Q1 2024 Comstock Resources Inc Earnings Call

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Operator: Good day, and thank you for standing by. Welcome to the Comstock Resources Inc. First Quarter 2024 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 11 on your telephone. You will then hear an automated message advising that your hand is raised. To withdraw your question, please press star 11 again. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chief Executive Officer. Please go ahead.

Good day and thank you for standing by welcome to the Comstock Resources, Inc. First quarter 'twenty 'twenty four 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.

Operator: To ask a question during the session you will need to press star one on your telephone.

Operator: Didn't hear an automated message advising your hand is raised.

Operator: Charter question. Please press star one again please.

Operator: Please be advised that today's conference is being recorded.

Operator: I'd now like to hand, the conference over to your first speaker today, Jay Allison Chief Executive Officer. Please go ahead.

Miles Jay Allison: Thank you. This is the Comstock Resources first quarter 2024 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 First Quarter 2024 Results. I'm Jay Allison, Chief Executive Officer of Comstock, and 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 Investment Relations.

Miles Jay Allison: Thank you. Thank you.

Miles Jay Allison: Welcome to the Comstock resources first quarter, 'twenty, 'twenty, four financial and operating results conference call.

Miles Jay Allison: A slide presentation during or after this call by going to our website at Www, Comstock Resources' dotcom and downloading the quarterly results presentation.

Miles Jay Allison: You'll find a presentation entitled first quarter 2020 core results.

Miles Jay Allison: Jay Allison Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating officer, and Ron Bills, our VP of Finance Investor Relations.

Miles Jay Allison: Please refer to slide two of our presentations and note that our discussion today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Miles Jay Allison: Please refer to slide two in our presentations and note that our discussion today will include forward looking statements within the meaning of securities laws, while we believe the expectations of such statements to be reasonable there can be no assurance that such expectations will prove to be correct.

Miles Jay Allison: If you would turn to slide three.

Miles Jay Allison: If you would, turn to slide three. You know, our corporate team of 255 strong wants to thank you for joining the call today. We've been very active over the last 100 days, with all hands focused on continuing to batten down the hatches in order to manage our assets and continue to create value during this week-long period for natural gas. Actions and achievements in the last 100 days have involved many of our stakeholders, including our bondholders, our bank group, our major stakeholder, Jerry Jones, and our service providers.

Miles Jay Allison: Our corporate team of 255 from <unk> to thank you for joining the call today.

Miles Jay Allison: We've been very active over the last 100 days with all hands are focused.

Miles Jay Allison: January to batten down the hatches in order to manage our assets and continuing to create value. During this weak period for natural gas.

Miles Jay Allison: Our actions and achievements in the last 100 days have involved many of our stakeholders.

Miles Jay Allison: Putting our bondholders our bank groups are major stakeholder, Jerry Jones, and our service providers.

Miles Jay Allison: On March 15th, we closed on an acquisition that enabled us to add 198,000 net acres to our Western Haynesville plate, which was substantially held by production, so we do not have to increase our drilling activity in order to retain the acreage. In the quarter, we turned four new Western Haynesville wells into sales, and each one looks fantastic.

Miles Jay Allison: On March 15th we closed on an acquisition that enabled us to add 198000 net acres to our western Haynesville plays which were substantially held by production. So we do not have to increase our drilling activity in order to retain the acreage and the quarter, we turn border Western Haynesville wells to sales.

Miles Jay Allison: We're now drilling on two well pads, which will reduce our cost, and we recently also reduced our drilling days to 54. Dan Harrison will give a full report on our progress on the 450,000 net acre plate later in the call. On March 25th, the Jones family purchased an additional $100.5 million in Comstock stock that demonstrated their confidence in our business plan, including the Western Haynesville acreage acquisition. On April 2nd, our bondholders stepped up in our $400 million new senior notes offering. The bonds were priced tighter to Treasuries than any of our other bonds that we have issued since 1999.

Miles Jay Allison: H, one looks fantastic, we're now drilling two well pads, which will reduce our cost and we recently also reduced our drilling days to 54, Dan Harrison will go forward on our progress on the 450000 net acre place later in the call on.

Miles Jay Allison: On March 28, the Jones family purchase an additional $145 million of Comstock stock that demonstrated their confidence in our business plan, including the western Haynesville acreage acquisition.

Miles Jay Allison: April the second our bondholders stepped up and our $400 million, new senior notes offering the bonds were priced tighter to treasuries than any of our other bonds that we issued since 1999.

Miles Jay Allison: Then, on April 30th, our bank lending group reaffirmed our borrowing base of $2 billion with a $1.5 billion commitment that has allowed us now to have $1.3 billion of liquidity. With the demand for natural gas growing in the future to service increased power generation, industrial, and LNG demand, as well as future demand to power AI, we're well positioned to deliver clean, responsibly produced natural gas from our 800,000 net acres in the Haynesville.

Miles Jay Allison: Then on April 30th.

Miles Jay Allison: Bank lending group reaffirmed our borrowing base of $2 billion with a $1 $5 billion committed but that has allowed us now to have $1 3 billion of liquidity.

Miles Jay Allison: With the demand for natural gas growing into the future to service increased power generation industrial.

Miles Jay Allison: LNG demand as well as future demand for power.

Miles Jay Allison: We are well positioned to deliver clean responsible produced natural gas from our 800000 net acres in the Haynesville Ola.

Miles Jay Allison: We have over 30 years of billing inventory, which we are adding to as we unlock value in our 450,000 net acres in western Haynesville, one well at a time. I want to thank you for supporting your company, Comstock Resources. On slide three, we'll summarize the highlights of the first quarter.

Miles Jay Allison: We have over 30 years of drilling inventory, which we are adding too as we unlock value in our 450000 net acres in the western Haynesville, one well at a time or to thank you for supporting your cap rate Comstock resources on slide three we will summarize the highlights of the first quarter.

Miles Jay Allison: The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and gas sales, including hedging, were $336 million in the quarter, and we generated cash flow from operations of $182 million, or $0.65 per share, and adjusted EBITDAX was $230 million. Our adjusted net loss was $0.03 per share for the quarter.

Miles Jay Allison: The financial results continued to be heavily impacted by the continued weak natural gas prices oil and gas sales, including hedging where $336 million in the quarter and we generated cash flow from operations of $182 million or <unk> 65 per share.

Miles Jay Allison: And adjusted EBITDAX was $230 million, our adjusted net loss was <unk> <unk> per share for the quarter to strengthen our balance sheet, we added $105 million to our liquidity with a private placement of equity with our major stockholder, Jerry Jones will continue to have strong.

Miles Jay Allison: To strengthen our balance sheet, we added $100.5 million to our liquidity with a private placement of equity with our major stockholder, Jerry Jones. We continue to have strong results from our drilling program. In the first quarter, we drilled 16 successful operated Haynesville and Bossier Shell horizontal wells in the quarter, with an average lateral length of 9,845 feet, and we turned on 18 successful operated Haynesville and Bossier Shell horizontal wells with an average IP rate of 27 million cubic feet per day and an average lateral length of 9,227 feet.

Miles Jay Allison: <unk> results from our drilling program in the first quarter, we drilled six chain successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of that 845 feet and we turned to sales 18 successful operated haynesville and Bossier shale horizontal wells.

Miles Jay Allison: <unk> with an average IP rate of 27 million cubic feet per day at an average lateral length of 909.

Miles Jay Allison: 100, <unk> thousand 227 feet, we're continuing to progress in our western Haynesville extra for exploratory play we added 198000 net acres to our expansive western haynesville acreage position in the first quarter, increasing our total acreage position in the play to over 450000 net acres.

Miles Jay Allison: We're continuing to progress in our Western Angel Exploratory play. We added 198,000 net acres to our expensive Western Angel acreage position in the first quarter, increasing our total acreage position in the play to over 450,000 net acres. Since we last reported earnings, we have turned four additional wells to shales in the western Hainesville and now have 12 successful wells in our new plate. The Glass, Farley, Harrison, and Ingram-Mark wells were all completed in the Hainesville shale, and each had IP rates of 35 to 38 million cubic feet per day.

Miles Jay Allison: Since we last reported earnings we acquired four additional wells to sales in the Western Haynesville and now have 12 successful wells in our <unk> play the glass Farley Harrison at anchor Mark Wells were all completed in the Haynesville shale and <unk> had IP rates of 35% to 38 million cubic feet per day were current.

Miles Jay Allison: We currently have two rigs running on the plate, both of which are drilling on two well pads. We continue to lower our cost to drill these wells, and on our last well, we were able to reduce the drilling days to 54 days.

Miles Jay Allison: We have two rigs running into play both of which are drilling a two well pads, where continued to lower our cost to drill. These wells at our last 12 were able to reduce the drilling days to 54 days.

Miles Jay Allison: I'll now have Roland go over the first quarter financial results. Roland? All right. Thanks.

Miles Jay Allison: Now have Roland go over the first quarter financial result, prevalent alright. Thanks, Thanks Jay.

Roland O. Burns: All right, thanks. Thanks, Jay.

Roland O. Burns: On slide four, we cover our first quarter financial results. Our production in the quarter of 1.5 BCFE per day increased 10% from the first quarter of 2023. The low natural gas prices resulted in our oil and gas sales in the quarter of $336 million, declining 14% from 2023's first quarter level, despite the 10% production increase. EBITDAX for the quarter was $230 million, and we generated $182 million of cash flow during the first quarter.

Roland O. Burns: Slide four we cover our first quarter financial results our production in the quarter of one five Bcf per day increased 10% from the first quarter of 2023.

Roland O. Burns: The low natural gas prices resulted in our oil and gas sales in the quarter of $336 million declining 14%.

Roland O. Burns: 2020, Three's first quarter level, despite the 10% production increase.

Roland O. Burns: EBITDAX for the quarter was $230 million and we generated $182 million of cash flow during the first quarter.

Roland O. Burns: We reported an adjusted net loss of $8.5 million for the first quarter on 3 cents per share as compared to income of $92 million in the first quarter of 2023. In Plot 5, we kind of break down our natural gas price realization in the quarter. During the first quarter, the quarterly NIMAC sell price averaged $2.24, which was 17 cents lower than the average Henry Hebb spot price in the quarter of daily prices of $2.41.

Roland O. Burns: We reported an adjusted net loss of $8 5 million for the first quarter, our <unk> per share as compared to income of $92 million in the first quarter of 2023.

Roland O. Burns: Slide five we kind of breakdown.

Roland O. Burns: Natural gas price realization in the quarter for.

Roland O. Burns: During the first quarter that correlate Nymex settlement price averaged $2 24, which was <unk> 17 cents lower than the average Henry hub spot price in the quarter or the daily price of $2 41.

Roland O. Burns: Our realized gas price during the first quarter averaged $2.06, reflecting an $0.18 differential to the settlement price and a $0.23 differential to our reference price. In the first quarter, we were 26% hedged, so this improved our real odds price in the quarter to $2.40. In the voluntary quarter, we also lost $800,000 on our third-party marketing activities.

Roland O. Burns: Our realized gas price during the first quarter averaged $2 <unk>.

Roland O. Burns: Reflecting a <unk> <unk> differential to the settlement price and at 23 differential to our reference price.

Roland O. Burns: In the first quarter, we were at 26% hedged. So this improved our realized price in the quarter to $2 40, and the volatile quarter. We also lost $800000 in our third party marketing activities.

Roland O. Burns: Slide six is an update on our hedge position. Since we last reported, we've been very busy adding some hedges to kind of build out our hedge positions for next year in 2026, as well as improving the amount that we've hedged for the fourth quarter of this year. We added 300 million a day of swaps covering the period from April, I mean, October 2024 through December 2026 at an average price of $3.51 for MCF.

