Comstock Resources, Inc.

Ladies and gentlemen, thank you for standing by. Welcome to the fourth quarter 2024 Comstock Resource 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 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 like now to turn the conference over to your speaker today, Jay Allison, Chairman and CEO. Please go ahead, sir.

Thank you and good morning, everyone. You know, what a fantastic morning here in Frisco, Texas with snowflakes coming down when I woke up. You know, I looked at the temperatures in Frisco. It was 15 degrees, feeling like a minus 2. I scrolled and looked at New York. It was 19, feeling like 5. Chicago, 4, feeling like a minus 4. And in Boston, it was 15, feeling like 2. So now let me tell you the story, the latest news about Comstock 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 Hainesville play in Texas. Over the past five years, we have been acquiring acreage in the Western Hainesville based on geologic data we put together, including well logs from the many producing vertical wells in the area. Today, we hold 518,000 net acres in our Western Hainesville area in addition to our 301,000 net acres in our legacy Hainesville area. This 518,000 net acres in the western Hainesville represents a massive footprint that 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 Hainesville well, the Circle M well, was turned to cells in April of 2022. We waited five months before we started our second well, evaluating the Circle M's performance. By the end of 2023, we had seven wells producing, and today we have 18 Western Hainesville 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 Hainesville acres. Fortunately, 80% of this acreage is HPP'd 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 Hainesville well by well, We made sure that 100% of our team held no distorted view of reality. Reality is truth. There's an old cowboy saying, quote, if the horse is dead, dismount, end of quote. Well, 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&A market and focus on organic growth. The challenge in the Western Anvil was not geological, as we are confident the shell 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 and 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 Hainesville area. We've been very cautious as we've developed our Western Hainesville 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 million for the build out of the gathering and treating systems in the Western Hainesville. In 2024, we kept two rigs busy in the Western Hainesville and turned 11 new wells to cells. And now we have four rigs in the new play and we'll drill 20 more wells this year. The creation of the Western Hainesville 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 in the weeds with us as we kept our focus to capture the prize of proving a vast natural gas reserves beneath 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 Hainesville well results look very promising at a time when America needs more natural gas to meet the growing demand for LNG, AI, and all the industrial growth along the Gulf Coast. Our Western Hainesville is located several hundred miles from the Gulf Coast where 100 billion 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 Hainesville. Today is the very first day we've shown the location of our 518,000 net Western Hainesville 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 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 Fourth Quarter 2024 Results. I am 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 Investor Relations. Please refer to slide two in our presentations and note that our discussions today will include forward-looking statements within the meeting of securities laws. While we believe the expectations in 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 accomplishments. Most importantly, we successfully navigated last year's very low natural gas prices. A realized gas price before hedging of $1.98 per MCF in 2024 represented a 30-year low if you exclude the 2020 COVID year. 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 shored up our balance sheet by adding $100.5 million to an equity private placement with our majority stockholder and enhanced our liquidity with a $400 million senior note offering. During this year of low natural gas prices, we were also able to grow our Western Hainesville 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 Hainesville exploratory play. We successfully turned 11 wells to cells with an average IP rate of 38 million cubic feet per day, and now have a total of 18 wells producing in the play. In the fourth quarter, we were able to significantly reduce our drilling and completion costs in the western Hainesville compared to the 2022 level. The drilling costs for lateral foot in 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 Hainesville-Bossier wells with a strong average IP rate of 26 billion per day. Our 2024 drilling program replaced 107% of our 2024 production and drove 6% reserve growth with 899 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 return among public E&P companies trading on a major exchange. If you would flip over to page four, the Hainesville Shell footprint. Slide four is an overview, first time ever, of our acreage footprint position in the Hainesville-Bossier Shell in East Texas and North Louisiana. Note that this map is to scale. It's not distorted. We have 1,099,000 gross and 819,000 net acres. that is perspective for commercial development of the Hainesville and Bossier Shills. On the left is our emerging western Hainesville, and on the right is our legacy Hainesville area. Since the beginning, our leasing program in the western Hainesville play in 2020, we have grown our acres position to 518,000 net acres. We still have around 1,300 net locations to drill on our 301,000 net acres. In the legacy Hainesville, which currently has 895 net producing wells, our legacy Hainesville acreage is 48% developed for the Hainesville shale and 8% developed for the Bossier shale. In comparison, our western Hainesville has only 18 net producing wells and is virtually undeveloped compared to our legacy Hainesville. We expect our Western Hainesville acreage to provide more inventory per acre versus the legacy Hainesville. Given the higher pay thickness and pressures we encounter in the Western Hainesville, we expect the Western Hainesville to yield significantly more resource potential per section than our legacy Hainesville. 