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 would 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 snow flakes coming down when I woke up. You know, I looked at the temperatures in Frisco. It was 15 degrees, feeling like a minus two. I scrolled and looked 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 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 sales in April of 2022. We waited five months before we sputtered 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 Hainesville 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 Hainesville 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 and complete either Beauxer or Hainesville 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 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 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 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 owns 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 mid-spring 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 .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 discussion today will include forward looking statements within the meeting of securities laws. While we believe the expectations of 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, 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. I realized gas price before hedging of a dollar ninety eight per MCF in twenty twenty four represented a thirty year low. If you exclude the twenty twenty, covid year, we acted early in twenty, twenty four 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 twenty twenty four realized gas price by twenty percent. It also safeguards our twenty, twenty five and twenty, twenty six drilling programs by targeting fifty percent of our expected production. We short up our balance sheet by adding a hundred point five million dollars to an equity private placement with our majority stockholder and enhance our liquidity with a four hundred million dollars senior notes offering. During this year of low natural gas prices, we were also able to grow our Western hands for footprint. We more than doubled our acreage position to five hundred and eighteen thousand net acres by acquiring two hundred and sixty five thousand net acres at a cost of four dollars and four oh one per acre. We made terrific progress proving up our Western hands will explore toward play. We successfully turned eleven wells to sell an average rate of thirty eight million cubic feet per day and now have a total of eighteen wells producing in the play. In the fourth quarter, we were able to significantly reduced our drilling and completion costs in a Western hands will compared to the twenty, The drilling cost for lateral foot in our new play are down thirty three percent and the completion costs for lateral foot are down twenty eight percent. Overall, our twenty, twenty four drilling program delivered solid results and proved reserve growth despite the lower activity last year. We drove fifty or forty two point nine net well successfully operated hands will both your wells with a strong average IP rate of twenty six million per day. Our twenty, twenty four drilling program replaced a hundred and seven percent of our twenty, Twenty four production and drove six percent reserve growth with eight hundred ninety nine BCF of drilling related reserve additions and achieved an overall finding cost of one dollar per MCF. Despite suspending our quarterly dividend, we still deliver the highest twenty, twenty four total shareholder return among public companies trading on a major exchange. If you would flip over to page four, The handfuls feel footprint slide for is an overview first time ever of our acreage footprint position in the hands will both your scale in East Texas and North Louisiana note that this map is to scale. It's not distorted. We have a million ninety nine thousand gross and eight hundred nineteen thousand net acres. The just perspective for commercial development of the handful and both your skills on the left is our merging western hands will and on the right is our legacy hands will area since the beginning our leasing program in the western handful play in twenty, twenty. We have grown our acres position to five hundred eighteen thousand net acres. We still have around one thousand three hundred net locations to drill on our three hundred one thousand net acres in the legacy hands will which currently has eight hundred and ninety five net producing wells. Our legacy angel acreage is forty eight percent developed for the handful shell at eight percent developed for the bozer shell. In comparison, our western hands will has only eighteen net producing wells and is virtually undeveloped compared to our legacy hands will we expect our western hands will acreage to provide more inventory per acre versus the legacy hands will. Given the higher paid thickness and pressures we encounter in the western hands will we expect the western hands will to yield significantly more resource potential per section than our legacy hands will. I will now turn it over to Roland to discuss the financial results reported today rolling.