Roland O. Burns: Slide six we update our hedge position.

Roland O. Burns: Since we last reported we've been very busy adding some hedges.

Roland O. Burns: Build out our hedge positions for next year in 2020, as well as improving our.

Roland O. Burns: Matt that we've hedged for the fourth quarter of this year.

Roland O. Burns: We added 300 million a.

Roland O. Burns: A day of swaps covering the period of April.

Roland O. Burns: October 2024 through December 2026 at an average price of $3 51 per Mcf.

Roland O. Burns: We added $75 million a day of swaps just for $25 at an average swap price of $3.57. And then we added $150 million a day of collars in 2025 with a floor price of $3.50 and an average ceiling price of $3.80. We've also had some in 2026.

Roland O. Burns: Added 75 million a day of swaps just for 25 at an average swap price of $3 50.

Roland O. Burns: And then we added 150 million a day of collars in 2025 with a floor price of $3 50, and an average ceiling price of $3 80.

Roland O. Burns: We have $250 million a day of collars that we added for 2026, which had a floor price of $3.50 and an average ceiling price of $3.98. So as a result of this activity, we're almost 50% hedged for the fourth quarter of this year, and we're about, you know, about a third hedged for each of 2025 and 2027. So we'll continue to look to opportunistically add to our hedge positions over time in order to get close to that 50% hedge kind of target that we have, and we will continue to put in positions that give us very meaningful floor protection. And as you can see, that's kind of sitting around the $3.50 area.

Roland O. Burns: We've also had some in 2026 that we have.

Roland O. Burns: 250 million a day of collars.

Roland O. Burns: That we added for 2020 states, which had a floor price of $3 50.

Roland O. Burns: And an average ceiling price of $3 98.

Roland O. Burns: So as a result of this activity we are almost 50% hedged for the fourth quarter of this year and we're about you know.

Roland O. Burns: About a third hedged for each of 2025 and 2026.

Roland O. Burns: So we'll continue to.

Roland O. Burns: Look to Opportunistically add to our hedge positions.

Roland O. Burns: Over time in order to get close to that 50% hedged kind of target that we have and we continue to put in positions that give us very meaningful floor protection.

Roland O. Burns: You can save that's kind of sitting around that $3 50 <unk> area.

Roland O. Burns: On slide seven, we detail our operating costs per MCFE and our EBITDAX margin for the first quarter. So our operating cost was, on average, 76 cents per MCFE produced, which was five cents lower than our fourth quarter rate. We saw some improvement in our production and ad valorem taxes, which were down 10%, but our other costs were up a little bit to slightly offset that. Our EBITDAX margin after hedging came in at 68% in the first quarter.

Roland O. Burns: On slide seven we detail our operating cost per Mcf and our EBITDAX margin in the first quarter, So our operating cost for.

Roland O. Burns: <unk> averaged <unk> 76 per Mcf per days.

Roland O. Burns: Which was <unk> <unk> lower than our fourth quarter rate we saw.

Roland O. Burns: Some improvement in our production and AD valorem taxes, which are down 10%, but our other costs were up a little bit to slightly offset that our.

Roland O. Burns: Our EBITDAX margin after hedging came in at 68% in the first quarter that was a similar margin.

Roland O. Burns: That was a similar margin to the margin that we had in the fourth quarter despite the fact that we had lower prices in the first quarter of this year. On slide 8, we recap our spending on drilling and other development activity for the quarter. We spent a total of $256 million on our drilling activities, including $252 million that directly relates to the Hainesville and Bossier Shale Drilling Program. And then we only spent $4 million on other development activities in the quarter. We drilled 16 or 14.3 net wells in our Haines School Program, and we turned 18 or 16.3 operated wells into sales during the quarter. These wells had an average IP rate of 27 million per day.

Roland O. Burns: That.

Roland O. Burns: That margin that we had in the fourth quarter. Despite the fact that we had lower prices.

Roland O. Burns: In the first quarter of this year.

Roland O. Burns: On slide eight we recap our spending on drilling and other development activity.

Roland O. Burns: For the quarter, we spent a total of $256 million.

Roland O. Burns: Our drilling activities, including 252 million that directly relates to the Haynesville and Bossier.

Roland O. Burns: <unk> drilling program.

Roland O. Burns: And then we already spent a $4 million on other development activity in the quarter.

Roland O. Burns: We drilled 16, there were $14 three net wells.

Roland O. Burns: In our Haynesville program and returned 18 or 16, three operated wells to sales in the quarter.

Roland O. Burns: These wells had an average IP rate of 27 million per day.

Daniel S. Harrison: In the quarter, we also did have four short lateral bosher wells drilled, which probably deleted the numbers a little bit, but they were drilled to hold acreage. On slide nine, we recap our balance sheet at the end of the first quarter. We ended the quarter with $540 million in borrowings outstanding on our credit facility, giving us $2.7 billion in total debt, including our outstanding senior debt. As Jay referenced, on March 25, we sold 12.5 million shares to our majority stockholder for $125 million in a private placement. Proceeds from that offering have offset some of the cost of our Western Hainesville Acreage Acquisition Program.

Daniel S. Harrison: In the quarter. We also did we did have four short lateral bossier wells, which were drilled which probably delete the numbers a little bit, but they were drilled to hold acreage.

Daniel S. Harrison: On slide nine we.

Daniel S. Harrison: To recap our balance sheet at the end of the first quarter.

Daniel S. Harrison: We ended the quarter with $540 million in borrowings outstanding on our credit facility, giving us $2 7 billion in total debt, including our outstanding senior notes.

Daniel S. Harrison: As Jay referenced we on March 25th we sold $12 5 billion shares to our majority stockholder for $125 million in a private placement.

Daniel S. Harrison: The proceeds from that offering helped offset some of the cost of our western Haynesville acreage acquisition program.

Daniel S. Harrison: Just after the end of the first quarter, we issued $400 million of additional senior notes due in 2029, and we used the proceeds to pay down the borrowings under our bank facility. The bond offering increased our liquidity on a pro-rata basis to $1.3 billion. And lastly, on April 30th, our bank reaffirmed our borrowing base at $2 billion, and then our elected commitment of $1.5 billion kind of remained the same. So I'll now turn the call over to Dan to discuss the operations in more detail. Okay.

Daniel S. Harrison: Just after the end of the first quarter, we issued $400 million of additional senior notes due in 2029, and we used the proceeds to pay down the borrowings under our bank facility.

Dan: The bond offering and increased our liquidity on a pro forma basis to $1 $3 billion.

Daniel S. Harrison: And then lastly on April 30, with our Bank group reaffirmed our borrowing base at $2 billion and that our elected commitment of $1 5 billion kind of remained the same so I'll now turn the call over to Dan to discuss the operations in more detail.

Daniel S. Harrison: Okay, thank you, Roland. Over on slide 10, this is our current drilling inventory that we have where we are at the end of the first quarter. Our total operated inventory currently has 1,702 gross locations and 1,296 net locations, which equates to a 76% average working interest across the operated inventory. On the non-operated inventory, we have 1,254 gross locations and 165 net locations, which represents a 13% average working interest on the non-operated inventory. The drilling inventory is split between Hainesville and Bossier locations, and we have it split down into our four different groups.

Daniel S. Harrison: Okay.

Speaker Change: Thank you Roland.

Daniel S. Harrison: Over on Slide 10 this is.

Daniel S. Harrison: This is our current drilling inventory that we have where we're at at the end of the first quarter.

Daniel S. Harrison: Total operated inventory currently has 1702 gross locations.

Daniel S. Harrison: 296, net locations, which is a.

Daniel S. Harrison: Thanks to a 76% average working interest across the operated inventory.

Daniel S. Harrison: Non operated inventory, we have 1254 gross locations in 165 net locations, which represents a 13% average.

Daniel S. Harrison: Working interest on the non operated inventory.

Daniel S. Harrison: The drilling inventory is split between Haynesville and Bossier locations and we have a split down into our four different groups are short laterals are up to 5000 foot long medium laterals at 5000 to 8500 feet.

Daniel S. Harrison: Our short laterals are up to 5,000 feet long, medium laterals at 5,000 to 8,500 feet, long laterals at 8,500 feet to 10,000 feet, and then our extra long laterals for everything over 10,000 feet. So if you look at each group in our gross operated inventory, we have 278 short laterals, 348 medium laterals, 433 long laterals, and 643 extra long laterals. This gross operating inventory is evenly split, with 51% in Haynesville and 49% in Bossier.

Daniel S. Harrison: Long laterals at 8500 feet to 10000 feet.

Daniel S. Harrison: And then our extra long laterals for everything over 10000 feet.

Daniel S. Harrison: So if you look at each group and our gross operated inventory, we have 278 short laterals 348 medium laterals.

Daniel S. Harrison: 433, long laterals and 643 extra long laterals.

Daniel S. Harrison: This gross operated inventory is evenly split with 51% in the Haynesville and 49% in the Bossier.

Daniel S. Harrison: 63% of our gross operated inventory has ladder links exceeding 10,000 feet, and 38% of our gross operated inventory, or six, the 643 locations have ladder links surpassing 10,000 feet. The average lateral length in our inventory now stands at 9,015 feet. This is up slightly from 8,971 feet that we had at the end of the fourth quarter. Based on our near-term activity levels, this inventory provides us with over 30 years of future drilling locations.

Daniel S. Harrison: 63% of our gross operated inventory has laterals longer than 8500 feet and 38% of our gross operated inventory or six out of the 643 locations had lateral lengths.

Daniel S. Harrison: Passing 10000 feet.

Daniel S. Harrison: The average lateral length in our inventory now stands at 9015 feet. This is up slightly from 8971 fee that we had at the end of the fourth quarter.

Daniel S. Harrison: Based on our near term activity levels. This inventory provides us with over 30 years of future drilling locations.

Daniel S. Harrison: On slide 11 is a chart outlining progress to date on our average lateral length drill based on the wells that we have turned to sales. During the first quarter, we turned 18 wells to sales with an average lateral length of 9,229 feet. The individual links range from 4,228 feet up to 14,308 feet.

Daniel S. Harrison: On Slide 11 is a chart outlining our progress to date on our average lateral length drilled based on the wells that we have turned to sales during.

Daniel S. Harrison: During the first quarter, we tired 18 wells to sales with an average lateral length of 9229 feet.

Daniel S. Harrison: The individual lengths range from 4228 feet up to 14308 feet.

Daniel S. Harrison: Our record longest lateral still stands at about 15,726 feet. 12 of the 18 wells we turned sales during the quarter had laterals exceeding 8500 feet, including four with laterals longer than 13,500 feet. As Roland mentioned earlier, our 9,229-foot average lateral length this quarter represents a departure from the upward trend we've been on for the last several years, and this is due to a handful of short laterals that were drilled on some isolated sections to preserve acreage while we're in this low gas price environment.

Daniel S. Harrison: Our record longest lateral still stands at about 15726 feet.

Daniel S. Harrison: 12 of the 18 wells, we turned to sales during the quarter had laterals exceeding 8500 feet, including four with laterals longer than 13500 feet.

Daniel S. Harrison: As I mentioned Roland mentioned earlier on 9229 foot average lateral length. This quarter represents a departure from the upper trend we've been on for the last several years.

Daniel S. Harrison: And this is due to a handful of short laterals that were drilled in some isolated sections to preserve acreage.

Daniel S. Harrison: While we're in this low gas price environment.

Daniel S. Harrison: We're not planning to drill any additional short lateral wells and we do expect our average lateral length will exceed 10000 feet for the remaining wells that we turned to sales this year.

