Comstock Resources, Inc. (NYSE:CRK) Q4 2024 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q4 2024 Earnings Call Transcript February 19, 2025

Operator: Ladies and gentlemen, thank you for standing by. Welcome to the Fourth Quarter 2024 Comstock Resources earnings conference call. At this time, all participants 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 one one on your telephone. You would then hear an automated message advising your hand is raised. To withdraw your question, please press star one one 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.

Jay Allison: 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 fifteen degrees feeling like a minus two. Now I scrolled and look at New York, it was nineteen, feeling like five. Chicago, four, feeling like a minus four. And in Boston, it was fifteen, 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 Ainsville play in Texas. Over the past five years, we have been acquiring acreage in the western Haynesville based on geologic data put together including well logs from the many producing vertical wells near area.

Today, we hold five hundred and eighteen thousand net acres in our Western Angel area in addition to our three hundred and one thousand net acres in our legacy Haynesville area. There’s five hundred and eighteen thousand net acres in the Western Haynesville 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 twenty twenty two. We waited five months before we splattered our second well evaluating the Circle Inn’s performance. By the end of twenty twenty three, we had seven wells producing, and today we have eight Western Haynesville wells producing.

During our leasing phase, our hardworking land team never lost perspective or focus as they built our position. With acquisitions and grassroots leasing we now have around twenty thousand leases that make up the five hundred and eighteen thousand net Western Hainesville Acres. Fortunately, eighty percent of this acreage is HPP ed from our acquisitions of deep rights. That leaves us around seventy wells to be drilled over the next five years to HPP the entire footprint. At the beginning of our undertaking to derisk the Western Haynesville well by well, we made sure that one hundred percent 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. I Western Hansel horse looks to be very much alive and potentially a triple Even a secretariat in the making.

Given the success we saw, we decided to forego the m and a mark and focus on organic growth that The challenge in the Western Angel was not geological. As we are confident the shale is there. The challenge was drilling ten thousand foot horizontal wells at vertical depths of nineteen thousand where temperatures can exceed four hundred degrees. As we will report today, our operations team led by Dan Harrison has met the challenge for the first eighteen 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 Haynesville area.

We’ve been very cautious as we developed our Western Haynesville footprint. Twenty twenty and twenty twenty one were mainly focused on leasing. In twenty twenty three, we reached out to Quantum Capital Solutions to help us fund the mid spring build out for the new play. Quantum committed up to three hundred million dollars for the build out of the Gathering treating systems in the Western Haynesville. In twenty twenty four, we kept two rigs busy in the West Hazel and turned eleven new wells to sales and now we have four rigs in the new play, and we’ll drill twenty more wells this year. The creation of the Western Angel opportunity is quite a feat for a company of our size. This could not have happened without the total support of Jerry Jones and his family who owns seventy one percent of Comstock.

They saw the vision. They got in the weeds with us as we kept our focus to capture the prize approving a vast natural gas reserves beneath our two our five hundred and eighteen thousand net acre footprint. Today, we feel the land grab is over. With us holding the five hundred and eighteen thousand net acres, We also own and control our midstream system with Quantum as our partner. Our Western Haynesville well results look very promising at a time when America needs more natural gas to meet the growing demand for LNG, AIF, and all the industrial growth along the Gulf Coast. Our western handle is located several hundred miles from the gulf gulf coast where a hundred billion plus of LNG facilities are located. Our location is y LNG cup utilities, data centers, and industrial users are contacting us to be a future supplier.

To have substantial natural gas reserves near the 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 Haines. Today is the very first day we’ve shown the location of our five hundred and eighteen thousand net western Hazel 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 eight wells as we now have a large enough sample size to evaluate the results. So now I’ll open up this call with our standard introduction and disclaimer. If you would all go to slide one, Welcome to the Comstock Resources fourth quarter twenty twenty four financial and operating results conference call.

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 titled fourth quarter twenty twenty four results, I’m Jay Allison, chief executive officer of Gobstalk, and with me is Roland Burns. 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 presentation to note that our discussions today will include forward looking statements within the within the meaning of securities laws, or we believe the expectations and such statements to be reasonable. There could be no assurance that such expectations will prove to be correct.

Now if you would go over to slide four or slide three, which is our twenty twenty four. On slide three, we highlight our major twenty twenty four. 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 shorted 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 Ainsville 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 four zero one per acre. We made terrific progress proving up our Western Haynesville exploratory. We successfully turned eleven wells to sales with an average IP 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, were able to significantly reduce our drilling and completion cost in the West Haynesville compared to the twenty twenty two level. The drilling cost per lateral foot in our new play are down thirty three percent and the completion cost 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 drilled fifty or forty two point nine net wells to in Haynesville, Bossier 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 that of one dollar per MCFA.

There’s five suspending our quarterly dividend, we still deliver the highest twenty twenty four total shareholder return a month public e and p companies trading on a major exchange. If you would flip over to page four, it’s the Haynesville Shell footprint. Slide four is an overview, first time ever, of our acreage footprint position in the Haynesville Bossier shale 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. That is prospective for commercial development of the Hainesville and Boerger 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 Haynesville play in twenty twenty we have grown our acreage position to five hundred and eighteen thousand net acres.

We still have around one thousand three hundred net locations to drill on our three hundred and one thousand net acres in the legacy Haynesville which currently has eight hundred and ninety five net producing wells at. Our legacy handle acreage is forty eight percent developed for the Haynesville shale, at eight percent developed for the Bossier shale. In comparison, our western Hansel has only eight eighteen net producing wells and is virtually undeveloped compared to our legacy Haynesville. We expect our western Haynesville acreage to provide more inventory per acre versus the Legacy Hanesville. Look. Given the higher pay thickness and pressures we encounter in the West Haynesville expect the Western Haynesville to yield significantly more resource potential per section than our legacy HingeVola, I will now turn it over to Roland to discuss the financial results reported today, Roland.

