Q2 2023 Comstock Resources Inc Earnings Call
Participants
Daniel S. Harrison; COO; Comstock Resources, Inc.
Miles Jay Allison; Chairman of the Board of Directors & CEO; Comstock Resources, Inc.
Roland O. Burns; President, CFO, Secretary & Director; Comstock Resources, Inc.
Ronald Eugene Mills; VP of Finance & IR; Comstock Resources, Inc.
Bertrand William Donnes; Associate; Truist Securities, Inc., Research Division
Charles Arthur Meade; Analyst; Johnson Rice & Company, L.L.C., Research Division
Derrick Lee Whitfield; MD of E&P & Senior Analyst; Stifel, Nicolaus & Company, Incorporated, Research Division
Gregg William Brody; MD; BofA Securities, Research Division
Jacob Phillip Roberts; Associate of Exploration and Production Research; Tudor, Pickering, Holt & Co. Securities, LLC, Research Division
John Phillips Little Johnston; Analyst; Capital One Securities, Inc., Research Division
Leo Paul Mariani; MD; ROTH MKM Partners, LLC, Research Division
Noel Augustus Parks; MD of CleanTech and E&P; Tuohy Brothers Investment Research, Inc.
Paul Michael Diamond; Research Analyst; Citigroup Inc., Research Division
Presentation
Operator
Thanks for standing by, and welcome to the Comstock Resources Second Quarter 2023 Earnings Conference Call. (Operator Instructions) As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Mr. Jay Allison, Chairman and CEO. Please go ahead, sir.
Miles Jay Allison
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. You can view the slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There, you'll find a presentation entitled Second Quarter 2023 Results.
I am Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations.
I'll flip over to Slide 2. Please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. I want to take the time to thank each of you that's listening today on this call and those who will listen later on.
As we all know, this year continues to be challenging as we've had weak natural gas prices coupled with the 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 to date to 21 Bcf by 2027 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 5 wells, which Dan Harrison will talk to you about later as we continue to move up the learning curve 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 Haynesville 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. At the same time, we have 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 and were 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 second quarter. The financial results were heavily impacted by the very low natural gas prices that we realized in the quarter. Oil and gas sales, including hedging were $285 million in the quarter. We generated cash flow from operations of $145 million or $0.53 per share, and adjusted EBITDAX was $182 million. With positive working capital contributions, we only had to borrow of $20 million to cover the overspend in the quarter. Our adjusted net income was just over breakeven for the quarter. We drilled 21 or 17.2 net successful 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 million cubic feet equivalent per day. We're having great success in our Western Haynesville exploratory play in the early innings. Our fourth and fifth wells were recently turned to sales with strong production rates, including our first well in the Haynesville shale. The first 4 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 by keeping competitors away.
I'll now turn it over to Roland to discuss the financial results. Roland?
Roland O. Burns
Yes. Thanks, Jay. On Slide 4, we cover our second quarter financial results. Our production in the second quarter was 1.4 Bcfe per day, which was 2% higher as compared to the second quarter of 2022. Low natural gas prices significantly impacted our oil and gas sales in the quarter of $285 million, which were 53% lower than 2022's second quarter. EBITDAX was $182 million, and we generated $145 million of cash flow during the quarter. We reported adjusted net income of $1 million for the second quarter, as Jay said, just above the breakeven level as compared to $274 million in the second quarter of 2022.
On Slide 5, we have the financial results for the first half of this year. Our production in the first half of 2023 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 2023 totaled $676 million, which were 1/3 lower than the first half of 2022. EBITDAX was $476 million, and we generated $400 million of cash flow during the first 6 months. We reported adjusted net income of $93 million for the first 6 months of 2023 as compared to $409 million in the first 6 months of 2022.
On Slide 6, we show our natural gas price realizations in the quarter. During the second quarter, 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 second quarter averaged $1.81, reflecting a $0.29 differential to both the settlement price and our reference price. This differential returned to more normal levels 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 second quarter, we were 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 million 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 in our EBITDAX margin. Our operating cost per Mcfe averaged $0.84 in the second quarter, $0.01 higher than the first quarter rate. The increased unit costs are related to the start-up phase in our Western Haynesville area, which we'll see improve as we connect more of sales through our own gathering and treating facilities in the future. 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 first quarter level.