Daniel S. Harrison: We're not planning to drill any additional short ladder wells, and we do expect our average ladder length will exceed 10,000 feet for the remaining wells that we turn to sales this year. Included in our 18 wells turned to sales for the quarter are four wells that are located on our Western Hainesville acreage. These four wells had an average lateral length of 9608 feet.

Daniel S. Harrison: Included in our 18 wells turned to sales for the quarter of four wells that are located on our western Haynesville acreage.

Daniel S. Harrison: These four wells had an average lateral length of 9608 feet.

Daniel S. Harrison: So to recap our longer lateral wells, we have drilled 91 wells; to date, we have drilled 91 wells with laterals over 10,000 feet, and 33 wells with laterals over 14,000 feet. On slide 12, we recap our new well activity since we last provided our well results in mid-February. We have turned to sales and tested 14 new wells since our last conference call. This group of whales had individual IP rates ranging from nine to 38 million cubic feet a day, with an average test rate of 25 million cubic feet a day. The average lateral length was 8,031 feet, and with the individual laterals, it ranges from 4,228 feet up to 14,137 feet. This is our last call.

Daniel S. Harrison: So to recap our longer lateral wells, we have drilled 91 wells to date, we have drilled 91 wells with laterals over 10000 feet 33 wells with laterals over 14000 feet.

Daniel S. Harrison: Okay.

Daniel S. Harrison: On slide 12, we recap our new well activity since we last provided our well results in mid February.

Daniel S. Harrison: We have turned to sales and tested 14, new well since our last conference call.

Daniel S. Harrison: This group of wells had individual IP rates ranging from nine up to 38 million cubic feet a day with an average test rate of 25 million cubic feet a day.

Daniel S. Harrison: The average lateral length was 8031 feet.

Daniel S. Harrison: Well with the individual laterals.

Daniel S. Harrison: <unk> 4228 feet up to 14137 feet.

Daniel S. Harrison: We have drilled four additional wells, two cells, in western Hainesville. The Glass, the Farley, the Harrison, and the Ingram-Martin Wells achieved IP rates of 35 to 38 million cubic feet a day, and all four of these oils targeted the Hainesville Shell.

Daniel S. Harrison: Since our last call we have turned four additional wells to sales in the western Haynesville.

Daniel S. Harrison: I think last the Farley, the Harrison and the Ingram Marten wells achieved IP rates of 35% to 38 million cubic feet a day.

Daniel S. Harrison: And all four of these wells targeted the Haynesville shale.

Daniel S. Harrison: Regarding our current activity levels, we are now running five rigs. This is after we dropped three rigs during the first quarter, and we are running two full-time frack crews. Two of these five rigs are currently drilling in Western Haynesville, and both of these rigs are now drilling on the first of our two well pads, which will yield increased efficiency. Now that we have our two Western Hazel rigs drilling on two well pads, we will not have any additional wells turn into cells in the Western Heisman until early in the fourth quarter.

Daniel S. Harrison: Regarding our current activity levels, we are now running five rigs.

Daniel S. Harrison: After we dropped three rigs during the first quarter.

Daniel S. Harrison: And we are running two fulltime frac crews.

Daniel S. Harrison: Two of these five rigs are currently drilling in the western Haynesville and both of these rigs are now drilling on the first of our two well pads.

Daniel S. Harrison: Which will yield increased efficiencies.

Daniel S. Harrison: Now that we have our two western haynesville rigs drilling on two well pads, we will not have any additional wells starting to sales.

Daniel S. Harrison: In the western Haynesville until early in the fourth quarter.

Daniel S. Harrison: Slide 13 summarizes our D&C costs through the first quarter for our benchmark long lateral wells, which are the wells located in our legacy core East Texas and North Louisiana acreage. Our benchmark wells cover all laterals greater than 8,500 feet long.

Daniel S. Harrison: Slide 13 summarizes our D&C costs through the first quarter for our benchmark long lateral wells.

Daniel S. Harrison: This is wells located in our legacy core East, Texas, and North Louisiana acreage.

Daniel S. Harrison: Our benchmark wells cover all laterals greater than 8500 feet long.

Daniel S. Harrison: During the quarter, we turned 14 wells to cells that were on our core acreage, and eight of these 14 wells fell into our benchmark long lateral group. In the first quarter, our D&C cost averaged $1,501 per foot on these benchmark wells, which reflects a 1% increase compared to the fourth quarter of last year. Our first quarter drilling cost averaged $714 a foot, which is a 17% increase compared to the fourth quarter. The higher drilling costs were primarily the result of all eight of our Bitsmark long lateral wells during this quarter being concentrated in our higher drilling cost area.

Daniel S. Harrison: During the quarter, we turned 14 wells to sales that were on our core.

Daniel S. Harrison: Acreage at eight eight of these 14 wells fell into our bits Mark long lateral group.

Daniel S. Harrison: In the first quarter, our D&C cost averaged 1501.

Daniel S. Harrison: <unk> per foot on these <unk> wells, which reflects a 1% increase compared to the fourth quarter of last year.

Daniel S. Harrison: Our first quarter drilling cost averaged $714, a foot, which is a 17% increase compared to the fourth quarter.

Daniel S. Harrison: The higher drilling costs were primarily result of all eight of our benchmark long lateral wells during this quarter.

Daniel S. Harrison: Being concentrated in our higher drilling cost areas.

Daniel S. Harrison: Our first quarter completion cost came in at $787 a foot. This represents a 10% decrease compared to the fourth quarter, and this mainly stems from lower gas prices, which has led to lower basin-wide completion activity and lower frac costs. As stated earlier, we did drop the two rigs during the first quarter, and we are now running five rigs. Our current outlook has us holding steady at five rigs for the remainder of the year.

Daniel S. Harrison: Our first quarter completion costs came in at $787 a foot.

Daniel S. Harrison: This represents a 10% decrease compared to the fourth quarter.

Daniel S. Harrison: It's mainly sales from the lower gas prices, which led to this has led to the lower basin wide completion activity and lower frac costs.

Daniel S. Harrison: As I stated earlier, we did drop to two rigs during the first quarter and we're now running we are now running five rigs current outlook has a solid and steady.

Daniel S. Harrison: At five rigs for the remainder of the year.

Daniel S. Harrison: On the completion side, we are today running two full-time frack crews, and we will stay at this level through the end of the second quarter. However, with the lower rig activity, we anticipate only working the equivalent of one and a half rack crews during the second half of the year.

Daniel S. Harrison: On the completion side, we are today running the two full time frac crews and we will stay at this level through the end of the second quarter.

Daniel S. Harrison: However, with the lower rig activity.

Daniel S. Harrison: We anticipate only working the equivalent of a one and a half frac crews during the second half of the year.

Daniel S. Harrison: On slide 14, we highlight our continued improvement related to greenhouse gas and methane emissions. We reported a greenhouse gas intensity of 3.45 kilograms CO2 equivalent per BOE of production. This is a 1% improvement versus 2022, increasing the improvement to 4% over the past two years. We also reported a methane emission intensity of 0.04%, which is an 11% improvement versus 2022 and a 26% improvement over the past two years. We achieved those emissions improvements despite our increased focus on the higher-intensity Western Haynesville. In addition, our turn to sales lateral feed increased by 15% in 2023.

Daniel S. Harrison: On slide 14, we highlight our continued improvement related to greenhouse gas methane emissions.

Daniel S. Harrison: We reported a greenhouse gas intensity of 345 kilograms cotwo equivalent per Boe.

Daniel S. Harrison: <unk>.

Daniel S. Harrison: This is a 1% improvement versus 2022.

Daniel S. Harrison: And increases to increasingly improvement to 4% over the past two years.

Daniel S. Harrison: We reported a methane emission intensity of 0.04%, which is an 11% improvement versus 2022, and a 26% improvement over the over the past two years.

Daniel S. Harrison: We achieved those emissions.

Daniel S. Harrison: <unk>, despite our increased focused on the higher intensity western Haynesville.

Daniel S. Harrison: In addition, our turned to sales lateral feet increased by 15% in 2023.

Daniel S. Harrison: Adjusting for lateral length footage completed for are turned to sales wells, our greenhouse gas emissions per lateral foot turned to sales improved 16% last year and 21% over the past two years.

Daniel S. Harrison: Adjusting for lateral link footage completed for our turn to sales wells, our greenhouse gas emissions per lateral foot turn to sales improved 16% last year and 21% over the past two years. Will our methane emissions per lateral foot turn to sales improve 25% last year and 38% over the past two years?

Daniel S. Harrison: While our methane emissions per lateral foot turned to sales.

Daniel S. Harrison: Improved 25% last year and 38% over the past two years.

Daniel S. Harrison: We've deployed optical gas imaging and aircraft leak monitoring technology at almost 100% of our production sites, which earned us the ability to certify our gases responsibly sourced. Our natural gas dual fuel powered frack fleet eliminated approximately 10.6 million gallons of diesel by utilizing natural gas and offsetting approximately 21,800 metric tons of CO2. Our dual fuel drilling rigs eliminated approximately 460,000 gallons of diesel by utilizing natural gas and offset approximately 1,400 metric tons of CO2.

Daniel S. Harrison: We've deployed op optical gas imaging and aircraft leak monitoring technology at almost at almost 100% of our production sites.

Daniel S. Harrison: Earned us the ability to certify our gases responsibly sourced.

Daniel S. Harrison: Our natural gas dual fuel powered frac fleets eliminated approximately $10 6 million gallons of diesel.

Daniel S. Harrison: By utilizing natural gas.

Daniel S. Harrison: Offsetting approximately 21 800 metric tons of Cotwo quibbling.

Daniel S. Harrison: Our dual fuel drilling rigs and we eliminated approximately 460000 gallons of diesel.

Daniel S. Harrison: By utilizing natural gas and offset approximately 1400 metric tons of Cotwo equivalent.

Daniel S. Harrison: We have installed instrument air on approximately 97% of our newly constructed production facilities, mitigating approximately 5500 metric tons of CO2 equivalent. Emissions from equipment leaks have decreased 97% since 2021. This is from 33,664 metric tons of CO2 equivalent emissions in 21 down to just 994 metric tons in 2023. I'll now turn the call back over to Jay.

Daniel S. Harrison: We have installed instrument air owned approximately 97% of our newly constructed production facilities.

Jay: Mitigating approximately 5500 metric tons of Cotwo equivalent.

Daniel S. Harrison: Emissions from equipment lakes have decreased 97% since 2021.

Jay: This is from 33664 metric tons of steel to equivalent emissions and.

Jay: <unk> 21 down to just 994 metric tons in 2023.

Daniel S. Harrison: I'll now turn the call back over to Jay Alright, Thanks, Dan. Thank you Roland.

Miles Jay Allison: All right. Thank you, Dan. Thank you, Roland.

Jay: Our direct you to slide 15, where we summarize our outlook for 2024.

Miles Jay Allison: I would direct you to slide 15, where we summarize our outlook for 2024. Now, we've taken a number of steps in response to significantly lower natural gas prices this year. During the first quarter, we released two of our operated rigs, as Dan said, reducing our count to five rigs. We also released one of our frack spreads, reducing our frack fleet to two spreads. We no longer have any long-term commitments for our pressure pumping service.

Jay: We've taken a number of steps in response to significantly lower natural gas prices this year.

Miles Jay Allison: During the first quarter, we released two of our operated rigs as Dan said.

Miles Jay Allison: By reducing our rig count to five rigs and we also released one of our frac spreads, reducing our Frac fleet to two spreads we no longer have any long term commitments for our pressure pumping services.

Miles Jay Allison: With those steps in 2024, CapEx is expected to be down 33 to 41% from the 2023 level. Additionally, we suspended our quarterly dividend, saving approximately $140 million a year in dividend payment. In late March, a majority stakeholder, Jerry Jones, invested an additional $100.5 million into the company through an equity private placement. Starting in late February, we've added significantly, as Roland said, to our hedge position starting in the fourth quarter of 2024 and extending to the end of 2026.