Roland Burns: Alright. Thanks, Jay. On slide five, we cover our fourth quarter financial results. Our production in the fourth quarter averaged one point three five DCFE per day, is twelve percent lower Then the fourth quarter of twenty twenty three reflected our decision to drop two rigs early in twenty four and drop and have that that frac holiday that we had in the third quarter. Only way we turn to sales in our legacy Haynesville area in the quarter was our Horseshoe well that we discussed last quarter. So oil and gas sales in the quarter declined five percent to three hundred thirty six million dollars due to the lower production level which is partially offset by better natural gas prices. EBITDAX for the quarter was two fifty two million dollars and we generated two twenty three million dollars of cash flow during the quarter.

We reported adjusted net income of forty six million dollars for the quarter or zero point one six dollars per share, In the fourth quarter, we recognized the fifty two million dollars tax benefit related primarily to r and d credits and other credits. And also due to a reduction in Louisiana state corporate tax rate. A higher provision for depreciation, depletion, and amortization accounted for the loss before income taxes in the quarter. The higher amortization rate resulted from the decrease to our proved undeveloped reserves which were determined under SEC rules where you have to use the first of the month average price looking back for the previous twelve months. 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 averaged one point four Bcf per day, which is very comparable to the production we had twenty twenty three. Natural gas prices that we realized in twenty twenty four fell by seven percent resulting in our oil and gas sales decreasing seven percent to one point three billion dollars EBITDAX 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 the higher DDA expense, we were in twenty twenty four or zero point two four dollars per share compared to the one hundred and thirty three million dollars 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 the previous quarters.

The quarterly NYMEX settlement price averaged two dollars and seventy nine cents per Mcf in the fourth quarter, And the average Henry Hub spot price in the quarter averaged two dollars and forty two cents. The forty five percent of our gas in the fourth quarter was sold in the spot market, so the Appropriate. Market price reference price for our gas that quarter was two dollars and sixty two cents. Realized gas price during the fourth quarter averaged two dollars and thirty two cents, reflecting a zero point three zero dollars 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 zero point zero five dollars 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 close and this year and in twenty twenty six. We have approximately fifty percent of our gas production hedged 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 and the and the remaining is the form of costless costless collars with a floor of three dollars and fifty cents and 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 point three five dollars then the remaining forty one percent of our twenty six hedge position.

Alright. Gas price swaps, which averaged three dollars and fifty one cents per Mcf. On slide nine, we detail our operating cost per Mcfe. And our EBITDAX margin. Our operating cost averaged zero point seven two dollars in the fourth quarter which was zero point zero five dollars 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 alarm taxes were down three cents in the quarter primarily reflecting the lower statutory severance test rate we have in Louisiana Which win? 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 in the quarter.

Overall, our g and a cost were unchanged at five cents in the fourth quarter. 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 forty million dollars on development activities in the fourth quarter, and we spent nine zero two billion dollars for the full year. In twenty twenty four, we drilled thirty two or twenty five point eight net horizontal Haynesville wells and eighteen or seventeen point one net Bossier wells. Return 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 proved reserves at the end of twenty twenty four Determined based on year end NYMEX market prices which have which been adjusted for our differentials.

As compared to the much lower prices that we’d have to use for SEC purposes and and to determine DD and A in the financial statements. Using year end DYMEX prices, we’re able to grow our proof reserves by six percent even though we had reduced overall drilling activity last year. So our proved reserves totaled seven TCFE we we added eight hundred and ninety nine BCF of drilling additions replaced a hundred and seventy percent of what we produced last year, five hundred twenty eight BCFE. We spent nine hundred and two million dollars on that drilling program. Which gives us a finding cost of right at a dollar. For twenty twenty four. In addition to the approved reserves, There’s an additional two point one TCFE approved end of up reserves, which are not included, because they’re not expected to be drilled within the the next five year period as required by FCC rules.

Otherwise, they could be included in pre 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 give us 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 fifteen million dollars of borrowings 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 and our elected commitment under our credit facility remains at one point five billion.

Dollars With improved natural gas prices and the strong hedge position, we expect our leverage ratio to improve significantly as we start to report twenty twenty five financial results. The end of the fourth quarter, we had approximately one point one billion dollars of financial did he On slide thirteen, we summarize the market hubs that we sell our natural gas at. Our proximity to the growing natural gas demand from LNG terminals petrochemical and industrial complexes along the Gulf Coast gas price realizations compared to most of our natural gas peers. Sixty eight percent of our gas production is sold Gulf Coast Markets, using our long term transport agreements. With the balance sold at the regional hubs at Perryville, Carthage, and Bethel.

Selling directly to end users and having access to various Gulf Coast hubs provides Has the ability to take advantage of changing market conditions Yep. 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. Slide fourteen, we show the footprint of our midstream system, in our Western Haynesville 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 Haynesville, to handle the growing production from this area. So we contributed our pinnacle gathering and treaty system to the partnership.

Then Quantum is controlling 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 a gas treating plant at Bethel at the north end of our system and we’re currently constructing a new four hundred made a day treating plant at Marquette, Texas on our southern end. So now I’ll turn it over to Dan to discuss our operations. Okay. Thanks, Roland.

