Comstock Resources Q2 2023 Earnings Call Transcript

Quartr
Provided by Quartr
August 1, 2023

There are 14 speakers on the call.

Operator

Hi, and welcome to the Comstock Resources Second Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Mr.

Operator

Jay Allison, Chairman and CEO. Please go ahead, sir.

Speaker 1

Thank you, Jonathan. I wish you controlled natural gas prices. We'd all be a little happier. I like your introduction. Welcome to the Comstock Resources Second Quarter 2023 Financial and Operating Results Conference Call.

Speaker 1

You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the There you'll find a presentation entitled 2nd Quarter 2023 Results. I'm Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer Dan Harrison, our Chief Operating Officer and Ron Mills, our VP of Finance and Investor Relations. Now flip over to Slide 2. Please refer to Slide 2 in our presentation to note that our discussion today will include forward looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there could be no assurance that such expectations will prove to be correct.

Speaker 1

I want to take the time to thank each of you that's listening today on this call and those who will listen later As we all know, this year continues to be challenging as we've had weak natural gas prices coupled with highly inflated drilling and completion costs. Looking beyond this year, we are very optimistic about natural gas. The growth in demand for natural gas driven by the growth of LNG exports from the Gulf Coast are expected to improve Natural gas prices next year and the years beyond, the demand for LNG should grow from the 12 Bcf we export today The 21 Bcf by 20.27 per day and beyond that, the total demand may hit 40 Bcf per day for LNG Not that many years out. So we're optimistic about the prospects of our Western Haynesville play Based upon the very early results of our first five wells, which Dan Harris will talk to you about later, as we continue to move up the learning on drilling these deeper wells. We've also exceeded our expectations on growing our already expansive acreage position Through our on the ground leasing efforts, the investments that we're making this year in the Western Haynes will pay substantial dividends in the future As the demand for natural gas grows, we're making this investment this year to build on the foundation for the future.

Speaker 1

At the same time, we've been mindful to protect the strong balance sheet and financial liquidity we created last year when we had stronger Natural gas prices. So for the next hour, we will go over the second quarter results, which were marked By very low natural gas prices, we're a little noisy on the disruptions caused by violent storms in June that we had in East Texas. On Slide 3, if you'll flip there. On Slide 3, we summarize the highlights of the 2nd quarter. The financial results were heavily impacted by the very low natural gas prices we realized in the quarter.

Speaker 1

Oil and gas sales, including hedging, were $285,000,000 in the quarter. We generated cash flow from operations of $145,000,000 or $0.53 per share And adjusted EBITDAX was $182,000,000 with positive working capital contributions, we only had to borrow $20,000,000 to cover the over Our adjusted net income was just over breakeven for the quarter. We drilled 21 or 17.2 net Successfully operated Haynesville and Bossier Shale horizontal wells in the quarter with an average lateral length of 10,887 feet. Since the last conference call, we've connected 15 or 12 net operated wells to sales with an average initial production rate of 21,000,000 cubic feet equivalent per day. We're having great success in our Westford Haynesville exploratory play in the early innings.

Speaker 1

Our 4th and 5th wells were recently turned to sales With strong production rates, including our first well in the Haynesville shale, the first four wells have been completed in the Bossier shale. We've also been very successful in adding to our extensive lease position. The low gas price environment is contributing to our success I'll now turn it over to Roland to discuss financial results. Roland?

Speaker 2

Yes. Thanks, Jay. On Slide 4, we cover our Q2 financial results. Our production in the Q2 was 1.4 Bcfe per day, which was 2% higher As compared to the Q2 of 2022, low natural gas prices significantly impacted our oil and gas sales in the quarter The DAX was $182,000,000 and we generated $145,000,000 of cash flow during the quarter. We reported adjusted net income of $1,000,000 for the 2nd quarter, as Jay said, just above the breakeven level as compared to $274,000,000 in the Q2 of 2022.

Speaker 2

On Slide 5, we have the financial results for the first Half of this year. Our production in the first half of twenty twenty three also averaged 1.4 Bcf per day, which was 6% higher as compared to the same period last year. Oil and Gas sales in the first half of twenty twenty three totaled $676,000,000 which were a third lower than the first half of twenty twenty two. EBITDAX was $476,000,000 and we generated $400,000,000 of cash flow during the 1st 6 months. We We reported adjusted net income of $93,000,000 for the 1st 6 months of 2023 as compared to $409,000,000 in the 1st 6 months of 2022.

Speaker 2

On Slide 6, we show our natural gas price realizations in the quarter. During the Q2, the NYMEX settlement price averaged $2.10 and it was very close to the same Daily average Henry Hub spot price in the quarter of $2.12 Our realized gas price during the Q2 averaged 1.81 reflected a $0.29 differential to both the settlement price and our reference price. This differential returned to a more normal in the quarter due to improvements in the Houston Ship Channel and Katy Hub prices following the restart of the Freeport LNG facility. In the Q2, we're also 49% hedged, which improved our realized gas price to 2.25 We've been using some of our excess transportation in the Haynesville to buy and resell third party natural gas. This generated about $3,000,000 of profits in the quarter and improved our average gas price realization by another $0.03 On slide 7, we detail our operating cost per Mcfe produced and our EBITDAX margin.

Speaker 2

Our operating cost per Mcfe averaged $0.84 in the 2nd quarter, $0.01 higher than the Q1 rate. The increased unit costs are related to the startup phase in our Western Haynesville area, which we'll see improve as we connect more sales to our own gathering and treating facilities in Our gathering costs were flat at $0.36 during the quarter and our lifting costs were also unchanged at $0.27 Our production taxes increased $0.03 compared to the Q1 level. Our G and A cost came in at $0.06 per Mcfe, which is down $0.02 from the Q1 rate. Our EBITDAX margin after hedging came in at 63 Percent in the second quarter, down from 73% in the first quarter due to the lower gas prices we experienced in the second quarter. On Slide 8, we recap our spending on our drilling and other development activity for the first half of this year.

Speaker 2

For the 1st 6 months, we spent a total of $647,000,000 on development activities, including $590,000,000 on our Operator Haynesville and Bossier Shale Drilling Program spending on other development activity including non operated projects, Installing production tubing, offset frac protection and other workovers totaled $57,000,000 In the 1st 6 months this year, we drilled 39 or 30.9 net operated Haynesville and Bossier Shale Wells and turned another 36 or 24.8 net operated wells to sales. These wells had an average IP rate of 23,000,000 cubic feet per day. Slide 9 recaps our balance sheet at the end of the second quarter. We ended the quarter with only $20,000,000 of Barings outstanding under our credit facility given us $2,200,000,000 in total debt. We ended the 2nd quarter with financial liquidity of almost $1,500,000,000 I'll now turn it over to Dan to discuss the operating results.

