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Earnings Calls
Comstock Resources faces challenges in natural gas prices, seeing a 7% revenue decline in 2024 to $1.3 billion. Despite this, they strategically expanded their Western Haynesville acreage to 518,000 net acres and successfully drilled 11 new wells in 2024. The company projects to drill around 20 wells in 2025 while anticipating steady cash flows bolstered by a hedging strategy of 50% at an average price of $3.48 for the year. Their enhanced operational efficiencies have delivered a notable EBITDAX margin improvement from 67% to 73%, highlighting their commitment to maintaining cost leadership in the industry.
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Ladies and gentlemen, thank you for standing by. Welcome to the Fourth Quarter 2024 Comstock Resource Earnings Conference Call. [Operator Instructions]
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.
Thank you, and good morning, everyone. What a fantastic morning here in Frisco, Texas, with snowflakes coming down when I woke up I looked at the temperatures in Frisco was 15 degrees, feeling like a minus 2. [indiscernible] at New York, it was 19 feeling like 5, Chicago 4 feeling like a minus 4. And in Boston, it was 15 feeling like 2. So now let me tell you the story, the latest news about Comstock Resources, which is a pure natural gas company. We're excited to report today the great success we've had to date in our Western Haynesville play in Texas, over the past 5 years, we have been acquiring acreage in the Western Haynesville, based on geologic data we put together, including well logs from the many producing vertical wells in the area.
Today, we hold 518,000 net acres in our Wester Haynesville area in addition to our 301,000 net acres in our legacy Haynesville area. This 518,000 net acres in the Western Haynesville represents a massive footprint that is fairly contiguous allowing us to drill 2 wells from a single pad to hold 2 separate units as we drill north and south from the same pad. Our initial Western Haynesville well, the Circle M well was turned to sales in April of 2022.
We waited 5 months before we spread our second well evaluating the Circle M's performance by the end of 2023, we had 7 wells producing. And today, we have 18 Western Haynesville wells producing. During our leasing phase, our hardworking land team never lost perspective or focus as they built our position with acquisitions and grassroots leasing. We now have around 20,000 leases that make up the 518,000 net Western Haynesville acres. Fortunately, of this acreage is HBP from our acquisitions of Deep Brits that leaves us around 70 wells to be drilled over the next 5 years to HBP, the entire footprint. At the beginning of our undertaking to derisk the Western Haynesville well by well, we make sure that 100% of our team held no distorted view of reality. Reality is truth.
There is an old cowboy saying, if the horse is dead dismount. Well, our Western Haynesville horse looks to be very much alive and potentially a Triple Crown winner even a secretary in the making. Given the success we saw, we decided to forgo the M&A market and focus on organic growth. The challenge in the Wester Haynesville was not geological as we are confident that 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 for the first 18 successful wells. They have 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.
2020 and 2021 were mainly focused on leasing in 2020 reached out the Quantum Capital Solutions to help us fund the midstream build-out for the new plate. Quantum committed of $300 million for the build-out of the gathering and treating systems in the Western Haynesville. In 2024, we kept 2 rigs busy in the Western Haynesville and turned 11 new wells to sales, and now we have 4 rigs in the new play and we'll drill 20 more wells this year. The creation of the Western Haynesville 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 for Comstock. They saw the vision.
They got into wheez with us as we kept our focus to capture the price of proving a vast natural gas reserves beneath our 518,000 net acre footprint. To date, we feel the land grab is over with this 518,000 net acres. We also only control our midstream system Quantum as our partner. Our Western Haynesville well results look very promising at time America needs more natural guests to meet the growing demand for LNG, a and all the industrial growth along the Gulf Coast. Our Wester Haynesville is located several hundred miles from the Gulf Coast were $100 billion plus of LNG facilities 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 Haynesville.
Today is the very first day we have chose the location of our 518,000 net Western Haynesville acres as we have closed the large acquisitions we have been working on and captured much of theses that we wanted. We also are providing specific well at 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 1.
Welcome to the Comstock Resources Fourth Quarter 2024 Financial and Operating Results Conference Call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There, you'll find a presentation entitled fourth quarter 2024 results. I am Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our President Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations.
Please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now if you would go over to Slide 4 -- Slide 3, which is our 2024 accomplishments.
On Slide 3, we highlight our major 2024 accomplishments. Most importantly, we successfully navigated last year's very low natural gas prices. Our realized gas price before hedging of $1.98 per Mcf in 2024 represented a 30-year low if you exclude the 2020 COVID year. We acted early in 2024 to significantly reduce our capital spending by release 2 operated rigs and 1 frac spread. We also suspended our quarterly dividend to conserve cash flow. We increased our hedging program, which improved our 2024 realized gas price by 20%. It also safeguards our 2025 and 2026 drilling programs by targeting 50% of our expected production.
We shored up our balance sheet by adding $100.5 million through an equity private placement with our majority stockholder and enhanced our liquidity with a $400 million senior note offering. During this year of low natural gas prices, we were also able to grow our Western Haynesville footprint. We more than doubled our acreage position to 518,000 net acres by acquiring 265,000 net acres at a cost of $401 per acre. We made terrific progress proving up our Western Haynesville exploratory play. We successfully turned 11 wells to sales with an average IP rate of 38 million cubic feet per day and now have a total of 18 wells producing in the play.
In the fourth quarter, we were able to significantly reduce our drilling and completion costs in the Western Haynesville compared to the 2022 level. The drilling cost per lateral foot in our new plays are down 33% and the completion cost per lateral foot are down 28%. Overall, our 2024 drilling program delivered solid results and proved reserve growth despite the lower activity last year. We drilled 50 or 42.9 net wells successfully operated Haynesville/Bossier wells with a strong average IP rate of 26 million per day.
Our 2024 drilling program replaced 107% of our 2024 production and drove 6% reserve growth with 899 Bcf of drilling-related reserve additions and achieved an overall finding cost of $1 per Mcfe. Despite suspending our quarterly dividend, we still delivered the highest 2024 total shareholder return among public E&P companies trading on a major exchange.