Miles Jay Allison: Steps in 2020 for Capex is expected to be down 33% to 41% from the 2023 level, we suspended our quarterly dividend saving approximately $140 million a year of dividend payments.

Miles Jay Allison: Late March how majority stakeholder Jerry Jones invested an additional $105 million into the company through an equity private placement.

Miles Jay Allison: Starting in late February we have had as significantly as Robin said, our hedge position starting in the fourth quarter of 2024 and extending through the end of 2026.

Miles Jay Allison: We're targeting a hedge level of 50% of our expected production level. In early April, we further enhanced our liquidity position with a $400 million senior notes offering. We will continue to maintain our very strong financial liquidity, which totaled just over $1.3 billion at the end of the first quarter, pro forma for the recent notes offering.

Miles Jay Allison: We're targeting a hedge level of 50% of our expected production level.

Miles Jay Allison: In early April we further enhanced our liquidity position with a $400 million senior notes offering will continue to maintain our very strong financial liquidity, which totaled just over $1 3 billion at the end of the first quarter pro forma for the recent notes offering yet.

Miles Jay Allison: Our industry-leading low cost structure is an asset in the current low natural gas price environment as our cost structure is substantially lower than the other public natural gas producers. We remain very focused on proving up our Western Angel play, continuing to add to our extensive acreage position at this exciting play. At the end of the first quarter, our Western Hainesville acreage position, as we stated earlier, totaled over 450,000 net acreage.

Miles Jay Allison: Industry, leading low cost structure as an asset in the current low natural gas price environment is our cost structure is substantially lower than the other public natural gas producers.

Miles Jay Allison: We remained very focused on proving up our western Haynesville play continuing to add to our extensive acreage position.

Miles Jay Allison: This exciting play.

Miles Jay Allison: It is the first quarter, our western Haynesville acreage position as we stated earlier totaled over 450000 net acres.

Miles Jay Allison: We believe that we're building a great asset in the Western Angel that will be well positioned to benefit from the substantial growth in demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports that begin to show up in the second half of next year. The Wall Street Journal on January 2nd, 2024 tracked 120 winners and losers by looking at how selected global stock indexes, bond ETFs, currencies, and commodities performed for the year 2023. NIMAX Natural Gas was the next to the last worst performer. Then, on April 1, 2024, the Wall Street Journal tracked the same group of 120. NYMEX natural gas was the worst performer for the entire group.

Miles Jay Allison: We believe that we are building a great asset and the western Haynesville, there will be well positioned to benefit from the substantial growth in demand for natural gas in a region that is on the horizon driven by the growth in.

Miles Jay Allison: And LNG exports that begins to show up in the second half of next year.

Miles Jay Allison: The Wall Street Journal.

Miles Jay Allison: On January the second 2024 track.

Miles Jay Allison: 120 winners and losers.

Miles Jay Allison: Looking at House selected global stock indexes bond Etfs currencies and commodities performed for the year 2023.

Miles Jay Allison: Nymex natural gas was the next to the last worse performer.

Miles Jay Allison: Then on April one 2020 for the Wall Street Journal track. The same group of 120, Nymex natural gas was the worst performer for the entire group.

Miles Jay Allison: That has been the stark reality over the past 15 months. So the question is, how can we manage in this weak price environment and exit as a much stronger company when demand for domestic as well as global natural gas arrives in 2025 and beyond. We have that answer. It is to manage our proven quality core area, continue to be a low cost producer, continue to protect our liquidity and balance sheet, and now continue to develop our 450,000 net acre wet Hainesville Western Hainesville play, which has, to date, shown great promise. I'll now have Ron provide some specific guidance for the rest of the year.

Miles Jay Allison: That is stark reality over the past 15 months.

Ronald Eugene Mills: Thank you, Gabe. On slide 16, we provide financial guidance for the second quarter and the full year 2024. The second quarter CAPEX expected on the DNC side is expected to be $200 to $250 million, and our full year DNC CAPEX guidance remains unchanged at $750 to $850 million. The lower DNC spending versus last year is related to the release of the two drilling rigs earlier this year in response to the low gas prices.

Ron: So the question is.

Ronald Eugene Mills: How we can manage in this weak price environment and exit a much stronger company when demand for domestic as well as global natural gas horizon 2025 and beyond.

Ronald Eugene Mills: We have that answer.

Ronald Eugene Mills: It is to manage our proven quality core area.

Ronald Eugene Mills: Continue to be a low cost producer.

Ronald Eugene Mills: Continue to protect our liquidity and balance sheet and now continue to develop our 450000 net acre we have haynesville western Haynesville play that is to date.

Ronald Eugene Mills: As shown great promise.

Ronald Eugene Mills: I will now have Ron provide some specific guidance for the rest of the year Ron.

Gabe: Thanks, Jane on Slide 16, we provide financial guidance for the second quarter and the full year 2024.

Ronald Eugene Mills: Second quarter Capex expected on the D&C side is expected to be $200 million to $250 million and our full year D&C capex guidance remains unchanged at $750 to $850 million.

Ronald Eugene Mills: The lower D&C spending versus last year is related to the release of the two drilling rigs earlier this year in response to the low gas prices with.

Ronald Eugene Mills: With the large lease acquisitions now completed, we anticipate spending $2 to $5 million in the second quarter and $70 to $80 million over the course of 2024. Capital expenditures related to Pinnacle Gas Services will be funded by our partner and are expected to total $30 to $40 million in the second quarter and $125 to $150 million for the year, which is unchanged. On the operating cost side,

Ronald Eugene Mills: With the large lease acquisitions now completed we anticipate spending $3 to $5 million in the second quarter and $70 million to $80 million over the course of 2024.

Ronald Eugene Mills: Capital expenditures related to Pinnacle gas services will be funded by our partner and are expected to total $30 million to $40 million in the second quarter and $125 million to $150 million for the year, which is unchanged.

Ronald Eugene Mills: On the operating cost side.

Ronald Eugene Mills: Our guidance for LOE, GTC, and production and ad valorem taxes remains unchanged from February, as does our DDNA. The only real change on our guidance on the cost side is related to interest expense, which has been increased slightly to reflect the impact of the notes offering we completed in April. Lastly, on the tax side, we still expect the tax rate to be 22 to 25%, but now we expect to defer 98 to 100%.

Ronald Eugene Mills: Our guidance for LOE, GTC and production and AD valorem taxes remain unchanged from February.

Ronald Eugene Mills: As does our DD&A.

Ronald Eugene Mills: The only real change on our guidance on the cost side is related to interest expense, which has been increased slightly to reflect the impact of the notes offering we completed in <unk>.

Ronald Eugene Mills: In April <unk>.

Ronald Eugene Mills: Lastly on the.

Ronald Eugene Mills: On the tax side, we still expect the tax rate to be 22% to 25%.

Ronald Eugene Mills: And really almost virtually 100% of our reported taxes this year, which is up from the prior range of 95 to 100%. I'll now turn the call back over to Andrea to answer questions from analysts who cover the stock. Thank you.

Ronald Eugene Mills: But now we expect to defer 98% to 100% in really almost virtually 100% of our reported taxes. This year, which is up from the prior range of 95% to 100%.

Ronald Eugene Mills: I'll now turn the call back over to Andrea to answer questions from analysts who cover the stock.

Operator: Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A list. Our first question comes from Derrick Whitfield on Stiefel. Please go ahead.

Andrea: Thank you at this time, we will conduct a question and answer session. As a reminder to ask a question you will need to press star one on your telephone and wait for your name to be announced to withdraw. Your question. Please press star one again, please standby, while we compile the Q&A roster.

Operator: Our first question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Lee Whitfield: Good morning, all. And thanks for your time. Warning.

Derrick Lee Whitfield: Good morning, all and thanks for your time.

Derrick Lee Whitfield: I have two questions for you, and they're both related to the Western Haines LASA. First, given the depressed price environment we're seeing at present, I want to make sure we're properly thinking about the capital efficiency of the investment relative to industry. If we think about your cost and recovery metrics based on the breadcrumbs provided, you've noted the Western Hane Tool is being developed at a cost that's about 2x that of your Legacy Hane Tool with a recovery that's about 3.5 to 4 BCF per thousand feet, and that ballpark.

Derrick Lee Whitfield: Morning.

Derrick Lee Whitfield: Two questions for you and they're both related to the western Haynesville asset.

Derrick Lee Whitfield: So that's 3,000 per foot for, let's call it three and a half to four BCF per thousand foot of EUR. So if we compare that to industry metrics of 2,000 per foot or 2 BCF per 1,000 foot, it would seem to us that you're about 50% more expensive, but you recover 75 to 100% more gas. Is that fair? And again, I'm just trying to frame the opportunity as we know it today.

Derrick Lee Whitfield: First given the depressed price environment, we're seeing at present.

Derrick Lee Whitfield: I wanted to make sure we're properly thinking about the capital efficiency of the investment relative to the industry. If we think about your cost and recovery metrics based on the bread crumbs provided you've noted the western Haynesville is being developed at a cost that's about <unk> of your legacy Haynesville with a recovery that's about three five to four Bcf per 1000 foot in that.

Derrick Lee Whitfield: Ballpark. So that's 3000 per foot for let's call. It three 5% to four bcf per thousand foot of EUR.

Derrick Lee Whitfield: So if we compare that to industry metrics 2000 per site for two Bcf per 1000 foot.

Derrick Lee Whitfield: It would seem to us youre about 50% more expensive, but you recover 75% to 100% more gas.

Derrick Lee Whitfield: Is that fair and again I'm, just trying to frame the opportunity as we know it today.

Roland O. Burns: Yeah, Derrick, this is Roland. I don't think that's too unfair. I mean, I think the difference really is that the larger reserves that we're finding in the Western Hainesville, but it also takes longer to get them out. We're not flowing the Western Hainesville wells at double the rates of the traditional Hainesville. It's possible we could, but we're choosing, you know, not to do that in this early stage, especially with the low price environment.

Roland O. Burns: Yes, Derek this is Earl and I don't think Thats too unfair I mean I think.

Roland O. Burns: The difference really is that the larger reserves that were finding in the western haynesville, but it also takes longer to get them out.

Roland O. Burns: Flowing the western Haynesville wells at double the rates of the traditional haynesville.

Roland O. Burns: It's possible, we could but were chosen.

Roland O. Burns: We've got to do that in this early stage, especially with the low price environment.

Roland O. Burns: So we're, I think you would really view it, I think we think overall, it's a very, it's a very similar type of return right now compared to the best part of our traditional Haynesville and probably superior to our, you know, tier two, tier three part of the Haynesville. But it's, it's longer term, it's an investment in the future. And so, you know, we still really have been very encouraged by the good performance and the EURs that they appear to be earning with their longer term performance.

Roland O. Burns: So I think you had really view it I think we think overall, it's a very it's a very similar.

Roland O. Burns: Type of return right now compared to the.

Roland O. Burns: The best part of our traditional Haynesville and price superior to our tier two tier three part of the Haynesville.

Roland O. Burns: But it's it's longer term, it's a it's an investment in the future.

Roland O. Burns: So yes, we still really have been very encouraged by the well performance.

Roland O. Burns: And the EUR is that they appear to be earning with their longer term performance.

Miles Jay Allison: Yeah, Derrick, I'll make this point, we have 12, 11 to 12 wells turned to cells, and we've only started drilling, you know, two wells per pad recently, and we've only had one well that's been producing over two years, so it's early on in the play, but what we have seen so far is exemplary, whether it's IP rates, whether it's the lack of decline, whether it's The question is, can you get it out economically? And in the birth of any play, particularly like the Corps of the Angels in 2008.