Speaker 3

Okay. Thanks, Roland. Slide 10 is a breakdown of the current drilling inventory now that we have At the end of the Q2, the drilling inventory is split between Haynesville and Bossier locations. It's divided into our 4 buckets. We have our short laterals up to 5,000 feet, medium laterals, so between 5,8000 feet, our long laterals at 8000 to 11000 feet and our extra long laterals out past 11,000 feet.

Speaker 3

Our total operated inventory now stands at 1782 gross locations and 1359 net locations. This equates to a 76% average working interest across the operated inventory. The non operated inventory Stands at 1278 gross locations and 166 net locations, which represents a 13% average working interest across the non operated inventory. The success of our long lateral drilling program allows us to modify our drilling inventory where possible to extend future laterals Into the 10000 to 15000 foot range. Breaking down the gross operated inventory, we have 313 short laterals, 291 medium length laterals, 7 19 long laterals and 459 Extra long laterals.

Speaker 3

Our gross operated inventory is split 52% in the Haynesville and 48% in the Bossier. We now have 26% of our gross operated inventory or 459 locations in our extra long lateral bucket, This is greater than 11,000 feet and full 2 thirds of the gross operated inventory has laterals exceeding 8,000 feet. The average lateral length now stands at 8,947 feet. This is up slightly from the 8,928 foot We had at the end of the Q1. Our inventory provides us with 25 years of future drilling locations based on existing activity.

Speaker 3

On Slide 11 is a chart that outlines our progress to date on our average lateral length drilled based on the wells that we have turned to sales. During the Q2, we turned 17 wells to sales with an average length of 11,244 feet, Thanks to the continued success of our long lateral program. The individual well lengths range from 7,338 feet up to 15,552 feet and our record long lateral still stands at 15,726 feet. During the Q2, 8 of the 17 wells returned to sales had laterals exceeding 11,000 feet, including 4 that had laterals out past 14,000 feet. To date, we have drilled a total of 56 Wells with laterals over 11,000 feet and we drilled 28 wells with laterals over 14,000 feet.

Speaker 3

During the Q2, we also had 2 additional wells that turned to sales in our new Western Haynesville acreage. The Denkins number 1 well was completed In the lower section of the mid Bossier, while the McCullough Ingram number 1 is our first well completed in the Haynesville. These wells are our 4th and 5th new vintage wells now completed and producing in the Western Haynesville. Based on our current schedule, we are planning to turn another 37 wells to sales by year end. 17 of these wells will be extra long laterals that Beyond 11,000 feet and 13 of the wells will be over 14,000 foot long.

Speaker 3

Upon successful execution, our 2023 year end average lateral length is expected to be approximately 11,000 feet. Slide 12 outlines our new well activity. We've turned to sales and tested 15 new wells since the time of our last call. The individual IP rates range from 16,000,000 today up to 35,000,000 cubic feet a day with an average test rate 21,000,000 cubic feet a day. The average lateral length was 10,671 feet With the individual laterals ranging from 7,338 feet up to 14,767 feet.

Speaker 3

Included this quarter are the 4th and 5th new vintage wells on the Western Haynesville acreage. The Denkins number 1 was completed in the lower section of the mid Bossier. It had a 9,565 foot long lateral and we turned the well to sales in May. We tested the well with an IP rate of 34,000,000 cubic feet a day. The McCullough Ingram number 1 well is our first Well that we've completed in the Haynesville interval, it had an 8,256 foot long lateral and the well was turned to sales in June.

Speaker 3

The IP rate achieved to date is 35,000,000 cubic feet a day, but we are still cleaning this well up and we are expected to Beyond these last two wells that we've turned to sales, we are currently in the process of completing our 6th and 7th wells on the Western Haynesville acreage. We expect to turn both of these wells to sales within the next couple of months. In addition, we are currently running 1 rig on our Western Haynesville acreage, but that will soon increase back to 2 rigs later this month. Slide 13 summarizes our D and C costs through the Q2 for our benchmark Long lateral wells that are on our legacy core East Texas and North Louisiana acreage position. This This covers all wells having laterals greater than 8,000 feet.

Speaker 3

During the quarter, we Louisiana acreage and 13 of the 15 wells were our bps mark long lateral wells. In the Q2, our D and C cost averaged $15.23 per foot, which is a 4% decrease compared to the Q1 and Still a 15% increase compared to our full year 2020 2 D and C cost. Our 2nd quarter drilling cost came in at $6.53 a foot, This is a 2% decrease compared to the Q1. A portion of the drilling cost decrease is attributable to a longer average lateral length We had this quarter versus the Q1. Our 2nd quarter completion cost came in at $8.70 a foot, which is a 5% We have seen our service costs began to decrease during the Q2 following the drop in activity levels since the 1st of the year.

Speaker 3

We expect these service costs will continue to decline throughout the 3rd Q4.

Speaker 2

At the end

Speaker 3

of June, we dropped a rig from the fleet, which has us currently running 6 rigs. However, later this month, we will be taking delivery of a new rig, which will take us back to 7 rigs, which is the level we plan to stay at through the end of the year. And also on the completion side, we are also running 3 frac crews and we will stay at the 3 frac crew level through year end. So that's kind of a summary of the operations. I'll now turn the call back over to Jay.

Speaker 1

Okay. Thank you, Dan. If you'll turn to Slide 14, I'll direct you to Slide 14, where we summarize our outlook for 2023. We look back on this year and the future, we'll view it as a year where we built the foundation that will drive our future growth. Our business plan for this year is focused on positioning Comstock to benefit from the substantial growth in demand for natural gas in our region That is on the horizon driven by the growth in LNG exports.

Speaker 1

Now to that end, we are working To prove up our new play in the Western Haynesville with a 2 rig program and complete our leasing program, now we currently only have 1 rig

Speaker 4

active in the Western Haynesville,

Speaker 1

as Dan mentioned, and we have Western Haynesville, as Dan mentioned, and we have leased approximately 90% of our targeted acres. We're almost at the finish line. We're making big investments for the future this year. At the same time, we are managing our drilling activity level To prudently respond to the lower gas price environment we continue to experience as Roland talked about earlier, We released 2 rigs on our legacy Haynesville footprint in late March mid April in order to pull in our Activity in response to lower natural gas prices and are currently operating 6 rigs as we await delivery of a new rig. We remain focused on maintaining the strong balance sheet we created last year.