If you will flip over to Page 4, the Haynesville shale footprint. Slide 4 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 1,099,000 gross and 819,000 net acres that is prospective for commercial development of the Haynesville and Bossier shales.
On the left is our merging Western Haynesville and on the right is our legacy Haynesville area. Since the beginning, our leasing program in the Western Haynesville play in 2020, we have grown our acreage position to 518,000 net acres. We still have around 1,300 net locations to drill on our 301,000 net acres in the legacy Haynesville, which currently has 895 net producing wells. Our legacy Haynesville acreage is 48% developed for the Haynesville shield and 8% developed for the Bossier shale. In comparison, our Western Haynesville has only 18 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 Haynesville, given the higher paid thickness and pressures we encounter in the Western Haynesville, we expect the Western Haynesville to yield significantly more resource potential per section than our legacy Angola. I will now turn it over to Roland to discuss the financial results we reported today. Roland?
All right. Thanks, Jay. On Slide 5, we cover our fourth quarter financial results. Our production in the fourth quarter averaged 1.35 Bcfe per day, which is 12% lower than the fourth quarter of 2023, reflecting our decision to drop 2 rigs early in '24 and drop and have that frac holiday that we had in the third quarter. The only well we turned to sales in our legacy Haynesville area in the quarter was our Horseshoe well that we discussed last quarter. So oil and gas sales in the quarter declined 5% to $336 million due to the lower production level, which was partially offset by better natural gas prices. EBITDAX for the quarter was $252 million, and we generated $223 million of cash flow during the quarter. We reported adjusted net income of $46 million for the fourth quarter or $0.16 per share. In the fourth quarter, we recognized a $52 million tax benefit related primarily to R&D credits and other credits and also due to a reduction in the Louisiana state corporate tax rate. A higher provision for depreciation, depletion and amortization accounted for the loss before income taxes in the quarter. The higher amortization rate resulted from the decrease to our 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 12 months. And of course, that price was very low in 2024.
On Slide 6, we recap the annual 2024 financial results. Production for the full year averaged 1.4 Bcf per day, which is very comparable to the production we had in 2023. Natural gas prices that we realized in 2024 fell by 7%, resulting in our oil and gas sales decreasing 7% to $1.3 billion. EBITDAX in 2024 totaled $850 million, and we generated $675 million of cash flow. With weaker natural gas prices and a higher DD&A expense, we reported an adjusted net loss of $69 million in 2024 or $0.24 per share compared to the $133 million of net income we had in 2023. On Slide 7, we further break down our natural gas price realizations in the quarter and for the previous quarters. The quarterly NYMEX settlement price averaged $2.79 per Mcf in the fourth quarter and the average Henry Hub spot price in the quarter averaged $2.42. The 45% of our gas in the fourth quarter was sold in the spot market, so the appropriate market price reference price for our gas that quarter was $2.62. Our realized gas price during the fourth quarter averaged $2.32, reflecting a $0.30 differential for the quarter.
We were 51% hedged in the fourth quarter, so that improved our realized gas price to $2.70. We also had a $0.05 uplift to our overall gas price realization from purchasing third-party gas to utilize our available transport. On Slide 8, we detail our natural gas hedge position that we have to protect cash flows this year and in 2026. We have approximately 50% of our gas production hedged for this year at an average price of $3.48 or better. 22% is in price swaps and the remaining is the form of costless collars with a floor of $3.50 and a ceiling of $3.80. For '26, 59% of our hedge position is in collars with the same floor level of $3.50, but a higher ceiling price of $4.35. And then the remaining 41% of our '26 hedge position are in gas price swaps, which averaged $3.51 per Mcf. On Slide 9, we detail our operating cost per Mcfe and our EBITDAX margin.
Our operating cost averaged $0.72 in the fourth quarter, which was $0.05 lower than the third quarter rate. Our EBITDAX margin improved to 73% in the fourth quarter as compared to 67% in the third quarter. So our production and ad valorem taxes were down $0.03 in the quarter, primarily reflecting the lower statutory severance tax rate we have in Louisiana, which went into effect in the middle of the year.
And our lifting cost in the quarter increased $0.03, while our gathering costs were down $0.05 in the quarter. Overall, our G&A costs were unchanged at $0.05 in the fourth quarter. On Slide 10, we recap our spending on drilling and other development activity that we had in the fourth quarter and for all of last year. We spent a total of $240 million on development activities in the fourth quarter, and we spent $902 million for the full year. In 2024, we drilled 32 or 25.8 net horizontal Haynesville wells and 18 or 17.1 net Bossier wells. We turned 48 wells or 42.9 net operated wells to sales, which had an average initial production rate of 26 million per day.
On Slide 11, we recap our proved reserves at the end of 2024, determined based on year-end NYMEX market prices, which have been adjusted for our differentials as compared to the much lower prices that we have to use for SEC purposes and to determine DD&A in the financial statements. Using year-end NYMEX prices, we're able to grow our proved reserves by 6%, even though we had reduced overall drilling activity last year. So our proved reserves totaled 7 Tcfe.
We added 899 Bcf of drilling additions, which replaced 170% of what we produced last year of 528 Bcfe. We spent $902 million on that drilling program, which gives us a finding cost of right at $1 for 2024. In addition to the proved reserves, there's an additional 2.1 Tcfe of proved and developed reserves, which are not included because they're not expected to be drilled within the next 5-year period as required by SEC rules. Otherwise, they could be included in proved reserves. And we also have another 2.4 Tcfe of 2P or probable reserves and 6.9 Tcfe of 3P or possible reserves give us the total reserve base of 18.4 Tcfe on a P3 basis. This does not include the reserve potential for much of the Western Haynesville acreage. Slide 12 recaps our capitalization at the end of 2024.