All right. Thanks Jay. On slide five, we cover our fourth quarter financial results are production in the fourth quarter average one point three five .F.E. per day, which is twelve percent 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 frack holiday that we had in the third quarter. The only way we turn to sales and our legacy hands will area in the quarter was our horseshoe well that we discussed last quarter. So, oil and gas sales in the quarter declined five percent to three hundred thirty six million dollars due to the lower production level, which is partially offset by better natural gas prices. Even Dax for the quarter was two hundred fifty two million dollars and we generated two hundred and twenty three million dollars of cash flow during the quarter. We reported adjusted that income of forty six million dollars for the fourth quarter or sixteen cents per share. In the fourth quarter, we recognized the fifty two million dollar tax benefit related primarily to R and D credits and other credit 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 decreased or 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 twelve months. Of course, that price was very low in twenty twenty four on slide six. We recap the annual twenty twenty four financial results production for the full year average one point four BCF per day, which is very comparable to the production we had in twenty twenty three natural gas prices that we realized in twenty twenty four fell by seven percent, resulting that our oil and gas sales decreasing seven percent to one point three billion dollars. Even Dax in twenty twenty four totaled eight hundred fifty million and we generated six hundred and seventy five million of cash flow. With weaker natural gas prices and a higher expense, we reported an adjusted net loss of sixty nine million dollars in twenty twenty four or twenty four cents per share compared to the hundred and thirty three million net income we had in twenty twenty three. On slide seven, we further break down our natural gas price realizations in the quarter and for the previous quarters. The quarterly nine X settlement price to average two dollars and seventy nine cents per MCF in the fourth quarter and the average Henry hub spot price in the quarter average two dollars and forty two cents. The forty five percent of our gas in the fourth quarter result in the spot market. So the appropriate market price reference price for our gas that quarter was two dollars and sixty two cents. I realized gas price during the fourth quarter average two dollars and thirty two cents reflected a thirty cent differential for the quarter. We were fifty one percent hedged in the fourth quarter, so that improved our realized gas price our realized gas price to two dollars and seventy cents. We also had a five set 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 in this year and in twenty twenty six. We have approximately fifty percent of our gas production heads for this year at an average price of three dollars and forty eight cents or better. Twenty two percent is in price swaps and the remaining is the form of costless costless collars with the floor of three hundred and fifty six. Three dollars and fifty cents in a ceiling of three dollars and eighty cents for twenty six. Fifty nine percent of our hedge position is in collars with the same floor level of three dollars and fifty cents, but a higher ceiling price of four dollars and thirty five cents and then the remaining forty one percent of our twenty six hedge position or in gas price swaps, which average three dollars and fifty one cents per MCF. On slide nine, we detail our operating cost per MCF and our EBITDAX margin. Our operating cost averaged seventy two cents in the fourth quarter, which was five cents lower than the third quarter rate. Our EBITDAX margin improved to seventy three percent in the fourth quarter as compared to sixty seven percent in the third quarter. So our production and abnormal taxes were down three 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 of the quarter increased three cents, while our gathering costs were down five cents in the quarter. Overall, our GNA costs were unchanged at five cents in the fourth quarter. On slide ten, 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 two hundred forty million dollars on development activities in the fourth quarter, and we spent nine hundred and two billion for the full year. In twenty twenty four, we drilled thirty two or twenty five point eight net horizontal Hainesville wells and eighteen or seventeen point one net exposure wells. We turned forty eight wells or forty two point nine net operated wells to sales, which had an average initial production rate of twenty six million per day. On slide eleven, we recap our approved reserves at the end of twenty twenty four determined based on year end NIMEX 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 DDA in the financial statements. Using year end NIMEX prices, we're able to grow our approved reserves by six percent, even though we had reduced overall drilling activity last year. So our approved reserves totaled seven TCFE. We added eight hundred and ninety nine BCF of drilling additions, which replaced one hundred seventy percent of what we produced last year, five hundred twenty eight BCFE. We spent nine hundred and two billion dollars on that drilling program, which gives us a finding cost of right out of dollar for twenty twenty four. In addition to the approved reserves, there's an additional two point one TCFE of approved undue 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 approved reserves. We also have another two point four TCFE of two P or probable reserves and six point nine TCFE of three P or possible reserves gives the total reserve base of eighteen point four TCFE on a P three basis. This does not include the reserve potential for much of the Western Hainesville acreage. Slide twelve recaps our capitalization at the end of twenty twenty four. We ended the quarter with four hundred fifteen million dollars of borrowing to outstanding under our credit facility, giving us three billion dollars in total debt, including our outstanding senior notes. Our borrowing base is currently at two billion dollars in our elected commitment under our credit facility remains at one point five 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 twenty twenty five financial results. At the end of the fourth quarter, we had approximately one point one billion dollars of financial liquidity. Slide thirteen, we summarized the market has 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 advantage gas price realizations compared to most of our natural gas peers. Sixty eight percent 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 Us the ability to take advantage of changing market conditions 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 fourteen, we show the footprint of our midstream system in our Western Hainesville area in 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 Hainesville to handle the growing production from this area. So we contributed our pinnacle gathering and treaty 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 two hundred forty six miles of high pressure pipelines that run across the middle of our acreage, as you can see on slide fourteen and we have a gas treating plant at Bethel at the north end of our system and we're currently constructing a new four hundred million a day treating plant at Marquet, Texas on our southern end. So now turn it over to Dan to discuss our operation.