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, which was 12% lower than the fourth quarter of 2023, reflecting our decision to drop two rigs early in 24 and have that frack holiday that we had in the third quarter. The only way we turned to sales in our legacy Hainesville 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 million due to the lower production level, which was partially offset by better natural gas prices. EBITDAX for the quarter was $252 million, and we generated $223 million of cash flow during the quarter. We reported adjusted net income of $46 million for the fourth quarter, or 16 cents per share, In the fourth quarter, we recognized a $52 million tax benefit related primarily to R&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 approved 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 12 months. Of course, that price was very low in 2024. On slide six, we recap the annual 2024 financial results. Production for the full year averaged 1.4 BCF per day, which is very comparable to the 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 $1.3 billion. EBITDAX in 2024 totaled $850 million, and we generated $675 million of cash flow. With weaker natural gas prices and a higher DDA expense, we reported an adjusted net loss of $69 million in 2024, or 24 cents per share, compared to the $133 million net income we had in 2023. On slide seven, we further break down our natural gas price realizations in the quarter and for 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 were sold in the spot market, so the appropriate market price reference price for our gas that quarter was $2.62. Our realized gas price during the fourth quarter averaged $2.32, reflected a 30-cent differential for the quarter. We were 51% hedged in the fourth quarter, so that improved our realized gas price to $2.70. We also had a 5-cent 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 $3.50 and a ceiling of $3.80. For 26, 59% of our hedge position is in collars with the same floor level of $3.50, but a higher ceiling price of $4.35. And then the remaining 41% of our 26 hedge position are in gas price swaps, which averaged $3.51 per MCF. On slide 9, we detail our operating cost per MCFE and our EBITDAX margin. Our operating cost averaged 72 cents in the fourth quarter, which was 5 cents 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 ad valorem taxes were down 3 cents in the quarter, primarily reflecting the lower statutory severance tax rate we have in Louisiana, which went into effect in the middle of the year. And our lifting cost in the quarter increased 3 cents, where our gathering costs were down 5 cents in the quarter. Overall, our G&A costs were unchanged at 5 cents in the fourth quarter. In 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 million on development activities in the fourth quarter, and we spent $902 million for the full year. In 2024, we drilled 32 or 25.8 net horizontal Hainesville wells and 18 or 17.1 net Bossier wells. We turned 48 wells or 42.9 net operated wells to sales, which had an average initial production rate of 26 million per day. On slide 11, we recap our approved 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&A in the financial statements. Using year-end NYMEX prices, we were able to grow our approved reserves by 6%, even though we had reduced overall drilling activity last year. So our approved reserves totaled 7 TCFE. We added 899 BCF of drilling additions, which replaced 170% of what we produced last year of 528 BCFE. We spent $902 million on that drilling program, which gives us a finding cost right at a dollar for 2024. In addition to the approved reserves, there's an additional 2.1 TCFE approved undeveloped 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 approved reserves. Then 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 Hainesville acreage. Slide 12 recaps our capitalization at the end of 2024. We ended the quarter with $415 million of borrowings outstanding under our credit facility, giving us $3 billion in total debt, including our outstanding senior notes. Our borrowing base is currently at $2 billion, and our elected commitment under our credit facility remains at $1.5 billion. 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 $1.1 billion of financial liquidity. On slide 13, we summarized 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 provides us with advantaged gas price realizations compared to most of our natural gas peers. 68% of our gas production is sold at 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 That's the ability to take advantage of changing market conditions, you know, on 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 Hainesville area. In late 2023, we partnered with Quantum Capital Solutions to create Pinnacle Gas Services, to fund the needed expansion of our existing midstream assets in the Western Hainesville to handle the growing production from this area. So we contributed our Pinnacle Gathering and Treating System to the partnership, and then Quantum is contributing the capital to build out the Gathering and Treating System in this area. We currently have 246 miles of high pressure pipelines that run across the middle of our acreage, as you can see on slide 14. And we have a gas treating plant at Bethel at the north end of our system, and we're currently constructing a new 400 million a day treating plant at Marquet, 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 1,548 gross locations and 1,211 net locations, which equates to a 78% average working interest. Our non-operated inventory, we have 1,110 gross locations or 139 net locations, which represents a 13% average working interest. The drilling inventory is split between Hainesville and Bossier wells, divided into our four categories by length. Our short laterals are less than 5,000 feet. Our medium laterals are between 5,000 and 8,500 feet. Our long laterals are between 8,500 and 10,000 feet. And our extra long laterals are all laterals over 10,000 feet. In our gross operated inventory, we now have 53 short laterals, 337 medium laterals, 570 long laterals, and 588 extra long laterals. 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 locations. 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 30 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 have been drilled and have reached TD or total depth. We have split out the data between both our legacy Hainesville and western Hainesville areas. In 2024, the 39 wells that reached total depth in the legacy Hainesville had an average lateral length of 10,922 feet. The individual lengths ranged 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 Western Hainesville had an average lateral length of 10,182 feet. The longest lateral we have drilled to date in the Western Hainesville had a lateral length of 12,763 feet. In the fourth quarter, we only turned one well to cells in the legacy Hainesville area, and this was our Sebastian number five Horseshoe well that we discussed on our third quarter conference call. In the western Hainesville, we turned six wells to cells during the fourth quarter, and five of these wells were turned to cells over the last 10 days of the quarter, or of the year. To recap our long lateral activity today, we drilled 110 wells with laterals longer than 10,000 feet, and we have 40 wells with laterals over 14,000 feet. Slide 17 outlines the wells that were turned to cells in the Legacy Hainesville in 2024. In 2024, we turned 37 wells in the Legacy Hainesville to cells. The individual IP rates on these wells ranged from 9 million a day up to 42 million cubic feet a day with an average test rate of 23 million a day. 