We ended the quarter with $415 million of borrowings outstanding under our credit facility, giving us $3 billion in total debt, including our outstanding senior notes. Our borrowing base is currently at $2 billion and our elected commitment under our credit facility remains at $1.5 billion. With improved natural gas prices and the strong hedge position, we expect our leverage ratio to improve significantly as we start to report the 2025 financial results. At the end of the fourth quarter, we had approximately $1.1 billion of financial liquidity.
On Slide 13, we 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 provides us with advantaged gas price realizations compared to most of our natural gas peers. 68% of our gas production is sold at Gulf Coast markets using our long-term transport agreements with the balance sold at the regional hubs at Perryville, Carthage and Bethel.
Selling directly to end users and having access to various Gulf Coast hubs provides 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 14, we show the footprint of our midstream system in our Western Haynesville area.
In late 2023, we partnered with Quantum Capital Solutions to create Pinnacle Gas Services to fund the needed expansion of our existing midstream assets in the Western Haynesville to handle the growing production from this area. So we contributed our Pinnacle gathering and treating system to the partnership, and then Quantum is contributing the capital to build out the gathering and treating system in this area. We currently have 246 miles of high-pressure pipelines that run across the middle of our acreage, as you can see on Slide 14, and we have a gas treating plant at Bethel at the north end of our system, and we're currently constructing a new 400 million a day treating plant at Marque, Texas on our southern end. So I'll now turn it over to Dan to discuss our operations.
Okay. Thanks, Roland. If you look at Slide 15, this is our updated drilling inventory at the end of last year, 2024. Our total operated inventory at year-end stands at 1,548 gross locations and 1,211 net locations, which equates to a 78% average working interest. Our non-operated inventory, we have 1,110 gross locations or 139 net locations, which represents a 13% average working interest.
The drilling inventory is split between Haynesville and Bossier wells divided into our 4 categories by length. Our short laterals are less than 5,000 feet, our medium laterals are between 5,000 and 8,500 feet. Our long laterals are between 8,500 and 10,000 feet and our extra-long laterals are all laterals over 10,000 feet. In our gross operated inventory, we now have 53 short laterals, 337 medium laterals, 570 long laterals and 588 extra-long laterals.
Our gross operated inventory is evenly split with 51% in the Haynesville and 49% in the Bossier. The updated drilling inventory also includes the impact of identifying 113 horseshoe locations. The average lateral length of our inventory is now at 9,603. This is up from 9,261 feet at the end of the third quarter due to converting more of our short laterals to the long lateral horseshoe wells. 75% of our inventory is now composed of laterals greater than 10,000 feet. And our inventory provides us with over 30 years of future drilling locations based on our current activity levels.
On Slide 16 is a chart outlining our average lateral length drilled based on the wells that have been drilled and have reached TD or total depth. We have split out the data between both our legacy Haynesville and Western Haynesville areas. In 2024, the 39 wells that reached total depth in the legacy Haynesville had an average lateral length of 10,922 feet. The individual lengths range from 4,222 feet to 17,400 feet. So our record longest lateral now stands at this 17,400 feet. In 2024, the 11 wells that reached total depth in the Western Haynesville had an average lateral length of 10,182 feet.
The longest lateral we have drilled to date in the Western Haynesville had a lateral length of 12,763 feet. In the fourth quarter, we only turned 1 well to sales in the legacy Haynesville area, and this was our Sebastian #5 Horseshoe well that we discussed on our third quarter conference call. In the Western Haynesville, we turned 6 wells to sales during the fourth quarter and 5 of these wells were turned to sales over the last 10 days of the quarter or of the year. To recap our long lateral activity to date, we've drilled 110 wells with laterals longer than 10,000 feet, and we have 40 wells with laterals over 14,000 feet.
Slide 17 outlines the wells that returned to sales in the legacy Haynesville in 2024. In 2024, we turned 37 wells in the legacy Haynesville to sales. The individual IP rates on these wells range from 9 million a day to 42 million cubic feet a day with an average test rate of 23 million a day. The average lateral length was 10,104 feet and the individual laterals range from 4,222 feet to 15,303 feet.
This list includes our first Horseshoe well, the Sebastian 11HTU #5 that was turned to sales in October with an IP rate of 31 million a day, which we discussed on the third quarter call. Other than the Horseshoe well, we did not turn any new wells to sales in the fourth quarter as we deferred that completion activity to wait for the improved natural gas prices. Two of our 6 rigs are currently drilling on our legacy Haynesville acreage. We do expect to add another rig to the legacy area later this year if the gas prices remain attractive. Slide 18 outlines the wells that we turned to sales in the Western Haynesville in 2024. In 2024, we had 11 wells turned to sales. The individual IP rates on these wells range from 31 million a day up to 44 million cubic feet a day with an average test rate of 38 million cubic feet per day.
The average lateral length was 10,032 feet, and the individual laterals range from 7,764 feet up to 12,055 feet. 6 of the 11 wells returned to sales in the fourth quarter and 5 of those turned to sales in the last 10 days of the year. We do have 4 of our 6 rigs that are currently drilling on our Western Haynesville acreage. Slide 19 highlights the total drilling days and the footage per day drilled in the legacy Haynesville. In 2024, our wells in the legacy Haynesville area averaged 26 days to total depth.
This represents a 10% improvement over 2023. Over the last 8 years, our drilling time in the legacy Haynesville area has averaged 27.5 days. The improvement in the drilling days is a function of the footage drilled per day. In 2024, we averaged 920 feet per day drilled in the legacy Haynesville, representing a 6% improvement over the 2023 average of 867 feet per day. Since 2017, the footage drilled per day has increased 35% with the fourth quarter of '24, the footage drilled per day of 1,012 feet is up 49% since 2017. Our best well drilled to date in the legacy Haynesville averaged 1,461 feet per day. There's a number of drivers to the recently improved drill times in the legacy Haynesville.
The main driver has been drilling the longer laterals. Since 2017, our average lateral length has increased by nearly 4,000 feet. In addition to just the normal things of minimizing problems and maintaining consistency, our other factors leading to drilling efficiencies have been the application of managed pressure drilling, rig upgrades and the continued improvement in our downhole motor performance.
