Roland Burns
All right, thanks, gay. On slide five, we cover our fourth quarter financial results. Our production of the fourth quarter averaged 1.35 BCFE per day, which was 12% lower than the fourth quarter of 2023, reflecting our decision to drop two rigs early in 24 and 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.
EIAX for the quarter was $252 million and we generated $223 million of cash flow during the quarter. The report had adjusted an income of $46 million for the fourth quarter or $0.16 per share. In the fourth quarter, we recognized the $52 million dollar 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 decreased or approved undeveloped reserves which were determined under SEC rules where you have to use the first of the month average price looking back for the previous 12 months. Of course, that price was very low in 2024.
On slide six, we recap the annual 2024 financial results. Production for the full year averaged 1.4 BCF per day, which is very comparable to the production we had in 2023. Natural gas prices that we realized in 2024 fell by 7%, resulting in our oil and gas sales decreasing 7% to $1.3 billion. EIAX in 2024 totaled $850 million and we generated $675 million of cash flow.
With weaker natural gas prices and a higher DDA expense, we reported an adjusted net loss of $69 million in 2024 or $0.24 per share compared to the $133 million net income we had in 2023. On slide seven, we further break down our natural gas price realizations in the quarter and for the previous quarters. The quarterly NEX settlement price averaged $0.279 per MCF in the fourth quarter, and the average Henry He spot price in the quarter averaged $0.242.
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 $0.262. I 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 gas price to $0.270. We also had a $0.05 uplift to our overall gas price utilization from purchasing third party gas to utilize our available transport. On slot eight, we detail our natural gas hedge position that we have to protect cash flows and.
This year and in 2026. We have approximately 50% of our gas production heads for this year at an average price of $0.348 or better. 22% is in price swaps and the and the and the remaining is the form of cost costless collars with a floor of $0.350 and a ceiling of $0.380. For 26. 59% of our hedge position is in collars with the same floor level of $0.350 but a higher ceiling price of $0.435.
And then the remaining 41% of our 26-hedge position are in. Gas price swaps, which averaged $0.351 per MCF. On slide nine, we detail our operating cost for 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 EIDAX margin improved to 73% in the fourth quarter as compared to 67% in the third quarter.
So, our production and a taxes were down $0.03 in the quarter, primarily reflecting the lower statutory [severage] 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 GNA costs were unchanged at $0.05 in the fourth quarter.
510, 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 billion for the full year.
In 2024 we drilled 32 or 25.8 net horizontal Haynesville wells and 18 or 17.1 net [posure] 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 plot 11, we recap our food reserves at the end of 2024 determined based on year-end NIMEX market prices,
which have been adjusted for our differentials as compared to the much lower prices that we'd have to use for SEC purposes and to determine DDNA in the financial statements. Using year-end IMAX prices, we're able to grow our crude reserves about 6%, even though we had reduced overall drilling activity last year.
So, our approved reserves totaled seven TCFE. We added 899 BCF of drilling additions which replaced 170% of what we produced last year, 528 BCFE. We spent $902 million on that drilling program, which gives us a finding cost of right at a dollar for 2024.
In addition to the approved reserves, there's an additional 2.1 TCFE of approved undeveloped reserves which are not included because they're not expected to be drilled within the next five year period as required by SEC rules. Otherwise they could be included in proved reserves.
Then we also have another 2.4 TCFE of 2% or probable reserves. And 6.9 TCFE of 3% or possible reserves gives 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 ga 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 Marquey, Texas on our southern end. So now I turn over to Dan to discuss our operations.
Daniel Harrison
Okay, thanks rolling. If you look at slide 15, this is our updated drilling inventory, at the end of last year, 2024. Our total operated inventory year-end stands at 1,548 gross locations and 1,211 net locations which equates to a 78% average working interest. Our non-operated inventory, we have 1,110 gross locations or 139 net locations which represents a 13% average working interest.
The drilling inventory is split between Haynesville and Bossier Wells, divided into our four categories by length. Our short laterals are less than 5,000 feet. Our medium laterals are between 5,000 and 8,500 feet. Our long laterals are between 8,500 and 10,000 feet, and our extra-long laterals are all laterals over 10,000 feet. In our gross operated inventory, we now have 53 short laterals, 337 medium laterals.