Okay, thanks Roland. If you look at slide fifteen, this is our updated drilling inventory at the end of last year, twenty, twenty four. Our total operated inventory year end stands at one thousand five hundred forty eight gross locations and one thousand two hundred and eleven net locations, which equates to a seventy eight percent average working interest. Our non operated inventory, we have one thousand one hundred and ten gross locations or one hundred and thirty nine net locations, which represents a thirteen percent average working interest. The drilling inventory is split between Hainesville and Beauxer Wells divided into our four categories by length. Our short laterals are less than five thousand feet, our medium laterals are between five thousand and eighty five hundred feet. Our long laterals are between eighty five hundred and ten thousand feet and our extra long laterals are all laterals over ten thousand feet. And our gross operated inventory, we now have fifty three short laterals, three hundred and thirty seven medium laterals. Five hundred and seventy long laterals and five hundred and eighty eight extra long laterals. Our gross operated inventory is evenly split with fifty one percent in the Hainesville and forty nine percent in the Beauxer. The updated drilling inventory also includes the impact of identifying a hundred and thirteen horseshoe locations. The average lateral length that our inventory is now at nine thousand six hundred and three. This is up from nine thousand two hundred and sixty one feet at the end of the third quarter due to converting more of our short laterals to the long lateral horseshoe wells. Seventy five percent of our inventory is now composed of laterals greater than ten thousand feet. And our inventory provides us with over thirty years of future drilling locations based on our current activity levels. On slide sixteen is a chart outlining our average lateral length drilled based on the wells that have 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 twenty twenty four, the thirty nine wells that reached total depth in the legacy Hainesville had an average lateral length of ten thousand nine hundred and twenty two feet. The individual links range from four thousand two hundred and twenty two feet to seventeen thousand four hundred feet. So our record longest lateral now stands at this seventeen thousand four hundred feet. In twenty twenty four, the eleven wells that reached total depth in the Western Hainesville had an average lateral length of ten thousand one hundred and eighty two feet. The longest lateral we have drilled to date in the Western Hainesville had a lateral length of twelve thousand seven hundred and sixty three feet. In the fourth quarter, we only turned one well to sales in the legacy Hainesville area and this was our Sebastian number five horse you well that we discussed on our third quarter conference call. In the Western Hainesville, we turned six wells to sales during the fourth quarter and five of these wells were turned to sales over the last ten days of the quarter or of the year. To recap our long lateral activity date, we've drilled one hundred and ten wells with laterals longer than ten thousand feet and we have forty wells with laterals over fourteen thousand feet. Slide seventeen outlines the wells that were turned to sales in the legacy Hainesville in twenty twenty four. In twenty twenty four, we turned thirty seven wells in the legacy Hainesville to sales. The individual IP rates on these wells range from nine million a day up to forty two million cubic feet a day with an average test rate of twenty three million a day. The average lateral length was ten thousand one hundred and four feet and the individual lateral range from four thousand two hundred and twenty two feet to fifteen thousand three hundred and three feet. This list includes our first horse you will the Sebastian eleven eight you number five that was turned to sales in October with an IP rate of thirty one million a day, which we discussed on the third quarter call. Other than the horse you will, 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. We do expect to add another rig to the legacy area later this year. You know, the gas prices remain attractive. Slide eighteen outlines the wells that we turn to sales in the Western Hainesville in twenty twenty four. In twenty twenty four, we had eleven wells turned to sales. The individual IP rates on these wells range from thirty one million a day up to forty four million cubic feet a day with an average test rate of thirty eight million cubic feet per day. The average lateral length was ten thousand and thirty two feet and the individual levels range from seventy seven sixty four feet up to twelve thousand and fifty five feet. Six of the eleven wells returned to sales in the fourth quarter and five of those turned to sales the last ten days of the year. We do have four of our six rigs are currently drilling on our Western Hainesville papers. Slide nineteen highlights the total drilling days and the footage per day drilled in the legacy Hainesville. In twenty twenty four, our wells in the legacy Hainesville area averaged twenty six days to total depth. This represents a ten percent improvement over twenty twenty three. Over the last eight years, our drilling time in the legacy Hainesville area has averaged twenty seven point five days. The improvement in the drilling days is a function of the footage drilled per day. In twenty twenty four, we averaged nine hundred and twenty feet per day drilled in the legacy Hainesville representing a six percent improvement over the twenty twenty three average of eight hundred and sixty seven feet per day. Since twenty seventeen, the footage drill per day has increased thirty five percent with the