Slide 20 highlights the significant improvements achieved in our drilling times in the Western Haynesville. Since we spud our initial well in the fourth quarter of 2021, we have seen significant and continuous improvement in our drilling times. Our first 3 wells were drilled in 2022 and averaged 95 days to reach TD, and this includes executing a very difficult sidetrack we had on our second well. Our average drilling time improved 26% down to 70 days in 2022, and we improved another 19% down to 57 days in 2024. We've drilled 21 wells to total depth through the end of the year. The fastest well was drilled to TD in 41 days, and that was during the fourth quarter. This represents an improvement of 45% or 35 days compared to our first well that was drilled to total depth in 75 days.
The improvement in drilling days is a function of the footage drilled per day, and our first 3 wells in 2022 averaged 281 feet per day, and that has steadily improved to 487 feet per day in 2024. We averaged 547 feet per day in the fourth quarter of '24 and the fastest well in this group drilled a record 608 feet per day. On average, our daily drilling footage has doubled since we started in 2022 through the end of '24. There are several drivers behind our improved drilling performance in the Western Haynesville. 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 through improved bit selection.
And in the laterals, we're utilizing thermal drill pipe and continue to see more consistent downhole motor performance as we continue to have just with the additional drilling activity. We also started incorporating 2-well pads into our drilling program in the middle of last year. Slide 21 is a summary of the summary of our D&C costs through the fourth quarter for our benchmark long lateral wells located on the East Texas, North Louisiana legacy acreage position. This covers all the wells with laterals greater than 8,500 feet in length. Our drilling costs are based on when the wells reach TD. This better aligns with when the drilling dollars are spent.
Our completion cost per foot continues to use the turn to sales dates. In the fourth quarter, our drilling cost averaged $660 a foot. This is a 1% decrease compared to the third quarter. And in the fourth quarter, our completion costs came in at $863 a foot, which represents a 7.5% increase compared to the third quarter. During the fourth quarter, we only turned the well to sales in the legacy Haynesville, and that was that Sebastian 11HQ # 5 single horse shoe that we turned to sales in October.
Both the drilling and completion cost trends show the impact of the significant inflation that took place starting in 2022. And looking ahead, we're anticipating our D&C cost on the legacy Haynesville acreage to remain relatively flat to slightly lower for the next couple of quarters. We did start seeing our pipe prices come down late last year. We do expect to maintain these cost savings through the next couple of quarters. The cost expectations are a little more uncertain out past midyear with the potential uptick in activity looming with the higher gas prices and the possible tariff discussions that are weighing on pipe prices.
We are currently running 2 rigs on our legacy Haynesville acreage, and we anticipate adding a third rig later this year if the gas prices stay attractive. On Slide 22, this is a summary of our D&C costs through the fourth quarter for all the wells we have drilled in the Western Haynesville. This slide provides the drilling and completion costs for all the wells we've drilled in the play to date. We have spent a large amount of exploratory capital on our first 10 to 12 wells drilled in the Western Haynesville as evidenced by the higher drilling and completion costs through the early part of 2024.
We've accumulated a wealth of knowledge drilling those early wells that is now paying big dividends for us. The early exploratory D&C 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 D&C capital to a point lower than our original estimates of roughly double what our legacy Haynesville wells cost. Our fourth quarter drilling costs averaged $1,396 a foot, while our fourth quarter completion costs came at $1,315 a foot. In addition to some of the main drivers affecting our drilling efficiency, such as the streamlined casing design, faster drilling in the vertical hole, utilization of the thermal drill pipe and our improved run times in the lateral.
This also comes from the impacts of starting our 2-well pads in our drilling program in the middle of last year, which helped us to shave additional days off our drill times. We've also had great execution on our completions and integrating the 2 well pads into our program has allowed us to be much more efficient with our frac crews and our wireline crews.
We do currently have the 4 rigs running in the Western Haynesville, and we do anticipate staying with the 4 rigs in the Western Haynesville for the near future. I'll also mention all our Western Haynesville rigs are new rigs that we have purpose-built with our Western Haynesville drilling program in mind. In closing, I just want to say to get where we are today has been highly rewarding. It's been a total team effort across the board, everybody pushing to improve 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 Haynesville rolling down. thank you for the transparency for the fourth quarter and the full year. 2024, if everyone would go to Slide 23. I direct 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 Haynesville that will position us to benefit from the longer-term growth in natural gas demand.
We currently have 4 operated rigs drilling in the Western Haynesville, as Dan said, to continue to delineate the new play. We expect to drill 20 or 19.9 net wells and turn 17 or 16.9 net wells to sales in the Western Haynesville this year. We will continue to build out the Western Haynesville midstream assets to keep up with the growing production from the area.
Midstream expenditures are expected to be $130 million to $150 million. They will all be funded by our midstream partner. In the legacy Haynesville, we will run 2 or 3 rigs depending upon prices to build production back up by the fourth quarter. We expect to drill 26 or 20.4 net wells and turn 29 or 22.8 net wells to sales in the legacy Haynesville this year. We anticipate funding our drilling program, as Roland said, out of operating cash flow and use any excess cash flow to pay down debt.
We continue to have the industry's lowest producing cost structure and expect drilling efficiencies to continue to drive down D&C cost in 2025 in both the Western and legacy Haynesville assets. We have strong financial liquidity totaling almost $1.1 billion. Note on Slides 24 and 25, we provide some specific guidance for the rest of the year. We'll now turn the call back to the operator to answer questions from analysts who follow the company.
[Operator Instructions] And our first question will come from Derek Whitfield with Texas Capital.
