Comstock Resources, Inc.

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 speaker's presentation, there will be a question and answer session. To ask a question during the session, you'll need to press star 1-1 on your telephone. To remove yourself from the queue, simply press star 1-1 again. 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.

Thank you, Jonathan. I wish you controlled natural gas prices. We'd all be a little happier. I like your introduction. Welcome to the CompSoc 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 have 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 Investment Relations. I'll flip over to slide two. Please refer to slide two In our presentation, note that our discussion today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there 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. You know, 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 today 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, you know, we're optimistic about the prospects for Western Hainesville plate based upon the very early results of our first five wells, which Dan Harris will talk to you about later, as we continue to move up the learning curve on drilling these deeper wells at 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 Hainesville 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 and were a little noisy on the disruptions caused by violent storms in June that we had in East Texas. On slide three, if you'll flip there. On slide three, we summarized the highlights of the second quarter. The financial results were heavily impacted by the very low natural gas prices 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 53 cents per share, and adjusted EBITDAX was $182 million. With positive working capital contributions, We only had to borrow $20 million to cover the overspend in the quarter. Our adjusted net income was just over break-even for the quarter. We drilled 21 or 17.2 net successful operated Hainesville 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 cells with an average initial production rate of 21 million cubic feet equivalent per day. We're having great success in our Western Hainesville exploratory play in the early innings. Our fourth and fifth wells were recently turned to cells with strong production rates, including our first well in the Hainesville shell. The first four wells have been completed in the Bossier shell. 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?

Yeah, 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 break-even level as compared to $274 million in the second quarter of 2022. On slide five, 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 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 six, 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, reflected a 29-cent 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 Hainesville 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 seven, we detail our operating cost per MCFE produced in our EBITDAX margin. Our operating cost per MCFE averaged 84 cents the second quarter, one penny higher than the first quarter rate. The increased unit costs are related to the startup phase in our Western Hainesville area, which we'll see improve as we connect more of sales to our own gathering and trading facilities in the future. Our gathering costs were flat at 36 cents during the quarter, and our lifting costs were also unchanged at 27 cents. Our production taxes increased 3 cents compared to the first quarter level. Our G&A cost came in at 6 cents per MCFE, which is down 2 cents 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. So the first six months, we spent a total of $647 million on development activities, including $590 million on our operated Hainesville and Bossier Shell drilling program. Spending on other development activity, including non-operated projects, installing production tubing, offset frack protection, and other workovers, totaled $57 million. In the first six months of this year, we drilled 39 or 30.9 net operated Hainesville and Bossier shell 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 nine 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 Hainesville and Bossier locations. It's divided into our four buckets. We have our short laterals up to 5,000 feet. medium laterals are between 5 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 link laterals, 719 long laterals, and 459 extra long laterals. Our gross operated inventory is split 52% in the Hainesville 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 is a chart that outlines our progress to date on our average lateral length drilled based on the wells that we have turned to cells. During the second quarter, we turned 17 wells to cells with an average length of 11,244 feet, thanks to the continued success of our long lateral program. The individual well lengths ranged 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've drilled 28 wells with laterals over 14,000 feet. During the second quarter, we also had two additional wells that turned to cells in our new Western Hainesville acreage. The Dinkins number one well was completed in the lower section of the Mid-Bossier, while the McCulloch-Ingram number one is our first well completed in the Hainesville. These wells are our fourth and fifth new vintage wells now completed and producing in the Western Hainesville. Based on our current schedule, we are planning to turn another 37 wells to cells 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 Hainesville acreage. The Dinkins No. 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 cells in May. We tested the well with an IP rate of 34 million cubic feet a day. The McCullough-Ingram No. 1 well is our first well that we've completed in the Hainesville interval. It had an 8,256-foot long lateral, and the well was turned to cells in June. The IP rate achieved today is 35 million cubic feet a day, but we are still cleaning this well up and 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 are currently in the process of completing our sixth and seventh wells on the Western Hainesville 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 hazel acreage, but that will soon increase back to two rigs later this month. Slide 13 summarizes our DNC 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 benchmark long lateral wells. In the second quarter, our DNC 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 DNC 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 dropped a rig from the fleet, which has us currently running six rigs. However, later this month, we will be taking delivery of a new rig, which will take us back to seven rigs, which is the level we plan to stay at through the end of the year. And also on the completion side, we are also running 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'll direct you to slide 14 where we summarize our outlook for 2023. You know, we look back on this year and 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 Hainesville with a two-rig program and complete our leasing program. Now, we currently only have one rig active in the Western Hainesville, as Dan mentioned, and we have leased approximately 90% of our targeted acres, so 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 Hainesville 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 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 12.5 cents 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? Thanks, Jay.

