Comstock Resources, Inc. Price & Performance (CRK)

Thank you, and good morning, everyone. What a fantastic morning here in Christo, Texas with snowflakes coming down when I woke up. I looked at the temperatures in Frisco, it was 15 degrees feeling like a minus two. Now scrolled and look at New York, it was 19 feeling like five, Chicago, four, feeling like a minus four. And in Boston, it was 15, feeling like two. So now let me tell you the story, the latest news about comps Resources, which is a pure natural gas company. We're excited to report today the great success we've had to date in our Western Haynesville play in Texas Over the past five years, we have been acquiring acreage in the Western Haynesville based on geologic data we put together including well logs from the many producing vertical wells near area Today, we hold five eighteen thousand net acres in our Western Angel area in addition 1,000 net acres in our legacy Haynesville area, There's 518,000 net acres in the West Haynesville represents a massive footprint is fairly contiguous allowing us to drill two wells from a single pad to hold two separate units as we drill north and south from the same pad.

Our initial Western Haynesville well, the Circle M well, was turned to sales in April of twenty twenty two we waited five months before we spread our second well evaluating the Circle M's performance. The end of twenty twenty three, We had seven wells producing and today we have eight Western Haynesville wells producing. During our leasing phase, our hardworking land team never lost perspective or focus as they built our position. With acquisitions and grassroots leasing we now have around 20,000 leases that make up the 518,000 net Western Haynesville acres. Fortunately, 80% of this acreage is HPP ed from our acquisitions of deep rights. That leaves us around 70 wells to be drilled over the next five years to HPP the entire footprint. At the beginning of our undertaking to de risk the Western Haynesville well by well, we made sure that 100% of our team held no distorted view of reality Reality is truth. There is an old cowboy saying, quote, if the horses did dismount, our Western Hansel horse looks to be very much alive and potentially a triple crown winner even a secretariat in the making Given the success we saw, we decided to forego the M and A market and focus on organic growth The challenge in the Western Angel was not geological, as we are confident the shale is there The challenge was drilling 10,000 foot horizontal wells at vertical depths of 19,000 feet where temperatures can exceed 400 degrees.

As we will report today, our operations team led by Dan Harrison has met the challenge with the first 18 successful wells they've continued to get better and better as we hone in on the formula to drill complete either Bossier or Haynesville wells in this area We have substantially reduced the well cost as Dan will review later today which puts the returns from these wells superior to the returns we see in our legacy Haynesville area. We've been very cautious as we developed our Western Haynesville footprint 2020 and 2021 were mainly focused on leasing In 2023, we reached out to Quantum Capital Solutions to help us fund the mid spring build out for the new play. Quantum committed up to $300,000,000 for the At 2024, we kept two rigs busy in the Western Hazel and turned 11 new wells to sales and now we have four rigs in the new play and we'll drill 20 more wells this year. The creation of the Western Angel opportunity is quite a feat for a company of our size This could not have happened without the total support of Jerry Jones and his family who own 71% of Comstock. They saw the vision, they got into wheeze with us as we kept our focus to capture the prize approving a vast natural gas reserves beneath our two our 518,000 net acre footprint.

Today, we feel the land grab is over with us holding the 518,000 net acres. We also own and control our midstream system with Quantum as our partner. Our Western Haynesville well results look very promising at a time when America needs more natural gas to meet the growing demand for LNG, [indiscernible] and all the industrial growth along the Gulf Coast Our Western Hansel is located several hundred miles from the Gulf Coast where 100,000,000,000 plus of LNG facilities are located. Our location is why LNG companies utilities, data centers and industrial users are contacting us to be a future supplier. To have substantial natural gas reserves near the proximity of the growing demand, on the Gulf Coast will serve us well in the next decade. The golden age of natural gas is here and we're on the leading edge of technology to unlock the value of the Western Haynes Today is the very first day we've shown the location of our 518,000 net Western Hansel acres as we have closed the large acquisitions we have been working on and captured much of the leases that we wanted We also are providing specific well data on the first 18 wells as we now have a large enough sample size to evaluate the results.

So now I'll open up this call with our standard introduction and disclaimer. If you would all go to Slide one, Welcome to the Comstock Resources fourth quarter twenty twenty four financial and Operating Results Conference Call. Site at www.comstockresources.com and downloading the quarterly results presentation there you'll find a presentation entitled Fourth Quarter twenty twenty four Results I have Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our and Chief Financial Officer, Dan Harrison our Chief Operating Officer and Ron Mills, our VP of Finance and Investor Relations. Please refer to Slide two in our presentation to note that our discussions today will include forward looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Now, if you would go over to Slide four or Slide three, which is our 2024 accomplishments. On Slide three, we highlight our major 2024 Most importantly, we successfully navigated last year's very low natural gas crisis Our realized gas price before hedging of $1.98 per Mc in 2024 represented a thirty year low if you We acted early in 2024 to significantly reduce our capital spending by releasing two operated rigs and one frac spread, we also suspended our quarterly dividend to conserve cash flow.

We increased our hedging program, which improved our 2024 realized gas price by 20% It also safeguards our 2025 and 2026 drilling programs by targeting 50% of our expected production. We shorted up our balance sheet by adding hundred $500,000 to an equity private placement with our majority stockholder and enhanced our liquidity with a $400,000,000 senior notes offering During this year of low natural gas prices, we were also able to grow our Western Amnesville footprint. We more than doubled our acreage position to 518,000 net acres by acquiring 265,000 net acres at a cost of $4.01 per acre. We made terrific progress proving up our Western Haynesville exploratory We successfully turned 11 wells to sales with an average IP rate of 38,000,000 cubic feet per day and now have a total of 18 wells producing into play. In the fourth quarter, we were able to significantly reduce our drilling and completion costs in the Western Haynesville compared to the 2022 level. The drilling costs for lateral foot and our new play are down 33% and the completion costs for lateral foot are down 28%. Overall, our 2024 drilling program delivered solid results and proved reserve growth despite the lower activity last year.

We drilled 50 or 42.9 net wells successfully operated Haynesville Bossier wells with a strong average IP rate of $26,000,000 per day Our 2024 drilling program replaced 107% of our 2024 production and drove 6% reserve growth With eight ninety nine Bcf of drilling related reserve additions and achieved an overall finding cost of $1 per Mcfe. Despite suspending our quarterly dividend, we still deliver the highest 2024 total shareholder trading on a major exchange. If you will flip over to Page four it's the Haynesville shale footprint. Slide four is an overview first time ever of our acreage footprint position in the Haynesville, Bossier shale and East Texas And Note that this map is to scale it's not distorted. We have 1,099,000 gross and 819,000 Net acres that is prospective for commercial development of the Haynesville and Bojer Fields On The Left Is Our Emerging Western Haynesville and on the right is our legacy Haynesville area. Since the beginning, our leasing program in the Western Haynesville play in 2020 we have grown our acreage position to 518,000 net acres. We still have around 1,300 net location to drill on our 301,000 net acres in the legacy Haynesville which currently has eight ninety five net producing wells at Our legacy Haynesville acreage is 48% developed for the Haynes shale and 8% developed for the Bossier shale In comparison, our Western Haynesville has only eight eighteen net producing wells and is virtually undeveloped compared to our legacy Haynesville.