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 horse, you will, the Sebastian 11 HU number five that was turned to sales in October with an IP rate of 31 million a day, which we discussed on the third quarter call. Other than the Horseshoe 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 prices. Two of our six rigs are currently drilling on our legacy Hainesville 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 Hainesville in 2024. In 2024, we had 11 wells turn to sales. The individual IP rates on these wells ranged from 31 million a day up to 44 million cubic feet a day with an average test rate of 38 million cubic feet per day. The average lateral length was 10,032 feet, and the individual levels ranged from 7764 feet up to 12,055 feet. Six of the 11 wells returned to sales in the fourth quarter, and five of those returned to sales the last 10 days of the year. We do have four of our six rigs are currently drilling on our western Hainesville acreage. Slide 19 highlights the total drilling days and the footage per day drilled in the legacy Hainesville. In 2024, our wells in the legacy Hainesville area averaged 26 days to total depth. This represents a 10% improvement over 2023. Over the last eight years, our drilling time in the Legacy-Hainesville area has averaged 27.5 days. The improvement in the drilling days is a function of the footage drilled per day. In 2024, we averaged 920 feet per day drilled in the Legacy-Hainesville, representing a 6% improvement over the 2023 average of 867 feet per day. Since 2017, the footage drilled per day has increased 35% with the fourth quarter of 24. The footage drilled per day of 1,012 feet is up 49% since 2017. Our best well drilled to date in the Legacy Hainesville averaged 1,461 feet per day. There was a number of drivers to the recently improved drill times in the Legacy Hainesville. The main driver has been drilling the longer laterals Since 2017, our average lateral length has increased by nearly 4,000 feet. In addition to just the normal things of minimizing problems and maintaining consistency, there are other factors leading to 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 Hainesville. Since we split our initial well in the fourth quarter of 2021, we have seen significant and continuous improvement in our drilling times. Our first three wells were drilled in 2022 and averaged 95 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 70 days in 2022, and we improved another 19% down to 57 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 41 days and that was during the fourth quarter. This represents an improvement of 45% or 35 days compared to our first well. Our first well, it was drilled to total depth in 75 days. The improvement in drilling days is a function of the footage drilled per day, and our first three wells in 2022 averaged 281 feet per day, and that has steadily improved to 487 feet per day in 2024. We averaged 547 feet per day in the fourth quarter of 24, and the fastest well in this group drilled a record 608 feet per day. On average, our daily drilling footage has doubled since we started in 2022 through the end of 24. There are several drivers behind our improved drilling performance in the Western Hainesville. Starting in the vertical hull, we've improved our casing point selections. We've streamlined our casing designs. We've achieved faster drilling in the vertical through improved bit selection. And in the laterals, we're utilizing thermal drill pipe and continue to see more consistent downhole motor performance as we continue to have just with the additional drilling activity. We also started incorporating two-well pads in our drilling program in the middle of last year. Slide 21 is the summary of our D&C cost through the fourth quarter for our Midsmark long lateral wells located on the East Texas, North Louisiana legacy acreage position. This covers all the wells with levels greater than 8,500 feet in length. 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 Hainesville, and that was that Sebastian 11HU number five single horseshoe that we turned to sales in October. Both the drilling and completion cost trends show the impact of the significant inflation that took place starting in 2022. And looking ahead, we're anticipating our DNC cost on the Legacy Hainesville 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 mid-year with the potential uptick in activity looming with the higher gas prices and the possible tariff discussions that are weighing on pipe prices. We are currently running two rigs on our legacy Hainesville acreage and we anticipate adding a third rig later this year if the gas prices stay attractive. On slide 22, this is a summary of our VNC costs through the fourth quarter for all the wells we've drilled in the western Hainesville. This slide provides the drilling and completion costs for all the wells we've drilled in the play to date. We have spent a large amount of exploratory capital on our first 10 to 12 wells drilled in the Western Hainesville as evidenced by the higher drilling and completion costs through the early part of 2024. We've accumulated a wealth of knowledge drilling those early wells that is now paying big dividends for us. The early exploratory DNC capital allowed us to hone in on the good well design for future wells. And as a result, we've been able to reduce our latest DNC capital to a point lower than our original estimates of roughly double what our legacy Hainesville wells cost. Our fourth quarter drilling cost averaged $1,396 a foot, while our fourth quarter completion cost came at $1,315 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, utilization of the thermal drill pipe, and our improved run times in the lateral. This also comes from the impacts of starting our two-well pads in our drilling program in the middle of last year, which helped us to shave 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 frack crews and our wireline crews. We do currently have the four rigs running in the Western Hainesville, and we do anticipate staying with the four rigs in the Western Hainesville for the near future. I'll also mention all our Western Hainesville rigs are new rigs that we had purpose built with our Western Hainesville 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 in all phases of our operations. I'll now turn the call back over to Jay.