Our G&A costs came in at $0.06 per Mcfe, which is down $0.02 from the first quarter rate. Our EBITDAX margin after hedging came in at 63% 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. For the first 6 months, we spent a total of $647 million in development activities, including $590 million on our operated 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 million. In the first 6 months of 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 million cubic feet per day.
Slide 9 recaps our balance sheet at the end of the second quarter. We ended the quarter with only $20 million of borrowings outstanding under our credit facility, giving us $2.2 billion in total debt. We ended the second quarter with financial liquidity of almost $1.5 billion.
I'll now turn it over to Dan to discuss the operating results.
Daniel S. Harrison
Okay. Thanks, Roland. Slide 10 is a breakdown of the current drilling inventory now that we have at the end of the second quarter. 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, sort of between 5,000 and 8,000 feet or long laterals at 8,000 to 11,000 feet and our extra-long laterals past 11,000 feet. Our total operated inventory now stands at 1,782 gross locations and 1,359 net locations. This equates to a 76% average working interest across the operated inventory. The non-operated inventory stands at 1,278 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 out into the 10,000 to 15,000 foot range.
Breaking down the gross operated inventory, we have 313 short laterals, 291 medium link laterals, 719 long laterals and 459 extra long laterals. 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 extralong lateral bucket, which is greater than 11,000 feet and full 2/3 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 first quarter. Our inventory provides us with 25 years of future drilling locations based on existing activity.
On Slide 11, there's a chart that outlines our progress to date on our average lateral rates drilled based on the wells that we have turned to sales. During the second quarter, 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 stays at 15,726 feet.
During the second quarter, 8 of the 17 wells we turned to sales had laterals exceeding 11,000 feet, including 4 of the head laterals out passed 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. During the second quarter, we also had 2 additional wells that turned to sales in our new Western Haynesville acreage. The Dinkins #1 well was completed in the lower section of the mid-Bossier, while the McCullough Ingram #1 is our first well completed in the Haynesville. These wells are our fourth and fifth in 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 extend beyond 11,000 feet and 13 of the wells will be over 14,000foot long. 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 turned to sales and tested 15 new wells since the time of our last call. The individual IP rates range from 16 million a day up to 35 million cubic feet a day with an average test rate of 21 million 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. Included this quarter are the fourth and fifth new vintage wells on the Western Haynesville acreage. The Dinkins #1 was completed in the lower section of the mid-Bossier. It had a 9,565foot long lateral and we turn the well to sales in May. We tested the well with an IP rate of 34 million cubic feet a day.
The McCullough Ingram #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. The IP rate achieved to-date is 35 million cubic feet a day, but we are still cleaning this well up and -- as we are expected to achieve a higher IP rate in the very near future.
Beyond these last 2 wells that we turned to sales, we are currently in the process of completing our sixth and seventh 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 one rig on our Western Haynesville acreage, but that will soon increase back to 2 rigs later this month.
Slide 13 summarizes our D&C costs through the second quarter for our benchmark long lateral wells that are on our legacy core East Texas and North Louisiana acreage position. This covers all wells having laterals greater than 8,000 feet. During the quarter, we turned 15 wells to sales on our core East Texas and North Louisiana acreage and 13 of the 15 wells were our Bismarck long lateral wells.
In the second quarter, our D&C cost averaged $1,523 per foot, which is a 4% decrease compared to the first quarter and still a 15% increase compared to our full year '22 D&C cost. Our second quarter drilling cost came in at $653 a foot, which is a 2% decrease compared to the first quarter.
A portion of the drilling cost decrease is attributable to a longer average lateral rate we had this quarter versus the first quarter. Our second quarter completion cost came in at $870 a foot, which is a 5% decrease compared to the first quarter. We have seen our service costs begin to decrease during the second quarter following the drop in activity levels since the first of the year. We expect these service costs will continue to decline throughout the third and fourth quarter.
At the end of June, we dropped a rig from the fleet, which has us currently run in 6 rigs. However, later this month, we will be taking delivery of the new rig, which will take us back to 7 rigs, which is the level we will be planning 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.
Miles Jay Allison
Okay. Thank you, Dan. If you'll turn to Slide 14, I'll direct you to Slide 14 where we summarize our outlook to 2023. We look back on this year in the future I will view it as a year where we built a foundation that will drive our future growth. Our business plan for this year is focused on positioning Comstock 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.
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 active in the Western Haynesville, as Dan mentioned, and we have leased approximately 90% of our targeted acreage. So 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 and 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.