fourth quarter of twenty four. The footage drilled per day of a thousand and twelve feet is up forty nine percent since twenty seventeen. Our best well drilled to date in the legacy Hainesville averaged one thousand four hundred sixty one feet per day. There's a number of drivers to the recently improved drill times in the legacy Hainesville. You know, the main driver has been drilling the longer laterals since twenty seventeen. Our average lateral length has increased by nearly four thousand feet. In addition to just the normal things of minimizing problems and maintaining consistency, there are other factors leading to drilling efficiency. The application of managed pressure drilling rig upgrades and the continued improvement in our down hole motor performance. Slide twenty highlights the significant improvements achieved in our drilling times in the Western Hainesville. 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 twenty twenty two and averaged ninety five days to reach TD. This includes executing a very difficult sidetrack we had on our second well. Our average drilling time improved twenty six percent down to seventy days in twenty twenty two and we improved another nineteen percent down to fifty seven days in twenty twenty four. We've drilled twenty one wells to total depth through the end of the year. The fastest well was drilled to TD in forty one days and that was during the fourth quarter. This represents an improvement of forty five percent or thirty five days compared to our first well. Our first well that was drilled to total depth in seventy five days. The improvement in drilling days is a function of the footage drill per day and our first three wells in twenty twenty two averaged two hundred and eighty one feet per day. And that has steadily improved to four hundred and eighty seven feet per day in twenty twenty four. We averaged five hundred and forty seven feet per day in the fourth quarter of twenty four and the fastest well in this group drilled a record six hundred and eight feet per day. On average, our daily drilling footage has doubled since we started in twenty twenty two through the end of twenty four. There are several drivers behind our improved drilling performance in the western Hainesville. Starting in the vertical hole, we've improved our casing point selections. We've streamlined our casing designs. We've achieved faster drilling in the vertical improved bit selection. And in the laterals, we're utilizing thermal drill pipe and continue to see more consistent down-hole motor performance as we continue to have just with the additional drilling activity. We also started incorporating two well paths in our drilling program in mid, the middle of last year. Slide twenty one is a summary of our is the summary of our DNC cost through the fourth quarter for a bit smart long lateral wells located on the East Texas, North Louisiana, legacy acreage position. This covers all the wells with levels greater than eighty five hundred feet in length. Our drilling cost 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 six hundred and sixty dollars a foot. This is a one percent decrease compared to the third quarter. And in the fourth quarter, our completion cost came in at eight hundred and sixty three dollars a foot. Which represents a seven and a half percent 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 eleven, eight, you number five single horseshoe that we turned to sales in October. Both the drilling and completion costs trends show the impact of the significant inflation that took place starting in twenty twenty two. 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 just 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 tariffs 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. Slide twenty two. This is a summary of our DNC 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 ten to twelve wells drilled in the Western Hainesville 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 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 one thousand three hundred ninety six dollars a foot while our fourth quarter completion cost came at one thousand three hundred and fifteen dollars a foot. In addition to some of the main drivers affecting our drilling efficiency such as the streamlined casing design, faster drilling, 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 and 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 frat crews and our wire line 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. Roland, Dan, thank you for the transparency for the fourth quarter and the fourth year 2024. If everyone would go to slide 23, I'd like you to slide 23 where we summarize our outlook for 2025. In 2025, we will remain primarily focused on building a great asset in the Western Hainesville that will position us to benefit from the longer term growth and natural gas demand. We currently have four operated rigs drilling in the Western Hainesville as Dan said to continue to delineate the new play. We expect to drill 20 or 19.9 net wells in turn 17 or 16.9 net wells to sell 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 sell in 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 DNC costs in 2025 in both the Western and legacy Hainesville assets. With 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 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 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 map is a dream scenario for anyone pursuing an organic leasing program in a new basin. Thank you. I have two questions that are 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 shallow portions of the subbasin? Surely, DNC costs would decrease, but is there a chance that reservoir quality would support recoveries in the 2.5 to 3 BCF per foot zip code?