570 long laterals and 588 extra long laterals. A 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 that 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 las 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 the total depth in the legacy hangs at an average lateral length of 10,922 feet. The individual lengths range from 4,222 feet to 17,400 feet. So, our record longest slider now stands at these 17,400 feet.
In 2024, the 11 wells that reached total depth in the western Haynesville had an average la length of 10,182 feet. The longest ladder we've drilled today in the western Haynesville had a la length of 12,763 feet. In the fourth quarter, we only turned one well to sales in the legacy Haynesville area, and this was our Sebastian [#5] horseshoe well that we discussed on our third quarter conference call.
In the western Haynesville, we turned six wells to sales during the fourth quarter and five of these wells were turned to sales over the last 10 days of the quarter of the year. To recap our long lateral activity today, we've drilled 110 wells with laterals, longer than 10,000 feet, and we have 40 wells with laterals over 14,000 feet.
17 outlines the wells that were turned the cells 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 up to $42 million cubic feet a day with an average test rate of $23 million a day. The average laal length was 10,104 feet, and the individual laterals ranged from 4,222 feet to 15,303 feet.
This list includes our first horse, you will, the Sebastian 11 HU number five that was turned to sales in October with an IP rate of $31 million a day. Which we discussed on the third quarter call. Other than the horseshoe well, we did not turn any new wells to sales in the fourth quarter, so we deferred that completion activity to wait for the improved natural gas prices.
Two of our six rigs are currently drilling on our legacy Haynesville acreage. We do expect to add another rig to the legacy area later this year, if the gas prices remain attractive. Slide 18 outlines the wells that we turned the cells in the western Haynesville in 2024.
In 2024, we had 11 wells turned to sales. The individual IP rates on these wells ranged from $31 million a day up to $44 million cubic feet a day with an average test rate of $38 million cubic feet per day. The average la length was 10,0032 feet, and the individual levels range from 7,764 feet up to 12,0055 feet.
6 of the 11 wells were returned to sales in the fourth quarter and five of those turned sales the last 10 days of the year. We do have four of our six rigs 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, the total depth. This represents a 10% improvement over 2023. Over the last eight 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 of 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 you wrote per day has increased 35% with the fourth quarter of 24. The footage drilled per day of 1,0012 feet is up 49% since 2017.
Our best well drilled to date in the legacy Haynesville average 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 that minimizing problems and maintaining consistency or other factors leading the drilling efficiencies and then the application of managed pressure drillings, rig upgrades, and the continued improvement in our downhole motor performance.
Slide 20 highlights the significant improvements achieved in our drilling times in the western Haynesville. Since we split our initial well in the fourth quarter of 2021, we have seen significant and continuous improvement in our drilling times. Our first three wells were drilled in 2022 and averaged 95 days to reach TD and this includes executing a very difficult sidetrack we had on our second well.
Our average drilling time improved 26% down to 70 days in 2022 and we improved another 19% down to 57 days in 2024. We've drilled 21 wells to total depth through the end of the year. The fastest well was drilled to TD in 41 days, and that was during the fourth quarter.
This represents an improvement of 45% or 35 days compared to our first well. Our first well it was drilled to total depth in 75 days. The improvement in drilling days is a function of the footage drilled per day, and our first three wells in 2022 averaged 281 feet per day, and that has steadily improved to 487 feet per day in 2024.
We averaged 547 feet per day in the fourth quarter of 24, and the fastest well in this group drilled a record 608 feet per day. On average, our daily drilling footage has doubled since we started in 2022 through the end of 24.
And there's 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 improved bit selection, and the, and in the ladders, we're utilizing thermal drill pipe and continue to see more consistent downhole motor performance as we continue to have, just with the additional drilling activity.
We also started incorporating two well pads in our drilling program in mid, in the middle of last year. Slide 21 is a summary of our, is the summary of our DNC cost through the 4th quarter for Bits marked long lateral wells, located on the East Texas, North Louisiana legacy acreage position.
This covers all the wells with las 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 perfo 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 one well to sales in the legacy Haynesville, and that was that Sebastian, 11 HU 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 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 just start seeing our pipe prices come down late last year. We do expect to maintain these cost savings through the next couple of quarters.