Dan Harrison: 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 and forty eight gross locations and one thousand two hundred and eleven net locations quite still a seventy eight percent average working interest. Our non operated inventory, we have one thousand one hundred and ten gross locations or a hundred and thirty nine net locations, which represents a thirteen percent average working interest. The drilling inventory is split between Haynesville and Bossier 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 or all laterals over ten thousand feet. In 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 Haynesville and forty nine percent in the Bossier. The up the updated drilling also includes the impact of identifying a hundred and thirteen horseshoe Locations. The average ladder 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 lab length drilled based on the wells that had that had been drilled and have reached PD or total depth. We have split out the data between both our legacy Haynesville and Western Haynesville hilarious. In twenty twenty four, the thirty nine wells that reached total depth in the legacy Haynesville at an average lateral length of ten thousand nine hundred and twenty two feet. Individual lengths 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 in the Western Haynesville 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 Hazel had a lateral length of twelve thousand seven hundred and sixty three feet. In the fourth quarter, we only turned one well of sales in the legacy Haynesville area. And this was our Sebastian No. Five Horseshoe well that we discussed on our third quarter conference call. In the Western Hazel, we turned six wells to sales during the fourth quarter, and five of these wells Return to sales over the last ten days of the quarter. Or of the year.

To recap, our long lateral activity today, we drilled a hundred and ten wells with laterals longer than ten thousand feet, and we have forty wells. With lateral’s over fourteen thousand feet. Slide seventeen outlines the wells that returned the sales in the legacy Haynesville in twenty twenty four. Twenty twenty four, we turned thirty seven wells in the legacy Haynesville to sales. 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 twenty three million today. The average lateral weight was ten thousand one hundred and four feet. And the individual laterals ranged from four thousand two hundred and twenty two feet Fifteen thousand three hundred and three feet. This list includes our first four, if you will, the Sebastian eleven eight u 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 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 price Two of our six rigs are currently drilling on our legacy Hinesville acreage. We do expect to add another rig to the legacy area later this year you know, if the gas prices remain attractive. Slide eighteen outlines the wells that we turned to sales in the Western Haynesville twenty twenty four. In twenty twenty four, we had eleven wells turned to sales. The individual OP 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 ladder length was ten thousand and thirty two feet. And the individual leverals 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 Current sales. The last ten days of the year. We do have four of our six rigs are currently drilling on our Western Haynesville papers. Slide nineteen. I highlights the total drilling days and the footage per day drilled in the legacy Haynesville. So In twenty twenty four, our wells in the legacy Hainesville area average 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 Haynesville area has averaged twenty seven point five days.

The improvement in the drilling days is a function of the footage drilled per day. In twenty twenty four, we averaged nine hundred and twenty feet per day drilled and the leg See, Haynes, what representing a six percent improvement over the twenty twenty twenty three average of eight hundred and sixty seven feet per day. Since twenty seventeen, the footage growth per day has increased thirty five percent with the fourth quarter of twenty four The footage of drill 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 Haynesville 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 Haynesville.

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 and minimizing problems and maintaining consistency, there are other factors leading the drilling efficiencies and then the application of managed pressure drillings, rig upgrades, and the continued improvement in our downhole motor performance. Slide twenty highlights the significant improvements achieved in our drilling times in the Western Haynesville. 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 and 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 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 wells 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, it was drilled to total depth in seventy five days. The improvement in drilling days is a function of the footage you roll per day. And our first three wells in twenty twenty two averaged two 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 then 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’s several drivers behind, you know, our improved drilling performance. In the Western and Honeywell Starting in the vertical hole, we’ve improved our casing point selections. We’ve streamlined our casing designs Let me see. You’re faster drilling? In the vertical through improved bit selection. And then the laterals, we’re utilizing thermal drill pipe and continue to see more consistent downhole motor performance as we continue to have, you know, just with the additional drilling activity.

We also started incorporating two well pads in our drill program in mid in the middle of last year. Slide twenty one is a summary of our is the summary of our BNC cost through the fourth quarter for our BITS Mark long lateral wells. Located on the East Texas, North Louisiana. Legacy acreage position. This covers all the wells with lateral’s greater than eighty five hundred feet. And length? Our drawing 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. 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 costs came in at eight 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 into Legacy Haynesville, and that was that Sebastian Eleven h u number five, single horseshoe.

That we turn to sales in October. Both the drilling and completion cost 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 Haynesville acreage to remain relatively flat to slightly lower for the next couple of quarters. We did start seeing our pipe prices come down late last year. We do expect to maintain these cost savings through the next couple of quarters. The cost expectations are a little more uncertain out past midyear with potential uptick in activity looming with the higher gas prices. And the possible tariffs discussions that are weighing with pipe prices. We are currently running two rigs on our legs St. Haynesville acreage and we anticipate adding a third rig later this year at the gas prices.

Stay attractive. On slide twenty two, this is a summary of our D and C cost through the fourth quarter for all the wells we have drilled in the Western High School. This slide provides the drilling and completion cost for all the wells we’ve drilled into play to date. We have spent a large amount of exploratory capital on our first ten to twelve wells drilled in the Western Haynesville as evidenced by the higher drilling and completion costs through the early part of twenty twenty four. We’ve accumulated a wealth of knowledge drilling those early wells that is now paying big dividends for us. The early exploratory DNC capital allowed us to hone in on the goodwill designs for future wells as a result, we’ve been able to reduce our latest D and C capital to a point lower than our original estimates of of roughly double, you know, what our legs high school wells cost.

Our fourth quarter drilling cost average one thousand three hundred ninety six dollars a foot. While our fourth quarter completion cost payment one thousand three hundred and fifteen dollars a foot. In addition to some of the main drivers affecting our drilling efficiency See, this is the streamlined casing design, faster drilling. You know, in the vertical hole, utilization of the thermal drill pipe, and our improved run times in the lateral This this also from the impacts of starting our two well pads and our drilling program in the middle of last year, which Help us to save additional days off for drill times. We’ve also had great execution on our completions and integrating the two well pads into has allowed us to be much more efficient with our frac crews and our I rubbed.

We do currently have the four rigs running in the Western Hainesville. And we do anticipate staying with the four rigs in the Western Heights for the near future. Also, mentioned all our Western Heinezville rigs are new rigs that we had purpose built with our Western Haynesville drilling program in mind. You know, in closing, I just wanna 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.

