came in and said, I am behind you. I want to go with you. Let us develop this. And you know what? We will see where the value comes.

We will see where it comes from.

Operator: Thank you. Our next question comes from Charles Arthur Meade with Johnson Rice. Your line is open. Good morning, Jay, Roland and Dan and to the rest of the Comstock team there.

Roland O. Burns: Dan, in response to the earlier question about the Brown TrueHeart B, I wanted to ask one more question on your response there. Can you tell whether the water you are

Daniel S. Harrison: producing there is, is that completion water, or is that formation water? And could it be related to the azimuth of that well and whether you are toe up versus toe down? Is there any—what is your thought process there?

Operator: Well, that is a really good question. I do not think anytime these—you know, we have had several wells in the core that will make hot water in the very beginning. And when we do make hot water in the beginning, it is hard to get a good peak rate until that water comes off. But I do not know of any really shale well that I can remember that we have made formation water. There is no formation water. It is all load water

Jay Allison: coming back

Operator: from what you fracked. And there have not on the Brown TrueHeart, but in other areas in the past, there have been discussions when we have had hot water about did the frac orientation change

Jay Allison: along the wellbore?

Operator: Instead of being perpendicular to the lateral from the toe to the heel, 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. Now

Jay Allison: that is possible on the Brown TrueHeart,

Operator: we do not think that is what is happening on the Brown TrueHeart. I think this is probably the second well—we have only had a few wells that have drilled up dip. This well was drilled up dip.

Jay Allison: And it could be that, or it could be a geometry thing, just how much they make on flowback

Operator: when you drill uphill versus drilling downhill. Like I said, this was a two-well pad. We had the down dip

Jay Allison: well IPed at over 30,000,000 a day. And this one, we IPed it at 22,000,000 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 is not good for the well. Well, when you fight gravity, you drill up dip and you are 1,000 feet shorter, the Brown than the Brown TrueHeart W number one, 1,000 feet shorter, you are up dip, and you fight gravity. Water

Operator: was going to flow down.

Jay Allison: So we IPed around 22 and the other one at 32. And all these wells where we have

Operator: instances where the water is high up front, what happens is it comes down over time, but it is after you have IPed the well and you are off 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.

Phillips Johnston: Right. That is 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 Ts that you added with your drilling program this year. That is a big number. And I guess we will get some more details 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 adds, how much of it was PUDs, and I think three-quarters of your wells in '25 were legacy, a quarter were Western Haynesville, but what is the ratio of those reserve adds, whether that versus legacy versus Western Haynesville?

Daniel S. Harrison: Yeah. I do not know if we have all those exact stats for you. Ron would probably have to work on that for you. But, basically, there was definitely some good growth in the PDP reserves. But you also had kind of a situational change here. You are looking at coming off of—we have added additional drilling rigs. So basically, in the next five years, we have 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 is still a lot of—yeah, we have got 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. So a lot of it is just extensions, because obviously we were able to book in the Western Haynesville as we had some new wells so we can have offsets to those. So it is a combination of all those things that

Operator: that

Roland O. Burns: that

Daniel S. Harrison: 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.

Jay Allison: Remember in 2024, our finding costs were $1.00. In 2025, they are $1.02. Went up two cents, but I think there were probably better adds this year than in '24.

Daniel S. Harrison: 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. So that is not reserves that got put back on the books because of improvement in gas prices. That you would see in our SEC reserves, which had tremendous amount of additions because a lot of reserves

Roland O. Burns: left, you know, left the SEC case and came back. Those are true,

Daniel S. Harrison: Yeah. That number, the 1.1 Ts, is true additions that are related to drilling activity, not to prices moving around.

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

Roland O. Burns: Yeah. Hi. It is actually Leo Mariani here from ROTH. Wanted to just touch base a little bit more on the Pinnacle deal here. So

Greta Drefke: wanted to just kind of get a sense from you folks. It looks like you are trying to replace, you know, 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 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 is not going to be completing or sort of contributing any capital for the next several months? 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.