Derek, 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. So, we're drilling the stuff that we've leased in the hold. And so that will kind of keep us down in that general area. And as we fan up to the northeast for the kind of the near term activity in the next couple of years, but kind of answer your question. And I think, 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 EURs are going to look like. But, you know, I would certainly think maybe, you know, a hair less 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. But we're, you know, 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.

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 one 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 Hanesville exposure going back to 2008 to 2011.

And that's my follow up. I wanted to focus on the DNC 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 Hanesville, is the added cost largely associated with higher treating pressures? 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 Hanesville, the treating pressures are definitely much higher down here just based on the depth and the frac gradients. The beauty is in the Western Hanesville, it 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 Hanesville. On average, we pump about 4000 pounds per foot and in the core we pump about 3500 pounds per foot. So that's also part of it.

Yeah. And Dan, I'd add to just you look at comparing the Western Hanesville to the legacy Hanesville. 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 Hanesville, 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 bearing 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 than less of that cost. You know, the future wells would be able to utilize that investment we're making today.

Yeah. And I'd just add to what Roland said, we are building larger pads in the Western Hanesville 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 collar on the Western Hanesville. 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 Hanesville 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 in the Beauxer versus in the Hanesville, areas where it's thicker versus thinner. I think we're going to all yield different answers. So, you know, 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. You know, 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, you know, two wells on a pad. So I think we're probably looking at about, you know, half, 50, maybe 60% of our wells any given year will be on two-well pads and the others will be singles. You know, 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 try to do, if you look, we de-risk maybe 26 miles of this flage. We show that on the map. And our goal is by the end of 2025, 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. 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 at 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 at acre play. And, you know, Dan had mentioned a lot of his HPP, so we don't plan on drilling on the HPP to 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, 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 Hainesville is materially hotter and deeper than legacy Hainesville, 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. 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, you know, 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, you know, lower. We're going to knock more days off, you know, in the future. More of that, I see more of just a percent reduction in cost on the drilling side and on the completion side. We are pumping the same, you know, the same frac job right now and all the Western Hainesville wells. I will make one note, you know, on slide 22, there was there in Q2, it showed a high completion cost of $1,970 a foot. And that is we just had one well that quarter and we popped, you know, what we call our big frac. We popped we popped six thousand 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. But 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 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.

Yeah, I'd say we've we've 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 we're just making adjustments, you know, on how we on how we do that managed to draw down 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 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 mid-stream 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 Haynesville-Bosier and O8, you compare those to the wells we've drilled today, ours are like lights out better.