Jay Allison: As all of you know, that’s a lot of data when you include the the Wristman Hainesville. Roland Dana. Thank you for the transparency for the fourth quarter and the full Twenty twenty four. If everyone would go to slide twenty three. I direct you to slide twenty three where we summarize our outlook for twenty twenty five. But In twenty twenty five, we will remain primarily focused on building a great asset in the Western Haynesville 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 twenty or nineteen point nine net wells and turn seventeen or sixteen point nine net wells to sales in the Western Hanover this year.

We will continue to build out the West Mainesville midstream assets to keep up with the growing production from the area. Midstream expenditures are expected to be a hundred and thirty to a hundred and fifty million dollars. They will all be funded by our midstream partner. In the legacy Haines, we will run two or three rigs depending upon prices to build production back up by the fourth quarter. We expect to drill twenty six or twenty point four net wells and turn twenty nine or twenty two point eight net wells to sales a legacy angle this year. We anticipate funding our drilling program to roll instead out of operating cash flow and use any excess cash flow to pay down debt. We continue to have the industry’s lowest producing call structure.

And expect drilling efficiencies to continue to drive down D and C costs in twenty twenty five in both the Western and legacy Angel assets. We have strong financial liquidity totaling almost one point one billion dollars. Note on slides twenty four and twenty five, we provide for the rest of the year. We’ll now turn the call back to the operator to ask a question from analysts who follow the company.

Operator: Thank you. As a reminder, to ask a question, please press star one one on your telephone and wait for your name to be announced. And our first question will come from Derek Whitfield with Tech Capital. Your line is open.

Q&A Session

Derrick Whitfield: Well, good morning, all, and thanks for your time. Also, congratulations on the position you have assembled into Western Haynesville as your map is a dream scenario for anyone pursuing. Organic leasing program in a new basin?

Jay Allison: Thank you.

Derrick Whitfield: I have two questions and they’re both related to Western Haynesville. So reference in slide eighteen. You’re drilling arguably the deepest and most complex parts of your today as we understand the geology. Do you have a view on reservoir quality as you move to the west to the shallower portions of the sub basin? Surely, D and C costs would decrease, but there’s is there a chance that reservoir quality would support recoveries in the two and a half to three BCF?

Dan Harrison: Derek, this is Dan. I I think that that’s a very good question. We are drilling the deeper the deepest, hottest stuff know, if you look at where the well locations are across the acreage. We haven’t drilled anything, you know, up there on that part of the acreage. A lot of that stuff is HBP acreage. So, you know, we’re drilling the stuff that we’ve leased in the hole, and so that’ll kinda keep us down in that general area. And as we stand up to the northeast, for the kind of the near term activity in the next couple of years. But kind of to answer your question, I think, 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 gonna look like, but You know, I would certainly think maybe, you know, a hairless just if you just correlate it to depth, But we also expect our DNC cost are gonna be a lot lower, you know, when we drill up there in the future.

And, you know, I think our DNC cost are gonna be a lot lower just drilling where we’re at now in the future. We’re You know, we’re still kinda going up the learning curve. We haven’t plateaued yet on even the lower cost that we’re at today.

Jay Allison: 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 we we we we looked at what reality looked like, and they look really good. And that’s where we ended up with these eighteen wells. There was a big enough dataset 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 Haynesville Bosch are going back to two thousand eight to two thousand eleven.

Derrick Whitfield: As my follow-up, I wanted to focus on the D and C cost compression you’re highlighting on page Twenty two Specifically focused on the completion side. The degree of the step down in q four suggests there’s more opportunity there, which is kinda what Dan suggested as well. But in comparison to your legacy Hainesful, is the added cost largely associated with higher treating pressures? Are there or are there other considerations? And I guess more broadly, how much lower could you drive that?

Dan Harrison: I think we have more room to probably lower our cost On on the drilling side, I mean, we’ve seen we’ve seen a bigger drop on the drilling side than the completion I think we have room to lower the completion cost a little bit further. I think that q four cost we have in there at thirteen hundred and fifteen dollars a foot, that’s kind of a number that we’re Planning with for the future wells just for forecasting. Kinda you know, you asked about treating pressures. Yes. So as far as compared to the legacy Haynesville the treating pressures are definitely much higher down here just based on the depth. And the frac gradients. The beauty is in the western high zone, the fracs very consistently. So it’s been really it’s been really kinda 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 four thousand pounds per foot, and then the core, we pump about three thousand five hundred pounds per foot. So that’s also part of it.

Roland Burns: Yeah. And Dan, I’d I’d add too just yeah. You look at comparing the Western Haynesville to the legacy Haynesville, I mean, we are having to build all the infrastructure, the new pads, I mean, you know, we’re really starting from scratch there. And the legacy Haynesville, you’ve got a lot of infrastructure that we built long time ago and very often using pads we built a long time ago So, you know, there’s a there’s a huge difference in the the up upfront cost. These early wells are bearing all that cost know, in the numbers. And then as you come back and infill drill and and continue to develop it, you know, you’ll have less and less of that cost Yeah. The future wells would be able to utilize that investment we’re making today.

Dan Harrison: Yeah. I’ll just add to what Roland said. We are building larger pads in the western high school to be able to come back and drill future wells.

Derrick Whitfield: Great update, guys.

Jay Allison: Thank you. Thanks.

Operator: And the next question comes from Carlos Escalante with Wolfe Research. Your line is open.

Carlos Escalante: Hey. Good morning, gentlemen. I wanted to first congratulate you all on the incremental caller on the Western Angel. It’s it’s really encouraging to see the results. 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 Hazel pad? In in terms of how many wells you would expect on on any given pad, and what your general assumption for spacing would be. Knowing, of course, that it’s it’s probably too early to know what the the right spacing is.