Also, congratulations on the position you assembled in the Western Haynesville your Mac is a dream scenario for anyone pursuing organic leasing program in a new basin. I have 2 questions and are both related to Western Haynesville. So reference in 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 sub-basin? Surely, D&C costs would decrease, but there is -- 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 deeper the deepest, hottest stuff. If you look at where the well locations are across the acreage. We haven't drilled anything up there on that part of the acreage. A lot of that stuff is HBP acreage. So we're drilling the stuff that we've leased in the hold. And so that will kind of keep us down in that general area and as we expand up to the Northeast for the kind of the near-term activity in the next couple of years.
But kind of to answer your question, I think as you get up in that acreage, you're talking about, it does get shallower, the TBDs get shallower and a little bit cooler. So I think it just remains to be seen what the EURs are going to look like, but I would certainly think maybe a hair less if you just correlate it to depth, but we also expect our D&C costs are going to be a lot lower when we drill up there in the future. And I think our D&C costs are going to be a lot lower just drilling where we're at now in the future. 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.
And to your point, I think it's really good. We didn't start out with the easy depth. We started out with the deeper depths, the hottest debts. And we looked at what reality looked like, and they look really good. And that's where we ended up with these 8 wells, there was a big enough data set so that we could actually come out and talk about the cost and all major Tier 1 plays. The more you drill the wells and complete them, typically, the cost structure comes down exactly like it did in the core of the Haynesville Bossier going back to 2008 to 2011.
And then my follow-up, I wanted to focus on the D&C cost compression you highlighted 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 Haynesville is the added cost largely associated with higher trading pressures? Are there [indiscernible] are there other considerations? And I guess more broadly, how much lower could you drive that?
I think we have more room to probably or 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 [indiscernible] 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 kind of you asked about treating pressures. Yes. So as far as compared to the legacy Haynesville, the treating pressures are definitely much higher down here just based on the depth and the frac gradients. The beauty is in the Western Haynesville at fracs very consistently. So it's been really kind of a trouble free, but it's a lot more horsepower, and we do pump slightly bigger jobs in the Western Haynesville. On average, we pumped about 4,000 pounds per foot. And then the core, we pumped about 3,500 pounds per foot. So that's also part of it.
Yes. And Dan, I'd add too, just you look at comparing the Western Haynesville to the legacy Haynesville I mean, we are having to build all the infrastructure, the new pads. I mean, we're really starting from scratch there in the legacy Haynesville, 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 there's a huge difference in the upfront costs. These early wells are burying all that cost in the numbers. And then as you come back and infill drill and continue to develop it, you have less and less of that cost to the future wells, we'll be able to utilize that investment we're making today.
Yes. And I'll just add to what Roland said, we are building larger pads in the Western Haynesville to be able to come back and drill future wells.
And the next question comes from Carlos Escalante with Wolfe Research.
I wanted to first congratulate you all on the incremental color on the Western handle. It's really encouraging to see the results. Let me start with a follow-up to the last question, but more geared forward the development plan. Could you speak -- this is perhaps for Dan. Could you speak to what a typical development plan look like for your average Western Haynesville tab in terms of how many wells you would expect on any given pad and what your general assumption for spacing would be knowing, of course, that it's probably too early to know what the right spacing is.
Yes. The last piece of that is definitely too early. drilling the whole acreage, the wells are spread out. So we haven't really honed in on what the spacing is going to be. I think we're going to have to accumulate a lot of data in the future to hone in on what the optimum spacing will be in the Bossier versus in the Haynesville areas where it's thicker versus thinner, I think are going to all yield different answers.
So I don't have a direct answer to that question. But as far as future development, we strive to drill everything with 2-well pads that we can. We're drilling and we're holding acreage. In some places, you just can't -- we just don't -- the acreage doesn't give you the opportunity to drill 2 laterals, 2 wells on a pad. So I think we're probably looking at about half, 50%, maybe 60% of our wells any given year will be on 2-well pads and the others will be singles. We strive to make as many 2-well pads as we can, but that's probably going to be our mix for the next couple of years.
And one thing we've tried to do, if you look, we've derisked maybe 26 miles of this play. 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 1 or 2, 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, we will build the gathering treating in the midstream to complement the program '25, '26. I think by the end of '25, definitely by the end of '26, we'll have fully derisked this whole 518,000 net acre play. Dan had mentioned a lot of this HPP. So we don't plan on drilling on the HBP acreage until we hold maybe 70 more wells we need to drill in the next several years to HBP our entire footprint.
Got you. My second question is on the CapEx trend on a per well basis. I think that it's very encouraging to see that you've saved on both fronts, the drilling and completion side. But given that the Western Haynesville is materially hotter and deeper than legacy Haynesville, you'd almost think that your drilling savings will be will hit a plateau soon, if you will, whereas on the completion side, you might -- you haven't reaped the full benefits of a full development cycle. So 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 headwind do you see on the drilling side as a whole?
I mean, so kind of alluded to that a little bit earlier. I think we'll see -- we haven't reached a plateau on the cost, first of all, in the Western Haynesville. I mean, obviously, with all the thousands of wells that we drilled up in the legacy area, it is. It's just small little tweaks here and there. It's minor things. It's great execution. Just shaves off just a day here and a day there. That's not the case in the Western Haynesville. In the Western Haynesville, we've been going up a steep learning curve.
We've cut off a lot of days. We haven't reached a plateau yet. I think we're going to drive these costs lower. We're going to knock more days off in the future. More of that, I see more of just a percent reduction in cost on the drilling side than on the completion side. We are pumping the same frac job right now on all the Western Haynesville wells.
I will make one note 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 pumped what we call our big frac. We pumped 6,000 pounds per foot on that well for a data point just to monitor how that well produces in the future compared to all our others, which is why that one stands out. But we've had really great execution on the completion side really today. So that's why I don't see the completion costs coming down as much as the drilling on a percentage basis.
Yes. The other thing we have managed the well is a little different. Each well is like a prototype, and we learn how to manage all the wells. We go back and we preview what Circle M look like, what we could do or didn't do and how well it's performed. And I think, Dan, if you want to comment on just well management, we're getting better and better and better, which is a learning curve from having the 18 wells.