As all of you know, that's a lot of data when you include the Western Hainesville rolling data. 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 the Western Hainesville that will position us to benefit from the longer-term growth in natural gas demand. We currently have four operated rigs drilling into Western Hainesville, 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 cells in the Western Hainesville this year. We will continue to build out the Western Hainesville midstream assets to keep up with the growing production from the area. Midstream expenditures are expected to be $130 to $150 million. They will all be funded by our midstream partner. In the legacy Hainesville, 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 cells and the Legacy Hainesville this year. We anticipate funding our drilling program, as Roland said, out of operating cash flow and using 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&C costs in 2025 in both the Western and Legacy Hainesville assets. We have strong financial liquidity, totaling almost $1.1 billion. Note on slides 24 and 25, 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, to ask a question, please press star 11 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. And our first question will come from Derek Whitfield with Texas Capital. Your line is open.

Well, good morning, all, and thanks for your time. Also, congratulations on the position you've assembled in the Western Hainesville as your MAAC is a dream scenario for anyone pursuing an organic leasing program in a new basin. Thank you. I have two questions, and they're both related to Western Hainesville. So referencing slide 18, 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 is there a chance that reservoir quality would support recoveries in the 2.5 to 3 BCS per foot zip code?

This is Dan. I think that's a very good question. We are drilling 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. We're drilling the stuff that we've leased in the hold. That'll keep us down in that general area. As we fan up to the northeast, uh for the kind of the near-term activity in the next couple of years but kind of answer your question i think uh you know 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 you know i think it just remains to be seen what the urs are going to look like but you know i would certainly think maybe you know a hair less just if you just correlate it to depth But we also expect our DNC costs are going to be a lot lower, you know, when we drill up there in the future. And, you know, I think our DNC costs are going to be a lot lower just drilling where we're at now in the future. You know, we're still kind of going up the learning curve. We haven't plateaued yet on even the lower costs that we're at today.

You know, and 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, you know, we looked at what reality looked like, and they look really good. And that's where we ended up with these 18 wells. There was a big enough data set so that we could actually come out and talk about the cost. And, you know, in all major Tier 1 plays, the more you drill the wells and complete them, typically the cost structure comes down exactly like it did in the core of the Hainesville-Bozier going back to 2008 to 2011.

And this is my follow-up. I wanted to focus on the DMC cost compression you're highlighting on page 22, specifically focused on the completion side. The degree of the 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 handful, is the added cost largely associated with higher treating pressures, 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 cost 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 $1,315 a foot, that's kind of a number that we're planning with for the future wells just for forecasting. You asked about treating pressures. Yes, so as far as compared to the legacy Hainesville, the treating pressures are definitely much higher down here just based on the depth and the frack gradients. The beauty is in the western Hainesville, it fracks 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 Hainesville. On 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.