Dan Harrison: Yeah. I’ll 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 Bozier versus in the Hinesville you know, areas where it’s thicker versus thinner, I think we’re gonna all yield different answers. So I don’t have a direct answer to that question. But as far as future development, we we strive to drill everything with two well pads that we can. We’re, you know, we’re drilling and we’re holding acreage. In some places, you just Yeah. Just don’t the acreage doesn’t give you the opportunity to drill to two laterals, you know, two wells on a pad.

So I think we’re probably looking at about, you know, half, fifty, maybe sixty percent 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 gonna be our mix for the next couple of years.

Jay Allison: And one thing we try to do you look, we derisk maybe twenty six miles of this plate. We show that on the map. And our goal is by the end of twenty twenty five, drilling twenty 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 the the gathering treating in in the midstream to complement the program at twenty five twenty six. I think by the end of twenty five, definitely by the end of twenty six, I will have fully derisked this whole five hundred and eighteen thousand net acre play know, Dan had mentioned a lot of this HPP so we don’t get plan on drilling on the HPP acreage until we hold maybe seventy more wells we need to drill in the next several years.

To HPP our entire footprint.

Carlos Escalante: Gotcha. 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 completion side. But given that the Western Hainesville is materially hotter and deeper than legacy Hainesville, you’d almost think that your your drilling savings will be will hit a a plateau soon, if you will, whereas on the completion side, you might you you haven’t reap the the full benefits of a full development cycle. So I was wondering if you can perhaps speak to how on the completion side, You you’ll achieve greater savings. What what are you doing specifically in terms of your completion design? And and how much headroom do you see on the drilling side as a whole?

Dan Harrison: I mean, so kind of alluded to that a little bit earlier. I think you know, we’ll see we haven’t we haven’t reached a plateau on the calls, first of all, in the Western Haynesville. Mean, obviously, with all the thousands of wells and we drilled up in the legacy area, you know, it is. It’s just small little tweaks here and there. It’s, you know, it’s minor things. It’s it’s great execution, you know, just saves off just, you know, a day here and a day there. That’s not the case in the Western Haynesville. In the Western Haynesville, 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 gonna drive these costs you know, lower. We’re gonna knock more days off.

You know, in the future. More of that I see more of a just a percent Reduction in cost on the drawing side and on the completion side. We are pumping the same, you know, the same frac job right now on all the Western Haynesville wells. I will make one note, you know, on slide twenty two, there was a there in in q two, showed a high completion cost of Nineteen hundred and seventy bucks a foot, and that is we just had one well that quarter and we popped know, what we call our big frac. We pumped we pump six thousand pounds per foot on that well for a data point just to monitor how that well produces in the future. Compare to all our others, which is well, 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 cost coming down. As much as the drilling on a percentage basis.

Jay Allison: 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 and we preview what Circle m looked like, what we 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 eighteen wells.

Carlos Escalante: Yeah. I’d say we we definitely have been conservative on how we’re drawing the wells down and

Dan Harrison: you know, based on a lot of the things we’re seeing, we’re we’re just making adjustments you know, on how we on how we do that, manage the drawdown how hard we pull the wells when we flow them back and clean them up, turn on the sales, And then know, where we set the rate after that.

Jay Allison: And what that’ll do, they’ll give more predictability, give more stability, It’ll give us, you know, what the the real top curve may look like. What the draw downs may look like, but 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 the mid frame is secure. So we can tell you a little more about it. And particularly, the dataset 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 eighteen wells ever drilled in the core, The Haynesville, Bossier and o eight, can you compare those to the wells we drilled today? Ours are like life sounds better. So

Operator: And our next question comes from Charles Meade with Johnson Rice. Your line is open.

Charles Meade: Good morning, Jay Rowan and Dan. And I’ll I I have my voice to the course of of of congratulations, not just on assembling this, position, but also the the great progress you’ve made. Screaming and yelling for us

Jay Allison: and you’ve lost your voice. I know. I understand.

Charles Meade: That’s that’s that’s the least of my problems, Jake. Jay, you already anticipated one of my or my my first question when you started talking about the the de risking the position. You you talked about the you you your first wells here, you’ve you’ve derased along a kind of a twenty six mile southwest northeast access. If I’m just eyeballing your map there on what is I think it’s page eighteen. Yeah. I just eyeballed. I would say that’s maybe derisked don’t know, twenty, thirty percent of your position. I I’m wondering if you could you could give an opinion on that and then maybe also wrap in as you, you know, as you go up dip or you you go north, what what are the risks? Is it is it formation thickness or is it just is it is it porosity that that is the risk that that’s gonna you know, determine exactly how much of this five eighteen really works. Well,

Jay Allison: if if what you noticed on the slide or or or kind of my introduction, I said that this file I’m paid for, it 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. You compare it to your other acreage, and it looks it looks skewed. So we we said you we just wanna 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 our legacy Hinge will I mean, it’s some of the most valuable acreage in North America, we believe, because where it’s located, in all the locations that we have left to drill in the Haynesville as well as only eight percent of those years developed So when you when you go back to the beginning, in in, you know, twenty twenty, twenty twenty one, too, you can see we’ve 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 we’re gonna get off of it. But if it continues to work and quite frankly, Jerry Jones and his family allow us to derisk this thing, which is very hard to do. It takes months and, 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 twenty twenty one, twenty two 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 how many logs do we have that penetrated the different thicknesses in the Bossier and the Haynesville? Then we look to see what seismic we ought to, what we needed to buy, And then we we we didn’t let the horses run wild.

We we drill the wells, circle them, we pull the rig back for five months. We let the well tell us to what to do. Then we did move that rig back on. We kept it pretty busy at now we were good we were good stewards to the the budget and liquidity. In twenty twenty four, 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 twenty twenty one, twenty two, twenty three, twenty four. We leased it along the way. So we avoided a big clip 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 twenty twenty five, twenty twenty six, twenty seven, we kinda 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 the 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, thirteen, fourteen hundred feet of perspective pay in some areas. Well, you look at that, that’s not true for all of it. Some of it’s gonna be the same, you know, pay thickness that we have in the tier of our of our legacy acreage So, you know, that’s that’s two hundred, three hundred feet, whatever. But, yeah, it it it’s it expands We did choose to drill the deepest, hottest, hardest first.