Yes, I'd say we definitely have been conservative on how we're drawing the wells down. And based on all the things we're seeing, we're just making adjustments on how we do that, manage the drawdown how hard we pull the wells when we flow them back and clean them up, turn them to sales. And then where we set the rate after that.
And what that will do, they'll give more predictability, give more stability it will give us what the real type curve may look like, what the drawdowns might look like when the wells have been produced in 1 or 2 or 3 years, we haven't gotten to that point yet. But I think the goal today was when you trusted us for 5 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 midstream 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 of the Haynesville/Bossier in '08 and you compare those to the wells we drilled today, ours are like lights out better.
And our next question comes from Charles Meade with Johnson Rice.
Dan, I'll add my voice to the course of congratulations, not just on assembling this position, but also the great progress.
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 -- or my first question when you started talking about the derisking of the position. You talked about the -- your first wells here, you've derisked along kind of a 26-mile Southwest to Northeast axis. If I'm just eyeballing your map there on what is -- I think it's Page 18, yes, I guess eyeball, I would say that's maybe derisked, I don't know, 20%, 30% of your position. I wondered 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 just -- is it porosity that is the risk that's going to determine exactly how much of this 518 really works?
Well, if you noticed on the slide or kind of my introduction, I said that the 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. So we said -- we just want to make sure you know it's not distorted footprint because you would think it could be distorted because there's so much of it because our legacy Haynesville, I mean, it's some of the most valuable acreage in North America, we believe, because where it's located and all the locations that we have left to drill in the Haynesville as well as only 8% of the Bossier is developed.
So when you go back to the beginning in 2020, 2021, too, you can see we've tried to outline the patience that we had. That's why I give the dead horse scenario. In other words, we're looking to see if this thing works, if it doesn't, then we're going to get off of it. But if it continues to work and quite frankly, Jerry Jones and his family allow us to derisk this thing, which is very hard to do. It takes months and some bad days, some good days. But you add it all up, what we try to do is we try to say how many acres do we have that we have to drill wells right now in 2021, '22 in order to hold leases that we had inherited from acquisitions. That's number one. Then number two, we looked at how many logs do we had that penetrated the different thicknesses in the Bossier and the Haynesville.
Then we look to see what seismic we own and what we needed to buy. And then we didn't let the horses run wild. We drill the wells, circle in, we pulled the rig back for 5 months. We let the well tell us what to do. Then when we did move that rig back on, we've kept it pretty busy. 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 2 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 HB Paid. So as we look at our 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 1,300, 1,400 feet of prospective pay in some areas.
Well, you look at that, that's not true for all of it. Some of it is going to be the same pay thickness that we had in the tier of our legacy acreage. So that's 200, 300 feet, whatever. But yes, it expands. We did choose to drill the deepest, hottest, hardest first because that would tell you whether we needed to pursue to spend more money on acreage and more money on seismic and to keep the land group leasing that acreage and feathered into the drilling program. It's a beautiful story to write when you see it because of like Roland had come up 80% of this is HPP. I mean, 80%, and this is the very first time we've ever shown it to you. And you might say, well, how come there's some wide acreage in there? Well, a lot of that acreage, maybe 1 or 2 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 derisk this with us. That's why we show you once we think the land grab is over. So at the end of this quarter, I think we'll have some more results. But I want you -- I mean, it's our bank, it's our analysts, that'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 derisk the whole footprint and see what the thicknesses are.
Charles, I'll add to -- if you look in the -- in our core acreage, some of our best wells are in the areas that are not as thick, like up around like the Elm Grove area. So as far as just speculating if it's something thin or thick on how it's going to perform, I don't think there's any correlation there at all, really.
Yes. Is it really more just a gas fill porosity is the biggest determinant then?
I mean thicker. I mean, obviously more gas in place, right, thicker rocke. But definitely, that does not correlate to how prolific it will be.
We have meaningful bottle pressure differences.
Yes. Interesting. And then one follow-up, Jay, you already -- you touched on this also. I think, Dan, you touched on this. A lot of focus on these new estate 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 learned from them, whether about the right way to manage the pressure drawdown, the landing zones within these formations or the right completion jobs. I know there's -- every day that ticks by, you add to the data file from the older venture wells. So can you just tell us what you've learned in that respect.
I think we obviously have been really laser-focused on the cost, just getting the wells down in TD. The land zones, I think a lot of these where we drill are in the relatively thicker part of the play. So we haven't really got real specific on if the landing zone should be a little higher, a little lower. We just wanted to get the wells down and basically to see these things as fast as we could. And as far as the drawdown and we've been pretty conservative. I think we'll probably tweak that a little bit in the future. These last few wells, we like to IP on pull them a little bit harder and get the wells clean, make sure they're good in claim before we get flow back off of them and then pull the rates back and start them basically on the type curve rate and this basically let them go from there.
Charles, something detail some of these wells, we took some we don't, specific cost variance, too. So we figure out what we need to do or not do as we drill more of these wells.
And the next question will come from Kyle Ackerman with Bank of America.
Jay, 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 7 rigs? It seems like the industry is following in a rhythm with demand, and that's a really good place to be.
Right. No, I think that's the key. One thing we wanted to make sure is that we don't produce too much gas, especially in one region area. So we've been looking at that. We think 7 rigs was always a really good level for the company to kind of maintain. I think when we dropped to 5 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 we're going to get very comfortable with 7. We're going to focus on getting our balance sheet back to like it was in 2022. That's our biggest goal. And I think '26 will be a year that we will have the level of production and good gas prices to drive the -- get the balance sheet in perfect shape. And I think '25, the level we're running now, we won't add any debt and we'll slowly pace some down. But then next year, we'll be able to really reduce debt significantly.