We expect our Western Haynesville acreage to provide more EBIT versus the legacy Haynesville given the higher pay fitness and pressures we encounter in the Western Haynesville, we expect the Western Haynesville to yield significantly more resource potential per section than our legacy Angola I will now turn it over to Roland to discuss the financial results reported today. Roland? All right. Thanks, Jay. On Slide five, we cover our fourth quarter financial results. Our production in the fourth quarter averaged 1.35 Bcfe per day, is 12% lower than the fourth quarter of twenty twenty three reflected our decision to drop two rigs early in 'twenty four and drop and have that frac holiday that we had in the third quarter. The only way we turn to sales in our legacy Haynesville area in the quarter was our Horseshoe well that we discussed last quarter. So oil and gas sales in the quarter declined 5% to $336,000,000 due to the lower production level which is partially offset by better natural gas prices. EBITDAX for the quarter was $252,000,000 and we generated $23,000,000 of cash flow during the quarter. We reported adjusted net income of $46,000,000 for the fourth quarter of $0.16 per share, compared to a net loss of $0.16 per share, compared to a net loss of $0.16 per share, In the fourth quarter, we recognized a $52,000,000 tax benefit related primarily to R and D credits and other credits, and also due to a reduction in the Louisiana State corporate tax rate a higher provision for depreciation, depletion and amortization accounted for the loss before income taxes in the quarter.

The higher amortization rate resulted from the decrease to our proved undeveloped reserves which were determined under SEC rules where you have to use the first of the month average price looking back for the previous twelve months. Course, that price was very low in 2024. On Slide six, we recap the annual 2024 financial results. Production for the full year average 1.4 Bcf per day, which is very comparable to production we had in 2023. Natural gas prices that we realized in 2024 fell by 7% resulting in our oil and gas sales decreasing 7% to $1,300,000,000 EBITDAX in 2024 totaled $850,000,000 and we generated $675,000,000 of cash flow We weaker natural gas prices and the higher DDA expense we reported an adjusted net loss of $69,000,000 2024 or $0.24 per share compared to the $133,000,000 net income we had in 2023. [indiscernible] further break down our natural gas price realizations in the quarter and For the the previous quarters. The quarterly NYMEX settlement price averaged $2.79 per Mcf in the fourth quarter, and the average Henry Hub spot price in the quarter averaged $2.42 The 45% of our gas in the fourth quarter was sold in the spot market, so the [indiscernible] market price reference price for our gas that quarter was $2.62 Our realized gas price during the fourth quarter averaged $2.32 reflecting a $0.3 differential for the quarter.

We were 51% hedged in the fourth quarter that improved our realized gas price $2.7 We also had a $0.05 uplift to our overall gas price realization from purchasing third party gas to utilize our available transport. On Slide eight, we detail our natural gas hedge position that we have to protect cash flows this year and in 2026. We have approximately 50% of our gas production hedged for this year at an average price of $3.48 or better. 22% is in price swaps and the remaining is the form of costless collars with a floor of $3.5 and a ceiling of $3.8 59% of our hedge position is in collars with the same floor level of $3.5 but a higher ceiling price of $4.35 then the remaining 41% of our 26 hedge position are in gas price swaps which averaged $3.51 per Mcf. On Slide nine, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost averaged $0.72 in the fourth quarter which was $0.05 lower than the third quarter rate. Our EBITDAX margin improved to 73% in the fourth quarter as compared to 67% in the third quarter So our production and abnormal arm taxes were down $0.03 in the quarter primarily reflecting the lower statutory severance tax rate we have in Louisiana into effect in the middle of the year [indiscernible] our lifting cost for the quarter increased $0.03 while our gathering costs were down $0.05 in the quarter.

Overall, our G and A Comstock were unchanged at $0.05 in the fourth quarter. Slide 10, we recap our spending on drilling and other development activity that we had in the fourth quarter and for all of last year. We spent a total of $240,000,000 on development activities in the fourth quarter and we spent $9.00 $2,000,000,000 for the full year. In 2024, we drilled 32 or 25.8 net horizontal Haynesville wells and 18 or 17.1 net Fosier wells. 48 wells or 42.9 net operated wells to sales which had an average initial production rate of $26,000,000 per day. On Slide 11, we recap our proved reserves at the end of 2024 determined based on year end NYMEX market prices which have been adjusted for our differentials. As compared to the much lower prices that we'd have to use for SEC purposes and to determine DD and A in the financial statements. Using year end NYMEX prices, we're able to grow our proved reserves by 6% even though we had reduced overall drilling activity last year. Our proved reserves totaled seven TCFE. We added eight ninety nine Bcf of drilling additions, which replaced 70% of what we produced last year or five twenty eight Bcfe.

We spent $9.00 $2,000,000 on that drilling program right at $1 for 2024. In addition to the proved reserves, There's an additional 2.1 TCFE of proved end of up reserves, which are not included because they're not expected to be drilled within the next five year period as required by SEC rules.

Otherwise, they could be included in proved reserves. We also have another 2.4 TCFE of 2P or probable reserves and 6.9 TCFE of 3P or possible reserves give us the total reserve base of 18.4 TCFE on a P3 basis.

This does not include the reserve potential for much of the Western Haynesville acreage.

Slide 12 recaps our capitalization at the end of 2024.

We ended the quarter with $415,000,000 of borrowings outstanding under our credit facility given us $3,000,000,000 in total debt including our outstanding senior notes.

Our borrowing base is currently at $2,000,000,000 and our elected commitment under our credit facility remains at $1,500,000,000 With improved natural gas prices and the strong hedge position, we expect our leverage ratio to improve significantly as we start to report the 2025 financial results.

At the end of the fourth quarter, we had approximately $1,100,000,000 of financial liquidity. On Slide 13, we summarize the market hubs that we sell our natural gas at.

Our proximity to the growing natural gas demand from LNG terminals petrochemical and industrial complexes along the Gulf Coast gas price realizations compared to most of our natural gas peers. 68% of our gas production is sold Gulf Coast Markets, using our long term transport agreements with the balance sold at the regional hubs at Perryville Carthage and Bethel. Selling directly to end users and having access to various Gulf Coast hubs provides us the ability to take advantage of changing market conditions [indiscernible] A daily basis. And then starting this year, we have access to a storage facility near our Bethel plant giving us greater operational flexibility and the ability to take advantage of seasonal pricing. On Slide 14, we show the footprint of our midstream system in our Western Haynesville area.