Daniel S. Harrison: Yeah. We just have an opportunity to replace Quantum. And we are going to do that, and we just started this process, so we cannot give you a lot of details yet because it just started. But it is 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 it will 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 that 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 until it grew up and had the credit stats to deserve that, which it has now. And we will probably have that in place first, and then hopefully complete an equity sale to allow us to do the full redemption this summer.

Greta Drefke: Okay. No. That is helpful. Then just with respect to Pinnacle, I presume there is probably no debt on that entity right now at the moment. And then just additionally, do you expect Pinnacle to be free cash flow positive, maybe next year or something like that? Can you just give us any color in terms of where it is in its life cycle from a cash flow perspective?

Daniel S. Harrison: 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

Operator: you know,

Daniel S. Harrison: putting in the treating plants is a really large capital expenditure that it has had. So as we get to that with Marquet Train 2 coming in, we will have over a Bcf a day of treating capacity. So we will be well positioned to where we will only be just spending money on well connections. So that is 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 the need for the capital infusions like Quantum made last year should not be there.

And so it is just because it has made those before it had a revenue stream. Now it has one.

Operator: Thank you. Our next question comes from Kevin MacCurdy with Pickering Energy Partners. Your line is open.

Roland O. Burns: Hey, great. Thank you for taking my question. Wanted to ask you about the production trajectory throughout the year.

Operator: I know you will not have any turn-in-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 nine rigs this year?

Daniel S. Harrison: Well, we put out the guidance that we like to put out, so we do not really—exit rates are interesting, but they are also so dependent on timing that a well could come online a week later and be in January versus December. So given that our capital program—big wells—and they come on in usually groups of two to three, so the timing of their production is really critical to one day’s production. So I think, generally,

Operator: I think what I would add to that is

Daniel S. Harrison: we will see

Operator: quite significant growth over the course of the year just based on our

Kevin MacCurdy: well

Operator: completion schedule. We only have five wells turning to sales here in the first quarter.

Greta Drefke: That means over the remainder of

Operator: 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

Kevin MacCurdy: strong kind of fourth quarter rate.

Greta Drefke: Historically, what we had said

Kevin MacCurdy: on the eight-rig program that we could, by the fourth quarter, get back to kind of the '24 type levels.

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

Kevin MacCurdy: It is just the capital lag versus production. Thank you. I appreciate that. I think that helps.

Operator: 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 cost.

Greta Drefke: Do you have any

Operator: color on what the lateral lengths will look like going forward in 2026? And have you guys kind of decided on what the long-term goal should be for lateral lengths in that play? Well, I will say the long-term goal is obviously to be longer. A lot of our sticks are controlled by the geology, and you are dead on—when we have an average shorter

Jay Allison: lateral length in any one quarter, it definitely leads to a higher cost. And,

Operator: we have got, like I said, we have got six that we have drilled over 12,000 feet long, but we also have several that are on the short end. I think the shortest one is about 7,800 feet that we have done to date. But we do have, here in the very near future, we are going to be

Roland O. Burns: drilling

Operator: towards our first—targeting our first 15,000-foot lateral. And we think we are going to be successful there. So I think the average is definitely going to be longer than where we have been if you look backwards on the average lateral length. So as long as the geology—we are in areas where we do not have to stop short due to a fault or something of that nature, we will definitely be longer in the future. I think the rotary steerable that we have got that has been working good for us in the core that we are going to deploy down here,

Roland O. Burns: and the 10K rig upgrade—we have got just the one rig we are upgrading right now—

Operator: those things are going to definitely help us get longer on the laterals.

Greta Drefke: Thank you. Our next

Operator: question comes from Jacob Phillip Roberts with TPH and Co. Your line is open.

Daniel S. Harrison: Good morning.

Jay Allison: Good morning.

Operator: I do not 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. So I am just wondering if you could talk a little bit about this dynamic. And then maybe if you could remind us what EUR you are expecting or underwriting across the Western Haynesville at the moment?