Speaker Change: Yes Derrick.

Miles Jay Allison: 12, 11 to 12 wells turned to sales.

Miles Jay Allison: And we've only shorter drilling two wells prepared recently.

Miles Jay Allison: And we've only had one well that's been producing over two years. So it's early on in the play, but what we've seen so far is exemplary whether it's.

Miles Jay Allison: IP rates, whether it's the lack of decline whether it's <unk>.

Miles Jay Allison: And any new play like this I mean, I think we all agree that the resources there.

Miles Jay Allison: <unk> is can you get it out economically.

Miles Jay Allison: And any birth of any blip, particularly like the core of the Haynesville in 2008.

Miles Jay Allison: I mean, the more wells you drill, the lower the costs are. I think Dan has done a good job. I mean, our first well took 80 days to drill, and now the last one has been 54. So these costs are coming down. I think we're getting better and better and better. Dan? Yeah.

Miles Jay Allison: I mean, the more wells you drill the lower the cost Star I think Dan has done a good job I mean, our first well for 80 days to drill. Another last one has been 54 today's cost are coming down I think we're getting better and better and better Dan Yes, I'll just add that when you compare the two areas. If you look at those the costs like <unk>.

Daniel S. Harrison: Yeah, I'll just add that when you compare the two areas, if you look at them side by side, the cost, like you mentioned in the core, those two areas are kind of pretty much set. We kind of know what we're going to drill them for, you know, absent any problems, and there's I mean, there's you're making some small improvements here and there, but you compare that to Western Hainesville where, if you look at the cost, like you mentioned, you know, that's where we started.

Daniel S. Harrison: Mentioned in the core those.

Daniel S. Harrison: Those are kind of pretty much set we kind of know what we're going to drill them for you know absent any problems and theirs.

Daniel S. Harrison: Youre, making some small improvements here and there, but you compare that to the western Haynesville, where.

Daniel S. Harrison: If you look at the cost like you mentioned, you know Thats, where we started so those costs are coming down right. So.

Daniel S. Harrison: Those costs are coming down. Right. So, on the Western Hainesville side, you're seeing the cost really move down, which is changing the economics, and you're not really seeing that in the core. Those are kind of fixed, right? We've kind of been optimized, you know, for a while.

Daniel S. Harrison: On the Western Haynesville side, Youre seeing the cost really moved down which is changing the economics and youre not really seeing that in the core those are kind of fixed right we've kind of.

Daniel S. Harrison: Been optimized for a while.

Miles Jay Allison: Well Derrick, the core goes from anywhere from 1.2 to maybe 2.2. I mean, you may see 2.3, but like you said, 2.0, I mean that's a blue ribbon weld in the core. I think what we're trying to prove with the Western Angel is that, you know, a large portion of that acreage is competitive, if not potentially better, than the best of the best in the core. That's what we're trying to prove.

Miles Jay Allison: Voluntary core goes from anywhere from one two to maybe $2 2 million.

Miles Jay Allison: You may see two three but I'd like to point out I mean, let's say, let's say blue ribbon well.

Miles Jay Allison: Well in the core I think what we're trying to de risk and western Haynesville is it.

Miles Jay Allison: Large portion of that acreage is.

Miles Jay Allison: <unk> is competitive.

Miles Jay Allison: If not potentially better than the best to the best of the core that's what we're trying to prove up.

Miles Jay Allison: Terrific, Keller. And then, as my follow-up, I just wanted to ask if you could help frame how we should think about the amount of activity that's required to HBP or protect the resource in light of your recent leasing success.

Speaker Change: Terrific color and then as my follow up but just wanted to ask you.

Speaker Change: You could help frame, how we should think about the amount of activity that's required to HPT H BP or protect the resource in light of your your recent leasing success.

Miles Jay Allison: Yeah, on the 198,000 acres, the net acres we acquired, I'd say 95% of that's HBP, the other 5%, those are round numbers; they're like 15-year leases. So, that does not change our drilling at all as far as our schedule for 2025-6-7. And as far as the acres that we've leased over the last 3.5 years, we've always said that we would really like to add a rig a year. And if we do that over several years, then that would be that acreage. So, we're not pushed at all to add rigs in a low-price environment, and even if prices are high, we're not pushed to add rigs at all to drill that acreage.

Miles Jay Allison: Yeah on the 198000 acres.

Miles Jay Allison: Acres, we acquired.

Miles Jay Allison: I would say, 95% of SHP paid dealer say, 5% is around numbers, they're like 15 year leases. So.

Miles Jay Allison: Very helpful. Thanks for your time.

Miles Jay Allison: That does not change our drilling at all as far as our schedule for 2020 567 at all.

Miles Jay Allison: And then as far as the acreage that we've leased over the last three and half years, we've always said that.

Miles Jay Allison: We would really like to add a rig at year end, if we do that over several years and that relationship is that acreage. So we're not we're not pushed it all to add rigs at a low price environment and even if prices are high we're not pushed to add rigs at all HP that acreage.

Speaker Change: Very helpful. Thanks for your time.

Miles Jay Allison: Yeah, good questions. Thank you, Derrick.

Speaker Change: Yes, good questions. Thank you Derrick.

Operator: Thank you. One moment for our next question. Our next question comes from Bertrand Donnes with Truist. Please go ahead.

Speaker Change: Thank you one moment for our next question.

Bertrand William Donnes: Our next question comes from Bertrand Dawns with Trust. Please go ahead.

Bertrand William Donnes: Hey, good morning team. I just wanted to start off asking around about the kind of exciting potential data center demand. You guys already have some LNG agreements. Obviously, you have LNG corridor exposure, but you've taken the indirect benefit strategy. So, just was wondering if when it comes to data center demand, is there any interest at Comstock in really taking a direct, maybe long-term agreement with a plant or something like that? And maybe you could tie in quantum, you know, a midstream build out for that purpose?

Bertrand William Donnes: Hey, good morning team I, just wanted to start off asking around the kind of exciting potential data center demand.

Bertrand William Donnes: <unk> already has an LNG agreements obviously.

Bertrand William Donnes: LNG corridor exposure, but you've taken the indirect benefit strategy. So just was wondering if when it comes to data center demand is there any interest at Comstock really taking a direct maybe long term agreement with <unk>.

Bertrand William Donnes: Plant or something like that and maybe could you tie in quantum.

Bertrand William Donnes: Our midstream build out for that purpose.

Roland O. Burns: Yeah, that's a great question. And you know, we're really excited about the Western Hanes cells we built volumes of because it's not, it's got, there are a lot of potential customers that are approaching us. And including, you know, recently, even some data centers that are really looking to build their centers where they can have, you know, uninterrupted supply and power supply. So it's an exciting new element to kind of add to the L. N. G. Demand and other industrial users, power generators. And, you know, we do see the land shifting, especially in our western Hainesville.

Speaker Change: Yes, that's a great question.

Roland O. Burns: We're really excited about the western Haynesville as we build volumes because it's not.

Roland O. Burns: It's got there's a lot of potential customers that are approaching us and including recently, even some data centers. They really are looking to build their centers, where they can have.

Roland O. Burns: Yes.

Roland O. Burns: On ad erupted.

Roland O. Burns: Supply and power supply. So that's an exciting new element to kind of add to the LNG demand in other industrial users power generators, and we do see shifting, especially our western Haynesville I think we will be selling a lot of that gas in the future because yet to our direct customers.

Roland O. Burns: I think we'll be selling a lot of that gas in the future because of our direct customers and then potentially, you know, using our relationship in the midstream venture, you know, to add some infrastructure as needed to be able to service those. So it's a really exciting area for us. We really want to have a diverse basket of customers in the future and have much, much less sales to other marketing companies or aggregators.

Roland O. Burns: Then potentially using our relationship.

Roland O. Burns: And the midstream venture.

Roland O. Burns: To add some infrastructure is needed to be able to service those so it's a really exciting area.

Roland O. Burns: For us, we really want to have a diverse basket of cut.

Roland O. Burns: Customers in the future.

Roland O. Burns: And much much less sales to other marketing companies are aggregators.

Roland O. Burns: And, you know, LNG will be a part of it. And I think we've got some exciting relationships they're developing, and then hopefully, other industrial users and, and, and utilities will be part of our customer base.

Roland O. Burns: And <unk> will be a part of it and I think we've got some.

Roland O. Burns: Exciting relationships, there developing and then hopefully other industrial users and.

Roland O. Burns: And utilities will be part of our customer base. So.

Miles Jay Allison: Well, if you look at that too, you know, 90 percent of our Western Angels are undedicated. So that's a big advantage if you're looking for gas, whether for a data center to provide power or take away as utility or LNG contracts.

Miles Jay Allison: Well, if you look at that to 90 plus percent of our western Angels on dedicated.

Miles Jay Allison: So that's a big advantage. If you are looking for gas for the for our data center to provide power our takeaway is utility our LNG contracts.

Miles Jay Allison: That's a really good point about.

Roland O. Burns: That's a really good point. Um, the other question, just maybe around the Jones transaction, could you maybe go into how that came together? Were they ready before you found the acreage? Was the acreage part of the push to maybe get the agreement? And, you know, I don't know, should we expect more cowboy cash in the future? Or is this kind of a one-time thing?

Roland O. Burns: Alright.

Roland O. Burns: The other question just maybe around the Jones transaction could.

Roland O. Burns: Could you maybe go into how that came together.

Roland O. Burns: What are they ready before you found the acreage was the acreage part of the push to maybe get the agreements and I don't know should we expect more cowboy cash in the future or is this kind of a onetime thing.

Miles Jay Allison: Well, I think, you know, come August, it'll be four years that we have had a group of landmen leasing acreage in this area. And we kind of set the boundaries, and as those boundaries have expanded, we've looked at where the kind of north, south, east, west sides are, and you work all those sides to come inward. And it just happened that this year, in 2024, we were able to pull off several of the larger transactions.

Miles Jay Allison: Well I think.

Miles Jay Allison: Come August to be four years.

Miles Jay Allison: Have been.

Miles Jay Allison: As ahead of group of land men leasing acreage.

Miles Jay Allison: In this area and we kind of sit to boundaries and as those boundaries have expanded we've look.

Miles Jay Allison: Good where that kind of the north South east West sides are.

Miles Jay Allison: And you work all of those signs to come in inward.

Miles Jay Allison: And it just happened that this.

Miles Jay Allison: This year in 2024.

Miles Jay Allison: We were able to pull off several of the larger transactions, we did that in 2022.

Miles Jay Allison: We did that in 2022. There was a big, big acquisition in 22 that we made, and we picked up the Pinnacle plant and that 145-mile high-pressure pipeline, and then this year, we were able to close another acquisition. But I think all of the, in our opinion, all of the major acquisitions that we would be looking at, they're in our rearview mirror. They're closed. And what we're doing now with our land group is just kind of cleaning up, and we think we've secured all the parameters. We're just cleaning up the infield.

Miles Jay Allison: There was a big big acquisition in 'twenty, two that we made and we picked up the pinnacle plant and at 145 mile High pressure pipeline and this year, we were able to close another acquisition.

Miles Jay Allison: But I think.

Miles Jay Allison: All of the in our opinion.

Miles Jay Allison: All of the major acquisitions that we would be looking at there. They are in our rearview mirror they're closed.

Miles Jay Allison: And what we're doing now with our land group futures kind of cleaning up and what we think we secured all the parameters, we're just cleaning up the infield.

Bertrand William Donnes: I appreciate the answers. Thanks, guys.

Speaker Change: I appreciate the answers thanks guys.