On slide 15, we provide the financial guidance for 2023. The third quarter DNC CapEx is expected to range between $240 to $280 million, and our full-year DNC 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 to $30 million during the third quarter and $75 to $125 million for the full year. In addition to what we spend on our drilling program noted above, we now anticipate spending $70 to $85 million this year for leasing activity. Our LOE is expected to average 24 to 28 cents 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 12 to 16 cent per MCFE range, while our DD&A rate is expected to remain in the $5 to $15 per MCFE. Cash G&A is still expected to run around $7 to $9 million in the third quarter and a total of $32 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 SOFA rates, the cash interest expense is now expected to total $40 to $42 million for the third quarter. and $160 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.

One moment for our first question. And our first question comes from the line of Charles Mead 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 your Western Hainesville wells, and not just these two most recent ones, but in general, you know, the 35 million a day, congratulations on that. That's a great stout rate. But there's more to find the well than just where it comes on, right? I mean, some of the best wells on the Louisiana side are delivering IPs of 40 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 Hainesville with these kind of 35 to 40 IPs versus the best stuff we're seeing on the Louisiana side.

So, Charles, I'll probably turn it over to Dan. I don't know how deep in the weeds you want to get. uh i think i'd start like this uh i want to go backwards and say how many acres have we leased and uh 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 uh all the acres that we want to lease we've recognized and that we know the mineral owners we have you know we're discussions with them so so i think that's a good place to start so we We can get to the end of that in 2023. And then I would just comment on the wells that we have drilled. Remember, this play is unlike the play in Louisiana that you're referencing that we've read about. We have a much bigger block, more contiguous. We have our own takeaway, so we don't have any infrastructure issues on the horizon. And the wells that we've been drilling are the inferior wells. They're not the Hainesville wells. They are the Bossier wells. So we, you know, typically your Hainesville 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 at, but the lateral length that we've drilled them at with the heat that we've encountered as effectively as we have. And that includes the circle end, which is a Bossier. the KC Blackridge, the Bossier, the Campbell, which is proof that we could drill extended laterals to 12,700 feet. That was a Bossier. And then, George, you get to the Dinkin, which is a lower Bossier. So we're, you know, now we're delineating the upper lower. Same thing with the Hainesville and then the McCullough-Ingram, which is a Hainesville, which Dan had commented on McCullough-Ingram. At the same time, we have completed the KCMS. and we have fracked it, and we've got stick pipe drilling out the fracks, and then we've got the linear 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?

Yeah, Charles. So, you know, one of the things I want to just add to what Jay said is we are being very conservative in how we're drawing the wells down. You know, obviously they're at a lot deeper TVDs here. Got a lot better bottom hole pressure. You know, the productivity is really good. You know, we're obviously not trying 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. The pressures, I'll say this McCullough well that's in the Haynesville, is flowing with more pressure at the same choke size as what we've seen on any of our Bossier wells. So we definitely are seeing a lot better deliverability on the Hainesville well versus the Bossier wells. And so we think it's going to be pretty good. And, you know, looking forward into drilling into this play, the Hainesville is going to always be our primary target. When we first started in the play, we knew it was going to be tough drilling these wells due to the depth and the temperatures. And we did specifically target drilling to the Bossier interval initially just from a drilling standpoint, you know, just to give ourselves the best chance at 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, you know, some of the deeper targets, been able to do that successfully. And, you know, we think that'll bear out with a lot better wells, you know, in the Hainesville.

That is great. Go ahead, I'm sorry. I want to go again. We circle the wagon. If this remaining 10% that we're trying to lease, if for some reason we don't get it, we've circled the wagon, started three 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 two to three, three to four rigs. We can HPC all this footprint. Again, you know, with Western Hazel, 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, you know, I think we're going to get a big blue ribbon. Now, what we want to make sure is that, you know, 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 great question, and we'll try to answer it as clear as we could with the set of facts we have, okay?