The cost expectations are a little more uncertain out past mid-year with the potential uptick in activity looming with the higher gas prices. And the possible tariff discussions that are weighing on pipe prices. We are currently running two rigs on our legs to 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 DNC costs through the fourth quarter for all the wells we've drilled in the Western High School. This slide provides the drilling and completion costs for all the wells we've drilled into 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 DNC capital allowed us to H1 in on the good well designed for future wells, and as a result, we've been able to reduce our latest DNC capital to a point lower than our original estimates of roughly double, what our legacy 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 two well pads in our drilling program in the middle of last year, which help us to save additional days off our drill times.
We've also had great execution on our completions and integrating the two well pads into our program has allowed us to be much more efficient with our freight crews and our wildland crews.
We do currently have the four rigs running in the Western Haynesville, and we do anticipate staying with the four rigs in the Western Haynesville for the near future. Also means, all our Western Haynesville rigs are new rigs that we had 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.
M. Jay Allison
As all of 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 four 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 cells 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 two or three rigs depending upon prices, to build production back up by the fourth quarter. We expect to drill 26 or 20.4 net wells and turn 29 or 22.8 net wells to sales in the legacy angel 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 DNC costs in 2025 in both the Western and Legacy angel assets.
With strong financial liquidity totaling almost $1.1 billion. Note on slides 24 and 25, we provide some specific guidance for the rest of the year. We'll now turn the call back to the operator to answer questions from analysts who follow the company.
Operator
Thank you. (Operator Instructions).
And our first question will come from Derek Kapavik with Texas Capital. Your line is open.
Derek Kapavik
Well, good morning all and thanks for your time. Also, congratulations on the position you assembled in the Western Haynesville as your math is a dream scenario for anyone pursuing an organic leasing program in a new basin.
M. Jay Allison
Thank you.
Derek Kapavik
I have two questions that are both related to Western Haynesville. So, referencing slide 18, you're drilling arguably the deepest and most complex parts of your position today as we understand the geology. Do you have a view on reservoir quality as you move to the west to the shallower portions of the subbasin. Surely D&C costs would decrease, but there's, is there a chance that reservoir quality would support recoveries in the 2.5 to 3 BCF perfo zip code?
Daniel Harrison
There, this is, I think that that's a very good question. We are drilling the deeper, the deepest, hottest stuff, if you look at where the well locations are across the acreage, we haven't drilled anything, up there on that part of the acreage. A lot of that stuff is HBP acreage. So, we're drilling the stuff that we've leased in the hole and so that'll kind of keep us down in that.
General area and as we found up to the northeast for the kind of the near-term activity in the next couple of years.
But kind of 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 just if you just correlate it to depth, but we also expect our DNC costs are going to be a lot lower, when we drill up there in the future.
And I think our DNC 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 costs that we're at today.
M. Jay Allison
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 we looked at what reality looked like, and they look really good and that's where we ended up with these 18 wells.
It was a big enough data set so that we could actually come out and talk about the cost and in all major tier one plays. The more you drill the wells and complete them, typically the cost structure comes down exactly like it did in the core of the hands of Bossier going back to 2008 to 2011.
Derek Kapavik
And that's my follow up. I wanted to focus on the DNC cost compression you're highlighting on page 22, specifically focusing on the completion side. The degree of the step down in Q4 suggests there's more opportunities there, which is kind of what Dan suggested as well.
But in comparison to your legacy handful, is the added cost largely associated with higher treating pressures? Are there or are there other considerations? And I guess more broadly how much lower could you drive that?
Daniel Harrison
I think we have more room to probably lower our cost on the drilling side. I mean, we've seen a bigger drop on the drilling side than the completion side. I think, we have room to lower the completion cost a little bit further. I think that Q4 cost we have in there at $1,315 a foot. That's kind of a number that we're planning with for the future wells just for forecasting.
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, the fracs very consistently, so it's been really kind of trouble-free, but It's a lot more horsepower and we do pump slightly bigger jobs in the western Haynesville. On average, we pump about GBP4,000 per foot and in the core, we pump about GBP3,500 per foot. So that's also part of it.
Roland Burns
Yeah, and then I, I'd have to 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, we're really starting from scratch there and 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 cost. These early wells are bearing all that cost, in the numbers and then as you come back and Infill drill and continue to develop it, you'll have less and less of that cost, the future wells would be able to utilize that investment we're making today.