Speaker 1

Now our industry leading lowest cost structure Is an asset in the current low natural gas price environment as our cost structure is substantially lower than the other public natural gas producers. As stated in our press release, we plan to retain the quarterly dividend of $0.125 per common share. And lastly, we will continue to maintain our very strong financial liquidity, which totaled around $1,500,000,000 at the end of the second quarter. I'll now have Ron provide some specific guidance for the rest of the year. Ron?

Speaker 5

Thanks, Jay. On Slide 15, we provide the Financial guidance for 2023. The 3rd quarter D and C CapEx is expected to range between 2 $40,000,000 to $280,000,000 and our full year D and C CapEx guidance remains unchanged at the $950,000,000 to 1.15 $1,000,000 to $1,150,000,000 range. While we're seeing signs of deflationary pressures on service costs, we believe most of those improvements will In terms of infrastructure and other spending, we continue to budget $15,000,000 to $30,000,000 During the Q3 and $75,000,000 to $125,000,000 to $125,000,000 for the full year. In addition to what we spend on our drilling program noted above, we now anticipate spending $70,000,000 to $85,000,000 this year for leasing activity.

Speaker 5

Our LOE is expected to average $0.24 to $0.28 for both the quarter and the full year, While our gathering and transportation costs are expected to be in the 32% to 36% range for the quarter and the year. Production and anilorm taxes are expected to remain in the $0.12 to $0.16 per Mcfe range, While our DD and A rate is expected to remain in the $1.05 to $1.15 per Mcfe. Cash G and A is still expected to run around $7,000,000 to $9,000,000 in the Q3 and a total of $32,000,000 to $36,000,000 For the full year, while the non cash G and A represents roughly $2,000,000 per quarter of that number. Due to the increase in SOFR rates, the cash interest expense is now expected to total $40,000,000 to $42,000,000 for the 3rd quarter and $160,000,000 to $165,000,000 for the year. Tax rate remains in the 22% to 25% range and we still expect to Defer between 95% 100% of our reported taxes this year.

Speaker 5

I'll now turn the call back over to Jonathan to answer questions.

Operator

Certainly, one moment for our first question. And our first question comes from the line of Charles Meade from Johnson Rice. Your question please.

Speaker 6

Good morning, Jay and Roland and the whole Comstock crew there.

Speaker 1

Good morning, Charles.

Speaker 6

Jay, I want to see if there's some more Detail you can offer on these on your Western Haynesville wells, not just these 2 most recent ones, but in general, $35,000,000 a day, congratulations on that. That's a great stout rate. But There's more to find the well than just where it comes on, right? I mean, on the some of the best wells On the Louisiana side, we're delivering IPs of 40 or even 50,000,000 a day. So how would you What are the other data points?

Speaker 6

And I'm thinking decline, but there may be some other things that you can talk about that will help us contextualize What you're doing in the Western Haynesville with these kind of 35 to 40 IPs versus the best stuff we're seeing on the Louisiana side?

Speaker 1

So Charles, I'll probably I'll turn it over to Dan. I don't know how deep in the weeds want to get. I think I'd start like this. I want to go backwards and say How many acres have we leased? And I mentioned that at the end of the commentary, and that is we're probably 90% plus through leasing our acreage position.

Speaker 1

And we're very careful about disclosures on what we're doing until we lease it all. But all the acreage that we want to lease, we've recognized and that we know the mineral owners We have we're in discussions with them. So I think that's a good place to start. So we can get to the end of that in 2023. And then I would just comment on the wells that we have drilled.

Speaker 1

Remember, this play is unlike the play In Louisiana that you're referencing that we've read about, we have a much bigger block, more contiguous. We have our own takeaway, so we don't have any infrastructure issues on the horizon. And the wells that we've been drilling are the inferior wells. They're not the Haynesville wells. They are the Bossier wells.

Speaker 1

So we Typically, your Haynesville well will be 15%, 20% better than your Bossier. And really no one to our knowledge has drilled these wells The depth that we've drilled them at, but the lateral length that we've drilled them at, with the heat that we've encountered as effectively as we have, And that includes the Circle M, which is a Bossier, the KC Blackbridge of Bossier, the Campbell, which is proved that we could drill extended laterals The 12,700 feet, that was a Bossier. And then, Charles, you get to the Denken, which is a lower Bossier. So we're Now we're delineating the upper lower, same thing with the Haynesville and then the McCullough Ingram, which is a Haynesville, which Dan had commented on McCullough Ingram. At the same time, we have completed the KCMS and we have fracked it and we've got a stick pipe building out the fracs And then we've got the Lanier that we're completing right now.

Speaker 1

And then we're drilling the glass. So I think it's I always say it's the early innings look really good, but it is early innings and we're still trying to Our rep is present up under the tree before we disclose to the world what we're trying to do. So let me make those comments and then I'll let Dan get a little deeper on that, okay?

Speaker 3

Yes. Charles, so one of the things I want Add to what Jay said is we are being very conservative in how we're drawing the wells down. Obviously, there are a lot DeeperTVD is here. We got a lot better bottom hole pressure. The productivity Yes, it's really good.

Speaker 3

We're obviously not trying to get just to get a super stellar IP rate on what the well could do right now because we are Really managing the wells based on the drawdown and just trying to make sure that we produce them out according to the type curves that we got created. But the wells look really good and the drawdowns look good. We the pressure is I'll say this McCullough well that's in the Haynesville It's flowing with more pressure at the same choke size as what we've seen on any of our Bossier wells. So we definitely are seeing a lot better deliverability on the Haynesville Well versus the Bossier wells. And so we think it's going to be pretty good.

Speaker 3

And looking forward in the drilling into this play, The Haynesville is going to always be our primary target. When we first started in the play, we knew it was going to be Tough drilling these wells due to the depth and the temperatures and we did specifically target drilling to the Bossier interval initially Just from a drilling standpoint, just to give ourselves the best chance of success to get started. So We've made great progress technically drilling the wells and dealing with the temperatures. So we turned our attention to drilling some of the deeper targets, Been able to do that successfully and we think that will bear out with a lot better wells in the Haynesville.

Speaker 6

That is great. Go ahead. I'm sorry.