It's great detail, Jay, and it makes sense that you guys are holding some cards close right now. That makes sense. You can count me among those eager to – to hear more when you want to offer more. But, Jay, you also kind of touched on the one question I want to follow up on, and that is the leasing and that your increased capital budget for leasing. It was a great data point that I hadn't heard from you before. I 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 based 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 exchange 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. This whole program, as you've seen, that's why we gave a whole slide on the lateral links. you know, the 5,000, 8,000, 10,000, 15,000 collaterals. We're trying to groom this so that when you see all of it at one time, you can say, oh, now I see why you added, you know, 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 a long time ago. So there's nothing that we're really trying to acquire on the peripheral side. of any material size that we have to own at all. So it's just a cleanup, like a mop, cleaning things up.

I appreciate the visual, Jay. Thanks for taking the questions. Thank you. One moment for our next question.

And our next question comes from the line of Derek 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?

Derek, it's Ron. The absolute exit rate, you know, 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, you know, there's a chance the exit rate can be above that to help create the average. 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.

Yeah, Derek, I think we've already more or less has seen that year unfold like we planned. I think that the, I think there's been, you know, slower kind of hookups, especially we have one, we have one area that's a month and a half, you know, behind and was really supposed to be online at the very end of the second quarter. And so, you know, you take a lot out of the third when you take a month and a half away, you know, for these, these are probably be high volume wells, you know. And so, you know, So 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.

Yep, could certainly be fortuitous from the standpoint of timing. With my follow-up, I wanted to, I guess, ask a question about the Western Painful 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.

So yeah, Derek, this is Dan. I'd say we've made really great strides. Obviously, these aren't easy wells to drill. I think everybody realizes that. We accepted a pretty good challenge here starting with these wells, but we have made really good progress. The vertical part of the hole has got some difficulties associated with the lost circulation zones. You know, 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, you know, as far as just shaving off a lot of days. The KZMS and the Lanier, which are the last two wells we drilled, are, if you kind of look at where they're located, the KZMS, we've shaved off probably 20 days on that well. It's right over near the Circle M, the Campbell. in the Casey 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, and I kind of separated into those two buckets. The other part is just the lateral and just dealing with the temperatures at these DVD 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. Uh, we've just gotten much better at, uh, you know, tweaking our bottom hole assemblies and motors that we're running in these high temperatures, getting better performance. We're getting longer runs and, uh, really just those two things coupled together, you know, faster up there in the vertical and that hard Travis peak section and, you know, better motor performance in the temperature and the laterals is what's, you know, where we made our headway. And so, like I said, we've, we've, The last well over on kind of that southwest end of the play where we've got the Circle M, the Casey, the Campbell, the Casey MS, and the McCullough, you know, this last well, we're 20 days faster. So conversely, kind of over on the other side in Leon County where we've got the Lanier and the Dinkins, the Lanier we shaved off a bunch of days compared to the Dinkins. 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 save additional days off here in the near future.

Derek, 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 gonna 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 we're 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 We took great ownership in 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. One moment for our next question. And our next question. comes from the line of Jacob Roberts from Tudor Pickering Holt and Company. Your question, please.

Good morning.

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.

Yeah, Jacob, this is Roland. Yeah, we've started to put in some 24 positions as we kind of show in our presentation. But, you know, we're not really ready to talk about our strategy yet. But you can kind of see where we're starting out, you know, and as we see opportunities, you know, that kind of meet our goals, you know, we'll continue to execute on our 24 hedging program.

You know, we typically hedge, you know, 40%. I still think that's probably a good visual out there. We'll see what happens. You know, prices haven't come our way in a month or so. We did put the swap in at, you know, $3.50 gas for $130 million a day. And we are very, you know, we want to have that revenue stream almost guaranteed for some type of hedge if we could, particularly as we're, you know, we're de-risking to Western Hainesville. So you need to know 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?

Yeah, those are just some non-operated interest that we sold. And, you know, like last year, you saw we – so as we see, you know, have opportunities to sell non-operated interest, you know, that are not part of our core, you know, we kind of execute on that. But, you know, that's a fairly very immaterial small part of the company, so I wouldn't say that there's a lot of, you know, potential for that in the future.

Thanks. Appreciate the time.

Thank you. One moment for our next question. And our next question comes from the line of Bertrand Dons 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 want 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 I'm just wondering what fits best with Comstock long-term and or maybe the decision just comes down to where Jonathan moves gas prices.