Daniel Harrison
Yeah, and I just add to what Roland said, we are building larger paths in the western highs to be able to come back and drill future wells.
M. Jay Allison
Great update guys.
Daniel Harrison
Thank you.
Operator
And the next question comes from Carlos Escalante with Wolf Research. Your line is open.
Carlos Escalante
Hey, good morning, gentlemen. I wanted to first congratulate you all on the incremental collar on the Western Angel. It's really encouraging to see the results. Let me start with a follow up to the last question, but more geared toward the development plan.
Could you speak, this is perhaps for Dan, could you speak to what a typical development plan would look like for your average Western Haynesville pad in terms of how many wells you would expect on any given pad. And what your general assumption for spacing would be, knowing, of course, that it's probably too early to know what the right spacing is.
Daniel Harrison
Yeah, I, the last piece of that is definitely too early, drilling the whole acres, the wells are spread out, so we haven't really H1d in on what the spacing's going to be. I think we're going to have to accumulate a lot of data in the future to H1 in on what the optimum spacing will be, in the Bossier versus in the Haynesville, areas where it's thicker versus thinner.
I think we're going to all yield different answers. So, I don't have a direct answer to that question, but as far as future development, we strive to drill everything with two well pads that we can, we're drilling and we're holding acreages in some places you just can't, we just don't, the acreage doesn't give you the opportunity to drill two laterals, two wells on the pad.
So, I think we're probably looking at about half 50% maybe 60% of our wells any given year will be on two well pads and the others will be singles. We strive to make as many two well pads as we can, but that's probably going to be our mix for the next couple of years.
M. Jay Allison
And one thing we TRY to do, you look, we de-risk maybe 26 miles of display, we show it on the map, and our goal is by the end of 2025 drilling 20 more wells. And hopefully all of those are to hold acreage, maybe one or two, we just have to drill outside of holding acreage.
But the goal is to drill all of those wells to delineate what this footprint really looks like, what the value is, what the resource potential is, and along with our partner with Quantum, we will build the gathering treating in the midstream to complement the program of 2,526.
I think by the end of 25, definitely by the end of 26. We'll have fully de-risked this whole 518,000-acre play, Dan had mentioned a lot of his HPP, so we don't plan on drilling on the HPP acreage until we hold and maybe 70 more wells, we need to drill in the next several years to HPP into our footprint.
Carlos Escalante
Gotcha. Thanks for the call. Jay. My second question is on the CapEx trend on a pro 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, you'll achieve greater savings. What are you doing specifically in terms of your completion design and how much headroom do you see on the drilling side, as a whole?
Roland Burns
I mean, so kind of alluded to that a little bit earlier, I think, we'll see. We haven't reached the 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. 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 a just a percent.
Reduction in cost on the drilling side and on the completion side. We are pumping the same frac job right now and 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 bucks a foot and that is we just had one well that quarter and we pumped, what we call our big frac.
We pumped GBP6,000 per foot on that well for a data point just to monitor how that well produces in the future comp 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.
M. Jay Allison
Yeah, the other thing we have managed the wells a little different, each well, it's like a prototype, and we learn how to manage all the wells, we go back and we preview what circle in looked like, what we could do or didn't do, and how well it performed, and, I think, Dan, who wants to comment on just well management, we're getting better and better and better, which is a learning curve from having the one wells.
Roland Burns
Yeah, I'd say we definitely have been conservative on how we're drawing the wells down and, based on a lot of the things we're seeing, we're just making adjustments, on how we do that, manage to draw down, how hard we pull the wells when we flow them back and clean them up, turn them to cells, and then, where we set the rate after that.
M. Jay Allison
And what they'll do, they'll give more predictability, give more stability. It'll give us, what the real top curve may look like, what the drawdowns may look like when the wells have been produced in one or two or three years, we hadn't gotten to that point yet, but I think the goal today was when, you trusted us for five years and we haven't given you all the data, and today the goal was to tell you that we think the land grab is over.
So we can give you the footprint. We think that the mid frame is secure, so we can tell you a little more about it and particularly the data set is big enough so that you can at least look at that as a beginning point to see what we can improve from there. I would tell you that if you go back and you look at the first 18 wells ever drilled in the core, the Hasel Bossier in ['08] and you compare those to the wells we drilled today. Ours are like lights out better, so.