Late twenty twenty three, we partnered with Quantum Capital Solutions to create Pinnacle Gas Services To fund the needed expansion of our existing midstream assets in the Western Haynesville, to handle the growing production from this area. So we contributed our Pinnacle Gathering and Treaty System to the partnership then Quantum is continuing the capital to build out the gathering and treating system in this area. We currently have two forty six miles of high pressure pipelines that run across the middle of our acreage as you can see on Slide 14. We have a a gas treating plant at Bethel at the north end of our system and we're currently constructing a new 400,000,000 a day treating plant at Marchex, Texas on our southern end. So I'll now turn it over to Dan to discuss our operations. Okay. Thanks, Roland.

If you look at Slide 15, this is our updated drilling inventory. At the end of last year, 2024. Our total operated inventory year end stands at fifteen forty eight gross locations and twelve eleven net locations quite still a 78% average working interest Our non operated inventory we have eleven ten gross locations or 139 net locations, which represents a 13% average working interest. The drilling inventory is split between Haynesville and Bossier wells, divide Our short laterals are less than 5,000 feet.

Our medium laterals are between 13,500 feet. Our long laterals are between 518,000 feet.

And our extra long laterals are all laterals over 10,000 feet.

In our gross operated inventory, we now have 53 short laterals, three thirty seven medium laterals, five seventy long laterals and five eighty eight ex [indiscernible] [indiscernible] Our gross operated inventory is evenly split with 51% in the Haynesville and 49% in the Bossier. The updated drilling inventory also includes the impact of identifying 113 Horseshoe [indiscernible] The average lateral length at our inventory is now at 9,603 This is up from 9,261 feet at the end of the third quarter. Due to converting more of our short laterals to the long lateral horseshoe wells. 75% of our inventory is now composed of laterals greater than 10,000 feet. And our inventory provides us with over thirty years of future drilling locations based on our current activity levels.

On Slide 16 is a chart outlining our average lateral length drilled based on the wells that had have been drilled and have reached PD or total depth. We have split out the data between both our legacy Haynesville and West In 2024, the 39 wells that reached total depth in the legacy Haynesville had an average lateral length of 10,922 feet.

The individual lengths range from 4,222 feet to 17,400 feet. So our record longest lateral now stands at this 17,400 feet.

In 2024, the 11 wells that reached total depth in the West Haynesville had an average lateral length of 10,182 feet.

The longest lateral we have drilled to date in the Western Hansville had a lateral length of 12,763 feet. In the fourth quarter, we only turned one well to sales in the legacy Haynesville area and this was our Sebastian No. 5 Horseshoe well that we discussed on our third quarter In the Western Hazel, we turned six wells to sales during the fourth quarter and five of these wells returned to sales over the last ten days of the quarter.

Or of the year. To recap, our long lever like activity today, we drilled 110 wells with laterals longer than 10,000 feet and we have 40 wells with laterals over 14,000 feet. [indiscernible] Slide 17 outlines the wells that returned the sales in the legacy Haynesville in 2024. In 2024, we turned 37 wells in the legacy Haynesville to sales.

The individual IP rates on these wells range from 9,000,000 a day up to 42,000,000 cubic feet a day with an average test rate of 23,000,000 today. The average lateral length was 10,104 feet and the individual laterals ranged from 4,222 feet to 15,303 feet. This list includes our first four, if you will, the Sebastian eleven-eight [indiscernible] was turned to sales in October with an IP rate of $31,000,000 a day. Which we discussed on the third quarter call.

Other than the Horsea well, we did not turn any new wells to sales in the fourth quarter as we deferred that completion activity to wait for the improved natural gas price Two of our six rigs are currently drilling on our legacy Haynesville acreage.

We do expect to add another rig to the legacy area later this year if the gas prices remain attractive. Slide 18 outlines the wells that we turned to sales in the Western Haynesville in 2024. In 2024, we had 11 wells turned to sales The individual OP rates on these wells range from 31,000,000 a day up to 44,000,000 cubic feet a day with an average test rate of 38,000,000 cubic feet per day.

The average lateral length was 10,032 feet.

And the individual laterals range from seventy seven sixty four feet up to 12,055 feet. Six of the 11 wells returned to sales in the fourth quarter and five of those the last ten days of the year. We do have four of our six rigs are currently drilling on our Western Haynesville papers. Slide 19 highlights total drilling days and the footage per day drilled in the legacy Haynesville In 2024, our wells in the legacy Haynesville area averaged twenty six days to total depth. This represents a 10% improvement over 2023. Over the last eight years, our drilling time in the legacy Haynesville area has averaged twenty seven point five days The improvement in the drilling days is a function of the footage drilled per day. In 2024, we averaged nine twenty feet per day drilled in the legacy Haynesville representing a 6% improvement over the twenty twenty twenty three average of eight sixty seven feet per day. Since 2017, the footage yield per day has increased 35% with the fourth quarter of 'twenty four The footage of drill per day of ten twelve feet is up 49% since 2017.

Our best well drilled to date in the legacy Haynesville average fourteen sixty one feet per day. There's a number of drivers to the recently improved drill times in the legacy Haynesville. The main driver has been drilling the longer laterals Since 2017, our average lateral has increased by nearly 4,000 feet. In addition to just the normal things and minimizing problems and maintaining consistency, there are other factors leading the drilling efficiencies and then the application of managed pressure drillings, rig upgrades and the continued improvement in our downhole motor performance.

Slide 20 highlights the significant improvements achieved in our drilling times in the Western Since we split our initial well in the fourth quarter of twenty twenty one, we have seen significant and continuous improvement in our drilling times.

Our first three wells were drilled in 2022 and averaged ninety five days to reach TD. And this includes executing a very difficult sidetrack we had on our second well. Our average drilling time improved 26% down to seventy days in 2022 and we improved another nineteen down to fifty seven days in 2024. We've drilled 21 wells to total depth through the end of the year.

The fastest well was drilled to TD in forty one days and that will during the fourth quarter. This represents an improvement of 45% or thirty five days compared to our first well our first well that was drilled to total depth in seventy five days The The improvement in drilling days is a function of the footage you drilled per day.

And our first three wells in 2022 averaged two eighty one feet per day and that has steadily improved to four eighty seven feet per day in 2024.

We averaged five forty seven feet per day in the fourth quarter of twenty four and the fastest well in this group drilled a record six zero eight feet per day. On average, our daily drilling footage has doubled since we started in 2022 through the end of twenty twenty four. There are several drivers behind our improved drilling performance. In the Western Highness Full Starting in the vertical hull, we've improved our casing point selections We've streamlined our casing designs.