Speaker 1

Onego again, we circle the wagon. If this remaining 10% that we're trying to lease, if for some reason we don't get it, we've circled the rack and started 3 years ago in August and Very low cost that we paid for the acreage. And you know the drilling commitments are very normal. We go from 2 to 3, 3 to 4 rigs, and we can We see all this footprint. Again, with Western Haynesville, we bought we did buy that infrastructure when we bought Legacy, The Pinnacle plant, etcetera.

Speaker 1

So all of those things give us a tremendous competitive advantage. Even if we were to stop leasing today or stop today. We think we're going to get a big blue ribbon. Now what we want to make sure is that We're accountable to you and you trust us for where we're spending our money and We'll complete this journey by the end of this year, and we'll have more disclosure on these well results. So great question, And we try to answer it as clear as we could with the set of facts we have, okay?

Speaker 6

That's it's great detail, Jay. And it makes Sense that you guys are holding some cards close right now. That makes sense. I'll just you can count me among those eager To hear more when you want to offer more, but Jay, you also kind of touched on the one question I want to follow-up on, and that is the leasing and that Your increased capital budget for leasing, it was a great data point that I hadn't heard from you before. I believe that you're 90% done.

Speaker 6

But is your view Is your target changing or is your view of what you want changing? And does that how does that Play or not play into the increased lease acquisition budget?

Speaker 1

Well, I think when you look 3 years ago, 2 years ago, 1 year ago, You come up with a budget and as you dev into the geology, it's all based upon geology, right? And you want to clean up maybe the middle, you find out there's some acreage that's opened in the middle. So you add 4,000,000 to 8,000 acres in the middle, really to clean it up to make all the acreage that you own more drillable, so you can extend your laterals. Again, as Dan Harrison said, we're trying to get these wells 10000, 11000 foot laterals and That's kind of spotty out there. This whole program, as you've seen, that's why we gave a whole slide on the lateral links, The 5000, 8000, 10000, 15,000 collaterals, we're trying to groom this so that when you see all of it at one time, You can say, oh, now I see why you added a couple of $1,000,000 to clean up some spots in the middle that we didn't know would be available to lease.

Speaker 1

It's not that we've really extended the peripheral. We kind of understood that long time ago. So there's nothing that we're really trying to acquire on the peripheral Of any material size that we have to own at all. So it's just a cleanup like a moth cleaning things up.

Speaker 6

I appreciate the visual, Jay. Thanks for taking the questions.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Derrick Whitfield from Stifel. Your question please.

Speaker 1

Thanks and good morning all. Good morning. Good morning. On my first question,

Speaker 7

I wanted to focus on the trajectory of your If we assume the low side of your production guidance range, the implied guidance for Q4 projects an average rate of About 1.5 Bcf per day, which is up from 1.4 in Q3. Would it be fair to assume your extra rate for the year Could meaningfully exceed 1.5, given the timing of your turn in lines.

Speaker 5

Derek, it's Ron. The absolute exit rate, we've never provided that. It depends on the actual Timing of when those turn to sales occur, to average 1.5 We're close to 1.5 for the quarter. If you try to back into that number, there can there's a chance The exit rate can be above that to help create the average if you but in terms of An absolute exit rate, that's something that we wouldn't provide, but your math, we've given you the Q3, you have the first half. And so To back into what we would need to get to that low end of the range, your average for the Q4 is where it should be.

Speaker 2

Yes, Derek, I think we more or less have seen that year unfold like we planned. I think there's been Yes. Lower kind of hookups, especially we have one area that's a month and a half Behind and it was really supposed to be online at the very end of the second quarter. And so you take a lot out of the 3rd when you take a month and a half away. Yes.

Speaker 2

For these, these are probably be high volume wells. And so that's the only that's a little setback, but I don't think that In the long run, it just pushes that production out in the future, hopefully, where we get a higher price for it.

Speaker 7

Yes. Could certainly be fortuitous from the standpoint of timing. With my follow-up, I Wanted to, I guess, ask a question about the Western Haynesville Exploration Program. With the understanding that you're still in the early stages of your learning curve, Could you speak to what you've experienced in operational efficiency gains? Again, I understand you're drilling for different targets and that's going to require Different degree of caution and but again, just to help us understand how you guys are tracking progress wise?

Speaker 3

So yes, Derek, this is Dan. I'd say we've made really great strides. Obviously, these aren't easy wells to drill. I think Everybody realizes that we accepted a pretty good challenge here starting with these wells, but we have made really good progress. The vertical part of the hole has got some difficulties associated with the loss circulation zones and It's got a really thick Travis Peak, which is some really hard and abrasive and slow drilling.

Speaker 3

And we've made really good strides there. As far as just shaving off a lot of days, The KZMS and the Lanier, which are the last two wells we drilled are if you kind of look at where they're located, The KZMS, we've shaved off probably 20 days on that well. It's right over near the Circle M, the Campbell In the KZ Black, and we drilled it 20 days less than where we started, just due to the strides in the vertical part of the hole. And then really, I kind of separated into those 2 buckets. The other part is just the lateral and just dealing with the temperatures at these CBD depths.

Speaker 3

And We've made really good strides there. We've shaved off a bunch of days in the lateral. We've gotten better at handling the temperatures. We've just gotten much better at tweaking our bottom hole assemblies and motors that we're running in these high temperatures, Getting better performance, we're getting longer runs and really just those two things coupled together, faster up there in the vertical and that hard Travis Peak section and better motor performance in the temperature and the laterals is what's is where we made our headway. And so like I said, The last well over on kind of that Southwest end of the play where we've got the Circle M, the Casey, the Campbell, the Casey MS and the McCullough, this last well We're 20 days faster.

Speaker 3

So conversely kind of over on the other side in Leon County where we've got the Lanier and the Denkins. The Lanier, we shaved off a bunch of days Compared to the Denkins, so and we're not done. We've got several things, kind of got a runway of some other things that we're going to be doing. We think we're going to Let us save additional days off here in the near future.

Speaker 1

Derek, I'd make a comment that before we Disclosed all of this, we built a pretty big wall around this, hundreds of thousands of acres that we've leased. And again, there's a few we need to pick up, not many. And it's going to be really hard to be competitive with us if we're right Because of all the reasons that Dan gave, it's a play that you You have to spend some money and have a big acreage position and be committed that we think will allow us to Deliver that gas that you're going to need in 20, 20 27, 20 28, 20 29. But I want to assure you are not drifting. You can see the answers that you give and yes, these great questions.

Speaker 1

You can see our commitment and you can see the well performance, but I think you also had to know that we feel like we took great ownership And putting up a big fence around the play as far as the part that we want before we start disclosing everything, Which you should do if you value it.