Those are all great strategies. That's something we continue to evaluate. We are already a big supplier to the LNG, and then we think that's going to – the share of gas that we produce that goes directly to LNG shippers is going to continue to increase, especially with the big expansion coming in the next two to three years. But we're still evaluating, you know, 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, you know, in international pricing? And, you know, we're actively exploring that and in talks, you know, to come out with that. So, yeah, I don't think we have a, have an answer for you yet on which one we think is best. But, yeah, like you see, our competitors are all kind of approaching it in different ways.

I do think, though, if you look at where our footprint is, you know, we're 200 or 300 miles away from where these $100 billion of export shipping facilities are being built. You look at the majority of the new acreage is undedicated. That's a good thing. You look at the 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. And you look at the demand out there. That's kind of how we started. We think, you know, there's about 12 bees a day of export LNG. This doesn't include Mexico. but you can see you're gonna have another nine Bs between now and maybe 25, six, seven. And then that's where that extra 17 or 18 Bs might come from. We wanna position the company to have great float 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 Roland said, seeing if we can capture some international prices, long haul, gathering. I think we're going to have the flexibility to look at all those things. But I can assure you, we're not going to tie ourselves into some type of a commitment that if prices dip, we get hurt.

just not going to do that we don't have to do that so so we're going to protect you and and the stakeholders and the analysts and we're going to run this thing right all right i appreciate that answer and then uh maybe on the dnc costs i just you mentioned it in your prepared remarks it seems like a portion of maybe that four percent decline quarter of a quarter came from longer uh laterals in the quarter but could you maybe

talk about you know where the the rest of that came from and maybe specifically which items you're seeing some deflation on and which items are holding their ground yeah i'd say uh you know a pretty good piece of it probably was the longer the longer links i mean obviously you the longer we get you know our cost per foot comes down so we look at that every quarter we look at what the average you know that group of wells averaged and so you know you know back there on Slide 13, when you look at that, that's the specific group of wells for the second quarter. You know, 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, you know, obviously lends itself to, you know, cheaper D&C costs. And really, I'd say just the other parts is we're starting to see that deflation, you know, 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, you know, a lot of the stuff we report on the second quarter, well, drilling at the first of the year. So just kind of start to turn the corner and come back the other way, which is why we'll see it continue to come down in the 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 frack crews get cheaper, which is obviously just straight tied to utilization.

What are the efficiencies of the frack crews you make?

Yeah, so the efficiency of the frack crews have gotten better, I mean specific to our crews that we're running. You know, just we've seen our stage counts per day have increased. We're, you know, just really happy with the crews. So, you know, just they've gotten faster, more efficient. So even if you're paying the same price, you know, 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.

Yeah, the one thing I'll comment on that question is, you know, we've got the core, which is the 1,500 locations and the thousands of acres, hundreds of thousands. And then yet, you know, we focus on a lot of this call is on the Western Angle. 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 really good place to be.

Thanks, Jay. That's it for me. Thank you. One moment for our next question. And our next question comes from the line of Greg Brody from Bank of America. Your question, please.

Hey, good morning, guys. Good morning. Sorry to cut off the reciprocation. 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?

Greg, this is Roland. I think the area that, in addition to the drilling cost, which you've kind of outlined, wanting to 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 as we look ahead, there will be larger investments to make. So there, I think we're looking, we're exploring creating a midstream kind of separate entity that will kind of handle you know, those capital needs in the future as we build that out, which also allow us to control, you know, the midstream in processing versus, you know, relying on a third-party company. And so you see a lot of the wells that are drilled in the western Hainesville from here forward, you know, 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 ability to control the timing is to maintain control. So we might seek partners to partner with us in building out that infrastructure over the next five years.

So you 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 as to how you're thinking about that?

There's not a near time. Basically, the capital... needed for, you know, next year. Yeah, we kind of spent that. You know, we just need to make 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, you know, to grow our volumes, you know, to handle next year. But as you look ahead, you know, the items beyond that have a lot longer lead time, longer construction time. So we're planning for that. We see those expenditures, you know, coming out in the future, but we're planning to We want to create a structure so that that midstream cost doesn't burden our drilling and completion budget, and that can be more like it's been in the past.