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 $1.5 billion at the end of the second quarter.
I'll now have Ron provide some specific guidance for the rest of the year. Ron?
Ronald Eugene Mills
Thanks, Jay. On Slide 15, we provide the financial guidance for 2023. The third quarter D&C CapEx is expected to range between $240 million to $280 million and our full year D&C CapEx guidance remains unchanged at the $950 million to $1.15 billion range. While we're seeing signs of deflationary pressures on service costs, we believe most of those improvements will be seen in 2024. In terms of infrastructure and other spending, we continue to budget $15 million to $30 million during the third quarter and $75 million to $100 million -- to $125 million for the full year.
In addition to what we spend on our drilling program noted above, we now anticipate spending $70 million to $85 million this year for leasing activity. 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 ad valorem taxes are expected to remain in the $0.12 to $0.16 per Mcfe range, while our DD&A rate is expected to remain in the $1.05 to $1.15 per Mcfe. Cash G&A is still expected to run around $7 million to $9 million in the third quarter and a total of $32 million to $36 million for the full year, while the non-cash G&A represents roughly $2 million per quarter of that number.
Due to the increase in [SOFR] rates, the cash interest expense is now expected to total $40 million to $42 million for the third quarter and $160 million to $165 million for the year. Tax rate remains in the 22% to 25% range, and we still expect to defer between 95% and 100% of our reported taxes this year.
I'll now turn the call back over to Jonathan to answer questions.
Question and Answer Session
Operator
And our first question comes from the line of Charles Meade from Johnson Rice.
Charles Arthur Meade
Jay, I want to see if there's more detail you can offer on your Western Haynesville wells and not just these 2 most recent ones, but in general, 35 million a day, congratulations on that. That's a great stock rate, but there's more defined well than just where it comes on, right? I mean, some of the best wells on the Louisiana side, I think we're delivering IPs of 40 million or even 50 million a day. So what are the other data points, 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 million to 40 million IPs versus the best stuff we're seeing on the Louisiana side?
Miles Jay Allison
So Charles, I'll probably turn it over to Dan. I don't know how deep in the weeds you want to get. I think I'd sure 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-percent through leasing our acreage position, 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 we know the mineral owners, and 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 will just comment on the wells that we have drilled. Remember that this play is unlike the play in Louisiana, which you're referencing that we've read about. But 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 for the inferior wells, they're not the Haynesville wells, they are the Bossier wells. 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 to the depth that we've drilled them out with the lateral length that we drilled them at with the heat that we've encountered as effectively as we have. And that includes Circle M, which is a Bossier, the Cazey Black is a Bossier, the Campbell, which has proved that we could drill extended laterals at the 12,700 feet as a Bossier.
And then Charles, you get to the Dinkins, which is a lower Bossier. So we're -- now we're delineating up for lower. Same thing with the Haynesville, McCullough Ingram, which is a Haynesville, which Dan had commented on McCullough Ingram. At the same time, we have completed that Cazey MS, and we have fracked it, and we've got a stick pipe drilling at the fracs. And then we've got the Lanier that we're completing right now. 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 wrap this 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?
Daniel S. Harrison
Yes, Charles. So one of the things I want to just add to what Jay said is we are being very conservative in how we're drilling the wells down. Obviously, there are a lot deeper TVDs here, got a lot better bottom hole pressure. The productivity is really good. 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, is slowing 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. And looking forward in the drilling into display, the Haynesville is going to always be our primary target. We -- when we first started in the play, we knew it was going to be tougher 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 and getting started. So we've made great progress technically, drilling the wells, 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.
Charles Arthur Meade
I think that is great, go ahead.
Miles Jay Allison
I want to go again. We circled a wagon at this remaining 10% that we're trying to lease it, if for some reason, we don't get it. We've circled the wagon 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, we can actually see all these footprint. Again, with Western Haynesville, we did buy that infrastructure when we bought the legacy, the Pinnacle plant, et cetera.
So all of those things give us a tremendous competitive advantage. Even if we were to stop leasing today or stop buying 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 that we'll complete this journey by the end of this year. And we'll have more disclosure on these well results. So a lot of great question and we try to answer it as clear as we could with the set of facts we have, okay?
Charles Arthur Meade
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 lease. And it was a great data point that I hadn't heard from you before, I don't believe that you're 90% done. 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?
