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Thank you for standing by, and welcome to the Comstock Resources Second Quarter 2023 Earnings Conference Call. At this time, all participants are in listen-only mode. After the speakers’ presentation, there will be a question-and-answer session. [Operator Instructions] As a reminder, today’s program is being recorded. Now I’d like to introduce your host for today’s program Mr. Jay Allison, Chairman and CEO. Please go ahead, sir.

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 a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you’ll find a presentation entitled second quarter 2023 results. I am Jay Allison, Chief Executive Officer of Comstock. 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 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 could 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 a highly inflated drilling and completion cost. Looking beyond this year, we’re 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 a day 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 a Western Haynesville play based upon the very early results of our first five 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’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 were a little noisy on the disruptions caused by violent storms in June that we had in East Texas.

Our adjusted net income was just over breakeven for the quarter, we drill 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 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 by keeping competitors away. I’ll now turn over to Roland to discuss the financial results. Roland?

Yes. Thanks, Jay. On Slide four, we cover our second quarter financial results. Our production in 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 a third lower than the first half of 2022. EBITDAX was $476 million, and we generated $400 million of cash flow during the first six months. We reported adjusted net income of $93 million for the first six months of 2023 as compared to $409 million in the first six 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 of daily average Henry Hub spot price in the quarter of $2.12. Our realized gas price during the second quarter averaged to $1.81 reflected a $0.29 differential to both the settlement price at – and our reference price. This differential return to a 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’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 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 the second quarter, $0.01 higher than the first quarter 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 of sales to 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 cents. Our production taxes increased $0.03 compared to the first quarter level. Our G&A cost 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 recapped our spending on our drilling and other development activity for the first half of this year. So the first six months, we spent a total of $647 million on 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 billion. In the first six 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 given 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.

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 shale locations. It’s divided into our four buckets. We have our short laterals up to 5,000 feet. Medium laterals are between 5,000 and 8,000 feet. Our long laterals at 8,000 to 11,000 feet, and our extra long laterals out 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 length 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 extra long lateral bucket, which is greater than 11,000 feet and a full two-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 first quarter. Our inventory provides us with 25 years of future drilling locations based on existing activity. On Slide 11 as 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 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 stands at 15,726 feet. During the second quarter, eight of the 17 wells we turned to sales had laterals exceeding 11,000 feet, including four 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. During the second quarter, we also had two additional wells that turned the 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 and new vintage wells now completed and producing in the Western Haynesville. Based on our current schedule, we’re 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 14,000 foot 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’ve 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 9,565 foot long lateral, and we turned 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 a day is 35 million cubic feet a day, but we are still cleaning this well up and is we are expected to achieve a higher IP rate in the very near future. Beyond these last two wells that we’ve turned to sales, we’re 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 two rigs later this month. Slide 13 summarizes our D&C cost through the second quarter for our benchmark long lateral wells that are on our legacy core East Texas in 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 benchmark long lateral wells. In the second quarter, our D&C cost average $1,523 per foot, which is a 4% decrease compared to the first quarter and still a 15% increase compared to our full year 2022 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 length 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 drop a rig from the fleet, which has it’s currently running in six rigs. However, later this month, we’ll be taking delivery of the new rig, which will take us back to seven rigs, which is the level we will – we plan to stay at through the end of the year. And also on the completion side, we are also running three frac crews and we will stay at the three 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.

Okay, thank you, Dan. If you’ll turn to Slide 14, I direct you to Slide 14 where we summarize our outlook for 2023. We look back on this year in the future, we’ll 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 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. Now to that end, we are working to prove up our new play in the Western Haynesville with a two rig program and complete our leasing program. Now, we currently only have one rig active in the 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’re 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 two 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 we’re currently operating six 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’ll 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 provides the specific guidance for the rest of the year. Ron?

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 of during the third quarter and $75 million to $100 million to $70 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 expected the 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 $0.32 to $0.36 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 to cash interest expenses 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.

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

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

Good morning, Charles.

Jay, I want to see if there’s some more detail you can offer on these – on your Western Haynesville wells, and not just these two most recent ones, but in general, the 35 million a day, congratulations on that. That’s a great stout rate, but you – there’s more defines a well than just what where it comes on, right? I mean, on the – some of the best wells on the Louisiana side, we are delivering IPs of $40 million or even $50 million a day? So how would you – 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 to 40 IPs versus the best stuff we’re seeing on the Louisiana side.