Yeah, 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, You know, we have takeaway capacity within this 90% of the acreage plus that we own to produce that gas in 23, 24, and midway through 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'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 midstreams. So when we drill these wells, we want to take them to sales. We want to have a home for them. 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 23, 24, mid-25. Got it.

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

This is Dan. You know, we'll definitely, when you get in development mode, you'll continue to see, obviously, efficiency gains and improvements, lower costs. We did, obviously, you know, right when 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 cost coming down in the next year based on some other things that we've kind of got coming down the pipe. You know, 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 stares at the accounting on some things, 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, I noticed an asset sale of about $41 million. I was curious what you sold and if that's in the updated guidance.

Sure, Greg. You know, working capital, you know, I think the best way to trend it since our activity level, you know, it reduced down from the level last year, but now it's fairly stable, you know, with the seven rigs. So then that means you're kind of that part of the working capital, the payables probably stays consistent. You know, the other item driving working capital, obviously, is the prices, right? And so, you know, we had the very, very low prices. So, you know, as those receivables, you know, get collected, you know, you see a big contribution of working capital this quarter. But then as gas prices improve, you know, as we go forward in the year, you know, you won't see more of that. You'll see the opposite effect. you'll have, you know, so it's really, I think you can, if you're really thinking about it, just think about, I think 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, you know, 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, you know, play out the rest of the year. This year, obviously the second quarter, the big contribution came because, you know, prices hit rock bottom.

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

Yeah, I think it's – well, it all depends on how – you have to tell me what the gas price is in the future, and I could give you a number. So, you know, if it modestly improves, you know, then it's going to modestly – do that if gas prices dramatically improve, you know, to where they were last year, obviously then it's a big number. And so I don't think it's, unless it gets as big as it was last year, that's what you're seeing is all that flushed through, you know, in the numbers, you know, on the, on the proceeds from sales, you know, last year, this year, we've any, any opportunity to sell non-operated non-strategic properties, if they can meet a return criteria, you know, we, we, uh, You know, we always look to do that. Like we answered before, you know, the whole non-operated, you know, part of our production and reserves is very small. So there's not a lot of material, you know, future, you know, stuff to do. But we're always open to doing that.

And that sells in your guidance, Ben.

Yeah, I think 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, you know, just a lot lower non-operated activity going forward. And I think that, again, will probably track, you know, how strong gas prices are to when that would come back.

I appreciate the time.

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

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

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

Hi. Good morning. Morning. 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 lull 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 mode A for the transition years and then thinking ahead to maybe something longer term you might try to do?

Those are good questions. The first question, the rising cost of capital and interest rates, I think that's where we're so thankful that we locked in a lot of our interest rates last year and don't really see having to go back into the debt markets 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 as a new three-year supply contract with one of the large LNG shippers. Early on, we did a 10-year, so we So we're not afraid of the longer-term durations as long as they're happy to commit to buy it. And we've found them to be great customers, always taking exactly what they ask for. So we see them as being a growing part of our market. And so I think it would really – we would be happy to sign longer-term contracts if they are. They're 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, you know, with this consolidation we've had in Haynesville, 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 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, you know, on the idea that maybe it was a little harder to work the Hainesville than they might have thought from the outside?

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

Yeah, Noel, 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 you're a gas company in Appalachia or you're a gas company in the Hainesville-Bossier, look, we've got to cheer for each other. So we hope everybody does really good. We think they will do good.

Great. Thanks a lot.

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

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

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 Hainesville where we can. It's being a little bit deeper and being that there are 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 four wells through the Bossier, kind of got 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 Hainesville. Didn't have any problems getting that drilled. 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've got several wells in a row where we're going to be drilling Hainesville. So if you just kind of look – so if you just take a long-term – view outs through the end of 25. 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 you know, probably become hands-full targets in the future. But today, you know, just a snapshot today looking out for the next, you know, two and a half years to the end of 25, 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 current resiliency kind of strength of the 24 and beyond curve?

I think everybody's waiting to see what really materializes. I think in the gas market, we're really still focused on the inventory levels and getting weather is a huge factor. The summer and 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 you know, what happens, I think, over the next, as this year plays out. Because that will set the stage for next year, along with, you know, the demand pull. How quickly do those projects start to pull the demand? You know, are they early or are they late? There's a lot of factors to really drive the return of activity. I think most operators are just waiting to see right now.