Speaker 7

That's great guys. Sounds very encouraging.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Jacob Roberts from Tudor, Pickering, Holt and Company. Your question please.

Speaker 8

Good morning.

Speaker 4

Good

Speaker 1

morning. Good morning.

Speaker 8

On the hedging front, we were hoping for the thoughts on the 2024 Market for contracts and what percentage of protection you ultimately think will be appropriate for next year?

Speaker 2

Yes. Jacob, this is Roland. Yes. We've started to put in some 24 positions as we kind of show in our presentation. But we're not really ready to Talk about our strategy, as you can kind of see where we're starting out and then as we see opportunities that kind of meet Our goal is we'll continue to execute on our 2024 hedging program.

Speaker 1

We typically hedge 40%. I still think that's probably a good visual out there. We'll see what happens. Process haven't come our way in a month or so. We did put the swap in at $3.50 gas for $130,000,000 a day.

Speaker 1

And we are very we want to have that revenue stream Almost guaranteed for some type of hedge if we could, particularly as we're de risking the Western Haynesville. So You need to know we've got our eyes on that. We're looking at it and we make decisions daily about it.

Speaker 8

Great. Thank you. My follow-up would be on the divestiture proceeds showing up this quarter. Could you provide Some color on what that was and maybe the opportunity set for those types of transactions in the future?

Speaker 2

Yes. Those are just some non operated interest That we sold and like last year, you saw we so as we see, just have opportunities to sell non operated interest That are not part of our core. We kind of execute on that. But that's a fairly, very immaterial, Small part of the company, so I wouldn't say that there's a lot of potential for that in the future.

Speaker 8

Thanks. Appreciate your time.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Bertrand Dans from Truist. Your question please.

Speaker 9

Good morning.

Speaker 1

Good morning.

Speaker 9

Good morning. The first question on LNG, I think I know the answer to this, but just want to get your thoughts on a few of your peers' LNG strategies. Some of

Speaker 3

them are taking full control of their volumes all

Speaker 9

the way to the destination and some are going through 3rd party traders and another segment want to So I'm just wondering what fits best with Comstock long term and or maybe the decision just comes down to where Jonathan moves gas prices?

Speaker 2

Those are all great strategies. That's something we continue to evaluate. We are already a big supplier To the LNG, and then we think that's going to the share of gas that we produce that goes directly to LNG Shippers is going to continue to increase, especially with the big expansion coming in the next 2 to 3 years. But we're still evaluating where does Com 1b, do we want to get the highest kind of benchmark to Henry Hub price? Do we want to participate In international pricing and we're actively exploring that and in talks To come out with that.

Speaker 2

So, yes, I don't think we have an answer for you yet on which one we think is best. But we can like you see, our competitors are all kind of approaching it in different ways.

Speaker 1

I do think though, if you look at where our footprint is, We're 200 or 300 miles away from where these over this $100,000,000,000 of export shipping facilities are being built. You look at the majority of the new acreage is undedicated. That's a good thing. You look at the relationship that we have with all the We deal with all of them. You look at the fact that we've been in this area probably 35 years, so they know us.

Speaker 1

And then you look at the liquidity we have, you look at the volumes that we have produced and maybe will produce in the future When you look at the demand out there, that's kind of how we started. We think there's about 12 Bs a day of export LNG. This doesn't include Mexico. As you can see, you're going to have another 9 Bs between now and maybe 25, 6, 7. And then that's where that extra 17 or 18 Bs might come from.

Speaker 1

We want to position the company to have great float in the stock, great liquidity, great inventory and these low costs We currently have. So whatever is the best for an upstream company, I think we're going to have We're going to have the ingredient to make it better, whether that's like Roland said, seeing if we can Capture some international prices, long haul gathering. I think we're going to have the flexibility to look at all those things. But I can assure you, we're not going to tie ourselves into some type of a commitment that if prices dip, We get hurt. We're just not going to do that.

Speaker 1

We don't have to do that. So we're going to protect you And the stakeholders and the analysts and we're going to run this thing right.

Speaker 9

I appreciate that answer. And then maybe on the D and C costs, I just you mentioned it in your prepared remarks, it seems like a portion of maybe that 4% Decline quarter over quarter came from longer laterals in the quarter, but could you maybe talk about where The rest of that came from and maybe specifically which items you're seeing some deflation on and which items are holding their ground?

Speaker 3

Yes. I'd say a pretty good piece of it probably was the longer length. I mean, obviously, the longer we get, our cost So we look at that every quarter. We look at what the average that group of wells averaged. And so back there on Slide 13, when you look at that, that's the specific group of wells for the Q2.

Speaker 3

The benchmark wells that we report on, The average length for the Q2 was nearly 12,200 feet. We were only 10,800 feet Plus or minus in the Q1. So that obviously lends itself to cheaper D and C costs. And really, I'd say just the other parts is We're starting to see the deflation, things starting to turn around and come back down since the activities dropped off at the 1st of the year. It's kind of slight really in the Q2, but a lot of the stuff we report on the Q2 were wells drilling at the 1st of the year.

Speaker 3

So Just kind of start to turn the corner and come back the other way, which is why we'll see it continue to come down in the Q3 Q4 when we report on those. Specific items, I'd say, really, we haven't seen a lot of movement on pipe prices, But we have seen the rig rates come down. We've seen the frac crews get cheaper and just which is obviously just straight tied to utilization.

Speaker 4

What will the

Speaker 1

efficiencies of the frac crews you made?

Speaker 3

Yes. So the efficiencies of the frac crews have gotten better, I mean, specific to our crews that we're running. Just we've seen our stage counts per day have increased. We're just really happy with the crews. So just they've gotten faster, just more efficient.

Speaker 3

So even if you're paying the same price, our cost per foot comes down if we can get the wells done faster, which leads us So we just get production on faster. So all of that stuff adds up to a really good answer.

Speaker 1

Yes. The one thing I'll tell you on that question is, We've got the core, which is the 1500 locations and the thousands of acres, hundreds of thousands. And then yet, we focus on A lot of this call is on the Western Angel. It's unusual to have it's almost like 2 different Companies, 2 different sets of assets. You manage both of them right.

Speaker 1

And if you do that and you protect your balance sheet And you can end up with something that you never dreamed you could end up with, particularly with, as you mentioned, LNG demand coming our way. So that's where we are. I think we're in the center of the scope and it's a pretty a really good place to be.

Speaker 9

Thanks, Jeff. That's it for me.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Gregg Brody from Bank of America. Your question please.