Operator
And our next question comes from Charles Mead with Johnson Rice. Your line is open.
Charles Meade
Good morning, Jay Roland and Dan and I had my voice to the course of congratulations, not just on assembling this position but also the great progress.
M. Jay Allison
You've been screaming and yelling for us, and you've lost your voice. I know, I understand.
Charles Meade
That, that's the least of my problems, Jay, you already anticipated one of my, or my first question when you started talking about the de-risking of the position. You talked about the, your first wells here you've deised along a kind of a 26 mile southwest to northeast axis. If I'm just eyeball on your map there on what is, I think it's page 18, yeah, I just eyeballed.
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 that's going to, determine exactly how much of this 518 really works?
M. Jay Allison
Well, if what you noticed on the slide or kind of my introduction, I said that the slide on page four, it is to scale because sometimes there's trickery, you don't have many acres, but you don't put it to scale and you compare it to your other acreage, and it looks skewed. So, we said you 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 Bossiers developed. So, when you go back to the beginning, in, 2020, 2021, '22, you can see we 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 work, 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 de-risk this thing, which is very hard to do.
It takes months and, some bad days, some good days, but you add it all up, what we TRY to do is we TRY to say, how many acres do we have that we have to drill wells right now in 2021, 2022, in order to hold leases that we had inherited from acquisitions? That's number one. And number two, we looked at, how many logs that we had that penetrated the different thicknesses in the Bossier and Haynesville.
Then we looked to see what seismic we owned or 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 kept it pretty busy, and now we were good stewards to the budget and liquidity. In 2024, we were going to add a third rig. We didn't, we kept it at two rigs.
And then Charles, what we did, we looked at acreage that was expiring. Now we didn't lease all this acreage in 2021, 2022, '23, '24. We leased it along the way. So, we avoided a big cliff where you had to drill a lot of acres because you had leased it all at the same time. We feathered it out so that we didn't have that issue and at the same time, we had several acquisitions that we bought deeper rights that are HPP.
So, as we look at a drilling program in 2025, 2026, 2027, we kind of pair that up with quantum and we say how far are we away from our main pinnacle line? What's the cost structure, what's the gathering cost? We look at the depth, the thickness. And you do have different thickness, we've told you on some of the calls that we've got maybe, 13 1,400 feet of perspective pay in some areas.
Well, you look at that, that's not true for all of it. Some of it's going to be the same, pay thickness that we have in the tier of our legacy acreage.
So, that's 200 300 feet, whatever, but yeah, it expands. We did choose to drill the deepest, hottest, hardest, first, because that would tell you whether we needed to pursue to spend more money on acreage and more money on seismic and to keep the land group leasing that acreage and feathered into the drilling program. It's a beautiful story to write when you see it because of like, 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 white acreage in there? Well, a lot of that acreage, maybe one or two other companies own, and we encourage them to drill wells out there. Maybe there's some little spotty acreage that we don't want to own, but we're not afraid to have people come out there and de-risk this with us. That's why we show you once we think the land grab is over.
So, at the end of this quarter, I think we'll have some more results, but I want you, I mean, it's, if you, it's our banks, 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 de-risk the whole footprint and see what the thicknesses are.
Charles, I had to, if you look up in the, up in our core acreage up there, some of our best wells are in the areas that are not as thick like up around like, the Elm Grove area, so I. As far as just speculating, if it's something's thinner or thicker on how it's going to perform, I don't think there's any correlation there at all, really.
Charles Meade
Is it really more just, gas filled porosity is the biggest determinant then? I mean, thicker, I mean, obviously more gas in place, right, thicker rot, but definitely that does not correlate to the to. You know how prolific it'll be.
M. Jay Allison
We have meaningful low-pressure differences.
Yeah. Interesting
Charles Meade
. And then one follow up, Jay, you already, you touched on this also, I think Dan, you touched on this, a lot of focus on these newest batch of wells and rightfully so, but you continue to watch these other older vintage wells, and I'm wondering if you can talk about what you've learned from them, whether about.
The right way to manage the pressure drawdown, the landing zones within these formations or the right completion jobs. I know there's, every day that ticks by you add to the data pile from those older finch as well. So can you just tell us what you've learned in that respect.