Operator: Thank you. One moment for our next question. Our next question comes from Jacob Roberts with TPH. Please go ahead.

Jacob Phillip Roberts: One moment for our next question.

Operator: Our next question comes from Jacob Roberts with TBH. Please go ahead.

Jacob Phillip Roberts: Good morning.

Jacob Phillip Roberts: Good morning.

Jacob Phillip Roberts: Maybe circling back to Derrick's first question, just thinking about the cost improvements on the core position over time. Wondering if you could speak to some of the levers that might be pulled in the Western Haynes bill that could also bring those costs down. Just looking for more specifics around what we could expect to see to get those days to drill lower or cost lower.

Jacob Phillip Roberts: Maybe circling back to Derek's first question, just thinking about the cost improvements on our core position.

Jacob Phillip Roberts: Over over time wondering if you could speak to some of the levers that might be part of a western haynesville that could also bring those costs down just just looking for more.

Jacob Phillip Roberts: Specifics around what we could expect to see to get those data drove lower costs lower.

Daniel S. Harrison: Yeah, this is a, you know, we've got kind of two things working in the Western Hainesville, a lot, obviously, the depth, it's deeper. The vertical hole section has, you know, a really thick Travis peak section. We've made a lot of improvements with the bits that we're using, getting better ROPs through that section, which takes several days. That's been part of the progress we've made. And then we have changed our casing design a little bit to save us some time.

Speaker Change: Yes. This is.

Daniel S. Harrison: We've got kind of two things working in the western Haynesville up obviously the depth that's deeper.

Daniel S. Harrison: Vertical hole section has.

Daniel S. Harrison: <unk> tried.

Daniel S. Harrison: <unk> speak section, we've made a lot of improvements with the bits that we're using.

Daniel S. Harrison: Getting better Rfps through that section, which takes several days thats been part of the progress we've made and then.

Daniel S. Harrison: We have changed our casing design, a little bit that saved us some time.

Daniel S. Harrison: Uh, we've also, you know, and in the lateral, it's, it's, uh, it's really the temperature that we've said many times and we've had a lot of really big improvements that have allowed us to handle the temperature. We're still making those improvements. And that's where we see the additional day savings, you know, moving forward from where we're at today.

Daniel S. Harrison: We've also and in the lateral.

Daniel S. Harrison: Really the temperature that we've said many times in the booth.

Daniel S. Harrison: Had a lot of a lot of really big improvements that have allowed us to handle the temperature, we're still making those improvements.

Daniel S. Harrison: And that's where we see the additional day savings moving forward from where we're at today.

Daniel S. Harrison: And we have seen that in the numbers. In other words, as we drill these wells, we have seen this cost improvement, and we've also seen, you know, a lot of upside in our EURs. So both of those metrics are going in the right direction.

Daniel S. Harrison: We have we have seen that in the numbers in other words as we drill these wells we have.

Daniel S. Harrison: <unk> seen this cost improvement.

Daniel S. Harrison: And we've also seen a lot of upside in our EUR. So both of those metrics are going the right direction in <unk>. The other thing I would add as Jay mentioned and and Dan. Both we're currently drilling with both of our rigs on two well pads. So in addition to the temperature being a key.

Daniel S. Harrison: and Jake, the other thing I would add is Jay mentioned, and Dan and I are currently drilling with both of our rigs on two well pads, so in addition to temperature being a key, the multi-well drilling pads should end up providing efficiencies like they do in all the plays.

Daniel S. Harrison: The multi well.

Daniel S. Harrison: Drilling pads full should end up providing efficiencies like they do in all the plays.

Daniel S. Harrison: And remember, we started out drilling Bossier, and then, as we said during this call, the four wells that we just put on, they're Hainesville wells. So you see, there's a little bit of a difference in drilling as you de-risk both of those NHANES.

Daniel S. Harrison: As well you remember we started out drilling Bossier and then as we said during this call. The four wells that were just put all their haynesville wells.

Daniel S. Harrison: Sure.

Daniel S. Harrison: So a little bit of a difference in drilling as you de risked both that measure in the haynesville.

Daniel S. Harrison: Great, I appreciate the color. Maybe staying on the same topic, I was wondering if you could comment on any variation and completion design that you might have pursued of the dozen welds or so that are online. And if you could offer any insight into what you think a full field development design might look like.

Speaker Change: Great I appreciate that color, maybe staying on the same topic I was wondering if you could comment on any.

Daniel S. Harrison: Variation in completion design that you might have pursued a dozen wells or so that are online.

Daniel S. Harrison: If you could offer any insight into what you think wholesale development design might look like.

Daniel S. Harrison: That's a really good question. You know, I kind of start with the last question, full field development. That's, I'd say... We haven't got too deep into thinking about that because that is kind of down the road with the plan for us to drill out basically just to drill out the acreage and get it held. We still have a few singles to drill, but we're drilling as many two-well pads as possible.

Daniel S. Harrison: That's a really good question.

Daniel S. Harrison: I'll kind of start with the last question fulfill development, that's I'd say.

Daniel S. Harrison: We havent got too deep into thinking about that because that is kind of down the road ways with the.

Daniel S. Harrison: The planned forced to drill out basically just to drill out the acreage and get it held.

Daniel S. Harrison: We will be doing and we still have a few singles the drill but we're drilling is 92, well pads as possible.

Daniel S. Harrison: On the completion design, we pumped a larger frac design on this last well that we turned to sales, the Ingram-Martin, just a larger job. The perforation, the cluster spacing, number of perfs, and all that was the same, but just a bigger loading, more water, and more sand.

Daniel S. Harrison: On the completion design, we did we have pumped a larger frac design on this last well that we turned to sales the Ingram Martin just just a larger job.

Daniel S. Harrison: The perforation.

Daniel S. Harrison: Cluster.

Daniel S. Harrison: <unk> spacing number of personnel that was the same but.

Daniel S. Harrison: Just a bigger loading more water more sand, we just wanted to get the clock started and see how that well is going to perform versus the.

Daniel S. Harrison: We just wanted to get the clock started and see how that well is going to perform versus... That's the first 11 that we turned to sales. Uh, nothing really, nothing really too different that we're doing on the completion design down here versus in the core. Um, you know, we'll just kind of continue to get our production data and, um, you know, we'll kind of depend on what it tells us. We'll see if we need to make any changes. But right now, I think what we have works pretty well. So, you know, we're just not looking to do anything drastic right now.

Daniel S. Harrison: The first 11 that we turned to sales.

Daniel S. Harrison: Nothing really nothing really too different that we're doing on our completion design down here versus in the core.

Daniel S. Harrison: We'll just kind of continue to get our production data and.

Daniel S. Harrison: Will.

Daniel S. Harrison: That has been what it tells US we will see if we need to make any changes, but right now I think what we have works pretty well so.

Daniel S. Harrison: We're just not looking to do anything drastic right now.

Jacob Phillip Roberts: Thank you very much. I appreciate the time. Thanks.

Speaker Change: Thank you very much I appreciate the time.

Speaker Change: Thank you.

Operator: Thank you. One moment for our next question. Our next question comes from Ati Modak with Goldman Sachs. Please go ahead.

Speaker Change: Q1 moment for our next question.

Ati Modak: Our next question comes from <unk> <unk> with Goldman Sachs. Please go ahead.

Ati Modak: Hi, good morning, team. Thanks for taking my question on. It seems like you moved more to more spot frack fleets for the rest of the year. Can you provide any color on the cost savings flexibility that that brings to your operations and maybe touch on if there are any efficiency related concerns or not associated with

Ati Modak: Hi, good morning team and thanks for taking my question.

Ati Modak: It seems like you moved more multiple more spot frac fleets for the rest of the year can you provide any color on the cost savings flexibility that brings to your operations and maybe touch on if that at any efficiency related concerns are not associated with that.

Daniel S. Harrison: Well, you know, we dropped the two rigs. We didn't have a need for as many frack crews, one, but we did, you know, it's obviously a squeeze on the frack crews, right, with the number of rigs dropping dramatically, and we have obviously gotten some concessions on pricing just due to the frack activity, and we We, you know, we've got a really good relationship with the FRAC provider that we got now, and so that's probably, I think, helped us a little bit with the pricing that we've been able to put into place for the rest of the year.

Daniel S. Harrison: Well, we dropped it to three rigs, but we didn't have a need for as many frac crews one but we did.

Daniel S. Harrison: It's obviously a squeeze on one the frac crews right with the number of rigs dropping dramatically.

Daniel S. Harrison: And then we have obviously gotten some concessions on pricing just.

Daniel S. Harrison: Due to the Frac activity.

Daniel S. Harrison: <unk>.

Daniel S. Harrison: <unk>.

Daniel S. Harrison: We've got a really good relationship with the Frac provider that we got now and so thats, probably I think helped us a little bit with the pricing that we've been able to put into place for the rest of the year.

Roland O. Burns: Got it, understood. And then as you think about the macro here for gas prices, any updated thoughts you can provide around the capital allocation strategy and balance sheet management with the sensitivity to gas prices as you are seeing?

Speaker Change: Got it understood and then as you think about the macro here far for gas prices.

Roland O. Burns: Any updated thoughts you can provide around the capital allocation strategy and balance sheet management.

Roland O. Burns: Sensitivity to gas prices as you are seeing.

Roland O. Burns: Yeah, we continue, of course, to monitor that, and we've had, you know, we have not only fairly volatile NYMEX prices but also spot prices that can be, you know, very volatile during the months based on, you know, how much gas is needed and where. So, you know, there's definitely, you know, you know, we've strategically done some shut-ins every now and then, it's usually for a We've delayed turning to sales, sometimes not opening them up in a spot market type scenario and waiting for a first of the month type.

Roland O. Burns: Yes.

Roland O. Burns: We continue of course to monitor that and we've had we have not only fairly volatile.

Roland O. Burns: Nymex prices, but also spot prices that can be very volatile during the March based on.

Roland O. Burns: Yes, how much gas is needed in and we're so yes, there is definitely.

Roland O. Burns: We've strategically.

Roland O. Burns: Do some shut ins every now and then.

Roland O. Burns: He has left for a day or two if we don't like to spot prices.

Roland O. Burns: We will continue to be able to <unk>.

Roland O. Burns: <unk> that and react to that.

Roland O. Burns: So we've, we've tried to, within the, you know, to maximize realizations in this really weak environment and continue to have the ability to, um, change the amount of rigs we're running. Uh, we definitely have the ability to, to defer, you know, turning wells to sales. So all those are still in the toolkit as we cut, look to navigate, you know, these next six months of expected weakness.

Roland O. Burns: <unk>.

Roland O. Burns: Turning to sales.

Roland O. Burns: Sometimes not to open them up in a spot market type scenario would wait for our first of the month type.

Roland O. Burns: We've tried to we've tried to manage within.

Roland O. Burns: To maximize.

Roland O. Burns: The realizations in this really weak environment and continue to have the ability to.

Roland O. Burns: To change the amount of <unk>.

Roland O. Burns: Rigs, we're running we definitely have that have the ability that to defer turning wells to sales. So all of those are still in the toolkit as we look to navigate this next upcoming six months.

Roland O. Burns: <unk> weakness.

Roland O. Burns: At the same time, you know, wanting to preserve the company's ability to benefit from the, you know, the stronger prices, which we've already started to lock into, you know, starting in the fourth quarter.

Roland O. Burns: At the same time wanting to preserve the company's.

Roland O. Burns: <unk> <unk> ability to benefit from the stronger prices, which we've already started to lock into starting in the fourth quarter.

Miles Jay Allison: I think the key is we do have that, like we said earlier in the conference call, our frack commitments. We don't have any frack commitments that are long term, so we can toggle those, and our frack provider has been very pro-Comstock, a big backer. So if we need to delay some of those fracks for the latter part of the year, then we'll have the choice to do that.