Yeah, and Dan, I'd add, too, just you look at comparing the Western Hainesville to the Legacy Hainesville. 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 Hainesville, you've got a lot of infrastructure that we built a long time ago, and we're often using pads we built a long time ago. So, you know, there's a huge difference in the upfront cost. These early wells are burying all that cost, you know, in the numbers. And then as you come back and infill drill and continue to develop it, you know, you'll have less and less of that cost. Future wells would be able to utilize that investment we're making today.

Yeah. And I'll just add to what Roland said. We are building larger paths 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 Wolf Research. Your line is open.

Hey, good morning, gentlemen. I wanted to first congratulate you all on the incremental caller on the Western Angel. It's 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?

Yeah, 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 to hone in on what the optimum spacing will be, you know, in the Bossier versus in the Haynesville, you know, areas where it's thicker versus thinner. I think we're going to all yield different answers. So, you know, I don't have a direct answer to that question, but As far as future development, 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 can't. The acreage doesn't give you the opportunity to drill two laterals, two wells on a pad. 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 paths as we can, but that's probably going to be our mix for the next couple of years.

One thing we try to do, if you look, we de-risk maybe 26 miles of this flag. We show that on the map. Our goal is by the end of 2025, building 20 more wells. Hopefully, all of those are to hold acreage, maybe one or two. We just have to drill outside of holding acreage. But the goal is to drill all of those wells to delineate what this footprint really looks like, what the value is, what the resource potential is, and along with our partner with Quantum, you know, we will build the gathering, treating in the midstream to complement the program of 25-26. I think by the end of 25, definitely by the end of 26, we'll have fully de-risked this whole 518,000-acre play. You know, Dan had mentioned a lot of his HPP, so we don't plan on drilling on the HPP acreage until we hold maybe 70 more wells we need to drill in the next several years to HPP our entire footprint.

Thanks for the call, RJ. 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 hit a plateau soon, if you will, whereas on the completion side, you haven't reaped the full benefits of a full development cycle. So I was wondering if you can perhaps speak to how, on the completion side, you'll achieve greater savings. 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, you know, we'll see. We haven't reached a plateau on the cost, first of all, in the western Hainesville. I mean, obviously, with all the thousands of wells that were drilled up in the legacy area, you know, it is. It's just small little tweaks here and there. You know, it's minor things. It's great execution. You know, just shaves off just, you know, a day here and a day there. That's not the case in the Western Hainesville. In the Western Hainesville, we've been going up a steep learning curve. We've cut off a lot of days. We haven't reached a plateau yet. I think we're going to drive these costs lower. We're going to knock more days off in the future. More of that, I see more of just a percent reduction in cost on the drilling side than on the completion side. We are pumping the same frack job right now in all the Western Hainesville wells. I will make one note. On slide 22, there in Q2, it showed a high completion cost of 1,970 bucks a foot, and that is we just had one well that quarter, and we popped what we call our big frack. We popped 6,000 pounds per foot on that well for a data point just to monitor how that well produces in the future compared to all our others, which is why that one stands out. We've had really great execution on the completion side, you know, really today, so that's why I don't see the completion costs coming down as much as the drilling on a percentage basis.

Yeah, the other thing, we have managed the wells a little different. You know, each well is like a prototype, and we learn how to manage all the wells. You know, we go back and we preview what Circle M looked like, what we could do or didn't do, and how well it's performed. And I think, you know, Dan, if you want to comment on just, well, management, we're getting better and better and better, which is a learning curve from having the 18 wells.

Yeah, I'd say we definitely have been conservative on how we're drawing the wells down. And, you know, based on all the things we're seeing, we're just making adjustments, you know, 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 cells, and then, you know, where we set the rate. after that.

And what that'll do, they'll give more predictability, give more stability. It'll give us, you know, what the real top curve may look like, what the drawdowns may look like when the wells have been producing one or two or three years. You know, we hadn't gotten to that point yet, but I think the goal today was when, you know, 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. so we can give you the footprint. We think that the MIPS frame is secure, so we can tell you a little more about it. And particularly, the data set is big enough so that 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 Hainesville, Bossier, and 08, and you compare those to the wells we've drilled today, ours are locked lots out better.

And our next question comes from Charles Mead with Johnson Rice. Your line is open.

Good morning, J. Rowan and Dan. And I'll add my voice to the chorus of congratulations, not just on assembling this position, but also the 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, J., Jay, you already anticipated my first question when you started talking about the de-risking of the position. You talked about your first wells here. You've de-risked along a kind of a 26-mile southwest to northeast axis. If I'm just eyeballing your map there on what is I think it's page 18, yeah, I just eyeballed. I would say that's maybe de-risked. I don't know, 20%, 30% of your position. I'm wondering if 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 porosity that is the risk that's going to determine exactly how much of this 518 really works?