Daniel Harrison
I think, we obviously have been really laser focused on the cost, just getting the wells down and TD, the landing zones, I think, a lot of these well, where we drill are in the, relatively thicker, part of the place. 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 just feeding these things as fast as we could.
And, as far as the drawdown and, we've been pretty conservative, I think we'll probably tweak that a little bit in the future, these last few wells, we like to IP them. Pull them a little bit harder and get the wells clean, make sure they're getting clean before we get flow back off of them, and then, pull the rates back and start them, basically on the tight curve rate and just basically, let them go from there.
M. Jay Allison
Charles, some detail, but some of these wells we do, but some we don't. It's a big cost variance too, so we figure out what we need to do or not do, as we drill more of these wells.
Charles Meade
Got it. Thank you, Dan and Jay.
Thank you.
Operator
And the next question will come from Kalei Akamine with Bank of America. Your line is open.
Kalei Akamine
Hey, good morning, guys. Jay, Roland. 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 7n Rigs? It 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, 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 seven rigs was always a really good level for the company to kind of maintain. I think we dropped to five rigs. You can see the impact of that, that's really too low of an activity level, but it was needed to help balance the market.
So, we're going to get very comfortable with seven, 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 will have the level of production and good gas prices to drive the, get the balance sheet in perfect shape, and I think, 25, that level we're running now, we won't add any debt, we'll slowly pace them down, but then next year we'll be able to really reduce debt significantly.
Kalei Akamine
Well, in as far as the year end 26 bogey, you think somewhere under 1.5 times is where the balance sheet would end up.
Roland Burns
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 this so low of gas prices, but, yeah, we definitely want to get it down as quickly as possible to the 1.5 times leverage area.
It's probably, that's probably something that we achieve in 206, but I think we'll be. Way in the very low, two times leverage numbers as we kind of work our way through 25. So, a lot will depend on, how strong gas prices are and then how, we do have to rebuild our production a little bit to kind of get. The leverage ratio, to its more optimal.
M. Jay Allison
That's a really good point though. I mean, we said this, but other than COVID, gas price last year was the lowest it's been in 30 years. So, if you look at that and you look at us getting rid of two roofs, you look at us having a crack holiday. And then you look at us adding 265,000 acres in the western Haynesville, you can see that we really monitor our leverage and our balance sheet.
We do that even in a very difficult year and at the same time, instead of M&A, we said we'd like to see if we can't grow organically and typically that's what these companies used to do and because of the Joneses, they kind of uncuffed us.
We could go in and as we were one of the first several companies to de-risk and discover the core of Haynesville, we just picked 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, that 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.
Kalei Akamine
That's right, it's. Exciting to watch. Jay Rowland. I'll see you guys. In a couple weeks.
M. Jay Allison
Yes, we look forward to it.
Operator
And our next question will come from Bertrand Donnes with Trust. Your line is now open.
Bertrand Donnes
Hey morning team. I just want to follow up on that on that M&A topic, not necessarily on the on the western side, but with higher gas prices, you'd think most of the private owners are probably thinking about, potentially selling or, maybe does that incentivize you to look more aggressively or are those sellers seeing the strip move up and maybe they're already seeing a $5 price that they want to see or something like that.
And then the second part of that would just be. On the oil side, most of these private equity shops normally ramp up production before a sale. Do you see that happening or that's not exactly how it would work on a gas?
Roland Burns
Well, it's hard to predict how, what you know what they're looking at, but obviously I think there are still some private companies out in the Haynesville that have invested a lot of capital and now that you're in a good gas price, situation that their business plan is to, sell that kind of like the same with the oil.
The private companies, the Permian and so but we do see a very low level of activity in the Haynesville, so we certainly haven't seen any type of effort to ramp up at all from the public or private operators.
We've seen great discipline, 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 volatile gas prices. And so, I think everybody's been very cautious to say we're not going to oversupply this market and maybe we undersupply it because we're so cautious.
M. Jay Allison
Well, and you can even see the first quarter, we give guidance down and we're not going to overproduce, period. And that 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, the HPP more the footprint.
So that's why we're doing that even we don't see any ENP company out there out of control on their production rates, none of them.