Speaker 10

Hey, good morning, guys. Good morning. Just on the sorry to cut off the reciprocation. Just on the Westray Haynesville, Just as you think about the capital required to keep going there and expand, can you talk a little bit about how you're thinking about Potentially raising capital for that to expand into next year?

Speaker 2

Greg, this is Roland. I think the area that addition to the drilling costs, which you've kind of outlined, wanting to Go from basically go to 3 rigs next year that kind of keeps us on track to holding all our acreage. In addition to that capital, there'll be a need for building out our midstream assets both treating and gathering, Not really so much for next year because we've made those investments and upgraded our Pinnacle plant to handle next year's volumes. As we look ahead, there are longer there are big larger investments to make. So there, I think we're looking we're exploring You know, kind of creating a midstream kind of separate entity that will kind of handle Those capital needs in the future as we build that out and which also allow us to control the midstream in Processing versus relying on a 3rd party company.

Speaker 2

And so you see a lot of the wells been drilled in the Western Haynesville from here forward It will be in our system, only one is in it right now. So it's just barely starting. But We see a lot of value in maximizing the value of the gas price we get, but also maximizing The ability to control the timing is to maintain control. So we might seek partners to Partner with us in building out that infrastructure over the next 5 years.

Speaker 10

So you've said building out over the next 5 years, do you think you'll Seek out a partner over the near term, is there a timeline that's how you're thinking about that?

Speaker 2

There's not a near time, basically the capital Needed for next year, yes, we kind of spent that. We just need to make some we made some minor Upgrades to what we bought last year in the legacy acquisition that was just a great purchase for us, which gives us the running room to grow our volumes To handle next year, but as you look ahead, the items beyond that have a lot longer lead time, longer construction time. So we're planning for that. We see those expenditures coming out in the future, but we're planning to want to create a structure for that is that midstream cost Does it burden our drilling and completion budget and that could be more like it's been in the past?

Speaker 1

Yes. I think again, the answer is we're going to do what it tells us to do. When we bought some acreage in The Pinnacle line and the high pressure, 145 mile high pressure line back in Q2 'twenty two, we spent some money to refurbish and upgrade We have takeaway capacity within this 90% of the acreage plus that we own to Produce said gas in 2023, 2024 and Midway to 2025. So as we derisk this stuff over the next months and quarters years, Then we'll see what the need is to have a midstream, and it'll tell us what we need to do. We We're not going to ask permission to sell our gas to anybody though.

Speaker 1

We want to control our midstream. So when we drill these wells, we want to take them to sales. We want to have a home For the long haul, there is a home. Now the question is, how do you get it there? And we've got plenty of takeaway between 2023, 20 24, mid-twenty 25.

Speaker 10

Got it. And then just on the cost per well, how do you see that progressing? Obviously, we have some service cost deflation, but Do you think we could see some material improvements next year? Or do we need to get to a more of a development mode for that to happen?

Speaker 3

This is Dan. We'll definitely when you get in development mode, you'll continue to see obviously efficiency gains and improvements, Lower calls. We did obviously, probably when we cranked up, got started in the place when we had all the inflation kicking in just Basically, right as we started on the first well, but we have made great strides, like I mentioned before, in just a number of days to get the wells drilled. So that's dropping the cost and we do see the cost coming down into next year based on some other things that we've kind of got coming down the pipe. Anytime you run more rigs and you start drilling more wells and you just get more practice at doing anything, you get a little better at it And we will get more efficient just in that regard.

Speaker 10

That's very helpful. And then just for the pesky credit analyst That stares at the accounting on some things. Just could you I know the working capital is a tough one To figure out, especially from our perspective, I was wondering if you had any insight on how to think about, how that's going to trend the rest of the year? And then also just I noticed an asset sale about $41,000,000 I was curious what you sold and if that's in your if that's in the updated guidance?

Speaker 2

Sure, Greg. Working capital, I think the best way to trend it since our activity level, Yes, there is a as it reduced down from the level last year, but now it's fairly stable With the 7 rigs, so then that means you're kind of that part of the working capital, the payables probably stays consistent. The other item driving working capital obviously is the prices, right? And so we had the very, very low prices. That's as those receivables get collected, Yes.

Speaker 2

You see a big contribution from working capital this quarter, but then as gas prices improve, as we go forward in the year, you shouldn't You won't see more of that. You'll see the opposite. You'll have, so it's really I think you can if you're really thinking about it, just think about I think if If our spending levels stay in fairly constant, the real change in working capital is just going to be driven by gas prices. So the higher gas prices go, the more There'll be a we'll be giving back some of that working capital and the lower if they go lower, obviously, you get some. So that's basically how I think you can see it Yes, play out the rest of the year.

Speaker 2

This year, obviously, the Q2, the big contribution came because prices hit rock bottom.

Speaker 10

Is there a ballpark number in terms of how much of reverse? Is $100,000,000 a good guess? Or is it closer to the 180

Speaker 2

Yes, I think it well, it all depends on how you have to tell me what the gas prices in the future and I could give you a number. So If it modestly improves, then it's going to modestly do that. If gas prices dramatically improve to where they were last year, obviously, then it's a big number. And so I don't think it's unless it gets as big as it was last year, that's what you're seeing is all that flushed through In the numbers. On the proceeds from sales, last year, this year we any opportunity to sell non operated, non strategic properties if They can meet the return criteria.

Speaker 2

We always look to do that. Like we answered before, Yes. The whole non operated part of our production and reserves is very small. So there's not A lot of material future stuff to do, but we're always open to doing that.

Speaker 10

And that's sales in your guidance then?

Speaker 2

Yes. I think and plus we've seen 2 things in our Guidance not only did we choose to sell off some non operated production, but we also see a huge reduction in non operated Activity because of the Haynesville, you noticed the rig counts were down. A lot of the other operators have Pullback activity, especially the private ones. So we just compared to last year, just a lot lower non operated activity going forward. And I think that again will probably track how strong gas prices are to when that would come back.

Speaker 2

It's not a big part of our numbers anyway. So you're really talking about a couple of percent here or there.

Speaker 10

That's what it looks like. I appreciate the time and the insight guys. I'll pass the mic back.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Your question please.

Speaker 4

Hi, good morning.

Speaker 1

Good morning. Good morning.

Speaker 4

Just a couple of things. Thinking about a couple of timing related issues, and I apologize if you touched on these already, But we sort of have these couple of one time corrections or changes or transitions ahead. So we've had this interest rate environment, now the highest it's been a long time and presumably at some point that reverses. And so just thoughts on how cost of capital might be fitting into your scenarios about development pace. And then also, we're kind of in this level now where the new LNG capacity near term Has been limited, but it's going to ramp up sharply in a step function over the next few years.