Miles Jay Allison
Well, I think when you look 3 years ago, 2 years ago, 1 year ago, you come up with a budget. And as you get 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, 5,000, 6,000, 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 10,000, 11,000 foot laterals and not kind of spotty yet there with this whole program, if you're seeing -- that's why we gave a whole slide on the lateral lengths, the 5,000, 8,000, 10,000, 15,000 foot laterals.
We're trying to grow 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 million dollars to clean up some spots in the middle that we didn't know would be available to lease. It's not that we 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 it all, at all. So it's just a clean up like a mop cleaning things up.
Charles Arthur Meade
I appreciate the visuals, Jay.
Operator
And our next question comes from the line of Derrick Whitfield from Stifel.
Derrick Lee Whitfield
On my first question, I wanted to focus on the trajectory of your 2023 guidance. 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 exit rate for the year could meaningfully exceed 1.5 Bcf given the timing of your turn in lines?
Ronald Eugene Mills
Derrick, 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 Bcf or close to 1.5 Bcf for the quarter, if you try to back into that number. There can -- there's a chance that 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 third quarter, 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 fourth quarter is where it should be.
Miles Jay Allison
Yes, Derrick, I think more or less the same that year unfold like we planned. I think there's been a slower kind of hookups, especially we have one area that's 1.5 months 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 third when you take 1.5 months away for 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, just pushes that that production out in the future, hopefully, where we get a higher price for it.
Derrick Lee Whitfield
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 a different degree of caution. But again, just to help us understand how you guys are tracking progress wise?
Daniel S. Harrison
So yes, Derrick, 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 lost circulation zones and -- it's got a really thick Travis Peak, which is some really hard and abrasive and slow drilling. And we've made really good strides there as far as just shaving off a lot of days. The Cazey MS and the Lanier, which are the last 2 wells we drilled are if you kind of look at where they're located, the Cazey MS, we've shaved off probably 20 days on that well. It's right over near the Circle M, the Campbell and the Cazey 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 TVD depths 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 2 things coupled together faster up there in the vertical and that hard try to speak section and better motor performance in the temperature and the laterals is what's -- 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 circling on the Cazey, the Campbell, the Cazey MS and the McCullough, this last well we're 20 days faster. So conversely, kind of over on the other side, in Lyon County, where we've got the Lanier and the Dinkins, the Lanier, we shaved off a bunch of days compared to the Dinkins. 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.
Miles Jay Allison
Derrick, I'd make a comment that before we disclose 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 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 2027, '28, '29. But I want to assure you are not drifting. You can see the answers that you gave when you ask these great questions. So 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.
Operator
And our next question comes from the line of Jacob Roberts from Tudor, Pickering, Holt & Co.
Jacob Phillip Roberts
On the hedging front, we were hoping further thoughts on the 2024 market for contracts and what percentage of protection you ultimately think will be appropriate for next year?
Roland O. Burns
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 yet, which you can kind of see where we're starting out. And then as we see opportunities that kind of meet our goals, we'll continue to execute on our 24 hedging program.
Miles Jay Allison
We typically hedge 40%. I still think that's probably a good visual out there. We'll see what happens. Process hasn't come our way in a month or so. We did put the swap in at $3.50 gas for 130 million a day. And we are very -- we want to have the revenue stream almost guaranteed for some type of hedge if we could, particularly as we're de-risking to 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.
Jacob Phillip Roberts
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?
Roland O. Burns
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.
Operator
And our next question comes from the line of Bertrand Donnes from Truist.
Bertrand William Donnes
The first question on LNG. I think I know the answer to this, but I just wanted to get your thoughts on a few of your peers' LNG strategies. Some of them are taking full control of their volumes all the way to the destination and some are going through third-party traders and another segment want to just retain a Henry Hub premium agreement. So just wondering what fits at with Comstock long term and -- or maybe the decision just comes down to where Jonathan moves gas prices?
Miles Jay Allison
Those are all great strategies. And 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. We're still evaluating where does Comstock want to be? 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 then talks to come out with that. So I don't think we have an answer for you yet on which one we think is best. But like you see our competitors, all kind of approaching it in different ways.