Bertrand Donnes
That's great. I think the market is happy to see that. And for my second question, several of your peers have started talking about potentially locking in a percentage of their production, the contracts, either Data Center or LNG, and it seems like most have fallen in a 10% to 20% of their volumes.
Is that where you guys feel like you'd fall, or you potentially have a larger appetite? Maybe you lock up, acreage dedication in the Western Haynesville or something like that for a, to backfill a demand project. Thanks.
Roland Burns
Yeah, that's a good question. We would also want to look at having a portfolio of purchasers for our gas and not putting, all our eggs in one basket. But we see, both being a major supplier to several of the LNG shippers and potentially, looking at some power generation projects to back too.
But again, I think having a good balance of that activity because, their demand comes at different times of the year and so, but there are great good opportunities for the gas producers now to start to directly.
Yeah, lock up with the industrial users and the exporters, and I think it's a good time for us to create good relationships where we could have more stable prices and also, know that we've got good, we've got that we balance out our production to what we know the market needs.
M. Jay Allison
So, particularly, probably 90% of our Western Haynesville is completely in dedicated, I mean. Completely, so it's free range out there. We can kind of do what we want to with it.
Bertrand Donnes
I just want to clarify so that an acreage dedication for a for a demand project that is that coming back or we done with that.
Roland Burns
Oh yeah, I'm not sure that, acreage dedication is probably, out there. I mean, typically that kind of comes to back up, a large amount of infrastructure, to make it, for the infrastructure partner to be comfortable that, they can get their capital out. But here I think, since we're going to own our 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 up our portfolio of gas both from the legacy in the western Haynesville and then we want to portion it out to, these direct contracts as we felt comfortable that, it's a good fit.
And obviously we're looking for 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 so, but it's a very exciting time to be developing a new place like the Western Haynesville at the same time. There's 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.
.
M. Jay Allison
It's 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, we don't want anyone to ever overlook that that 301,000 acres and that inventory with plenty of takeaway there that that gave us the ability to come look at the Western angel that along with the operational technical skill that we had. But the value of the legacy allowed us to do the Western Haynesville.
Bertrand Donnes
Perfect, thanks for the answers, guys.
M. Jay Allison
Thank you.
Operator
And our next question will come from Jacob Roberts with TPH and Company. Your lines open.
Jake Roberts
Morning.
M. Jay Allison
Morning. Just.
Jake Roberts
I hate to ask about 2026 plus, but thinking about the 43 rig split as we kind of progress through 2025, is that a level that can meet any HVP needs, any NBC 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.
Roland Burns
Well, the real positive, the way we structure things is that we don't even need to maintain that type of activity to kind of meet, any NBCs or other requirements. We've been, very conservative as you build something out, not to get over committed. So, I think it's a very comfortable level, the, for the company and so it's really going to be like what is the markets, where's the gas really needed.
And I think we will adjust that, based on kind of how we see these markets go out. I think we're very comfortable with the activity level and running, be able to run four rigs in the Haynesville will keep us on track to. HBP and all of our acreage and easily meeting, supporting. The belt out of the midstream.
Jake Roberts
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 this land that helps you understand it the way you do?
Daniel Harrison
Yeah, I'd say there's been a lot of 3D seismic shot across all of this acreage, just a lot of different vintage data that's out there that can be bought that has been tremendously, helpful and 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-controlled purposes and geo steering and we've also got some future coring and stuff we're going to do as far as, just doing some more sites. And to get the performance properties on the rock. Excellent I'll echo the sentiment of appreciating the update guys.
M. Jay Allison
Thank you.
Operator
And our next question will come from Gregg 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 pencil in and then when do you think you will exhaust the. The midstream JV and how do you think about funding it after that?
Roland Burns
Yeah, it's a great question. Yeah, we, this is a, with building the new treating plant, this is 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 plans. 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 we, the build out of the midstream is amazingly fit almost perfectly with our five-year plan for it so far, and so we've been really pleased, and I think our partner has been too, and. So, I think that eventually, there's 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, you 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 UBIAX, 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 big asset for the company and under our structure, once we. You return that capital with the preferred return, that will revert 100% back, 70% back to the company, and then we can buy out the minority interest if we like in the future also.