Well, you notice 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 know, 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 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 Hainesville, I mean, it's some of the most valuable acreage in North America, we believe, because where it's located. and all the locations that we have left to drill in the Hainesville, as well as only 8% of the boziers developed. So when you go back to the beginning in 2020, 2021 too, you can see we 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 Johns and his family allow us to de-risk this thing which is very hard to do it takes months and you know 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 2021-22 in order to hold leases that we had inherited from acquisitions that's number one and number two we looked at You know, how many logs do we have that penetrated the different thicknesses in the Bossier and the Hainesville? Then we looked 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, circled in, 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 kept it pretty busy. 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 at 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, 22, 23, 24. 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 so that we didn't have that issue. And at the same time, we had several acquisitions that we bought deeper rights that are HPP'd. So as we look at a drilling program in 2025, 2026, 27, we kind of pair that up with quantum And we say, how far are we away from our main clinical line? What's the cost structure? What's the gathering cost? We look at the depth, the thickness, and you do have different thickness. You know, we've told you on some of the calls that we've got maybe, you know, 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's going to be the same, you know, pay thickness that we have. in the tier of our legacy acreage. So, you know, that's 200, 300 feet, whatever. But, yeah, 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, you know, Roland had come up with, 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 white acreage in there? Well, a lot of that acreage may be one or two other companies own, and we encourage them to drill wells out there. 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 de-risk this with us. That's why we show you once we think the land grab is over. So, you know, 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 de-risk the whole footprint and see what the thicknesses are.

If you look up in our core acreage upper, some of our best wells are in the areas that are not as thick, like up around the Elm Grove area. As far as just speculating if something's thinner or thicker on how it's gonna perform, I don't think there's any correlation there at all, really.

Is it really more just gas-filled porosity is the biggest determinant then?

I mean, obviously more gas in place, right, thicker rock. But definitely that does not correlate to how prolific it will be. And we have meaningful bottle pressure differences.

Yeah, interesting. And then one follow-up, Jay, you already touched on this also. I think, Dan, you touched on this earlier. a lot of focus on these newest batch of wells, and rightfully so, but you continue to watch these other older vintage 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, you know, every day that ticks by, you add to the data pile from those older vintage wells, so can you just Tell us what you've learned in that respect.

I think, you know, we obviously have been really laser focused on the cost, just getting the wells down and TD. The landing zones, I think, you know, a lot of these where we drill are in the, you know, relatively thicker, you know, part of the place. So we haven't really, you know, got real – specific on if the landing zone should be a little higher or a little lower. We just wanted to get the wells down and basically just PD these things as fast as we could. As far as the drawdown, 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 of them. pull the rates back and start them, you know, basically on the type curve rate and just basically, you know, let them go from there.

You know, Charles, some of these wells we tube up, some we don't. It's a big cost variance too. So we figure out what we need to do or not do as we drill more of these wells.

Got it. Thank you, Dan and Jay. Thank you.

And the next question will come from Kali Ackermine with Bank of America. Your line is open.

Hey, good morning, guys. Jay Rowland. I think the update here is being received well, so I'm going to keep it quick here. Any early thoughts on 2026 on maybe holding activity here at Seven Rigs? It 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. You know, one thing we wanted to make sure is that we don't produce too much gas, especially in one region area. So we've been, you know, 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 to help balance the market. So, you know, we're going to get very comfortable with seven. We're going to focus on getting our balance sheet you know, back to like it was in 2022. That's our biggest goal. And I think 26 will be a year that we'll have the level of production and good gas prices to drive the, get the balance sheet in perfect shape. And I think, you know, 25, you know, that level we're running now, you know, we won't add any debt and we'll 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 one and a half times is where the balance sheet would end up?

Well, I think, of course, you'll see the leverage ratio improve rapidly as we can start to count the 25 results and take off the results of last year where we had just so low of gas prices, you know. But yeah, we definitely want to get it down as quickly as possible to the one and a half times leverage area. That's probably something that we achieve in 26. But I think we'll be way in the very low two times 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 that leverage ratio, you know, to its more optimal level.

You know, 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 30 years. So if you look at that and you look at us getting rid of two reefs, you look at us having a frack holiday, and then you look at us adding 265,000 net acres in the western Ainsvold, 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&A, we said we'd like to see if we can't grow organically. And typically that's what these companies used to do. And because of the Joneses, they kind of uncuffed us. We could go in and as we were one of the first several companies to de-risk and discover the core of Hainesville. We just took the same group down to the western Hainesville, 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 massive. Our footprint is massive. And we're in the exact right 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 weeks. Yep. We look forward to it.