Because that would tell you whether we needed to pursue to spend more money on acreage and more money on seismic and to keep the land group leasing that acreage and feathered into the drilling program. It’s a beautiful story to write when you see it. Because of of of, like, you know, Roland had come up eighty percent of this is HPP. I mean, eighty percent, 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 own, and we encourage them to drill wells out there. Maybe there’s some little spotty acreage that we don’t wanna own, but we’re not afraid to have people come out there and derisk this with us. That’s why we show you once we think the LandGram is over.

So, you know, at the end of of this quarter, I think we’ll have some more results. But I want you I mean, it’s it’s you it’s our banks. It’s our analysts. It’s our equity owners. It’s our bondholders that believe in what we’re doing. Want you to always know what we’re doing. And and our goal in twenty twenty five is to to materially derisk the whole footprint and see what the thicknesses are. You know, Charles, I’ll ask you.

Dan Harrison: If yeah. If you look on the in the If in our core acreage, Jeffrey, you know, some of our best wells are And the areas that are not as thick, like, up around, like, you know, the Elm Grove area. So I, you know, I as far as just speculating, you know, if it’s something standard or thicker on how it’s gonna perform, I don’t think there’s any correlation there at all, really. Yep.

Charles Meade: Yeah. Is it is it really more just a, you know, gas fill porosity is the is the biggest determinant then? Yeah. I mean, thicker I mean, obviously, more gas in place. Right? Thicker rot. But Yeah.

Dan Harrison: Definitely, that does not correlate to the to you know, how prolific it’ll be.

Jay Allison: And we have many cool model cold pressure differences.

Charles Meade: 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 you continue to watch these other older vintage wells, and I’m more 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 or the right completion jobs. I I I know there’s you know, every day that ticks by, you you add to the data pile from those older finches as well. So can you just tell us what you’ve learned in that respect?

Dan Harrison: I think, you know, we we we obviously have been really laser focused on the cost. Just getting the wells down in TD, The landing zones, I think, you know, a lot of these where we where we drill are in the You know, relatively thicker you know, part of the place. So we haven’t We haven’t really you know, got real specific on, you know, the landing zone should be a little higher, a little lower, just wanted to get the wells down, you know, and basically just feeding these things as fast as we could. And far as the drawdown and 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 we like to IP them you know, pull them a little bit harder and get the wells cleaned, 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.

Jay Allison: No. Charles, tell me Thank you for the added detail. You, but Some of these wells we two buck, some we don’t. It’s a big cost variance too. We figure out what we need to do or not do. As we drill more of these wells.

Charles Meade: Got it. Thank you, Dan and Jay.

Jay Allison: Thank you.

Operator: And the next question will come from Colly with Bank of America. Your line is open. Hey. Good morning, guys. Jay Rillan.

Colly: I think the update here is being received well, so I’m gonna keep it quick here. Any early thoughts on twenty twenty six on maybe holding activity here at Seven rigs seems like the industry is falling in a rhythm with demand, and that’s a really good place to be.

Roland Burns: Right. No. I think that’s the key. You know, one thing we we wanted to make sure is that we don’t produce too much gas, especially in one region area. We’ve been, you know, been looking at that. We think seven rigs was always a really when we dropped to five rigs, good level for the company to kinda maintain, I think, 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 gonna get very comfortable with seven. We’re gonna balance sheet Yeah. Back to like it was in twenty twenty two. That’s our biggest goal. And I think twenty six will be a year that will have the level of production and good gas prices to drive the get the balance sheet and and perfect shape, but and I think, you know, it’s twenty five, you know, That level we’re running now, you know, we won’t we won’t add any debt, most slowly pay them down.

But then next year, we’ll be able to really reduce debt significantly.

Colly: Brilliant. As far as the year end twenty six bogey, you think somewhere under one and a half times is where the balance sheet would end up.

Roland Burns: Well, I I think you’ll first, you’ll see the leverage ratio improve rapidly as we can start to count the twenty five results and and and take off the results of last year, we had to so low of gas prices Yeah. But but, yeah, we definitely wanna 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 twenty six But I think we’ll be you know, way in the very low Two times leverage numbers as we kinda work our way through twenty five. So so a lot will depend on, you know, how strong gas prices are and then how know, we do have to rebuild our production a little bit to kinda get that leverage ratio, you know, to us more optimal

Jay Allison: You know, that that’s a really good point though. I mean, we said this but other than COVID, gas price last year was was the lowest it’s been in thirty years. So if you look at that and you look at us getting rid of two roofs, you look at us having a frack Holiday. You And then you look at us adding two hundred and sixty five thousand net acres in the Western Angle, you can see that we we we really, really monitor our leverage and our balance sheet We do that even in a very, very difficult year, and at the same time, Instead of m and a, we we said we’d like to to see if we can grow organically. And and typically, that’s what these companies used to do. And because of the Joneses, they kinda uncut this We could go in and you know, as we were one of the first several companies to derisk and discover the core angel, we’re we we just picked the same group down to the Western Angle, knowing what we were looking for.

And and it it took five years for it to turn out to which turned out right now. Still preliminary. But if we’re right, the these reserves will be there’d be massive Our footprint is massive, and we’re in the exact bright part of North America for all this demand, particularly for LNG. So it’s it’s gonna be a really beautiful story.

Colly: That’s right. It’s it’s exciting to watch. Jay Roland, I’ll see you guys in a couple weeks.

Jay Allison: Yep. We look forward to it.