In the verticals through improved bit selection And in the laterals, we're utilizing thermal drill pipe and continue to see more consistent motor performance as we continue to have just with the additional drilling activity. We also started incorporating two well pads into our drilling program in mid in the middle of last year. Slide 21 is a summary of our is the summary of our D and C Comstock through the fourth quarter for our Mid Mark long lateral wells located on the East Texas, North Louisiana legacy acreage position. This covers all the wells with lateral's greater than 8,500 feet Our drilling costs are based on when the wells reach TD. This better aligns with when the drilling dollars are spent. Our completion cost per foot continues to use the turn to sales dates. In the fourth quarter, our drilling cost averaged $660 a foot This is a 1% decrease compared to the third quarter. And in the fourth quarter, our completion cost came in at $863 a foot which represents a 7.5% increase compared to the third quarter During the fourth quarter, we only turned the one well to sales in the legacy Haynesville and that was Sebastian 11HQ, number five, single Horseshoe that returned to sales in October.

Both the drilling and completion Comstock trends show the impact of the significant inflation that took place starting in 2022.

And looking ahead, we're anticipating our D and C cost on the legacy Haynesville acreage to remain relatively flat to slightly lower for the next couple of quarters. We did start seeing our pipe prices come down Late last year, we do expect to maintain these cost savings through the next couple of quarters. The cost expectations are a little more uncertain out past midyear with potential uptick in activity looming with the higher gas prices and the possible tariffs discussions that are weighing on pipe prices.

We are currently running two rigs on our Lexington Haynesville acreage and we anticipate adding a third rig later this year at the gas prices. Stay attractive. On Slide 22, this is a summary of our D and C cost through the fourth quarter for all the wells we have drilled in the Western High School. Slide provides the drilling and completion costs for all the wells we've drilled into play to date. We have spent a large amount of exploratory capital on our first 10 to 12 wells drilled in the Western Haynesville as evidenced by the higher drilling and completion costs through the early part of twenty twenty four We've accumulated a wealth of knowledge drilling those early wells that is now paying big dividends for us. The early exploratory D and C capital allowed us to hone in on the good well designs for future wells And as a result, we've been able to reduce our latest in D and C capital to a point lower than our original estimates of roughly double what our legacy Haynesville wells cost.

Our fourth quarter drilling cost while our fourth quarter completion cost came at $13.15 dollars a foot. In addition to some of the main drivers affecting our drilling efficiency, such as the streamlined casing design, faster drilling, in the vertical hole, the utilization of the thermal drill pipe and our improved run times in the lateral This also from the impacts of starting our two well pads and our drilling program in the middle of last year, which help us to save additional days off our drill times. We've also had great execution on our completions and integrating the two well pads into our program.

Has allowed us to be much more efficient with our frac crews and our wireline crews. Also, it meant all our Western Haynesville rigs are new rigs that we had built with our Western Haynesville drilling program in mind. In closing, I just want to say to get where we are today has been highly rewarding. It's been a total team effort across the board. Everybody pushing to improve and all phases of our operations. I'll now turn the call back over to Jay. As all of you know, there's a lot of data when you include the West from Haynesville rolling down. Thank you for the transparency for the fourth quarter and the full year. 2024. If everyone would go to Slide 23, I'll direct you to Slide 23 where we summarize our outlook for 2025. In 2025, we will remain primarily focused on building our great assets in a way Haynesville that will position us to benefit from the longer term growth in net gas demand. We currently have four operated rigs drilling into Western Angle as Dan said to continue to delineate the new play. We expect to drill 20 or 19.9 net wells and turn 17 or 16.9 net wells to sales in the Western Haynesville of this year.

We will continue to build out the Western Haynesville midstream assets to keep up with the growing production from the area. Midstream expenditures are expected to be $130,000,000 to $150,000,000 They will all be funded by our midstream partner. In the legacy Haynesville, we will run two or three rigs depending upon prices to build production back up by the fourth quarter, we expect to drill 26 or 20.4 net wells and turn 29 or 22.8 net wells to sales a legacy handful this year. We anticipate funding our drilling program as Roland said out of operating cash flow and use any excess cash flow to pay down debt. We continue to have the industry's lowest producing cost structure and expect drilling efficiencies to continue to drive down D and C costs in 2025 in both the Western and legacy Haynesville assets. We have strong financial liquidity totaling almost $1,100,000,000 Note on Slides 2425, we provide some specific guidance for the rest of the year We'll now turn the call back to the operator to answer questions from analysts who follow the company. Thank you. As a reminder, Taff And our first question will come from Derek Whitfield with TEC Well, good morning, all, and thanks for your time.

Also congratulations on the position you have assembled in the Western Haynesville as your Mac is a dream scenario for anyone pursuing organic leasing program in a new basin.

Thank you. I have two questions and they're both related to Western Haynesville. [indiscernible] you're drilling arguably the deepest and most complex parts of your position today as we understand the geology. Do you have a view on reservoir quality as you move to the West to the shallower portions of the sub basin? Surely D and C costs would decrease, but there's is there a chance that reservoir quality would support recoveries in the 2.5 to three Bcf?

Derek, this is Dan. I think that's a very good question. We are drilling the deeper the deepest, hottest stuff if you look at where the well locations are across the acreage. We haven't drilled anything up there on that part of the acreage. A lot of that stuff is HBP acreage. So we're drilling the stuff that we've leased in the hole and that will kind of keep us down in that general area. And as we stand up to the Northeast, for the kind of the near term activity in the next couple of years, But kind of to answer your question, I think as you get up in that acreage, you're talking about, it does get shallower, the TBDs get shallower and a little bit cooler.

So I think it just remains to be seen what the EURs are going to look like, but I would certainly think maybe a hairless just if you just correlate it to depth. But we also expect our D and C costs are going to be a lot lower when we drill up there in the future. And I think our D and C costs are going to be a lot lower just drilling where we're at now in the future. We're We're still kind of going up the learning curve. We haven't plateaued yet on even the lower cost that we're at today. To your point, I think it's really good. We didn't start out with the easy depths. We started out with the deeper depths, the hottest depths. And we we looked at what reality looked like and they look really good.

And that's where we ended up with these 18 wells. It was a big enough data set so that we could actually come out and talk about the cost and in all major Tier one plays, more you drill the wells and complete them, typically the cost structure comes down. Exactly like it did in the core of the Haynesville Bossier going back to 02/2008 to 2011.