Daniel S. Harrison
I do think, though, if you look at where our footprint is, we're 200 or 300 miles away from what these -- this $100 million of export shipping facilities are being built. You look at the majority of the new acreage is undedicated, that's a good thing. If you look at the relationships that we have with all the exporters, 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. 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. But you can see, you're going to have another 9 Bs between now and maybe '25, 26, '27 and then that's for that extra 17 or 18 Bs may come from. We want to position the company to have great flow in the stock, great liquidity, great inventory and these low costs that we currently have. So whatever is the best for an upstream company, I think we're going to have the ingredient to make it better, whether that's like Ronald said, seeing if we could 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 tire ourself into some type of a commitment that if prices dip, we get hurt. We're just not going to do that. 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.
Bertrand William Donnes
I appreciate that answer. And then maybe on the D&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 you're holding the ground?
Roland O. Burns
Yes, I'd say a pretty good piece of it probably was the longer length. I mean, obviously, the longer we get our cost per foot comes down. 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 second quarter, the benchmark wells that we report on, the average length for the second quarter was nearly 12,200 feet. We were only 10,800 feet plus or minus in the first quarter.
So that, obviously, lends itself to cheaper D&C cost. 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 first of the year. It's kind of slight really in the second quarter, but a lot of the stuff we report on the second quarter wells drilling at the first of the year. So just start to turn the corner and come back the other way, which is why we'll see it continue to come down in the third quarter and fourth quarter when we report on those. Specific items, I'd say, really, we haven't seen a lot of movement on high prices, but we have seen the rig rates come down. We've seen the frac crews get cheaper, which is obviously just straight tied to utilization.
Bertrand William Donnes
Efficiencies for frac crew, you make?
Roland O. Burns
Yes. So the efficiency 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 they've gotten faster, just more efficient. 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 to get production on faster. So all that stuff adds up to a really good answer.
Miles Jay Allison
The one thing I'd add on that question is, we've got the core, which is a 1,500 locations and the thousands of acres, hundreds of thousands. And then yet we focus on a lot of this call is on the Western Haynesville. It's almost like 2 different companies, 2 different sets of assets, you manage both of them right. 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 that scope. It's a really good place to be.
Operator
And our next question comes from the line of Gregg Brody from Bank of America.
Gregg William Brody
Sorry to cut off the reciprocation. Just on the West for 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?
Roland O. Burns
Gregg, this is Roland. I think the area in addition to the drilling cost, which you've kind of outlined, wanting to go from basically go to 3 rigs next year that keeps us on track holding all our acreage. In addition to that capital, there will 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. But as we look ahead, there are longer -- there will be larger investments to make. So there -- I think we're looking -- we're exploring 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, which also allow us to control the midstream and processing versus relying on a third-party company.
And so you see a lot of the wells being drilled in the Western Haynesville from here forward 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 not only maximizing the value of the gas price we get, but also maximizing the – the ability to control the timing is to maintain control. So we might seek partners to – partner with us in building out that – building out that infrastructure over the next 5 years.
Gregg William Brody
So you've said build it over the next 5 years, do you think you'll seek out a partner over the near-term? Is there a time line that's how you're thinking about that?
Miles Jay Allison
There's not a near time, basically, the capital needed for next year. We have spent that. We just need to made 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 restructuring times. So we're planning for that, but we see those expenditures coming out in the future, but we're planning to want to create a structure that, so that midstream cost doesn't burden our drilling and completion budget, and that could be more like it's been in the past.
Roland O. Burns
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 second quarter '22, and we spent some money to repark it and upgrade it. We have takeaway capacity within this 90% of the acreage plus that we own to produce that gas in '23, '24 and midway to '25, so as we de-risk this stuff over the next months and quarters and years, then we'll see what the need is to have a midstream and it will tell us what we need to do. We're not going to ask permission to sell our gas to anybody though. 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 them of a long haul, there is a home. Now the question is, how do you get it there? And we've got plenty of takeaway between '23, '24 mid-'25.
Gregg William Brody
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?
Daniel S. Harrison
This is Dan. Well, definitely, when you get in development mode, you'll continue to see, obviously, efficiency gains and improvements, lower cost. We did -- obviously, probably we cranked up and got started in the plays 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 the number of days to get the wells drilled. So that's dropping the cost, and we do see the costs coming down into next year based on some other things that we've kind of got coming down the pipe. Any time you run more rigs and you start drilling more wells, you need to just get more practice at doing anything, you get a little better at it. And we will get more efficient just in that regard.
Gregg William Brody
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 million. I was curious what you sold and if that's in your -- if that's in the updated guidance.