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

Bertrand Donnes: Hey. Morning, team. I just wanna follow-up on that on that M and A topic Not necessarily on the on the western side, but with higher gas prices, you’d think most of the the private owners are probably thinking about, you know, potentially selling or you know, maybe does that incentivize you to to look more aggressively, or are those sellers seeing the strip move up and and maybe they’re already seeing a five dollar price that they wanna see or or something like that. And then the the second part of that would just be on the oil side, most of these these private equity shops normally ramp up production before a sale. Do do you see that happening, or or that’s not exactly how it would work on a gas side?

Roland Burns: Well, it’s it’s hard to predict how, you know, what what they’re looking at. But, obviously, I think there are sales some private companies out in the Haynesville 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 kinda like the same with the oil. The private companies in the Permian, and so net But we we do see a very low level of activity in the Haynesville, so we certainly haven’t seen any type of effort to ramp up at all from from the public or private operators. We’ve we’ve seen great discipline you know, in the basin. And I think I think all the producers really wanna get very comfortable that, you know, that that the gas is really needed and We’ve seen very, very volatile gas prices And so I think everybody’s been very cautious to say, hey, we’re not going to oversupply this market.

And maybe we under supply it because we’re so cautious.

Jay Allison: Well, and you can even say the first quarter, you know, we give guidance down We’re not gonna overproduce, period. And that that guidance is a result of dropping those rigs. And, you know, we’re not adding it. The rigs in the Western Angle 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 to HPP more of the footprint. So that that’s why we’re doing that even. We don’t see any e and p company out there out of control on their production rates. None of them.

Bertrand Donnes: That’s great. And I I think the market is is happy to see that. And then for my my second question, you know, several of your peers have started talking about potentially locking in a percentage of their production. The contracts either data center or LNG, and and it seems like most are have fallen in at ten percent to twenty percent of their volumes. Is that where you guys feel like you’d fall, or or you potentially have a a larger app type? Maybe you lock up, you know, acreage dedication in the western Hainesville or or something like that. For a you know, to backfill a demand project. Thanks.

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

Jay Allison: So Well, particularly, you know, probably ninety percent of our Western Haynesville is completely in dedicated I mean, completely So it’s it’s it’s pretty range out there. We can kinda do what we want to with it.

Bertrand Donnes: Alright. And just wanna clarify, so that an acreage dedication for a for a demand project, that’s it is that coming back or are we we done with that?

Roland Burns: Yeah. I’m not sure that, you know, acreage dedication probably, you know, out there. I mean, typically, that it kinda comes to backup, you know, large amount of infrastructure, you know, to 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 gonna own our we way we structured things, we’re gonna be able to own all that. And so, I think instead, we wanna kind of look out and say, hey, we can we wanna take up our portfolio of gas, but for the legacy and the Western Haynesville and and then want to portion it out to, you know, these these direct the you know, what’s the best deal for CommSox. So who’s gonna pay the higher premium?

They all have kinda different needs and and so so so but it’s a it’s a very exciting time to be developing a new plate like the Western Hainesville, at the same time you know, 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.

Jay Allison: You know, this is probably a good time to talk about too. The reason we were able to go look at the Western Angel is because the value of our core You know, we we don’t want anyone to ever overlook that. That’s three hundred and one thousand net acres in that inventory. With plenty of takeaway there. That that gave us the ability to come look at the Western Hansel, that along with the operational technical skill that we had But the but but the value of the legacy allowed us to do the Western Hainesville.

Bertrand Donnes: Perfect. Thanks for the answers, guys.

Jay Allison: Thank you.

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

Jacob Roberts: Morning.

Jay Allison: Morning. Morning.

Jacob Roberts: Just you know, I hate to ask about twenty twenty six plus, but thinking about the four three rigs split as we kind of progress through twenty twenty five, is that a level that can meet any HPP needs, any MVC needs with Quantum? Or are you contemplating a, you know, five two, 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.

Roland Burns: The the real positive, the way we structure things is that we don’t even need to maintain that type of activity to kinda meet you know, any NVCs or or other requirements. We’ve been, you know, 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 know, for the company? And so it’s really gonna be, like, what is the market You know, where is the gas really needed? And I think we would adjust that, you know, based on kinda how we see these market go out. I think we’re very comfortable with the activity level and running be able to run four rigs in the Haynesville will keep us on track to Six two. HBP in all of our acreage and easily meeting, you know, supporting, you know, The build out of the midstream.

Jacob Roberts: 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, you know, the amount of seismic, the amount of historical, work that’s been done on this land that helps you understand that The way you do?

Dan Harrison: Yeah. It’s like there’s been a lot there’s been a lot of three d seismic shot across all of this acreage. Just a lot of different different vintage data The South Third that can be bought that has been tremendously, you know, Helpful. We’ve got a planning out where we wanna drill and we’ve got we’ve got some future wells that we’re gonna be drilling some 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 quoting in stuff we’re gonna do as far as, you know, just doing some more sites you know, and to get the performance properties on the rock.

Jacob Roberts: Excellent. I’ll echo the sentiment of appreciating the update, guys.

Jay Allison: Thank you.

Operator: And our next question will come from Greg Brody with Bank of America. Your line is open.

Gregg Brody: 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 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 a new treating plant, this is a 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 gonna have a lot of treating capacity that’s gonna 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 our volumes and then decide when we want to add additional trains know, to either either a new plan or adding to our north or south plan.

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 so we we feel really good about where that is. I think that we it it the the build out of the bid stream is amazingly fit almost perfectly with our five year plan for it so far. And so we’ve been really Please And I think our partner has been too. And So so I think that eventually, you know, there’s the entity has now has a lot of volumes and it’s gonna have a really good year this year. Gonna be able to maybe have you put in its own credit structure there so we can kinda kinda get less expensive capital to kinda fund some of its build out. But that’s probably gonna be you know, more later in the year after, you know, after it’s up and running and generating a very strong EBITDA.