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

Hey, morning team. I just want to follow up on that M&A topic. Not necessarily on the Western side, but with higher gas prices, 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 that they want to see or something like that. And then the second part of that would just be, on the oil side, most of 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, you know, what they're looking at, but obviously I think there are still some private companies out in the Hainesville that, you know, that have invested a lot of capital, and now that you're in a good gas price you know, situation that there's their business plan is to, you know, sell that kind of like the same with the oil, the private companies, 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 the public or private operators. We've seen great discipline, you know, in the basin. And I think all the producers really want to get very comfortable that, you know, that the gas is really needed. And, you know, we've seen very, very volatile gas prices. And so I think everybody's being very cautious to say, like, we're not going to oversupply this market. And maybe we undersupply it because we're so cautious.

Well, and you can even see the first quarter, you know, we give guidance down. We're not going to overproduce, period. And that guidance is a result of dropping those rigs. And, you know, we're not adding it. the rigs in the western Hainville 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, the HPP, more of the footprint. So that's why we're doing that even. We don't see any E&P company out there out of control on their production rates, none of them.

That's great. I think the market 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 to 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 appetite? Maybe you lock up acreage dedication in the western Hainesville or something like that to backfill a demand project. Thanks.

Yeah, 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 too. But again, I think having a good balance of that activity because their demand comes at different times of the year. But there are 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 can 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.

Particularly, you know, probably 90% of our Western Hainesville is completely undedicated. I mean, completely. So it's free range out there. We can kind of do what we want to with it.

I just wanted to clarify, an acreage dedication for a demand project, is that coming back or are we done with that?

Yeah, I'm not sure that, you know, acreage dedication... is probably, you know, out there. I mean, typically that kind of comes to back up, you know, a large amount of infrastructure, you know, to make it, you know, for the infrastructure partner to be comfortable that, you know, they can get their capital out. But here, I think, you know, since we're going to own our, the way we've structured things, we're going to be able to own all that. And so I think instead, we want to kind of look out and say, hey, we can, we want to take of our portfolio of gas, both from the legacy in the Western Hainesville and, and then We want to portion it out to these direct contracts as we felt comfortable that it's a good fit. And obviously, we're looking for what's the best deal for Comstock. So who's going to pay the higher premium? They all have kind of different needs. But it's a very exciting time to be developing a new play like the Western Hainesville 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.

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

Perfect. Thanks for the answers, Ed.

Thank you.

And our next question will come from Jacob Roberts with TPH and Company. Your line's open.

morning morning morning just uh you know i hate to ask about 2026 plus but thinking about the 4-3 rig split uh as we kind of progress through 2025 is that a level that can meet any hvp needs any mvc needs with quantum or are you contemplating a uh you know 5-2 a 5-3 just just wondering You know, what are the commitments as we get into 26, 27 that we might need to be thinking about?

Well, the real positive, the way we structure things is that we don't even need to maintain that type of activity to kind of meet, you know, any MVCs or other requirements. We've been, you know, very conservative as you build something out, you know, not to get overcommitted. So I think it's a very comfortable level, you know, for the company. And so it's really going to be like, what is the markets, you know, where's the gas really needed? And I think we would adjust that, you know, based on kind of how we see these markets go out. But I think we're very comfortable with the activity level and running, be able to run four rigs in the Hainesville will keep us on track to HBP and all of our acreage and easily meeting, you know, supporting, you know, 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 it the way you do?

Yeah, I'd say there's been a lot of 3D seismic shot across all of this acreage, just a lot of different vintage data that's out there that can be bought that has been tremendously, you know, helpful in kind of planning out where we want to drill. And we've got some future wells that we're going to be drilling some pilot holes on and getting, you know, 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 and stuff we're going to do as far as, you know, just doing some more sites you know, 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 midstream JV, and how do you think about funding it after that?

Yeah, that's a great question. This is, you know, with building the new trading plant, this is a big capital investment that we started making in the fourth quarter and you know, 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, you know, in the second quarter. And so, you know, then we, you know, continue to, you know, look at our volumes and then decide when we want to add additional trains, you know, to either a new plant or adding to our north or south plants. So we also have some good partners nearby that we've secured additional capacity, you know, 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 vidstream is amazingly fit almost perfectly with our five year plan for it so far. And so we've been really pleased and I think our partner has been too. And so I think that eventually, you know, as the entity now has a lot of volumes in it. It's going to have a really good year this year. It's going to be able to maybe put in its own credit structure there so we can kind of get less expensive capital to fund some of its build out. But 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 70% back to the company, and then we can buy out the minority interest if we'd like in the future also.