So Charles, I – probably, I’ll turn it over to Dan. I don’t know how deep of a wheat you 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. And we’re very careful about disclosures on what we’re doing until we lease it all. But all the acres that we want to lease, we’ve recognized and we know the mineral owners, we have – we’re 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’ve drilled. Remember that this play is unlike the play in Louisiana that you’re referencing, that we’ve read about. We have a much bigger block or 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’re the Bossier wells. So we – typically your Haynesville 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 at, but the lateral link that we’ve drilled them at with the heat that we’ve encountered as effectively as we have and that includes a Circle M, which is a Bossier, the Casey Blackford Bossier, the Campbell, which is proved that we could drill extended laterals to 12,700 feet, that was a Bossier. And then charge, you get to the Dinkin, which is a lower Bossier. So we’re, you know, now delineating the upper lower, same thing with the Haynesville, then the McCullough Ingram, which is the Haynesville, which Dan had commented on McCullough Ingram. At the same time, we have completed that KCMS. And we have fracked it, and we’ve got stick pipe drilling out the fracks. 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.

Yes, Charles. So one of the things I wanted to just add to what Jay said is we are being very conservative in how we’re drawing the wells down. Obviously, they’re at a lot deeper TBDs 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 pressures I’ll say this McCullough, well that’s in the Haynesville is flowing with more pressure at the same choke size is 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 into drilling into this play, the Haynesville’s going to always be our primary target. We -- when we first started into 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’ll bear out with a lot better wells in the Haynesville.

That is great. Go ahead. I’m sorry.

I want to go again. We’ve circled the wagon. If this remaining 10% that we’re trying to lease for some reason we don’t get it. We’ve circled the racks started three years ago in August, and very low cost that we paid for the acreage. And the drilling commitments are very phenomenal. We go from two to three, three to four rigs, we can HPC all this footprint. Again, with the Western Haynesville, we bought – we did buy that infrastructure when we bought 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, is that – we’re accountable to you and you trust us for where we’re spending our money and that that 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.

That – 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 follow-up on, and that is the leasing and that you’re increased capital budget for leasing. 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?

Well, I think when you look – three years ago, two years ago, one year ago, you come up with a budget and as you dive into the geology, it’s all about upon geology, right? And you want to clean up maybe the middle, you find out there’s some acreage that’s open 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 out there with this whole program, as you’ve seen. 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 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 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’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. It’s like a mop cleaning things up.

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

Thank you. [Operator Instructions] And our next question comes from the line of Derrick Whitfield from Stifel. Your question please.

Thanks. And good morning, all.

Good morning. Good morning.

Well, 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 given the timing of your turn in lines?

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 or 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 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.

Yes. Derrick, I think we – more or less has seen that year unfold like we’ve planned. I think the – I think there’s been slower kind of hookups, especially we have one area that’s a month and a half behind and is 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 a month and a half away 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 just pushes that production out in the future, hopefully where we get a higher price for it.

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. And but again, just to help us understand how you guys are tracking progress wise.

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 is got some difficulties associated with flow 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 KCMS and the Lanier, which are the last two wells we drilled are if you kind of look at where they’re located, the KCMS, we’ve shaved off probably 20 days on that well, it’s right over near the Circle M, the Campbell and the KC Black. And we drilled it 20 days less than where we started just due to the strides and the vertical part of the hole. And then really – and then I kind of separated into those two 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 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 is where we made our headway. And so, like I said, we’ve – the last well over on kind of that southwest end of the play, where we’ve got the Circle M, the KC, the Campbell, the KCMS and the McCullough, this last well, we’ve – we’re 20 days faster. So conversely kind of over on the other side, Leon 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 are going to let us shave additional days off here in the near future.

Derrick, 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 is 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, 2028, 2029. But I want to assure you are not drifting. You can see the answers that you give when you ask these great questions. 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 plate as far as the part that we want before we start disclosing everything, which you should do if you value it.

That’s great, guys. Sounds very encouraging.

Thank you. [Operator Instructions] And our next question comes from the line of Jacob Roberts from Tudor Pickering Holt & Company. Your question, please?

Good morning.

Good morning.

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.

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. 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.

We typically hedge 40%, I still think that’s probably a good visual out there. We’ll see what happens. Prices haven’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 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’re – we’ve got our eyes on that, we’re looking at it and we make decisions daily about it.

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?

Yes, that are just some non-operated interests that we sold. And like last year you saw – we saw as we seized just have opportunities to sell non-operated interests that are not part of our core, we kind of execute on that. 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.

Thanks. Appreciate your time.

Thank you. [Operator Instructions] And our next question comes from the line of Bertrand Donnes from Truist. Your question, please.

Good morning.

Good morning.

Good morning. The first question on LNG, I think I know the answer to this, but 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 a another segment want to just retain a Henry Hub premium agreement. So I just wondering what fits best with Comstock long-term and or maybe the decision just comes down to where Jonathan moves gas prices.