But very excited about what Pinnacle can become, and value it’s gonna be adding. I think you look down the road, it’s gonna be a very, very big asset. For the company. And under our structure, you know, once we Yeah. Return that capital with the preferred return, you know, that will revert a Yep. Seventy percent back to the company, and then we can buy out the minority interest if we’d like in the future also.

Jay Allison: Yeah. The goal was we as we were acquiring all the sacred we wanted to control, midstream. We we trusted, you know, Quantum as a company, lending money, and Porting. Plays like this, which 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 of that that point, which should only gotten better. I mean, they said we’re, you know, we’re exactly with three hundred million We 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 wanna lose control of that. And Quanta became the perfect partner. So it’s fair to say that between

Roland Burns: Quantum’s equity and a potential credit facility at this at the JV It’s That entity is self funding for the next several years.

Gregg Brody: Right. Right. We would see it, hopefully, transitioning in the next year. They really and as you get through twenty six, that probably where it know, it doesn’t really need it’ll start to be totally self funding. You know, and and we we all supposed to be maybe bringing in some of the nearby operators, you know, could also help accelerate that if if we can land some of those as customers. As we build the system out.

Gregg Brody: Great. Thanks for your time, Debs.

Operator: And our next question will come from Noel Parks with Tuohy Brothers. Your line is now open.

Noel Parks: Hi. Good morning. You know, just thinking about the 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 Your earliest well and whether there’s anything different now That you’re this far in? Sort of, like, what Yo. Talked about some of the things you’ve you’ve preached. I’m just wondering you know, kinda what was your starting point like when you were approaching the play?

Dan Harrison: You know, it’s a interesting question because when we you know, we looked at everything we had done in the legacy you know, on our legacy acreage in all of the years past, and kinda 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 were were being drilled twice as long, you know, say five k’s to ten k’s, and at the same time, they were getting twice as long, you know, they were being drilled at half the time. And there were a couple of, you know, there was a couple of Old wells that had been drilled, old horizontal that had been drilled back in twenty ten down here in the Western High School kinda provided some of the earliest data to take a look at, you know, that we looked at.

They had a lot of just a 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 how many days it took them to drill those wells, and those were were essentially five k ish type wells. And so if you just applied the same industry progression You know, twice as long and half the days. That’s kinda what we targeted you know, and it was around that seventy five to eighty eighty 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 eighty days. Starting out. And the good thing is is that, you know, there’s a lot of running room. These wells were 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

Jay Allison: Well, on our confidence level group, you know, we were gonna drill the sixteen thousand foot vertical, and then As our conference crew was well after well after well, we did go to nineteen thousand feet. So we wouldn’t have done that had we not had more confidence in the sixteen thousand foot vertical.

Dan Harrison: You know, you 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 you all practice makes perfect, the more you drill, the better you’re gonna get. The more the industry drills, the better the industry gets. And, you know, that’s know, that’s what we’re seeing.

Noel Parks: Great. Thanks. And, you know, understandably, there’s been so much attention to us seeing the the map for the first time and And results from the the newest slate of wells. So I just wondered if I could just talk a little bit about gas macro and looking at your hedges I was just wondering, is there anything particular about the three fifty 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 gonna look like or might look like as the LNG ramp up continues along? Well, you know, we look today, and I just looked this as a

Jay Allison: US LNG fleet hit a new record high of sixteen point four seven b’s You know, we we are very, very, very positive on that. Forget in latter part of twenty five, twenty six, even twenty seven. So when when we when we look at the Western Haynesville, not the Legacy I mean, we do need to drill the Legacy, of course, It provides us a a very dependable revenue stream. But what we wanna do, we wanna guarantee that we can drill all these wells that we need to drill in twenty five, twenty six. And still deliver the balance sheet. Our our big land grab and the and the lot of money we spent on that is we’re we’ll spend a little bit as we do even in the core cleaning it up all the time with be perpetual. But we don’t see any big acreage at their positions that we’re chasing that we don’t have.

So this is purely it’s it’s a protect 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 twenty sixth, great. Early twenty seventh, whatever. But we want to delever the company now, drill these Well, is it stay true to the midstream partner with Quantum. And deliver this gas not when it’s when it’s needed, And the beauty of this is nobody tells us when to drill it, how to drill it, or we control it ourselves. It’s it’s it’s something we bar we control. And where it is is is perfect. You could pick a map. If you would look at where our pipeline is, which we showed that while we went over it, We bought that a lot of that pipeline in one of our acquisitions It is the backbone of where our footprint is.

You cannot have a better location for that pipeline and it’s not there by mistake. Twenty years ago, that was the core of the core where they were drilling. That’s why that pipeline was there. It just wasn’t worth anything when we bought it. Somebody had to, you know, re rigorate it and and put some gas in it. We’re the only ones willing to do it. So it has become a very valuable piece of the company.

Roland Burns: The replacement cost for two hundred and and forty six miles of high pressureRoland Burns: 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 the amount of equity that’s already there is is pretty phenomenal.

Noel Parks: Great. Thanks. That’s that’s really helpful insight. That’s all for me.

Operator: 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.

Jay Allison: I wanna thank all of you. It’s it’s a much longer call than normal. It’s almost an hour and a half. We knew it it would go longer. We didn’t wanna cut anybody off, but know, again, I I wanna thank you. There’s probably two hundred and fifty plus men and women who make up the Comstock team, and a lot of them listened to the call. I wanna thank all of you as well. I wanna thank our 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 wanna say again, especially thanks to Jerry Jones in this family who are the backbone support. To unlocking the Western Hansel value. You know, I gave an old cowboy spear. I’ll give you another one. It says if you climb up on the saddle, you better be ready to ride. And we at CommSpark are ready, and you can take that to the bank. Thank you.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.