Miles Jay Allison
Sure, yes. On working capital, I think the best way to trend it since our activity level, there's 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. So, that as those receivables get collected, you see a big contribution of 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 our spending levels staying 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 -- we'll be giving back some of that working capital. In the lower -- they go lower, obviously, you get some. So that's basically how I think you can see it play out the rest of the year. This year, obviously, the second quarter, the big contribution came because prices hit rock bottom.
Gregg William Brody
Is there a ballpark in terms of how much of a reverse is $100 million a good guess? Or is it closer to the $180 million that…
Ronald Eugene Mills
Yes, I think well, it all depends on how -- tell me what the gas price is 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 flush 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 a return criteria. We always look to do that like we answered before, 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.
Gregg William Brody
And that sales in your guidance then?
Roland O. Burns
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 we down, a lot of the other operators have pulled back 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. It's not a big part of our numbers anyway. So we're really talking about a couple of percent here or there.
Operator
And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research.
Noel Augustus Parks
Just a couple of things, thinking about a couple of timing-related issues, and I apologize if you touched on these already. But we certainly have these couple of onetime corrections or changes or transitions ahead. So we have this interest rate environment now the highest has been in 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. 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 as you're trying to either do third-party or direct sale or other types of LNG arrangements? Are you 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?
Miles Jay Allison
The first question you had the rising cost of capital and interest rates and I think that's where we're so thankful that we locked in a lot of our interest rates last year. So 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. 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 why 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 is a new 3-year supply contract with one of the large LNG shippers. We were on -- 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 taken exactly what they ask for -- so we see them as being a growing part of our market. And so I think it would really -- we'll be happy to sign longer-term contracts if they are there the buyer as 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.
Noel Augustus Parks
Great. And one question with this consolidation we've had in the Haynesville and you were, of course, early to that with Covey Park and then has a lot of other deals following the years after. I'm just curious, you've done a lot with pushing sort of 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 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 to handle than they might have bought from the outside?
Roland O. Burns
I don't think so. I mean we've seen our other peers in the Haynesville/Bossier do really well. I mean I think we're probably pushing the leading edge for the Western Haynesville and maybe one of our -- one of them is there with us. But I think, generally, I mean, I don't think we see that observation.
Daniel S. Harrison
Yes. No, I'll tell you we're the biggest cheerleader for all of them. I mean we want whether an oil company in the Permian or your gas company in place Europe as gas company in the Haynesville/Bossier. Look, we've got to cheer for each other. So, we hope everybody does really good, and we think they will do good.
Operator
And our next question comes from the line of Paul Diamond from Citi.
Paul Michael Diamond
Just a quick one. You talked a bit about the kind of your development cadence in Western Haynesville. I just wanted to see if there was any -- in your deal over the next several years, any idea on how the breakdown sits between targeting Haynesville versus the Bossier?
Daniel S. Harrison
Yes, this is Dan. It's a good question. We 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 is there -- this is 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 why we targeted the Bossier initially when we put our first rig out here, we drilled our first 4 wells to the Bossier, got kind of everything settled down a little bit. We made some progress dealing with the temperatures and then obviously, with our fifth well, we targeted the Haynesville, I didn't have any problems getting that drilled. The next 2 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've got several wells in a row where we're going to be drilling Haynesville.
So if you just kind of -- look, so if you just take a long-term view out through the end of 2025, right now, we're about 50-50 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 will become probably become Haynesville targets in the future. But today, just a snapshot today looking out for the next 2.5 years or the other 2025, we're about half and half.
Paul Michael Diamond
Understood. And just one quick follow-up. How do you guys think about the potential or the timing and potential for a return of activity given the current resiliency kind of strength in the 2024 and beyond curve?
Miles Jay Allison
Well, I think everybody is waiting to see what really materializes. I think there's -- in the gas market, we're really still focused on the inventory levels and getting -- weather is a huge factor this 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 what happens, I think, over the next -- this year plays out because I will set the stage for next year, along with the demand pull, how quickly do those projects start to pull the demand are they early or are they laid? There's a lot of factors to really drive the return of activity. I think most operators are just wait and see right now.
Daniel S. Harrison
And we got overall and we ask Ron to do this, what is -- what it could have showed what if Freeport had not gone offline for all those months. I mean, we do this every Thursday. 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 would have been exported. If you look at the number where we would be today on the 5-year average, we would have a deficit of about 8.8%. So I still think the gas market 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 exportable and it's not being injected into storage. It changes things. So they have a 250, 260 gas price right now is pretty remarkable.