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

Good morning, Jay Rowland and Dan. And I had 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, Jay. Jay, you already anticipated one of my first questions when you started talking about the de-risking of the position. You talked about your first wells here, you've de-risked along a 26-mile southwest to northeast axis. If I'm just eyeballing your map there on page 18, I would say that's maybe de-risked -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 noticed on the slide or kind of my introduction, I said that this slide on page 4, 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 skewed. We just want to make sure you know it's not a distorted footprint because you would think it could be distorted because there's so much of it. Our legacy Hanesville, it's some of the most valuable acreage in North America, we believe, because of where it's located and all the locations that we have left to drill in the Hanesville as well as only 8% of the bozures developed. So when you go back to the beginning in 2020, 2021, you can see we tried to outline the patients that we had. That's why I gave 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 Johnson's 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 bozure and the Hanesville. Then we looked to see what seismic we had on, what we needed to buy. And then we didn't let the horses run wild. We drilled the wells, circled 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 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 HBP'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 pinnacle line? What's the cost structure? What's the gathering cost? We look at the depth, the thickness, and you do have different thickness. We've told you on some of the calls that we've got maybe 13, 1400 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 wide acreage in there? Well, a lot of that acreage, maybe 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 materially de-risk the whole foot print and see what the thicknesses are.

You know, if you look up in the up in our core acreage up here, you know, some of our best wells are in the areas that are not as thick like up around, like, you know, the Elm Grove area. So, you know, as far as just speculate, you know, if it's something thin or thicker on how it's going to perform, I don't think there's any correlation there at all, really.

Yeah, is it really more just gas fill porosity is the biggest determinant then?

I mean, thicker, I mean, obviously more gas in place, right? Thicker rot, but definitely that does not correlate to, you know, how prolific it'll be. We have meaningful bottom flow pressure

differences.

Yeah,

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 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, you know, 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 relatively thicker part of the place. So we haven't really got real specific on, you know, if the landing zone should be a little higher, a little lower. We just wanted to get the wells down, you know, basically just TD these things as fast as we could. And as far as the drawdown and, you know, we've been pretty conservative, you know, I think we'll probably tweak that a little bit in the future. You know, these last few wells, we like to IP them, you know, 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 and then, you know, 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, something like that in detail, but 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 Kylee Ackermeyn 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 will 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 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 a year and 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. We had to solo of gas prices. You know, but, but, you know, we definitely want to get it down as quickly as possible to the one and a half times leverage area. It's probably 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, 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 the leverage ratio to its 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 30 years. So if you look at that and you look at us getting rid of two weeks, you look at us having a crack holiday, and then you look at us adding 265,000 net acres in the Western Ainsville. 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, you know, as we were one of the first several companies to de-risk and discover the core Ainsville, we just took the same group down to the Western Ainsville, 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 Rowland, I'll see you guys in a couple of weeks. Yep, we look

forward

to

it.

And our next question will come from Bertrand Donz 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, you know, potentially selling or, you know, 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 situation, their business plan is to 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 Hainesville. 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 been very cautious to 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, you know, we give guidance down. We're not going to overproduce period. And that's that guidance is a result of dropping those rigs. And, you know, we're not adding the rigs in the Western Hainesville to increase production right now. We're adding those rigs because that's the best place for us to drill because we need to we need to drill more wells, the HPP, more the footprint. So that's why we're doing that even. We don't see any ENP 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, the contracts, either data center or LNG. And it seems like most have fallen in a 10 to 20 percent 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 for a 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 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 great 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. You know, we've got that we bet we balance out our production to what we know the market needs. So

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

All right. And just want to clarify that an acreage dedication for a for a demand project that is that coming back or are we we done with that?

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

it's probably a good time to talk about to the reason we were able to go look at the Western Hainesville is because the value of our core. You know, we don't want anyone to ever overlook that that three hundred one thousand net acres and that inventory with plenty of takeaway there that 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 answer.

Thank you.

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

Morning. Morning. Morning. Just you know, I hate to ask about twenty twenty six plus, but thinking about the four three rig split as we kind of progress through twenty twenty five, is that a level that can meet any HPP needs any NBC needs with quantum or are you contemplating a five to a five three? Just just wondering, you know, what are the commitments as we get into twenty six, twenty seven that we might need to be thinking about?