Brian, as far as the year-end '26 spoke, you think somewhere under 1.5x 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 just so low of gas prices. But yes, we definitely want to get it down as quickly as possible to the 1.5x leverage area. It's probably -- that's probably something that we achieve in '26. But I think we'll be way in the very low 2x leverage numbers as we kind of work our way through '25. So a lot will depend on how strong gas prices are and then how -- we do have to rebuild our production a little bit to kind of get 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 2 rigs, you look at us having a frac holiday and then you look at us adding 265,000 net acres in the Western Haynesville, you can see that we really, really monitor our leverage and our balance sheet. We do that even in a very, very difficult year. And at the same time, instead of M&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 Jones is, they kind of uncu we could go in. And as we were one of the first several companies to derisk and discover the core Haynesville, we just took the same group down to the Western Haynesville, knowing what we were looking for. And it took 5 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 -- they'll be massive. Our footprint is massive, and we're in the exact bright part of North America for all this demand, particularly for LNG. So it's going to be a really beautiful story.
And our next question will come from Bertrand Donnes with Truist.
I just want to follow up on that M&A topic, not necessarily on the western side, but with higher gas prices, you'd think most of the private owners are probably thinking about potentially selling or maybe does that incentivize you to look more aggressively? Or are those sellers seeing the strip move up and maybe they're already seeing a $5 price that they want to see or something like that? And then the second part of that would just be, on the oil side, most of these private equity shops normally ramp up production before a sale. Do you see that happening? Or that's not exactly how it would work on the gas side?
Well, it's hard to predict what they're looking at. But obviously, I think there are some private companies out in the Haynesville, that have invested a lot of capital and now that you're in a good gas price situation, their business plan is to sell that kind of like the same with the oil, the private companies in the Permian. And so -- but we do see a very low level of activity in the Haynesville. So we certainly haven't seen any type of effort to ramp up at all from the public or private operators, we've seen great discipline in the basin. And I think all the producers really want to get very comfortable that the gas is really needed. And we've seen very, very volatile gas prices. And so I think everybody has been very cautious to say, we're not going to oversupply this market. And maybe we undersupply it because we're so cautious.
Well, and you can even see in the first quarter, we give guidance down, we're not going to overproduce period. And that guidance is a result of dropping those rigs. And we're not adding the rigs in the Western Haynesville to increase production right now. We're adding those rigs because that's the best place for us to drill because we need to drill more wells more of the footprint. So that's why we're doing that even. We don't see any E&P company out there out of control on their production rates. None of them.
That's great. And I think the market is happy to see that. And then for my second question, several of your peers have started talking about potentially locking in a percentage of their production to contracts, either data center or LNG. And it seems like most have fallen in a 10% to 20% of their volumes. Is that where you guys feel like you'd fall? Or do you potentially have a larger appetite? Maybe you lock up acreage dedication in the Western Haynesville or something like that for a backfill a demand project.
Yes, that's a good question. We would also want to look at having a portfolio of purchasers for our gas and not putting all our eggs in one basket. But we see both being a major supplier to several of the LNG shippers and potentially looking at some power generation projects to back to. But again, I think having a good balance of that activity because their demand comes at different times of the year.
And so -- but there are good opportunities for the gas producers now to start to directly lock up with the industrial users and the exporters. And I think it's a good time for us to create good relationships where we can have more stable prices and also know that we've got good -- we've got that -- we balance out our production to what we know the market needs.
Particularly, probably 90% of our Western ville is completely undedicated, I mean completely. So it's free range out there. We can kind of do what we want to with it.
And I just want to clarify, so an acreage dedication for a demand project that is that coming back? Or are we done with that?
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 -- the way we've structured things, we're going to be able to own all that.
And so I think instead, we want to kind of look out and say, hey, we can -- we want to take our portfolio of gas, both from the legacy and the Western Haynesville and then we want to portion it out to these direct contracts as we feel comfortable that it's a good fit. And obviously, we're looking for the -- what's the best deal for Comstock. So who's going to pay the higher premium. They all have kind of different needs. And -- but it's a very exciting time to be developing a new play like the Western Haynesville. At the same time, there is a lot of market development opportunities that our gas industry hasn't seen in a long time. So it's a great combination of those 2 together.
It's probably a good time to talk about too. The reason we were able to go look at the Western Haynesville is because of the value of our core we don't want anyone to ever overlook at that 301,000 net acres in that inventory with plenty of takeaway there. That gave us the ability to come look at the Western Haynesville and along with the operational technical skill that we had. But the value of the legacy allowed us to do the Western Haynesville.
And our next question will come from Jacob Roberts with TPH & Company.
Just I hate to ask about 2026 plus. But thinking about the 4.3 rig split as we kind of progress through 2025, is that a level that can meet any HBP needs, any MVC needs with Quantum? Or are you contemplating a 5.2, a 5. 3? Just wondering what are the commitments as we get into '26, '27 that we might need to be thinking about?
Well, the real positive of the way we've structured things is that we don't even need to maintain that type of activity to kind of meet any MVCs or other requirements. We've been very conservative as you build something out not to get overcommitted. So I think it's a very comfortable level for the company. And so it's really going to be like what is the market -- where is the gas really needed. And I think we will adjust that based on kind of how we see these markets go out. But I think we're very comfortable with the activity level and running -- be able to run 4 rigs in the Haynesville will keep us on track to HBP in all of our acreage and easily meeting supporting the build-out of the midstream.
Okay. Perfect. And then maybe just a quick follow-up. I appreciate some of the discussion about your understanding of the broader Western Haynesville acreage that you've disclosed. Can you just frame the amount of seismic, the amount of historical work that's been done on the land that helps you understand it the way you do?
Yes, I'd say there's been a lot of 3D seismic shot across all of this acreage, just a lot of different vintage data that's out there that can be bought that has been tremendously helpful in kind of planning out where we want to drill. And we've got some future wells that we're going to be drilling some pilot holes on and getting -- drilling all the way through the section through the bottom of the Haynesville for well control purposes and geosteering. And we've also got some future coring and stuff we're going to do as far as just doing some more sites to get the performance properties on the rock.