Speaker 4

And so I just wondered if the fact that we know that that's ahead, does it give you any thoughts On what sort of contract durations you might be looking at, if you're trying to either do 3rd party or direct sale or other types of LNG arrangements or Thinking about maybe like a Mode A for the transition years and then thinking ahead to maybe something longer term or You might try to do?

Speaker 2

Yes. Those are good. The first question you had, the rising cost of capital and Interest rates, I mean, I think that's where we're so thankful that we locked in a lot of our interest rates last year. And don't really see having to go back into the debt markets to In any significant way to have to bear those higher interest costs. So that's A good issue for us.

Speaker 2

And then if you look ahead to the pull from the LNG demand, obviously that's a big part of Our long term thinking and while we want to control our midstream and create a lot of abilities to connect To increase our sales to the LNG shippers and talks with them. I think if you look at contact duration, I think we can point to our most recent deal that we're about to finish up as a new 3 year supply contract with 1 of the large LNG shippers. We were early on, we did a 10 year. So we're not afraid of the longer term durations As long as they're happy to commit to buy it and we found them to be great customers, always taking exactly what they ask for. So we see them as being a growing part of our market.

Speaker 2

And so I think it would really We'll be happy to sign longer term contracts if they are, the buyer. We obviously have the ability to get the gas to them And to guarantee them a gas supply for as long as they want to contract for it.

Speaker 4

Great. Thanks. And one question, with this consolidation we've had in the Haynesville And you are of course early to that was Covey Park, and then have a lot of other deals Following the years after, I'm just curious, you've done a lot with pushing So what the limits of the technology are at in what still can be achieved and can be gotten out of the rock. I'm just wondering, Are any of the other entrants are you aware of any of them struggling to make technical progress And wondering whether that sets up the possibility for maybe some of them looking to exit or maybe trim their positions On the idea that maybe it was a little harder to work the Haynesville than they might have thought from the outside?

Speaker 2

I don't think so. I mean, we've seen Our other peers in the Haynesville do really well. I mean, I think we're probably pushing the leading edge for the Western Haynesville And maybe one of them is there with us. But I think generally, I mean, I don't think we see that observation.

Speaker 1

Yes. Noah, I'll tell you, we're the biggest cheerleader for all of them. I mean, we want whether you're an oil company and a farm in or you're a gas company In Appalachia, you're a NASDAQ Gas Company in the Haynesville budget. Look, we got to cheer for each other. So we hope everybody does really good We think they will do good.

Speaker 4

Great. Thanks a lot.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Paul Diamond from Citi. Your question please.

Speaker 11

Hi, good morning. Thanks for taking my call. Just a quick one. You talked a bit about the kind of your development cadence in Western Haynesville. Just want to see if there was any in your ideal Over the next several years, any idea on how the breakdown sits between targeting Haynesville versus the brochure?

Speaker 3

Yes. So this is Dan. We it's a good question. We I stated earlier, I don't know if you really heard me, but we stated earlier, obviously, our target really is to drill the Haynesville Where we can, it's being a little bit deeper and being that this is a kind of a high temperature play. We Look at that really closely just to make sure we're comfortable with the target that we're going to chase on any particular well, which is While we targeted the Bossier initially, when we put our first rig out here, we drilled our first four wells to the Bossier, kind of We've got kind of everything settled down a little bit.

Speaker 3

We made some progress dealing with the temperatures and then we obviously with our 5th well, we targeted the Haynesville. Didn't have any problems getting that drilled. We the next two wells, we've targeted Bossier wells. Those are the 2 wells that we're completing now. And then after that, we're going to we got several wells in a row where we're going to be drilling Haynesville.

Speaker 3

So if you just kind of look So if you just take a long term view out through the end of 'twenty five, right now, we're about fifty-fifty on what we're targeting, Bossier versus Haynesville. But I will say that, that was a smaller percentage of Haynesville several months ago. So I think as we continue to make progress and get better at dealing with these temperatures and get our days down on the wells, I think we'll see some of these Wells that are on our list as Bossier's today will probably become Haynesville targets in the future. But today, just a snapshot today looking out for the next two and a half years or the other 25, we're about half and half.

Speaker 11

Understood. Thanks for the clarity. And just one quick follow-up. How do you guys think about the potential or the timing and potential for return of activity Given the current resiliency, kind of strength in the 2024 and beyond curve.

Speaker 2

Well, I think everybody is waiting to see what really materializes. I think there's a in the gas market, we're really Yes, I'm still focused on the inventory levels and getting at weather is a huge factor. The summer and next in upcoming winter Will be a huge factor in determining what prices really do. And I think the basin is on hold waiting to kind of see Yes. What happens I think over the next as this year plays out, because that will set the stage for next year along with Yes, the demand pull, how quickly do those projects start to pull the demand?

Speaker 2

Are they early or are they late? There's a lot of factors To really drive the return of activity, I think most operators are just wait and see right now.

Speaker 1

And we go overall and we asked Ron to do this. What would it could have showed or what if Freeport had not gone offline For all those months, I mean, we do this every Thursday. In our gas storage right now, in the 5 year average, we got a Surplus of 13% above the normal 5 year average. But at Freeport, if that 2 Bs hadn't been injected into storage, but it had been exported. If you look at the number where we would be today on the 5 year average, we'd have a deficit of about 8.8%.

Speaker 1

So I still think the gas part is a little bit misunderstood because I think we're doing the right thing. But all of a sudden, you take 2 Bs a day that's It's portable and it's not being injected into storage, it changes things. So they have a 2 fifty-sixty gas price right now is pretty remarkable.

Speaker 11

Understood. Thanks for the clarity and your time.

Operator

Thank you. One moment for our next question. Our next question comes from the line of Phillips Johnston from Capital One Securities. Your question please.

Speaker 12

Hey, guys. Thanks. Just one question for me in the interest of time, I guess, but it's a follow-up on Charles' question on the productivity of the Western Haynesville Wells. And Jay, I hope this isn't pushing too far, but if I'm not mistaken, Netherland sold both Circle N well at roughly 3.5 Bcf per 1,000 foot, which obviously is much higher than your legacy Haynesville wells. Would you say Then all 5 of the wells that you've now brought online and a player tracking to a similar EUR or do you think there's a fair amount of variability?