Jay Allison: So the last—as far as, you know, we have made an effort to

Operator: basically control our drawdowns a lot more than we did in the very beginning.

Jay Allison: We are not looking—you know, all these wells can be IPed at what we want to be IPed at. We like to get them up to about a 30,000,000 to 35,000,000 range and IP them there. But all of these wells are capable of IPing at over 40,000,000 a day if we want

Operator: to, but we do not want to pull the wells that hard.

Jay Allison: So I would not read a lot into that, just the

Operator: IP rate on a length-adjusted basis. I think that is part of what you are seeing there is just how we are flowing the wells back. But,

Jay Allison: I think as we fan out across the acreage, we are going to see a little bit

Operator: of different performance in different areas. And so, we still have some of the acreage that we have not drilled on yet. We are going to be drilling more wells this year up on the northeast end by the Elijah One. And I think all the offset wells for that one up there will resemble that well.

Jay Allison: Which had a good IP. Could have been a lot better IP, but

Operator: so I think that is going to ebb and flow. I would not read a lot into that as far as any kind of a trend.

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

Operator: Yeah. So we have cored—we have zeroed four pilot holes to date, we have cored three of those. All of the cores look great, and we are—no surprises to the downside on any of the core work that we have done. It fully supports the resource estimates that we have 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 are landed.

Where 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 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 closer to where we want them and not forsake that maybe to drill a lot faster.

So that is day to day, that is just a balance for us, where we want the well to be and how fast we are trying to drill the well.

Daniel S. Harrison: And the cores tell us now really where we should land these laterals, so we did not have that data before. That is right.

Jay Allison: And we have got one core—we just

Operator: cored a well up on the northeast end of the field by the Elijah One that the rig is on now.

Jay Allison: And our other two cores are back down towards the

Operator: 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 are various factors that might have impacted production or production reporting last year. But it looks like there is 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, if you just look across the entire area up there, all operators—I mean, there has obviously been some small amount of degradation as the basin has been filled in. There have been thousands and thousands of wells drilled. Everybody drills their—Plus, as the gas prices pick up, I think you see more people starting to drill in maybe some even some of the lower type curve areas. With the higher pricing, those become a lot more economic. I think we will see on our side, I think we will see maybe a little bit movement back in the other direction now that we are drilling a lot more of these horseshoe wells.

Because a lot of the horseshoe wells, from a lot of our stranded short laterals, were in our better type curve areas. So once we kind of went the horseshoe route and they have been looking great for us, we have drilled—we have got 10 of those TD to date. Going really good. And the performance on those has been better just because they are in the better type curve areas. So like I said, it has been a natural degradation, I think, just for the whole basin, basin-wide, on how the laterals are drilled. So I would say next year flat kind of to this past year where we are.

Well, if you can add a rig and drill, you know, like 115 gross horseshoe wells, 50/50 Haynesville/Bossier—which we will drill 16, I think, this year—but let us say you use that rig and you say, well, I am just going to drill horseshoe wells. Remember, like Dan said, those are 2.0, 2.1 B’s per thousand. Those are really, really good locations except they were shorter laterals. So 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. So that is one reason we found a rig and added it earlier on. Thank you.

Our next question comes from Paul Michael Diamond with Citi. Your line is open. Thank you. Good morning, all. Thanks for taking the call.

Daniel S. Harrison: Just wanted to touch base on—you have not talked a lot about the delineation over the last few between Western Haynesville and the core. Then some of the noncore asset sales. I guess, is there anything on the horizon that would kind of shift more of the legacy core into that noncore category in which you would be potentially looking to monetize? Or would the deals towards the end of last year be more one-offs?

Operator: Yeah. We do not have any current plans to divest any properties. But we obviously react to

Daniel S. Harrison: people coming to us or react to

Roland O. Burns: activity in the areas, though. But there is no planned divestitures for 2026.

Operator: Yeah. We look at that, and Shelby was kind of dangling out there, and we had

Daniel S. Harrison: 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, which also proves that we trust what we have been de-risking in the Western Haynesville.