And, you know, we go overall, and, you know, we asked Ron to do this, You know, what it could have showed, or what if Freeport had not gone offline for all those months? I mean, we do this every Thursday. You know, gas storage right now, in the five-year average, we've got a surplus of 13% above the normal five-year average. But at Freeport, if that two Bs hadn't been injected into storage, but had been exported, if you look at the number where we would be today on the five-year average, we'd have a deficit of about 8.8%. So I still think the gas market's a little bit misunderstood because I think we're doing the right thing, but all of a sudden you take two bees a day that's exportable and it's now being injected into storage. It changes things. So to have a two 50-60 gas price right now is pretty remarkable.

Understood. Thanks, Mr. Carradine. Your time. Thank you. One moment for our next question. Our next question comes in line of Phillips Johnson from Capital One Securities. Your question, please.

Yeah, 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 Hainesville Wells. And Jay, I hope this isn't pushing too far, but if I'm not mistaken, Nettle and Sewell both circle in well at roughly 3.5 BCF per thousand foot, which obviously is much higher than your legacy Hainesville wells. Would you say that all five of the wells that you've now brought in line of player tracking to a similar EUR, or do you think there's a fair amount of variability?

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, you know, Netherlands 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 real EUR is per thousand. But the starting point is, we were very pleased with the starting point. And then we've got, as you know, you should go back, you say, well, are they competitive and economic? And that's where you go to Dan and the group and say, well, you know, this is a big boy game. So can you really get these costs down and keep the UR for the R or toggle one way or the other and deliver a brand new region that is competitive with the best of New York, Texas, Louisiana, Hainesville, 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 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.

Okay, great. Thanks, Jay. Sounds good.

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

Thank you. One moment for our next question. And our next question comes from the line of Leo Marinari from Roth MKM. Your question, please.

Hey, guys. I wanted to follow up a little bit on activity levels here. So it sounds like you're going – back to seven rigs, uh, kind of the end of this month here and kind of run that, you know, through the end of the year. Um, you know, just looking at 2024, I mean, obviously, you know, 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, uh, you know, in, in 24, you know, at this point in time. So as you guys look to next year, there's, seven rigs kind of feel like a pretty reasonable place to kind of start the year. And do you think you can grow production, you know, with seven rigs, given that, you know, you guys were running more, obviously, you know, early this year?

Well, I think your comment, the script for 24 is at $315, the script for 25 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. You know, our goal is to keep 2024 pretty constant at seven. We would have probably four in the core and three in the western angel. But all that is subjective, and we'll figure it 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 ankle wills while you complete the others. So you've got to model that lumpiness. And then, of course, you always have to model that. Do 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 the appetite we have.

Yeah, as we get more production from the longer laterals in the western Haynesville wells with, 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 kind of set the budget, usually November, December for next year, So a lot of things will weigh in on that. We'll also be just seeing kind of where we see that coming out. But seven is aggressive. That's how we would kind of be looking at it now is we're just looking ahead. And we'd adjust that based on a lot of factors, including, you know, does the gas price environment of 350 still there or has it changed? And, you know, and how we see the well performance, you know, maintaining that production rate.

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, you know, the position. I think you've got, you know, five wells in at this point in time. You know, do you think that, you know, I'll just make something up and you guys can correct me if I'm wrong, but, you know, 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've at least drilled the, you know, 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 to sort of, you know, proving it up. I mean, it seems like you guys are five for five on the wells with, you know, no issues at this point in time. So maybe just talk about your, you know, timeline to kind of get all this position proved up.

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'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. By the end of 2023, we should have this reportable. When you ask a question, we can answer it, you know, with a little calmer answer. And then I think as far as the drilling program, our goal is to de-risk this whole acreage, you know, by maybe the end of 24, early 25, as you extend these wells from foot fence to footprint, whether we're going north, south, east, and west geologically, so that And in some of these wells in 2024, you'll drill two wells per pad site. So we've got just this abundance of acreage so we can do that. I think we'll start coming down there. And some of them will be bojo wells, some will be Hainesville wells. 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 you have to trust what we're doing right now.

Okay, that's helpful, caller. And then just lastly, in terms of some of the early wells in play, you're obviously starting to build up some pretty good production history. Are you seeing those wells holding there pretty flat with fairly limited pressure drawdowns on some of those first couple wells?

You know what we expected? We've demonstrated that 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. 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

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

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