The goal was, as we were acquiring all the securities, we wanted to control the mid-frame. We trusted Quantum as a company in lending money and supporting plays like this. We really trusted them. We wanted to see if there was something that we were missing. So when Quantum came in, look at the acreage, look at the well results to that point, which have only gotten better. I mean, they said, we're exactly with 300 million. 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 Hainesville. 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 the JV, that entity is self-funding for the next several years.

Right, right. And we would see it hopefully transitioning in the next year. I mean, really, if you get through 26, probably where it doesn't really need – it'll start to be totally self-funding. And we also see maybe bringing in some of the – Our nearby operators could also help accelerate that if we 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. You know, just thinking about the drilling time improvements you've already been able to achieve. I just wondered, could you just talk a bit about maybe what assumptions you had going in in your earliest well and whether there's anything different now that you're this far in? You talked about some of the things you've preached, but I'm just wondering what was your starting point like when you were approaching the play?

You know, it's an interesting question because when we, you know, we looked at everything we had done in the legacy, you know, in our legacy acreage in all of the years past, and kind of just one of the real general things, you know, we had seen was before we ever started in the western high school, you know, in general, in the core, you know, all the wells were being drilled twice as long, you know, say 5Ks to 10Ks. And at the same time, they were getting twice as long, you know, they were being drilled in half the time. And there were a couple of, you know, 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 Hainesville that kind of provided some of the earliest data to take a look at, you know, that we looked at. They had a lot of, just a lot of mechanical issues, collapsed casing, and just, you know, really was pretty ugly, but But, you know, we just looked at how many days it took them to drill those wells, and those were essentially 5K-ish type wells. And so if you just applied the same industry progression, you know, twice as long in half the days, that's kind of what we targeted, you know, and it was around that 75 to 80-day timeframe. And that's exactly where we landed. You know, on average, if you take out that sidetrack we had on our second well, we landed at about 80 days. starting out. And the good thing is that there's a lot of running room. These wells are deeper and hotter, and we just have so much more room to run down here to get better versus we did up in the core.

Well, and our confidence level grew. We were going to drill to 16,000 foot vertical, and then as our confidence grew with 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.

You know, on anything you do, anywhere you drill, the longer – if you can just – you know, wells are good, and you can keep drilling additional wells, and you can increase your activity. You know, if the old 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, you know, that's what we're seeing.

Great. Thanks. And, you know, understandably, there's been so much attention to us seeing the map for the first time and the results from the newest slate of wells. So I just wondered if I could just talk a little bit about gas macro. And, you know, looking at your hedges, I was just wondering, is there anything particular about the 350 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, you know, we looked today, and I just looked, and it says the U.S. LNG fleet hit a new record high of 16.47 bees. You know, we are very, very, very positive on natural gas in the latter part of 2025, 2026, even 2027. So when we look at the Western Hainesville, 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 that we need to drill in 25, 26, 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. That'll be perpetual. But we don't see any big acreage out there, positions that we're chasing that we don't have. So this is purely, it's a protection of a balance sheet to get us back to have a dividend. You know, if we could have a dividend in the latter part of 26th grade, early 27th, whatever, but we want to delever the company now, drill these wells, stay true to the mid-spring partner with quantum, and deliver this gas when it's needed. And the beauty of this is nobody tells us when to drill it, how to drill it. We control it ourself. It's something we birth, 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 and really went over it, We bought 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 of where they were drilling. That's why that pipeline was there. It just wasn't worth anything when we bought it. Somebody had to, you know, reinvigorate it and put some gas in it, and we're the only ones willing to do it. So it has become a very valuable piece of the company.

Yeah, the replacement cost for 246 miles of high-pressure pipeline and a treating plant, it would be unbelievable to have to put all that in from scratch. I mean, you're talking about the amount of equity that's already there is pretty phenomenal.

Great. Thanks. That's really helpful insight. It's all for me.

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, you know, again, I want to thank you. There's probably 250 plus men and women who make up the CompSoc team, and a lot of them listened to the call. I want to thank all of you as well. I want to thank our loyal banks. I mean, the banks have believed in us. The bondholders 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 backbone support to unlocking the Western Hainesville value. You know, I gave an old cowboy's fear. I'll give you another one. It says, if you climb up on the saddle, you better be ready to ride. And we at Comstock are ready, and you can take that to the bank.

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