Daniel S. Harrison: Understood. Appreciate the clarity. And then just talk a bit about the other improvements in the capital, whether it is rotary steering, high-pressure apparatus, or other efficiency routes. You talked 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?

Operator: Yes, that is a good question. So all the operators in the core, I would just say, really, this rotary steerable started—the vendors have been putting R&D dollars into the rotary steerable systems for the Haynesville. They are used extensively in all the other basins because they are lower temperature. Not really in the Western Haynesville till, say, the last half of '25. We have had probably 10 runs to date with that system so far, and that has really made good progress.

The vendors, they are tweaking their tools, and as far as deploying it to the Western Haynesville, I am going to say sometime here within the next three months we will be making our first run in the Western Haynesville. We are going to make—we do plan to make several runs in the Western Haynesville over this year. As far as the full cost savings, I think we will get pretty immediate cost savings when we get our first 10K rig in place late this summer.

The rotary steerable I think will be more a little bit more of a gradual increase as far as the realized savings on that system, but hopefully this time next year we can be achieving this two weeks reduction in drill times from where we are at today on average. The vendors are super interested. They are putting a lot of money in the R&D for these tools. All the operators are trying to—they are running the tools in the core. So we have looked at all the numbers and very doable in the Western Haynesville. I think once we see some success early on in the Western Haynesville, we will be pushing to get the temperature rating on that

Jay Allison: tool

Operator: even higher. And I think that may be deeper into next year as far as having, say, a 392-degree-rated rotary steerable tool. But, like I said, if we just can repeat in the first half of our Western Haynesville laterals with what we have seen in the core, we are going to definitely cut off a lot of days.

Jay Allison: Thank you.

Phillips Johnston: And our final question comes from Phillips Johnston with

Phillips Johnston: Capital One. Your line is open. Hey, thanks for the time. 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? And then maybe talk about how that compares to the legacy Haynesville.

Roland O. Burns: Yeah. I am not sure why you referenced Lee Keeling. Our reserves are audited by Netherland, Sewell & Associates. Leo. Got it. They have—Phillips. Yeah. So the Western Haynesville, basically, I think the overall average reserve EURs are probably—they do range from anywhere from 3 B’s per thousand foot of lateral to 4 B’s 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, 3.5 is a good average for the Western Haynesville. So

Phillips Johnston: Okay. Sounds good.

Jay Allison: Yeah.

Phillips Johnston: Sorry about that. I have forgot it was Netherland, Sewell. Just one more on the reserve report. What is sort of the implied next twelve-month PDP decline rate in your report, and how does that maybe compare to the decline rate in your year-end '24 report? It has actually come down a little bit. It is from 40%, it is down like one 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 are starting to see that.

It is 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.

Operator: Jay, 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 have got to have inventory.

Phillips Johnston: And if you just look at these numbers in the legacy Haynesville, which is 4,000,000 acres, has produced 48.5 T’s

Operator: from 7,600 wells, and we think

Phillips Johnston: Comstock is exposed to 50 T’s. Well, that is more than has been produced from the legacy Haynesville.

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

Phillips Johnston: Yeah. Because they have a lot of work built in for decades if they can do that.

Operator: And they are spending their own money doing it. So they not only believe what we are doing, we believe what we are 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

Phillips Johnston: and it is accurate.

Operator: So we are thankful. We are fortunate that we captured that footprint, and I think that goes back to toggling. As I visit with Jerry, we will toggle stuff. 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. So you do it in '25, kind of like what Dan is doing with these rotary steerables. You

Phillips Johnston: accelerate it

Operator: and go into the Western Haynesville. And then if the opportunity comes where we should divest something in the core that we will not drill for years, but somebody else would drill now, and you can both win, you toggle that. So that is what we have been doing, and that is 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 are going to try to give you good news when it is there. And if something is not there, we will always tell you the truth. It is a pretty good world we live in.

Thank you. Thank you. This concludes today’s conference call.

Phillips Johnston: Thank you for participating. You may now disconnect.

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