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 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 two to three years. But 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 in talks, to come out with that. So, yes, 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.

I do think though, if you look at where our footprint is, we’re 200 or 300 miles away from where these $100 billionof 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 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 we’ll produce in the future. And 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 that 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 where that extra 17 or 18 Bs may come from. We want to position the company to have great float in the stock, great liquidity, great inventory, and these low cost 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 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 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 the we’re going to run this thing right.

All right. I appreciate that answer. And then maybe on the D&C cost, 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 you’re holding the ground?

Yes. I’d say, a pretty good piece of it probably was the longer lengths. I mean, obviously –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’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 at only 10,800 feet plus or minus in the first quarter. So that obviously lends itself to cheaper D&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 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 kind of starting 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 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 tide to utilization.

Well, efficiencies, the frac crews you made.

Yes. So the efficiency, 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. 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 – we just get production on faster. So all of that stuff adds up to a really good answer.

Yes. The one thing 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 unusual to have – it’s almost like two different companies, two 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, and it’s a pretty – a really good place to be.

Thanks, Jay. That’s it for me.

Thank you. [Operator Instructions] And our next question comes from the line of Gregg Brody from Bank of America. Your question, please.

Hey, good morning, guys. Just in the – sorry to cut off the reciprocation. Just – the Western Haynesville, just as you think about the capital required to keep going there and expand, can you talk a little bit how you’re thinking about potentially raising capital for that to expand into next year?

Gregg, this is Roland. I think on the area that in addition to, yes, the drilling cost, which you’ve kind of outlined wanting to go from – basically go to three 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. But if we – as we look ahead, they’re longer – there would be larger investments to make. So there, I think we’re looking, we’re exploring 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 third party company. And so you see a lot of the wells that been drilled in the Western Haynesville from here forward will be in our system. Only one is in it right now like that. 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 ability to control, the timing is to maintaining control. So we might seek partners to – partner with us in building out that – building out that infrastructure over the next five years.

So you’ve said build it over the next five years. Do you think you’ll seek out a partner over the near-term? Is there a timeline that, that’s how you’re thinking about that?

There’s not a near time, it’s – yes, 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 the 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, but we see those expenditures coming out in the future, but we’re planning to – want to create a structure so that is – that that midstream cost doesn’t burden our drilling and completion budget and that could be more like it’s been in the past.

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 2022, it – and we spent some money to repurchase and upgrade it. We have takeaway capacity within this 90% of the acreage plus that we own to produce that gas in 2023, 2024 and midway through 2025. So as we de-risk this stuff over the next months and quarters and years, then we will see what the need is to have a midstream and it’ll 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 take them to sales. We want to have a home farm 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, 2024 and mid-2025.

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?

This is Dan. We’ll 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 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 the number of days to get the wells drill. 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.

That’s really helpful. And then just for the pesky credit analyst that, that stares at the accounting on some things, just could you – is – 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…

Sure. Gregg, working capital – yes, and working capital, I think the best way to trend it since our activity level, yes, there’s a – has it reduced down for the level last year, but now it’s fairly stable with the seven 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’s – that as those receivables get collected, you see a big contribution with 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 our – 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 play out the rest of the year. This year, obviously the second quarter, the big contribution came because prices hit rock bottom.

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

No. I think it’s – well, it all depends on how, you’d have to tell me what the gas price is in the future, and I could give you a number. So if it’s a – 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 a very small, so there’s not a lot of material future stuff to do, but that we’re always open to doing that.

And that’s sales in your guidance then?

Yes. Yes, I think – and plus we’ve seen two 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 notice the rig counts way 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. I think its not…

I appreciate the time.

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

That’s what it looked like. I appreciate the time and the insight, guys. I’m passing the mic back.

Thank you. [Operator Instructions] And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Your question, please.

Hi, good morning.

Good morning.

Good morning.

Just a couple 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 has 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 the 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 if you’re trying to either do third-party or direct sale or other types of LNG arrangements, are you thinking about maybe like a [indiscernible] for the transition years and then thinking ahead to maybe something longer-term or you might try to do.

Yes, that – those are a good question. Well, the first question you had, the other 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. 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 to 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 as a new three-year supply contract with one of the large LNG shippers, we were one 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 they – 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 the buyer because 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.

Great. Thanks. And one question, was this consolidation we’ve had in Hayesville, and you were of course early to that with Covey Park and then had 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 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 handles than they might have thought from the outside?

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 our – one of them is there with us. But I think generally, I mean, I don’t think we see that observation.

Yes. No, 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 farming or your gas company and Appalachia, you’re a natural gas company in the Haynesville/Bossier. Look, we got to cheer for each other. So we hope everybody does really good and we think they will do good.