M. Jay Allison
Yeah, the goal was, we, as we were acquiring all the sacres, we wanted to control the mid frame. We trusted, Quantum as a company, in lending money and supporting 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 acreages, look at the well results of that point, which have only gotten better. I mean, they said we're back with $300 million. We wanted to make sure that we would control that, and it wouldn't be sold to some third party, which would then control what we'd be doing in the Western names we didn't want to lose control of that, and Quantum became the perfect partner.
Gregg Brody
So, it's fair to say that between quantum's equity and potential credit facility at the at the JV that entity self-funding for the next several years.
Roland Burns
Right, we would see it hopefully transitioning in the next year. I mean really if you get through 26 that probably where it doesn't really need it, they'll start to be totally self-funding. And we are supposed to see maybe bringing in some of our nearby operators, could also help accelerate that if we can land some of those as customers as we build the system out.
Gregg Brody
Great, thanks for your time, guys.
Operator
And our next question will come from Noelle Parks with Tuy Brothers. Your line is now open.
Noel Parks
Hi, good morning, just thinking about the drilling time improvements you've already, been able to achieve, I just wondered, could you just talk a bit about maybe what assumptions you have going in your early. Just well and whether there's anything different now that you're this far in sort of like what you know you talked about some of the things you tweaked but I was just wondering you know kind of what was your starting point like when you were approaching the play.
It'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, you'll say 5 ks to 10Ks, and at the same time, they were getting twice as long, they were being drilled and half the time.
And there were a couple of, there was a couple of old wells that that had been drilled, old horizontals that had been drilled back in 2010 down here in the western Haynesville that was kind of provided some of the earliest data to take a look at, that we looked at, they had a lot of just a Just a lot of mechanical issues, collapse 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 5kish type wells.
And so, if you just applied the same industry progression. Twice as long in half the days, 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 harder and we just have so much more room to run down here to get better. Versus we did up in the core. So
M. Jay Allison
While our confidence level grew, we were going to drill to 16,000 feet vertical and then as our confidence grew with well after well after well, we did go to 19,000 feet. So, we wouldn't have done that had we not had more confidence in the 16,000 feet 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, field practice makes perfect. The more you drill, the better you're going to get. The more the industry drills, the better the industry gets, and that's what we're seeing.
Daniel Harrison
Great, thanks and understandably there's been so much attention to us seeing the map for the first time and the results from the newest la of wealth. So, I just wonder if I could just talk a little bit about gas macro and you know looking at your hedges. I was just wondering, is there anything particular about the 350 mark as where your downside protection is that you've been gravitating toward and I also if you have any thoughts about. What things are going to look like or might look like as the LNG ramp up continues along. Well.
M. Jay Allison
We look today and I just looked and says the US LNG fleet hit a new record high of 16.47 [bes.] We are very positive on natural gas and latter part of 25, 2016, even 27.
So, when we, when we look at the Western angel, 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 guarantee that we can drill all these wells that we need to drill in 25, 26 and still deliver the balance sheet.
Our big land grab and a lot of money we spent on that it's over. We'll spend a little bit as we do even in the core cleaning it up all the time where that'll be perpetual, but we don't see any big acreage at their positions that we're chasing that we don't have. So, this is surely it's a protection of the balance sheet to get us back to have a dividend.
If we could have a dividend in the latter part of 26th grade, early 27, whatever, but we want to lever of the company now, drill these wells, 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 something we birth; we control. And where it is perfect. You could pick a map. If you would look at where our pipeline is, which we showed that all went over it. We bought that a lot of that pipeline at one of our acquisitions. It is the backbone of where our footprint is. You could have a better location for that pipeline, and it's not there by mistake. 20 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, 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.
Roland Burns
Yeah. The replacement cost for 246 miles of high-pressure pipeline and a treating plant, it would be unbelievable to have to put all that in from scratch. I mean, you're talking about the amount of equity that's already there is pretty phenomenal, so.
Noel Parks
Great thanks that's really helpful insight it'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.
M. Jay Allison
I want to thank all of you. It's a much longer call than normal. It's almost an hour and a half. We knew it would go longer. We didn't want to cut anybody off, but again, I want to thank you. There's probably 250+ 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 that 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 spirit. 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.
Operator
This concludes today's conference call.
Thank you for participating. You may now disconnect.