Speaker 1

No, I would think it's a really good question, number 1. I think it's a fair question. I think that if you have produced well for 8 months And Netherland is exemplary reservoir engineers and they come in with a 3.5b. So I think that's a good starting point. But as we said, we're in the early innings.

Speaker 1

I think we need to get the rest of these wells producing And see what that real EUR is per 1,000. But the starting point is we were very pleased with the starting point. We've got as you know, you should go back, you say, well, are they competitive and economic? And that's where you go to Dan and the group and say, well, This is a big boy game. So can you really get these costs down and keep the EUR for the or toggle in one way or the other And deliver a brand new region that is competitive with the best of your Texas, Louisiana, HaynesvilleBossier.

Speaker 1

And that's where you have to have a big footprint, you have to have commitment and you have to have an A plus operations completion group This committed and dedicated to doing this for years after years after years within a budget that protects Both the bondholders, the equity owners, the banks, everybody, including the largest stockholder, We're trying to thread that needle. I think we've done it.

Speaker 12

Okay, great. Thanks, Jay. Sounds good.

Speaker 1

Sir, thank you. That's a good question. I appreciate your question.

Operator

Thank you. One moment for our next question. And our next question comes from the line of Leo Mariani from ROTH MKM. Your question please.

Speaker 13

Hey guys, wanted to follow-up a little bit on activity levels here. So it sounds like you're going Back to 7 rigs, kind of the end of this month here and kind of run that through the end of the year. Just looking at 2024, I mean, Obviously, no one knows how it turns out exactly at this point, but strip prices have been pretty constant around $3.50 plus or minus a small amount In 2024, at this point in time, so as you guys look to next year, does 7 rigs kind of feel like a pretty reasonable place to kind of start the year and you think you can grow production with 7 rigs, given that you guys were running more obviously early this year.

Speaker 1

Well, I think your comment, the strip for $24 is to $3.50 and the strip for $25 is Just shy of $4,000,000 So those are really good prices for our cost structure. And I think that what we've not done is Contracted a bunch of rigs on long term commitment. So if we need to add a rig or get rid of a rig or 2, we can do that. Our goal is Keep 2024 pretty confident at 7. We would have probably 4 in the core and 3 in the Western Haynesville.

Speaker 1

But all that is subjective and we'll figure out in the Q4 if we want to change any of that.

Speaker 13

Okay. And do you guys think that's a level of activity that kind of lends itself to some kind of modest growth in production with that kind of 7 rigs?

Speaker 1

I think right now, again, you got to take out a little bit of the lumpiness that we've had in the performance, Which is shutting in some of the Western Angel wells while you complete the others. You've got to model that lumpiness and then of course And you always have to model in, do you have other shut ins because of rig activity in your core and you got a little weather delay. So no, I think overall, I think that's Right now, that's the uptime we have.

Speaker 2

Yes. As we get more production from the longer laterals in the Western Haynesville wells with the We think a lower decline profile than our core Haynesville, that will hopefully reduce the need for Yes, more rigs in order to maintain production and grow modestly. And so we'll As we get into the 4th quarter, it's usually when we kind of set the budget, usually November, December for next year. There are a lot of things we'll weigh in on that. We'll also be just seeing kind of where we see that coming out and do we but 7 is aggressive.

Speaker 2

That's how we would kind of be looking at it now as we're Looking ahead and we'd adjust that based on a lot of factors including just the gas price environment of 350 is still there or has it changed and how we see the well performance maintaining that production.

Speaker 1

Okay. That's helpful for sure.

Speaker 13

And then just wanted to also ask a little bit on the Western Haynesville here. If I heard you right, I think you guys were saying that there's still fairly limited competition for acreage over there, but maybe I didn't hear that correctly. So maybe just If you can speak a little bit to kind of leasing competition and then just maybe talk about others that are sort of drilling In and around there. And then just wanted to ask about kind of what the plan is to prove up the position. I think you've got 5 wells in at this point in time.

Speaker 13

Do you think that I'll just make something up and you guys can correct me if I'm wrong, but is it Sort of by kind of mid next year, do you feel like you've kind of tested most of the acreage where you'd be least drilled the 4 corners and kind of the middle parts of this thing where You'll have a really good look at it. Just kind of any timeline you can kind of provide to sort of proving it up. I mean, it seems like you guys are 5 for 5 on the wells with No issues at this point in time. So maybe just talk about your timeline to kind of get all this position proved up.

Speaker 1

Well, in our crystal ball, We would again, 90% plus of the acreage is leased. We wouldn't be happy, but if we couldn't lease another acre, it wouldn't be the end of the world for us. I mean, we leased 100 of 1000 of acres, okay. So you don't want to get greedy, but we'd like to go ahead and get this Remaining dribble that we have out there, I think it'd be a win for everybody. So by the end of 2023, we should have this Reportable.

Speaker 1

When you ask a question, we can answer it with a little far more answer. And then I think as far as the drilling program, our goal Yes. To de risk this whole acreage by maybe end of 'twenty four or early 'twenty five as you extend these wells from Footprints and footprint whether we're doing north, south, east and west geologically so that and then some of these wells in 2024, You'll drill 2 wells per pad site. So we've got just this abundance of acreage, so we can do that. I think we'll call for the store coming down there and some of them will be both will, some will be Haynesville will.

Speaker 1

So the further we get down the road, I think the more clarity we can give you, the more comfort or discomfort, whatever you choose to have, we can give you. But that's you have to trust what we're doing right now.

Speaker 13

Okay. That's helpful color. And then just Lastly, in terms of some of the early wells in play, you're obviously starting to build up some pretty good production history. Are you seeing those wells holding there pretty flat with fairly limited pressure draw downs on some

Speaker 1

of those first couple of wells? You know what, we We've demonstrated we keep drilling these wells. So obviously, we're not totally displeased with what And we're going to continue to drill the wells. So that's about all the comment we can make right now.

Speaker 13

Okay. Thanks.

Operator

Thank you. This does conclude the question and answer session of today's program. I'd like to hand the program back to Jay Olson for any further remarks.

Speaker 1

Okay, Jonathan. Again, I mean, in conclusion, Kind of a broad view, but America and the world, they need success in adding natural gas reserves and inventory, which We are attempting to deliver. Management, which you talked to some of us today, there's 244 people that are here at the Comstock umbrella, all of the employees, management, our Board and our major stockholder, We really do want to thank all of you for your encouragement and support as we report early results. We want to thank you for your time that you've given us this morning. So thank you.

Operator

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.

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Earnings Conference Call
Comstock Resources Q2 2023
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