Great. Thanks a lot.

Thank you. [Operator Instructions] And our next question comes from the line of Paul Diamond from Citi. Your question, please.

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

Yes. So this is Dan. So we – 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 this – there are – 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 why we targeted the Bossier initially, when we put our first rig out here, we drilled our first four wells to the Bossier kind of got kind of everything settled down a little bit. We made some progress dealing with the temperatures, and then we obviously with our fifth 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 two 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. So if you just kind of look, so if you just take a long-term view outs 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 is 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 for the end of the 2025, we’re about half and half.

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 kind – given the current resiliency kind of strength of 2024 and beyond curve?

I think everybody’s waiting to see what really materializes, I think there’s a – in the gas market, we’re really still focused on the inventory levels and getting weather is a huge factor this summer and the 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 – as this year plays out because I’ll set the stage for next year, along with the demand pull, how quickly do those projects start to pull the demand? Were they – are they early or they late? All – there’s a lot of factors to really drive the return of activity. I think most operators are just wait and see right now.

Understood. Thanks for clarity and the time.

Thank you. [Operator Instructions] Our next question comes to the line of Phillips Johnston from Capital One Securities. Your question, please.

Hey guys, thanks. Just one question for me in the interest of time, I guess, but it’s a follow-up on Charles’s 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, Sewell book, the Circle M, well at roughly 3.5 Bcf per 1,000 foot, which obviously is much higher than your Legacy, Haynesville wells. Would you say that, that all five of the wells that you’ve now brought line in the play are tracking to a similar EUR? Or do you think there’s a fair amount of variability?

No, I would think that’s a – 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 eight months and Netherland is exemplary reservoir engineers and they come in with a 3.5 Bs, 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, that real EUR 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 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 them one way or the other and deliver a brand new region that is competitive with the best of your Texas, Louisiana, Haynesville/Bossier. 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 that’s committed and dedicated to doing this for years, after years, after years within a budget that protects both the bond holders, the equity owners, the banks everybody, including the largest stockholder. And we’re trying to thread that needle. I think we’ve done it.

Okay. Great. Thanks, Jay. Sounds good.

So thank you. That’s a good question. I appreciate your question.

Thank you. [Operator Instructions] And our next question comes from the line of Leo Mariani from ROTH MKM. Your question, please.

Hey guys, wanted to follow-up a little bit on activity levels here. So it sounds like you’re going back to seven 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 350 plus or minus a small amount in 2024, at this point in time. So as you guys look to next year, does seven rigs kind of feel like a pretty reasonable place to kind of start the year and you think you can grow production with seven rigs, given that you guys were running more obviously early this year?

Well, I think your comment, the script for 2024 is the 350 and the script for 2025 is just shy of $4. 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 two, we can do that. Our goal is to keep the 2024 pretty confident at seven. We would’ve probably four in the core and three 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.

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 seven rigs?

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 while you complete the others. So you’ve got a model that lumpiness, and then of course, you always have to model in. You have other shut-ins because of rig activity in your core, and you’ve got a little weather delay. So, no, I think overall, I think that’s – right now that’s [indiscernible] we have.

Yes. As we get more production from the longer laterals and the Western Haynesville wells with the – 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 we’ll – as we get into the fourth quarters usually when we kind of set the budget, usually November, December for next year, a lot of things will weigh in on that. We’ll also be just seeing kind of where we see that coming out and do we, but seven is a great, that’s how we would kind of be looking at it now as we’re just looking ahead and we’d adjust that based on a lot of factors, including does the gas price environment of 350 still there or is it changed? And how we see the well performance maintaining that production.

Okay. That’s helpful for sure. 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 five wells in at this point in time. 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 four 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 the sort of proving it up. I mean, it seems like you guys are five for five 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.

Well, in our crystal ball, we would again 90%-plus of the 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’ve leased hundreds of thousands 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. When you ask a question, we can answer it with a little former answer. And then I think as far as the drilling program, our goal is to de-risk this whole acreage by maybe the end of 2024, early 2025, as you extend these wells from footprint whether we’re going North, South, East, and West geologically. So that – and then some of these wells in 2024, you’ll drill two wells per pad site. So we’ve got a just this abundance of acreage so we can do that. I think a cost will start coming down there, and some of them will be Bossier wells, some 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.

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 holding there pretty flat with fairly limited pressure drawdowns on some of those first couple wells?

What we expected, we’ve demonstrated, we keep drilling these wells. So obviously we’re not totally displeased what we’ve seen. And we’re going to continue to drill the wells. So that’s – that is that – that’s about all the comment we can make right now.

Okay. Thanks.

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.

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’ve talked to some of us today. There’s 244 people that are here at come to 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.