And as my follow-up, I wanted to focus on the D and C cost compression you highlighted on Page 22. Specifically focused on the completion side, the degree of a step down in Q4 suggests there's more opportunity there, which is kind of what Dan suggested as well. But in comparison to your legacy Haynesville, is the added Comstock largely associated with higher treating pressures? Are there or are there other considerations And I guess more broadly, how much lower could you drive that? I think we have more room to probably lower our costs on the drilling side. I mean, we've seen a bigger drop on the drilling side than the completion side. I think we have room to lower the completion cost a little bit further. I think that Q4 cost we have in there at $13.15 dollars a foot, that's kind of a number that we're planning with for the future wells just for forecasting. Kind of you asked about treating pressures. Yes, So as far as compared to the legacy Haynesville the treating pressures are definitely much higher down here just based on the depth and the frac gradients. The beauty is in the Western Heisel, the fracs very consistently.

So it's been really kind of trouble free. But it's a lot more horsepower and we do pump slightly bigger jobs in the Western Haynesville On an average, we pump about 4,000 pounds per foot and in the core, we pump about 3,500 pounds per foot. So that's also part of it. Yes. And Dan, I'd add to just you look at Comparing the Western Haynesville to the legacy Haynesville, I mean, we are having to build all the infrastructure, the new pads, I mean, we're really starting from scratch there. And the legacy Haynesville, you've got a lot of infrastructure that we built long time ago and we're often using pads we built a long time ago. So, yes, there's a huge difference in the upfront cost. These early wells are bearing all that cost in the numbers. And then as you come back and infill drill and continue to develop to the future wells would be able to utilize that investment we're making today.

Yes.

And I'll just add to what Roland said. We are building larger pads in the Western High School to be able to come back and drill future wells.

Great update, guys. Thank you.

And the next question comes from Carlos Escalante with Wolfe Research. Your line is open. Hey, good morning, gentlemen. I wanted to first congratulate you all on the incremental color on the Western Angel really encouraging to see the results. Let me start with a follow-up to the last question, but more geared toward the development plan. Could you speak this is perhaps for Dan, could you speak to what a typical development plan would look like for your average Western Hainesville pad in terms of how many wells you would expect on any given pad? And what your general assumption for spacing would be knowing, of course, that it's probably too early to know what the right spacing is?

Yes. The last piece of that is definitely too early drilling the whole acreage. The wells are spread out. So we haven't really honed in on what the spacing is going to be. I think we're going to have to accumulate a lot of data in the future I want to know what the optimum spacing will be in the Bossier versus in the Haynesville areas where it's thicker versus thinner. I think we're going to all yield different So, I don't have a direct answer to that question. But far as future development, we we strive to drill everything with two well pads that we can. We're drilling and we're holding acreage. In some places, you just just don't acreage doesn't give you the opportunity to drill to two laterals, two wells on the pad. So I think we're probably looking at about half 50% maybe 60% of our wells any given year will be on two well pads and the others will be singles. We strive to make as many two well pads as we can, but that's probably going to be our mix for the next couple of years. And one thing we've tried to do, look, we derisk maybe 26 miles of this play.

We show that on the map. And our goal is by the end of twenty twenty five, drilling 20 more wells and hopefully all of those are to hold acreage maybe one or two, we just have to drill outside of holding acreage.

The goal is to drill all of those wells to delineate what this footprint really look like, what the value is, what the resource potential is, and along with our partner with Quantum, we will build the the gathering treating in the midstream to complement the program of '25, '26. I think by the end of twenty twenty five, definitely by end of twenty twenty six, we'll have fully derisked this whole 518,000 net acre play Dan had mentioned a lot of this HBP so we don't plan on drilling on the HBP acreage until we hold maybe 70 more wells we need to drill in the next several years. To HPP. Our entire footprint.

Got you. Thanks for the color, Jake. My second question is on the CapEx trend on a per well basis. I think that it's very encouraging to see that you've saved on both fronts the drilling and completion side. But given that the Western Haynesville is materially hotter and deeper than legacy Haynesville, you'd almost think that your drilling savings will be what hit a plateau soon, if you will, whereas on the completion side, you might you haven't reaped the full benefits of a full development cycle.

So So I was wondering if you can perhaps speak to how on the completion side, you'll achieve greater savings. What What are you doing specifically in terms of your completion design? And how much headroom do you see on the drilling side as a whole?

I mean, so kind of alluded to that a little bit earlier. I think we'll see we haven't reached a plateau on the cost first of all in the Western Haynesville. Mean, obviously, with all the thousands of wells drilled up in the legacy area, it is. It's just small little tweaks here and there. It's minor things. It's It's great execution. Just shades off just a day here and a day there. That's not the case in the Western Haynesville. In the Western Haynesville, we've been going up a steep learning curve. We've cut off a lot of days. Haven't reached a plateau yet. I think we're going to drive these costs lower. We're going to knock more days [indiscernible] More of that, I see more about just a percent reduction in cost on the drilling side than on the completion side. We are pumping the same frac job right now in all the Western Haynesville wells.

I will make one note on Slide 22, there was a there in Q2 it showed a high completion costs of $19.70 dollars a foot and that is we just had one well that quarter and we pumped what we call our big frac. We pumped We pump 6,000 pounds per foot on that well for a data point just to monitor how that well provisions in the future. Compared to all our others, which is why that one stands out. But We've had really great execution on the completion side really today. So that's why I don't see the completion costs coming down.

As much as the drilling on a percentage basis.

Yes. The other thing we have managed the wells a little different Each well is like a prototype. And we learn how to manage all the wells. We go back and we preview What Circle M look like? What we could do or didn't do and how well is the And I think Dan, if he wants to comment on just well management, we're getting better and better and better which is a learning curve from having the 18 wells.

Yes, I'd say we definitely have been conservative on how we're drawing the wells down and based on a lot of the things we're seeing, we're just making adjustments on how we do that, manage the drawdown how hard we pull the wells when we flow them back and clean them up, turn them to sales. And then where we set the rate after that.

And what that will do, that will give more predictability, give more stability. It will give us what the real top curve may look like. What the draw downs may look like, when the wells have been producing one or two or three years. We hadn't gotten to that point yet. But I think the goal today was when you trusted us for five years and we haven't given you all the data, And today, the goal was to tell you that we think the land grab is over. We think that the midstream is secure. So we can tell you a little more about it And particularly the data set is big enough, so the you can at least look at that as a beginning point to see what we can improve from there. I would tell you that if you go back and you look at the first 18 wells ever drilled in the core, the Haynesville, Bossier and 'eight, and you compare those to the wells we've drilled today, Ours are like lights out better. So And our next question comes from Charles Meade with Johnson Rice. Your line is open. Good morning, Jay, Rowan and Dan and I'll add my my voice to the course of of congratulations, not just on assembling this position, but also great progress you've made.

You've been screaming and yelling for us and you've lost your voice. I know I understand That's the least of my problems, Jake.

Jay, you already anticipated one of my my first question when you started talking about the de risking of the position.