Well, the real positive, the way we structure things is that we we don't even need to maintain that type of activity to kind of meet any NBC's or other requirements. We've been very conservative as you build something out, you know, not to over not to get over committed. So I think it's a very comfortable level, you know, the you know, for the company. And so it's really going to be like, what is the markets? Yeah. 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. 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 to HPP and all of our acreage and easily meeting, you know, supporting, you know, the build out of the midstream.

OK, 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, you know, 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 there's been a lot of 3D 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 and kind of planning out where we want to drill. And we've got 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 Hainesville for well control purposes and geo steering. 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 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?

Yeah, it's a great question. Yeah, we this is a, 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 in the second quarter. And so, you know, then we continue to look at our volumes and then decide when we want to add additional trains to either either a new plan 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 we 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. And I think our partner has been too. And so, so I think that eventually, you know, as the entity has now has a lot of volumes and it's going to have a really good year this year. It's going to be able to maybe, you know, 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, you know, after it's up and running and generating a very strong EBITDAX. 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 our structure. You know, once we return that capital with a preferred return, you know, 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.

Yeah, the goal was we, as we were acquiring all the sacred, we wanted to control the mid frame. We trusted, you know, Quantum as a company and 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 acres, look at the well results, that point, which have only gotten better. I mean, they said we're exactly, we're 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 angel. 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 potential credit facility at the JV, that entity is self-funding for the next several years.

Right, right. We would see it hopefully transitioning in the next year. I mean, really, as you get through 26, probably where it, you know, it doesn't really need, it'll start to be totally self-funding. You know, and, you know, we also see maybe bringing in some of the nearby operators, you know, could also help accelerate that if we can land some of those as customers as we build the system out.

Great. Thanks for the time, guys.

And our next question will come from Noel Parks with TUI 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 know, you talked about some of the things you've preached, but I was wondering, you know, kind of 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 High School that kind of provided some of the earliest data to take a look at, you know, that we looked at. And we also had a lot of just a lot of mechanical issues, collapse casing and just, you know, really was pretty ugly. But, you know, we just looked at how many days it took them to drill those wells and those were essentially 5Ks type wells. And so if you just applied the same industry progression, you know, twice as long and half the days, that's kind of what we targeted, you know, and it was around that 75 to 80 day time frame. 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, is that, you know, there's a lot 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, in our confidence level group, you know, we were going to drill to 16,000 foot vertical. And then, as our conference crew was well, well, well, 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 article.

You know, 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 you 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, you know, that's, 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 Slato wells. So I just wanted to talk a little bit about gas macro and, you know, looking at your 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 I 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 at this as the US LNG fleet hit a new record high of 16.47 B's. You know, we're very, very, very positive on that for gas and a lot of part of 25, 26, even 27. So when we when we look at the Western Hanesville, 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 2526 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'll 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 surely it's a protection of the balance sheet to get us back to have a dividend. You know, if we could have a dividend, a lot of part of 26, great early 27, whatever. But we want to deliver the company now drill these wells, stay true to the mid spring partner with quantum and deliver this gas. Not when it's when it's needed. The beauty of this is nobody tells us when to drill it, how to drill it. We control it ourselves. It's it's 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 Roller went over it. We bought that a lot of that pipeline and one of our acquisitions. It is the backbone of where our footprint is. You could not have a better location for that pipeline. And it's not there by mistake. Twenty years ago, there was the core, 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, you know, we rigorated 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 two hundred and forty six 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.

So. Great. Thanks. That's that's really helpful insight. Tell for me.

This is all the time that we do have for questions. I would now like to turn the call back to Jay Alston 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. You know, again, I want to thank you. There's probably two hundred and 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. 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 spirit. Give you another one. It says, if you climb up on the saddle, you better be ready to ride. And we're ready and you can take that to the bank. Thank you.

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