Operator
Our next question comes from the line of Phillips Johnston from Capital One Securities.
John Phillips Little Johnston
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, Netherlands SOL booked - circling well, at roughly 3.5 Bcf per 1,000 foot, which obviously is much higher than your legacy Haynesville wells. Would you say that 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?
Miles Jay Allison
No, I would think -- I think it's a really good question. Number one, 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. I think we need to get the rest of these wells producing and see what that real AUR is per 1,000. But the starting point is we were very pleased with the starting point. And then we've got -- as you know you so 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 AUR for the or way or the other and deliver a brand-new region that is competitive with the best of Europe, Texas, Louisiana, Haynesville/Bossier and that's where you have to have a big footprint, you have that commitment and you have to have an A+ operations completion group that's 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. And we're trying to thread that needle. I think we've done it.
John Phillips Little Johnston
Okay. Great.
Miles Jay Allison
Thank you. You asked the good question. I appreciate your question.
Operator
And our next question comes from the line of Leo Mariani from ROTH MKM.
Leo Paul Mariani
I wanted to follow-up a little bit on activity levels here. So it sounds like you're going back to 7 rigs at the end of this month here and 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 350, plus or minus a small amount in ‘24 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 start the year? And do you think you can grow production with 7 rigs given that you guys were running more, obviously, early this year?
Miles Jay Allison
Well, I think your comment, the script for ‘24 is 350, and the script for ’25 is just shy of $4. So those are really good process 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 to keep 2024 pretty constant at seven. We would have probably 4 in the core and 3 in the Western Haynesville. But all that is subjective and we'll figure out in the fourth quarter if we want to change any of that.
Leo Paul Mariani
Okay. And do you guys think that's a level of activity that lends itself to some kind of modest growth in production with that 7 rigs?
Miles Jay Allison
I think right now, again, you've 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 Haynesville wells while you complete the others. So 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 delays. So no, I think overall, I think right now, that's the appetite we have.
Roland O. Burns
Yes, as we get more production from the longer laterals in the Western Haynesville wells, we think a lower decline profile than our core Haynesville, that will hopefully reduce the need for more rigs in order to maintain production and grow modestly. And so as we get into the fourth quarter, it's usually when we set the budget usually November, December for next year, there are a lot of things we weigh in on that. We'll also be just seeing where we see that coming out. But seven is a great risk. That's how we would be looking at it now as we're just looking ahead, and we'd adjust that based on a lot of factors, including the gas price environment of 350 is still there, or has it changed and how we see the well performance, maintaining that production.
Leo Paul Mariani
And then I 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 leasing competition? And then just maybe talk about others that are 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. Do you think that to make something up and you guys can correct me if I'm wrong, but is it sort of by kind of mid next year or do you feel like you've kind of tested most of the acreage, where you've at least drilled the 4 corners and kind of the middle part of this thing, where you'll have a really good look at it. Just kind of any time line you can kind of provide the 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 time line to kind of get all this position proved up.
Miles Jay Allison
Well, in our crystal ball, we would -- again, 90-plus percent of this 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 hundreds of thousands of acreage, 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, when you ask the question, we can answer it with a little firmer answer. And then I think as far as the drilling program, our goal is to derisk this whole acreage by maybe end of '24, early '25, as you extend these wells from footprint to footprint, whether we're going north, southeast and west geologically so that -- and in some of these wells in 2024, you will drill 2 wells per pad site. So we've got just this abundance of acreage, so we can do that. I think the cost of floor coming down there and some of them will be Bossier well, some of them will be Haynesville well. 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.
Leo Paul Mariani
Okay. That's helpful color. And then just lastly, in terms of some of the early wells in the play, you're obviously starting to build up some pretty good production history. Are you seeing those wells hold in there pretty flat with fairly limited pressure drawdowns on some of those first couple of wells?
Miles Jay Allison
You know what we expected, we've demonstrated we keep drilling these wells. So obviously, we're not totally displeased with what we've seen, and we're going to continue to drill the wells. So that's about all the comment we can make right now.
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 Allison for any further remarks.
Miles Jay Allison
Okay, Jonathan, again. I mean, in conclusion, kind of a broad view. But in 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 are 244 people that are here on 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.