You talked about the your first wells here, you've you've deraced along the kind of a 26 mile Southwest Northeast axis. If I'm just eyeballing your map there on what is I think it's Page 18, Yes, I just eyeballed. I would say that's maybe derisked don't know, 20%, 30% of your position. I'm wondering if you could you could give an opinion on that. And then maybe also wrap in, as you go up dip or you go north, what are the risks? Is it formation thickness or is it just is it porosity that is the risk that's going to going to determine exactly how much of this five eighteen really works?

Well, if you noticed on the slide or kind of my introduction, I said that this slide on Page four, it is to scale because sometimes there's trickery, you don't have many acres, but you don't put it to scale and you compare it to your other acreage and it looks it looks skewed So we said we just want to make sure you know it's not distorted footprint because you would think it could be distorted because there's so much of it. Because our legacy Haynesville, I mean, it's some of the most valuable acreage in North America, we believe, because where it's located, in all the locations that we have left to drill in the Haynesville as well as only 8% of those years develop So when you go back to the beginning, in 2020, twenty twenty one-two, you can see tried to outline the patients that we had That's why I give the dead horse scenario. In other words, we're looking to see if this thing works. If it doesn't, then we're going to get off of it. But if it continues to work and quite frankly, Jerry Jones and his family allow us to derisk this thing, which is very hard to do.

It takes months and some bad days, some good days, but you add it all up, what we try to do is we try to say, how many acres do we have that we have to drill wells right now in 2021, 2022 in order to hold leases that we had inherited from acquisitions. That's number one. And number two, we looked at how many logs do we have that penetrated the different thicknesses in the Bossier and Haynesville. Then we look to see what seismic we owned and what we needed to buy And then we didn't let the horses run wild. We drilled the wells, circle them, we pulled the rig back for five months. We let the well tell us what to do. Then when we did move that rig back on, we've kept it pretty busy. And now we were good stewards to the budget and liquidity. In 2024, we were going to add a third rig. We didn't. We kept it two rigs. And then Charles, what we did, we looked at acreage that was expiring. Now we didn't lease all this acreage in 2021, 2022, 2023, 2024. We leased it along the way. So we avoided a big cliff where you had to drill a lot of acres because you had leased it all at the same time.

We feathered it out that we didn't have that issue. And at the same time, we had several acquisitions that we bought deeper rights that are HPP ed So as we look at our drilling program in 2025, 2026, 2027, we kind of pair that up with Quantum and we say how far are we away from our main pinnacle line, what's the cost structure, what's the gathering Comstock look at the the depth, the thickness and you do have different thickness. We've told you on some of the calls we've got maybe 1,300, 1,400 feet of prospective pay in some areas. Well, you look at that, that's not true for all of it. Some of it is going to be the same, a pay thickness that we have in the tier of our legacy acreage So that's 200, 300 feet, whatever. But yes, it's it expands. We did choose to drill the deepest, hottest, hardest first. Because that would tell you whether we needed to pursue to spend more money on acreage and more money on seismic and to keep the land group leasing that acreage and feathered into the drilling program. It's a beautiful story to write when you see it, Because of like Roland had come up 80% of this is HPP.

I mean 80% and this is the very first time we've ever shown it to you. And you might say, well, how come there's some wide acreage in there? Well, a lot of that acreage, maybe one or two other companies are owned and we Maybe there's some little spotty acreage that we don't want to own. But we're not afraid to have people come out there and derisk this with us. That's why we show you once we think the land grab is over.

So at the end of this quarter, I think we'll have some more results. But I want you, I mean, it's our banks, it's our analysts, it's our equity owners, it's our bondholders, that believe in what we're doing I want you to always know what we're doing. And our goal in 2025 is to to materially derisk the whole footprint and see what the thicknesses are. [indiscernible] In our core acreage, Jeffrey, some of our best wells are In the areas that are not as big like up around like the Elm Grove area area. So As far as just speculating, if it's something thinner or thicker on how it's going to perform, I don't think there's any Yeah.

Yes. Is it really more just gas fill porosity? Is the biggest determinant then?

Yes.

I mean, thicker, I mean, obviously more gas in place, right, thicker rod, but definitely, that does not correlate to the how prolific it will be.

We have meaningful bottle flow pressure differences.

Yes.

Interesting. And then one follow-up, Jay, you already you touched on this also. I think Dan, you touched on this a lot of focus on these newest batch of wells and rightfully so. But you continue to watch these other older wells. And I'm wondering if you can talk about what you've learned from them whether about the right way to manage the pressure drawdown, the landing zones within these formations or the right completion jobs? I know there's every day that ticks by you add to the data pile from those older fringes wells. So can you just tell us what you've learned in that respect? [indiscernible] [indiscernible] Just getting the wells down in TD. The landing zones, I think a lot of these where we where we drill are in the relatively thicker part of the play. So we haven't We haven't really got real specific on the landing zone should be a little higher, a little lower, just wanted to get the wells down, basically just feeding these things as fast as we could. And as far as the drawdown and we've been pretty conservative. I think we'll probably tweak that a little bit in the future.

These last few wells, we like to IP them pull them a little bit harder and get the wells clean, make sure they're getting clean before we get flow back off And then pull the rates back and start them basically on the type curve rate and just basically let them go from there. [indiscernible] Some of these wells we tube up, some we don't. It's a big cost variance too.

We figure out what we need to do or not do. As we drill more of these wells. Thank you. And the next question will come from Caley Ackerman with Bank of America.

Hey, good morning guys. Jay Rillen. I think the update here is being well, so I'm going to keep it quick here.

Any early thoughts on 2026 on maybe holding activity here at Seven rigs seems like the industry is falling in a rhythm with demand and that's a really good place to be.

Right.

No, I think that's the key. One thing we wanted to make sure we don't produce too much gas, especially in one region area. So we've been been looking at that. We think seven rigs was always a really good level for the company to kind of maintain. I think we dropped to five rigs You can see the impact of that. That's really too low of an activity level, but it was needed help balance the market So we're going to get very comfortable with 7% and we're going to focus on getting our balance sheet Yes, back to like it was in 2022, that's our biggest goal. And I think '26 will be a year that will have the level of production and good gas prices to drive the get the balance sheet and perfect shape, but And I think '25 That level we're running now, we won't add any debt. Slowly pace them down, but then next year we'll be able to really reduce debt significantly.

Brilliant. As far as the year end '26 bogey, you think somewhere under 1.5x is where the balance sheet would end up?

Well, I think first you'll see the leverage ratio improve rapidly as we can start to count the '25 year we had to so low of gas prices But we definitely want to get it down as quickly as possible to the 1.5x leverage area. It's probably That's probably something that we achieve in 2026, But I think we'll be way in the very low 2x leverage numbers as we kind of work our way through '25. So a lot will depend on how strong gas prices are and then how we do have to rebuild our production a little bit to kind of get leverage ratio to us more optimal That's a really good point though. I mean, we said this, but other than COVID, Gas price last year was the lowest it's been in thirty years. If you look at that and you look at us getting rid of two reefs, you look at us having a frac haul And then you look at us adding 265,000 net acres in the Western Haynesville, you can see that we really, really monitor our leverage and our balance sheet We do that even in a very, very difficult year and at the same time instead of M and A, we said we'd like to see if we can grow organically.