Miles Jay Allison: I think the key is we do have that ability like we said earlier in the conference and the conference call.

Miles Jay Allison: Yes.

Miles Jay Allison: Our frac commitments, we don't have any frac commitments that are going to long term. So we can talk of those and our frac providers has been very very probe Comstock vary.

Miles Jay Allison: A big backer so.

Miles Jay Allison: If we need to delay some of those fracs to latter part of the year.

Miles Jay Allison: We will have the choice to do that.

Ati Modak: Well, I appreciate you taking the questions. I'll turn it over to you.

Speaker Change: Alright, I appreciate you taking the questions I'll turn it over.

Operator: Thank you. One moment for our next question. Our next question comes from Noel Parks with the Tui Brothers. Please go ahead.

Speaker Change: One moment for our next question.

Operator: Okay.

Operator: Our next question comes from Noel Parks with Tuohy Brothers. Please go ahead.

Noel Augustus Parks: Hi, good morning.

Operator: No.

Noel Augustus Parks: A lot of interesting questions that got me thinking, and I was wondering, with your being at the two-year mark, I guess a little beyond for your first Western Haynesville well, I'm just wondering whether there are any surprises in the type curve as you've gotten more data, and with the tweaks you've made to completions, drilling completions, do you foresee that the type curve for the first wells is being kind of representative of I just get a sense of whether you're at the point where you kind of think you have a working benchmark for going forward.

Noel Augustus Parks: A lot of interesting questions and that got me thinking and I was wondering.

Noel Augustus Parks: Youre being at.

Noel Augustus Parks: Two year, Mark I guess, a little beyond for your first western Haynesville well I'm just wondering whether there are any surprises in the type curve as you've gotten more data.

Noel Augustus Parks: And.

Noel Augustus Parks: With the tweaks you've made to completions drilling and completion. Since then do you foresee that first wells type curves as being kind of representative of what you're going to see in the more recent wells.

Noel Augustus Parks: Okay.

Noel Augustus Parks: Whether you're at the point you kind of think you have a working benchmark for for going forward.

Miles Jay Allison: Well, you know, when we started drilling the first well over two years ago, two and a half years ago, we felt comfortable, Noel, that the resource was there. Because there was a major field, all the shakers that we now have secured, it was a major gas field. Uh, that's why the pinnacle plant was here and the 145 mile high pressure line was there. The question was, kind of like it was in, uh, 07, 08, could you use this technology there to really drill a shell plate?

Noel Augustus Parks: But when we when we started drilling the first well over two years ago.

Miles Jay Allison: Two and half years ago.

Miles Jay Allison: We felt comfortable no that.

Miles Jay Allison: Okay.

Miles Jay Allison: Resource was there.

Miles Jay Allison: Because there was a major field all of this acreage that we now have had secured is a major field gas field.

Miles Jay Allison: That's one of the critical plant was here in the 145 mile High pressure line with your other question was kind of like.

Miles Jay Allison: It was in <unk>.

Miles Jay Allison: <unk> can use this technology, there to really drill a shale play.

Miles Jay Allison: with a Bossier and a Haynesville, and we've proved that it was an 08-9 in the core. Now, I think we've seen kind of a mirror image of that. We've started to see that materialize in western Haynesville, but you don't know, right? I mean, the jury's still out. So, as you have this Circle M well producing for eight months, and our outside reservoir group gives us some reserves, and then the next year, they continue to be a little better, and the next year, a little better, it does give you a lot of confidence that the resources there, one, and then when you listen to Dan, it gives you confidence that the questions are, you know, how have you changed your drilling? Have you changed your completion?

Miles Jay Allison: Both the Bossier and the Haynesville and.

Miles Jay Allison: We've proved that it was not in the core now I think we've seen kind of a mirror image of that we have started to see that.

Miles Jay Allison: <unk>.

Miles Jay Allison: That materialized in the Western Haynesville, but you don't know right I mean, the jury is still out so as you have this circle them well.

Miles Jay Allison: Producing eight months in.

Miles Jay Allison: And our outside reservoir.

Miles Jay Allison: It gives us some reserves in the next year they continued to be a little better in the next year, a little better. It does give you a lot of confidence.

Miles Jay Allison: The resources there one and then when you listened to Dan.

Miles Jay Allison: It gives you confidence that the questions are.

Miles Jay Allison: Have you changed your drilling have you changed your completion, we're getting better and better and better.

Miles Jay Allison: We're getting better and better and better. Again, remember, no group has really completed the Haynesville-Bosier Wells period better than we have. So our confidence is really strong right now because we have seen this happen back in the core in 08, 09, 10, 11. If you were to look at those first wells where you get to have an upset stomach there, they weren't very good wells in 08, 9. And if you compare the results there versus our first 12 here, I mean, these look exemplary compared to what those wells look like in LA. So that's why we went out to secure our footprint. We went out, and we didn't try to push on the reserves.

Miles Jay Allison: Again remember no no group has drilled and completed more haynesville Bossier wells period that we have.

Miles Jay Allison: So our confidence is really strong run now because we have seen this happen back into core and all eight 910 11. If you were to look at those first wells that you had to have an upset stomach there weren't very good wells now eight nine.

Miles Jay Allison: And if you compare the results there versus our first 12 here.

Miles Jay Allison: I mean, this looks slick exemplary compared to what those wells look like currently.

Miles Jay Allison: That's why we went out to secure our footprint, we went out and we didn't try to to.

Miles Jay Allison: Push on reserves. We just said this is what we think the <unk> and so far they've held up really solid and in fact, we've seen improvements on them.

Miles Jay Allison: We just said this is what we think the URs are. And so far, they've held up really solid. And in fact, we've seen improvements on them. So that's what we're saying, cost down, AUR steady, maybe going up. That gives us this hope. As we say, this is our business plan to continue to add inventory and to de-risk our big footprint, which now we do.

Miles Jay Allison: So that's what we're saying costs down.

Miles Jay Allison: Our steady may be going up.

Miles Jay Allison: That gives us this hope as we say this is our business plan to continue well by well to add inventory into de risk footprint, which now.

Roland O. Burns: And Noel, I would add, you know, our first wells were Bossier fill wells because we were targeting, you know, a little shallower, a little less complex to drill, but we've got the confidence to drill Hainesville, and we think that our latest wells, being Hainesville wells, we think they're coming out of the gate stronger, but they don't have the two years of proof that the But that's what really excites us is the fact that Hainesville, just like Hainesville is better in Louisiana too, it always seems to be a little bit better. It's a better rock; it definitely fits better than the Bossier.

Miles Jay Allison: We do control.

Roland O. Burns: And that will allow us to add our first wells were Bossier shale wells, because we were targeting.

Roland O. Burns: Hello shallower little.

Roland O. Burns: Less complex to drought.

Roland O. Burns: We've got the confidence to draw the Haynesville.

Roland O. Burns: And.

Roland O. Burns: We think that our latest wells being Haynesville wells, we think they're coming out of the gate stronger yes, they don't have that.

Roland O. Burns: I don't have the two years.

Roland O. Burns: Proof that the first Bossier well has been.

Roland O. Burns: That's what really excites US is the fact that the Haynesville just like at the Haynesville is better in Louisiana to its always seems to be a little bit better it's a better rocket.

Roland O. Burns: It definitely complete spatter to the Bossier. So we're excited about the potential that the next batch of Haynesville warehouse.

Daniel S. Harrison: So we're excited about the potential that the next batch of Haynesville wellhouses holds. And we're really focused, you know, you can see most of the wells; we focus now on the Haynesville formation in the play. Umang Choudhary, Roland Burns, Daniel Harrison, Derrick Whitfield, Noel Parks, Charles Meade; A total of nine wills turned to sales this year; seven of those will be Haynesville, two will be Bossiers, but... Part of that early on was we, you know, obviously concerned with the high temperatures and increasing our chance of success and having a better drilling performance.

Daniel S. Harrison: And we're really focused here you can see most of the wells. We are focused now on the Haynesville formation in the play.

Daniel S. Harrison: Versus the Bossier I think we have wet six Bossier wells and I think we're almost half and half.

Speaker Change: Yes, that'd be right to date turned to sales basically about half and half on Bossier and Haynesville and we will have I will say, we'll we've leaned in heavier.

Daniel S. Harrison: On the Haynesville wells this year I think we're going to have.

Daniel S. Harrison: Total non wells turn to sales this year seven of those will be haynesville <unk>, but.

Daniel S. Harrison: Part of that early on was we.

Daniel S. Harrison: Obviously.

Daniel S. Harrison: Concerned with the high temperatures and increase in our chance of success and have a better drilling performance. We targeted the bossier early on but we've made such great progress with dealing with the temperatures that we know basically to see the the haynesville is so much of a challenge compared to the Bossier.

Daniel S. Harrison: You know, we targeted Bossier early on, but we've made such great progress with dealing with the temperatures that, you know, we now basically don't see Hainesville as such a challenge compared to Bossier.

Noel Augustus Parks: Great, thanks for the detail. And, um, I was, uh, just wondering, is it, um... The formation being defined on those, does that affect the spacing at all? Are there a lot of questions about what, ultimately, sort of, sort of the density you would be pursuing in the Western Haynesville?

Speaker Change: Great. Thanks for the detail.

Noel Augustus Parks: I was.

Noel Augustus Parks: Just wondering is it.

Noel Augustus Parks: The foundation being defrayed analyst that effect the spacing at all is it.

Noel Augustus Parks: Sure.

Noel Augustus Parks: Is there a lot of question about what ultimately sort of sort of a density would be pursuing them.

Daniel S. Harrison: Uh, sure, you know, obviously, these wells are expensive, and you're going to have to be really careful not to get them too close together and have, uh, a lot of interference between wells. I mean, you're not going to have as much of a margin for error for that in a play where you're deeper and got more extensive wells.

Noel Augustus Parks: And the western Haynesville.

Daniel S. Harrison: Sure.

Daniel S. Harrison: Obviously these wells are expensive.

Daniel S. Harrison: <unk>.

Daniel S. Harrison: Youre going to have to be.

Daniel S. Harrison: We're really careful not to get them too close together and have.

Daniel S. Harrison: A lot of interference between wells I mean, youre not going to have as big of a margin for error.

Daniel S. Harrison: For that in a play where you're deeper and got more expensive wells, but.

Daniel S. Harrison: We've got I mean, some of the stuff is really thick somebody asked earlier was really good question about how are we going to how we're thinking about the future development of this play.

Daniel S. Harrison: But we've got, I mean, some of the stuff is really thick. And, you know, somebody asked earlier a really good question about, you know, how are we going to, what are we thinking about the future development of this play? And because we do, we're blessed with that. The task to solve is, you know, how many, how many, how many can we stack on top of each other? And what's the spacing going to be?

Daniel S. Harrison: And because we do we're blessed with that with that task to solve is how many how many.

Daniel S. Harrison: How many can we stack on top of each other and whats the spacing going to be.

Daniel S. Harrison: Part of that is we wanted to get this last well, pump a bigger frack, and see what kind of recovery we get, you know, because that obviously will also affect the space. But really, to answer your question, we do not know what that exact spacing is going to be for the future. We'll just have to see what these type curves show us, what they look like, and, you know, where we end up.

Daniel S. Harrison: Part of that is we wanted to get this last well a bigger frac and see what kind of recovery would get because that obviously will also affect the spacing.

Daniel S. Harrison: But really to answer your question, we do not know what that exact spacing is going to be for the future and we'll just have to see what these type curves show us what they looked like in.

Daniel S. Harrison: Where we ended up with that.