And our next question will come from Gregg Brody with Bank of America.
Just as we think about midstream for next year, what type of capital should we pencil in? And then when do you think you will exhaust the midstream JV? And how do you think about funding it after that?
Yes, it's a great question. We -- this is -- with building the new treating plant, this was a big capital investment that we started making in the fourth quarter and through this first half of the year, then we're going to have a lot of treating capacity that's going to be available to us starting in the second quarter. And so then we continue to look at our volumes and then decide when we want to add additional trains to either a new plant or adding to our North or South plant. So we also have some good partners nearby that we've secured additional capacity in order to not have to build everything. So we feel really good about where that is. I think that the build-out of the midstream is amazingly fit almost perfectly with our 5-year plan for it so far. And so we've been really pleased, and I think our partner has been, too.
And so I think that eventually, as the entity 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 put in its own credit structure there, so we can kind of get less expensive capital to fund some of its build-out. But that's probably going to be more later in the year after it's up and running and generating a very strong EBITDA. But we're very excited about what Pinnacle can become and the value it's going to be adding. I think you look down the road, it's going to be a very, very big asset for the company. And under our structure, once we return that capital with a preferred return, that will revert 100% back to -- yes, 70% back to the company, and then we can buy out the minority interest if we like, in the future also.
The goal was we -- as we were acquiring all the securities, we wanted to control the midstream. We trusted Quantum as a company in lending money and supporting plays like this, we really trusted them. We wanted to see if there was something that we were missing. So when Quantum came in, look at the acreage, look at the well results at that point. which have only gotten better. I mean I said exactly with $300 million. We wanted to make sure that we would control that and it wouldn't be sold to some third party which we didn't control what we'd be doing in the Western Haynesville. We didn't want to lose control of that. And Quantum became the perfect partner.
So it's fair to say that between Quantum's equity and potential credit facility at the JV entity 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, they probably where it doesn't really need start to be totally self-funding. And we also see maybe bringing in some of the -- our nearby operators could also help accelerate that if we can land some of those as customers as we build the system out.
And our next question will come from Noel Parks with Tuohy Brothers..
Just thinking about the drilling time improvements you've already been able to achieve. I just wonder, 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 sort of like what -- you talked about some of the things you've tweaked, but I just wondering kind of what was your starting point like when you were approaching the play?
That's an interesting question because when we looked at everything we had done in the legacy -- on our legacy acreage in all of the years past. And kind of just one of the real general things we had seen was before we ever started in the Western Haynesville, in general, in the core, all the wells were being drilled twice as long, say, 500 to 10K. And at the same time, they were getting twice as long, they were being drilled in half the time. And there were a couple of -- there was a couple of old wells that had been drilled -- old horizontals that have been drilled back in 2010 down here in the Western Haynesville that kind of provided some of the earliest data to take a look at that we looked at. They had a lot of -- just a lot of mechanical issues collapsed casing and just really was pretty ugly. But we just looked at how many days it took them to drill those wells, and those were essentially 50-ish type wells. And so if you just applied the same industry progression of twice as long and half the day, that's kind of what we targeted, and it was around that 75- to 80-day time frame. And that's exactly where we landed. On average, if you take out that sidetrack, we had on our second well, we landed at about 80 days starting out. And the good thing is that there's a lot of running room. These wells are deeper and hotter, and we just have so much more room to run down here to get better. versus we did up in the core..
Well, on our confidence level grew, we were going to drill the 16,000-foot vertical and then as our confidence grew as well after well after well, we did go to 19,000 feet. So we wouldn't have done that had we not had more confidence in the 16,000-foot vertical.
On anything you do anywhere you drill, the longer -- if you can just -- wells are good and you can keep drilling additional wells and you can increase your activity the all practice makes perfect, the more you drill the but you're going to get, the more the industry drills, the better the industry gets. And that's what we're seeing.
Great. And I understand there's been so much attention to us seeing the map for the first time and results from the newest slate of wells. So I just wonder if you could just talk a little bit about gas macro. And looking at your hedges, I was just wondering, is there anything in particular about the 350 mark as where your downside protection is that you've been gravitating toward? And also, if you had any thoughts about what things are going to look like or might look like as the LNG ramp-up continue along?
Well, we look today, and I just looked at this as U.S. LNG fleet hit a new record high of 16.47 Bs. We are very, very, very positive on natural gas in the latter part of '25, '26, even '27. So when we look at the Western Haynesville, not the legacy, I mean, we do need to drill the legacy, of course, it provides us a very dependable revenue stream. But what we want to do, we want to guarantee that we can drill all these wells that we need to drill in '25, '26 and still delever 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, but that will be perpetual. But we don't see any big acreage out there positions that we're chasing that we don't have.
So this is surely -- it's a protection of the balance sheet to get us back to have a dividend. If we could have a dividend in the latter part of '26, great, early '27, whatever. But we want to delever the company now, drill these wells, stay true to the midstream partner with Quantum and deliver this gas, not when it's needed. And the beauty of this is nobody tells us when to drill it, how to drill it or we control it ourselves. It's something we b, 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 Rand 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 could not have a better location for that pipeline. And it's not there by mistake. 20 years ago, that was the core of the core of where they were drilling. That's why that pipeline was there. It just wasn't worth anything when we bought it. somebody had to revigorate it and put some gas in it, and we're the only ones willing to do it. So it has become a very valuable piece of the company.
Yes, the replacement cost for 46 miles of high-pressure pipeline and 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.
I would now like to turn the call back to Jay Allison for closing remarks.
I want to thank all of you. It's a much longer call than normal. It's almost 1.5 hours. We knew it would go longer, and we didn't want to cut anybody off. But again, I want to thank you. There's probably 250-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 Haynesville value. I gave an old cowboy here. I'll give you another one. It says, if you climb up on the saddle, you better be ready to ride. And we at Comstock are ready and you can take that to the bank. Thank you.
This concludes today's conference call. Thank you for participating. You may now disconnect.