And typically, that's what these companies used to do. And because We could go in and as we were one of the first several companies to derisk and discover the core Angel, we just picked the same group [indiscernible] To the Western Ainsworth, knowing what we were looking for and it took five years for it to turn out the way it's turned out right now. It's still preliminary. But if we're right, these reserves will be there'll be massive Our footprint is massive and we're in the exact bright part of North America for all this demand, particularly for LNG. So it's going to be a really beautiful story.

That's right. It's exciting to watch. Jay Roland, I'll see you guys in a couple of weeks.

Yes. We look forward to it.

And our next question will come from Bertrand with Truist. Your line is now open.

Hey, good morning team. I just want to follow-up on that on that M and A topic. Not necessarily on the West you'd think most of the private owners are probably thinking about potentially selling or maybe does that incentivize you to look more aggressively or are those sellers seeing the strip move up and maybe they're already seeing a $5 price they want to see or something like that? And then the the second part of that would just be on the oil side, most of these these private equity shops normally ramp up production before a sale. Do you see that happening? Or that's not exactly how it would work on a gas side?

Well, it's hard to predict how what they're looking at. But obviously, I think there are some private companies out in the Haynesville that have invested a lot of capital and now that you're in a good gas price situation that their business plan is to sell that kind of like the same with the oil private companies in the Permian. And so, but we do see a very low level of activity in the Haynesville. So we certainly haven't seen any type of effort to ramp up at all from from the public or private operators seen great discipline in the basin. And I think all the producers really want to get very comfortable that the gas is really needed. And we've seen very, very volatile gas prices And so I think everybody's been very cautious and say, we're not going to oversupply this market and maybe we under supply it because we're so cautious.

Well, and you can even see the first quarter, we give guidance down We're not going to overproduce period. And that guidance is a result of dropping those rigs. And we're not adding the rigs in the Western Hanville to increase production right now. We're adding those rigs because that's the best place for us to drill because we need to drill more wells to HPP more of the footprint. So that's why we're doing that even. Don't see any E and P company out there out of control on their production rates, none of them. That's great. And I think the market is is happy to see that. And then for my second question, several of your peers have started talking about potentially locking in a percentage of their production, the contracts either data center or LNG and it seems like most have fallen in at 10% to 20% of their volumes.

Is that where you guys feel like you'd fall or you potentially have a larger app type, maybe you lock up acreage dedication in the Western Haynesville or something like that for a backfill a demand project?

Thanks.

Yes, that's a good question. We would also want to look at having a portfolio of purchasers for our gas and not putting all our eggs in one basket But we see both being a major supplier to several of the LNG shippers and potentially looking at some power generation projects to back to But again, I think having a good balance of that activity because their demand comes at different times of the year. And so so but there are great good opportunities for the gas producers now to start to directly lock up with the industrial users, and the exporters And I think it's a good time for us to create good relationships where we could have more stable prices and also know that we've got good we've got that we balance out our production to what we know the market needs.

And particularly, probably 90% of our Western Ainsville is completely in Dedicated I mean, completely. So it's free range out there. We can kind of do what we want to with it.

And just want to clarify, so that an acreage dedication for for a demand project, that's is that coming back or are we done with that?

Yes, I'm not sure that acreage dedication is probably out there. I mean, typically that it kind of comes to backup large amount of infrastructure to make it for the infrastructure partner to be comfortable that they can get their capital out But here, I think since we're going to own our with the way we structured things, we're going to be able own all that.

And so I think instead we want to kind of look out and say, hey, we can we want to take up our portfolio of gas both the legacy and the Western Haynesville and to portion it out to these direct contracts as we feel comfortable that it's a good fit. And obviously, we're looking for the what's the best deal for Comstock. So who's going to pay the higher premium? They all have kind of different needs and And so but it's a very exciting time to be developing a new play like the Western Haynesville at the same time there is a lot of market development opportunities that our gas industry hasn't seen in a long time. So it's a great combination of those two together.

Certainly. This is probably a good time to talk about too. The reason we were able to go look at the Western Angel is because of the value of our core We don't want anyone to ever overlook that, that 301,000 net eight with plenty of takeaway there. That gave us the ability to come look at the Western Hanford, that along with the operational technical skill that we had. But the value of the legacy allowed us to do the Western Haynesville.

Perfect. Thanks for the answers guys.

Thank you.

And our next question will come from Jacob Robert with TPH and Company. Your line is open.

Good morning.

Good morning. Good morning.

Just I hate to ask about 2026 plus but thinking about the four-three rigs split as we kind of progress through 2025, is that a level that can meet any HBP needs, any MVC needs with Quantum?

Or are you contemplating a 5.2, a 5.3? Just wondering what are the commitments as we get into 2026, 2027 that we might need to be thinking about Well, the real positive the way we structured things is that we don't even need to maintain that type of activity to kind of meet any NVCs or other requirements. We've been very conservative as you build something out not to over not to get over committed. So I think it's a very comfortable level [indiscernible] For the company, And so it's really going to be like what is the market where is the gas really needed, And I think we would adjust that based on kind of how we see these market go out. But I think we're very comfortable with the activity level and running be able to run four rigs in the Haynesville will keep us on track to HBP in all of our acreage and easily meeting supporting the build out of the midstream Okay, perfect. And then maybe just a quick follow-up. I appreciate some of the discussion about your understanding of the broader Western Hainesville acreage that you've disclosed. Can you just frame the amount of seismic, the amount of historical work that's been done on this land that helps you understand The way you do?

Yes. I'd say there's been a lot of three d seismic shot across all of this acreage, just a lot of different different vintage data that's out there that can be bought that has been tremendously Helpful. Got a planning out where we want to drill and we've got some future wells that we're going to be drilling some some pilot holes on and getting drilling all the way through the section through the bottom of the Haynesville for well control purposes and geosteering. And we've also got some future coring in stuff we're going to do as far as just doing some more sites And to get the performance properties on the rock.

Excellent. I'll echo the sentiment of appreciating the update guys.

Thank you. And our next question will come from Greg Brody with Bank of America.

Your line is open.

Hey guys. Just as we think about Midstream, for next year, what type of capital should we pencil in? And then when do you think you will exhaust the the midstream JV and how do you think about funding it after that?