Daniel S. Harrison: I know with our big acreage position, it could be a decade or more before we do any aggressive infield drilling.

Daniel S. Harrison: With our big acreage positions I mean, it could be a decade or more.

Daniel S. Harrison: Before we do any aggressive infill drilling.

Noel Augustus Parks: Wow. Okay. Great point.

Speaker Change: Wow Okay.

Speaker Change: Great point, Thanks, a lot.

Noel Augustus Parks: Thanks a lot.

Speaker Change: Thank you one moment for our next question.

Operator: Thank you. One moment for our next question. Our next question comes from Paul Diamond with Citi. Please go ahead.

Noel Augustus Parks: Our next question comes from Paul Diamond with Citi. Please go ahead.

Paul Michael Diamond: Uh, thank you and good morning. Thanks for taking my call. I just want to touch quickly on staying in Western Haynesville, you know, once you move beyond, uh, you know, held by production needs, where do they, where do you see their pad size going? I guess how much does that impact the economy over the longer term?

Speaker Change: Thank you and good morning, Thanks for taking my call I just wanted to touch quickly staying in the western Haynesville once you move beyond.

Paul Michael Diamond: By production needs.

Paul Michael Diamond: Where do you see the pad size going guess, how much is out compact economics over the longer term.

Operator: I didn't catch the full question wording there.

Speaker Change: I didn't catch the full question there.

Paul Michael Diamond: Oh, sorry. When you get beyond health and production needs, and you can, how big do you see the pad size getting out in Western Hainesville?

Speaker Change: Oh, sorry.

Paul Michael Diamond: When you get beyond the held by production needs and you can how big you see pad size getting out of western Haynesville.

Paul Michael Diamond: Our pad size.

Daniel S. Harrison: [inaudible] Well, I mean, everything that we have drilled to date in the core and in the Western Hainesville, you know, for multi-well pads. I mean, we're, Our pad, I think the biggest pad we've built is like 500 by 700 feet for multi-well pads. You know, occasionally we'll come back and add on to those if we come back and drill additional wells off the pad.

Daniel S. Harrison: Well I mean, everything that we have drilled to date in the core and in the Western Haynesville.

Daniel S. Harrison: Multi well pads I mean, we're.

Daniel S. Harrison: I think the biggest pad, we built 500 by 700 foot for multi well pads.

Daniel S. Harrison: Occasionally we'll come back and add onto those if we come back and drill additional wells off the pad but.

Roland O. Burns: He's probably interested in how many wells per pad we could look at. Obviously, we have both the Bossier and the Haynesville play. And then given our, you know, vast acreage, we're able to go both directions from the pad, you know, versus just one. So, you know, we're kind of at least...

Roland O. Burns: It's probably understated in that many wells per pad can we look at absolutely have the both the Bossier and the Haynesville play.

Roland O. Burns: And then given our vast acreage that we're able to go both directions from the pad versus just one so yes we.

Roland O. Burns: Seems like we're really targeting 10,000 foot laterals here as kind of an optimal area. So I think, you know, 10,000 foot laterals, multiple benches, and maybe each of Hainesville and Bossier, potentially, and then going from both directions from a pad. So quite a few wells could be on a pad in the future, which obviously creates a lot of efficiencies for, you know, everything, including the midstream hookup. Yeah, I'm sorry, I didn't understand that.

Roland O. Burns: We're kind of at least it seems like we're really targeting 10000 foot laterals here as kind of an optimal area. So I think 10000 foot laterals.

Roland O. Burns: Multiple benches, and maybe each of the Haynesville and Bossier potentially and then going from both directions from a pad so quite a few wells could be on a pad in the future.

Roland O. Burns: Which obviously creates a lot of efficiencies for.

Roland O. Burns: Everything, including the midstream hookup.

Daniel S. Harrison: Yeah, everything that we've got targeted today is for two well pads where we can do it. We drill in opposite directions to hold the maximum amount of acreage, but we do have them built. We'll come back and drill on these pads in the future with additional wells.

Speaker Change: Yes, I'm, sorry, I didn't get that.

Daniel S. Harrison: Yes, everything that we've got targeted today is for two well pads, where we can do it we do drill in opposite direction to hold the maximum amount of acreage, but we do have them built will come back and drill one of these pads in the future with additional wells.

Miles Jay Allison: You know, kind of all along the same line is take away, you know, are we going to have enough take away in the Western Angeville? And that's where we came in last year with Pinnacle, which is backed by Quantum. So, we are planning, as we drill these wells, you know, we're planning on taking away literally years ahead, not that we have to drill those wells at all, because most of it's

Miles Jay Allison: Kind of along those same line is.

Miles Jay Allison: Takeaway.

Miles Jay Allison: We're going to have enough takeaway.

Miles Jay Allison: In the Western Haynesville, and Thats, where we came in last year.

Miles Jay Allison: With critical which is backed by quantum.

Miles Jay Allison: So we are planning as we drill these wells.

Miles Jay Allison: Planning on takeaway literally years ahead.

Miles Jay Allison: We have to drill those wells at all because.

Miles Jay Allison: But, you know, we can plan our own path for taking away. So that's, that's very rare. And big acreage positions like this that don't have an aggressive drill schedule are very rare, too. So we know, if you capture this amount of acreage, it's a power $600 or less. That's typically when you make your money.

Miles Jay Allison: Most of that's HP.

Miles Jay Allison: We can plan our own path for takeaway.

Miles Jay Allison: So that's very rare.

Miles Jay Allison: Big acreage position is like this.

Speaker Change: I don't have a.

Miles Jay Allison: An aggressive drill schedule is very rare too.

Paul Michael Diamond: So we have captured that. And then the question is, do you aggressively have to drill it? The answer is no. And then you say, well, is the paint thickness there? The answer is, we think yes. And has the weld performance been positive? The answer is yes.

Miles Jay Allison: So we've captured this amount of acreage, it's a $600 or less that's typically when you make your money so.

Paul Michael Diamond: So we have captured that and then the question is are you aggressively after drill it.

Paul Michael Diamond: Understood. Thanks for the clarification.

Paul Michael Diamond: <unk> no.

Paul Michael Diamond: And then you say well is the pay thickness. There. The answer is we think yes.

Paul Michael Diamond: And as the well performance.

Speaker Change: There have been positive and answers yes.

Paul Michael Diamond: Just one quick follow-up, shifting back to the core. For the rest of the 2024 operational plan, I guess, what percentage is likely to include, you know, additional wells similar to the four Bozier ones you drilled in Q1 that are kind of required to hold the acreage? Can you ask that again? Sure. And the 2024 operational plan. So in the first quarter, there were four of those bozier wells, shorter laterals required to hold the acreage. How much of that should we expect?

Speaker Change: Understood. Thanks for the clarity just one quick follow up shifting back to the core.

Paul Michael Diamond: For the rest of the 2024 operational plan I guess what percentage are likely to include.

Paul Michael Diamond: Additional wells somewhere before Bossier wells you drilled in Q1 that are required to hold the acreage.

Paul Michael Diamond: Can you ask that again.

Speaker Change: Sure. The 2024 operational plan so in the first quarter. Therefore, those bossier wells shorter laterals required to hold the acreage how much of that should we expect to.

Paul Michael Diamond: Oh, there's no more.

Speaker Change: There is no more.

Daniel S. Harrison: I'll tell you, so interestingly enough, you know, we do have some additional sections that will come up. We've actually got a, we're actually going to drill one of these horseshoe wells later this year. I'll go ahead and tell you that.

Daniel S. Harrison: That's kind of something that we're looking forward to trying, but we don't have many of the We don't have many of these isolated sections left where we'll have any of those issues.

Speaker Change: Yeah. So interestingly enough. We we we do have some additional sections that will come up we've actually got a.

Daniel S. Harrison: We're actually going to drill one of these horseshoe wells later this year I'll go ahead.

Daniel S. Harrison: So that thats kind of soften that we're looking forward to trian, but.

Daniel S. Harrison: We don't have many of the we don't have many of these isolated sections left where we will have had any of those issues.

Miles Jay Allison: Yeah, and I think the key to that is... If you don't think they're valuable, you don't drill them. And we think they're valuable enough to drill. So even if they're shorter, I mean, they're very economical. We're excited about

Miles Jay Allison: And I think the key to that is.

Miles Jay Allison: If you don't think they are a valuable you don't drill them and.

Miles Jay Allison: And we think they are a valuable enough to drilling so even if they're shorter coming to it.

Daniel S. Harrison: We're excited about the horseshoe design, and it could eliminate the stranded, you know, shorties, as we like to call them, the 5,000-foot lateral wells. It has the potential to allow you to eliminate those and turn it into a horseshoe well and have a long lateral well on one section. So that'll be kind of an exciting thing to do here later in the year. understood.

Miles Jay Allison: Theyre very economics, we're excited about the horse you to them and they can eliminate in out of that the stranded <unk> as we like to call them.

Daniel S. Harrison: The 5000 foot lateral wells.

Daniel S. Harrison: Has the potential to allow you to eliminate those and turn it into a horseshoe well and have a long lateral well, yes on one section. So that's that will be kind of an exciting.

Daniel S. Harrison: Thing to do here later in the year.

Speaker Change: Understood. Thanks for the clarity.

Daniel S. Harrison: Thanks for clarifying. Because we do believe that shorter laterals in the basic Haynesville are definitely our lowest return projects, just because of the so much cost into the well and the reserves you recover with only the shorter lateral. So that the ability to eliminate a lot of those that are inventory and turn them into longs will be, you know, it will be very beneficial.

Daniel S. Harrison: Because we do believe that shorter laterals in that.

Daniel S. Harrison: And the basic Haynesville are definitely our lowest return projects just because of so much cost into the well and the reserves you recover with only that a shorter lateral so that so the ability.

Daniel S. Harrison: To eliminate a lot of those out of our inventory and turn them into along as.

Speaker Change: Yes, it will be very enhancing.

Speaker Change: I appreciate it.

Operator: Thank you. I'm showing no further questions at this time. I'd now like to turn it back to Jay Allison for closing remarks.

Daniel S. Harrison: I'm showing no further questions at this time I would now like to turn it back to Jay Allison for closing remarks.

Miles Jay Allison: Hey, perfect. Again, I know everybody's time is valuable, and we thank you for sharing your time with us. You know, Comstock, we do recognize the growing need for natural gas around the world. I mean, our long-term goal, as we said over and over and over, is to be a significant supplier to the growing LNG market that's developing really several hundred miles from our Hainesville Shell operations, including our western Hainesville area.

Miles Jay Allison: Perfect again, I know everybody's time is valuable and quick.

Miles Jay Allison: We thank you for sharing your time with US Comstock, we do recognize the growing need for natural gas around the world.

Miles Jay Allison: Our long term goal as we said over and over and over is to be a significant supplier to the growing LNG market is developing to really show several hundred miles from our Haynesville shale operations, including our western Haynesville area. So.

Miles Jay Allison: So, we're going to be good stewards with your money. We want to thank the bondholders. We want to thank our banks that support us. We want to thank the Joneses that support us, and the other stakeholders, and the service companies. Everybody has kind of teamed up and has helped Comstock over the last hundred days. So, we're thankful for that. Thank you for your time.

Miles Jay Allison: We're going to be good stewards with your money, we want to thank the bondholders, we want to thank our banks that support us we want to thank the joneses at support us and the other stakeholders and the service companies everybody over the last 100 days is kind of teamed up and has helped.

Miles Jay Allison: As have gone Scott So we're thankful for that thank you for your time.

Operator: Thank you for your participation in today's conference. This concludes the program. You may now disconnect.

Speaker Change: Thank you for your participation in today's conference. This concludes the program you may now disconnect.

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