Yes, it's a great question. Yes, we this is with building a new treating plant, this was a big capital investment that we started making in the fourth quarter and through this first half of the year, then we're going to have a lot of treating capacity that's going to be available to us starting in the second quarter. And so so then we continue to look at our volumes and then decide when we want to add additional trains to either either a new plant or adding to our North or South plant So we also have some good partners nearby that we've secured additional capacity in order to to not have to build everything. So we feel really good about where that is. I think that the build out of the midstream is amazingly fit almost perfectly with our five year plan for it so far. And so we've been really pleased I think our partner has been too, And So I think that eventually as the entity has now has a lot of volumes and it's going to have a really good year this year. Going to be able to maybe maybe put in its own credit structure there, so we can kind of get less expensive capital to fund some of its build out.

That's probably going to be more later in the year after it's up and running and generating a very strong EBITDA. But we're very excited about what Pinnacle can become and the value it's going to be adding. I think you look down the road, it's going to be a very, very big asset. For the company. And under our structure, once we return that capital with a preferred return that will revert 100% back to 70% back to the company and then we can buy out the minority interest if we'd like in the future also.

Yes, the goal was we as we were acquiring all the sectors, we wanted to control the midstream. We We trusted Quantum as a company lending money and so [indiscernible] plays like this, which we really trusted them. We wanted see if there was something that we were missing. So when Quanta came in, look at the acreage, look at the well results that point, which have only gotten better. I mean, they said we're exactly with $300,000,000 We wanted to make sure that we would control that.

And it wouldn't be sold to some third party.

Which would then control what we'd be doing in the Western Haynesville. We didn't want to lose control of that. And Quantum became the perfect partner.

So it's fair to say that between Quantum's equity and a potential credit facility at this at the JV that entity is self funding for the next several years.

Right. Right. And we would see it hopefully transitioning into next year I mean, really, as you get through 2026, probably where doesn't really need it'll start to be totally self funding And we also see maybe bringing in some of the nearby operators could also help accelerate that if can land some of those as customers as we build the system out.

Great.

Thanks for your time guys.

And our next question will come from Noel Parks with Tuohy Brothers. Your line is now open. Hi, good morning.

Just thinking about the drilling time improvements you've [indiscernible] been able to achieve. I just wondered, could you just talk a bit about maybe what assumptions you had going in your [indiscernible] earliest well and whether there's anything different now that you're this far in sort of like what You talked about some of the things you've preached, but I'm just wondering kind of what was your starting point like when you were approaching the play?

It's an interesting question because when we we looked at everything we had done in the legacy on our legacy acreage in all of the years past and kind of just one of the real general things we had seen was before we ever started in the Western High School, In general, in the core, all the wells were being drilled twice as long, say five ks is the 10Ks And at the same time, they were getting twice as long, they were being drilled at half the time. And there were a couple of there was a couple of old wells that had been drilled, old horizontals that had been drilled back in 2010 down here in the Western High School that was kind of provided some of the earliest data to take a look at that we looked at. They had a lot of just just a lot of mechanical issues, collapsed casing and just really was pretty ugly. But But we just looked at how many days took them to drill those wells and those were essentially five ks ish type wells.

And so if you just applied the same industry progression twice as long and half the days, that's kind of what we targeted And it was around that seventy five to eighty day timeframe that's exactly where we landed. On average, if you take out that size, right, we had on our second well, we landed at about eighty days. Starting out. And the good thing is that there's a of running room. These wells are deeper and harder and we just have so much more room to run down here to get better. Versus we did up in the core. So Well, on our confidence level grew, we were going to drill to 16,000 foot vertical and then as our confidence crew was well after well after well, we did go to 19,000 feet. So we wouldn't have done that had we not had more confidence in the 16,000 foot vertical.

Yes. Anything you do, anywhere you drill, the longer if you can just wells are good and you can keep drilling additional wells and you can increase your activity, If we all practice makes perfect, the more you drill, the better you're going to get. The more the industry drills, the better the industry gets. And that's that's what we're seeing.

Great. Thanks. And understandably, there's been so much attention to us seeing the the map for the first time and the results from the newest Slater wells. So I just wondered if I could just talk a little bit about gas macro. And looking at your hedges I was just wondering, is there anything particular about the $350,000,000 mark as where your downside protection is that you've been gravitating toward? And also if you had any thoughts about What things are going to look like or might look like as the LNG ramp up continues along?

Well, we look today and I just looked and says U. S. LNG fleet hit a new record high of 16.47 Bs. We are very, very, very positive on that for gas in latter part 'twenty five, 'twenty six, 'twenty seven. So when we look at the Western Haynesville, not the legacy, I mean, we do need to drill the legacy, of course, It provides us a very dependable revenue stream But what we want to do, we want to guarantee that we can drill all these wells we need to drill in 2025, 2026. And still deliver the balance sheet. Our big land grab and a lot of money we spent on that It's over. We'll spend a little bit as we do even in the core cleaning it up all the time where that will be perpetual.

But we don't see any big acreage at their positions that we're chasing that we don't have So this is purely it's a have a dividend If we could have a dividend in the latter part of 2026, grade, early twenty twenty seven, whatever, but we want to delever the company now, drill these wells, stay true to the midstream partner with Quantum, and deliver this gas not when it's needed And the beauty of this is nobody tells us when to drill it, how to drill it or we control it ourselves. It's something we control and where it is, is perfect. You could pick a map. If you would look at where our pipeline is, which we showed that, Raul went over it, We bought that a lot of that pipeline in one of our acquisitions It is the backbone of where our footprint is. You cannot have a better location for that pipeline and it's not there by mistake. Twenty years ago that was the core of the core where they were drilling. That's why that pipeline was there. It just wasn't worth anything when we bought it.

Somebody had to re rigorate it and put some gas in it. We're the only ones willing to do it. So it has become a very valuable piece of the company.

Yes, the replacement cost for two forty six miles of high pressure pipeline and a treating plant It would be unbelievable to have to put all that in from scratch. Mean, you're talking about the amount of equity that's already there is pretty phenomenal. So Great. Thanks. That's really helpful insight. [indiscernible] This is all the time that we do have for questions. I would now like to turn the call back to Jay Allison for closing remarks.

I want to thank all of you. It's a much longer call than normal. It's almost an hour and a half. We knew it would go longer. We didn't want to cut anybody off. But again, I want to thank you. There's probably two fifty plus men and women who make up the Comstock team and a lot of them listen to the call. I want to thank all of you as well want to thank our loyal banks. I mean, the banks that believed in us, the Bob holders have believed in us. The equity owners have believed in us. The analysts have believed in us. And I want to say again, especially thanks to Jerry Jones and his family who are the back bone support to unlocking the Western Haynesville value. I gave an old cowboy spear, I'll give you another one. It says if you climb up on the saddle, you better be ready to ride. And we at CommSpark are ready and you can take that to the bank. Thank you.

This concludes today's conference call. Thank you