Thank you for joining us, and welcome to Comstock Resources' Earnings Conference Call for the Second Quarter of 2024. I will now turn the call over to Jay Allison, our Chairman and CEO. Please continue.

Thank you. I want to thank everybody for spending the time with us this morning going over our results. We appreciate your time. Welcome to the Comstock Resources second quarter 2024 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 presentations. There you'll find a presentation entitled second quarter 2024 results. I am Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to Slide 2 in our presentations and note that the discussions today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations in such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Before I start in the formal part of the presentation, I'd like to make a few comments. As a pure-play natural gas producer with 750,000 net acres in the Haynesville Shale basin, which is the best location to serve the growing natural gas demand along the Gulf coast, the future for the company has never been brighter. However, the present challenge is managing through these times with natural gas prices at all-time lows on an inflation-adjusted basis. So, now it's how you manage the present to shine the brightest when the rebound occurs. We have all the tools to accomplish this, including a very experienced management team who has managed in much harder times, strong financial liquidity of $1.2 billion, the industry's lowest cost structure, no bond maturities until 2029, and a very supportive major shareholder with the Jones family who recently directly invested $100 million in the company to support our leasing program. Our 300,000 net acres in legacy Haynesville still has over 1,400 net drilling locations, which represents over 30 years of future drilling. In addition, we have captured 450,000 net acres in our emerging Western Haynesville area that continues to look promising with each new well that we drill. Our operations group, as Dan Harrison will address in a few minutes, is becoming more efficient with each new well drilled and is bringing down our drilling and completion cost in the new play. So even when the quarterly numbers are weaker due to natural gas prices being low, we are more encouraged than ever about the future because we trust our core region as well as our Western Haynesville region and know our task is to execute daily to continue to create wealth by de-risking our new play and by reducing well cost in our new play. We are in a very volatile time, but we have been here before and I've never seen a brighter future for natural gas in more North America for the world than I see today. Now, we'll go to Slide 3, the second quarter 2024 highlights. On Slide 3, we summarize the highlights for the second quarter. Our financial results continue to be heavily impacted by the continued weak natural gas prices as our average realized gas price before hedging was $1.65 for the quarter. With hedging, it was $2.12. As a result, our oil and gas sales, including hedging were $278 million in the quarter, and we generated cash flow from operations of $118 million or $0.41 per share in adjusted EBITDAX was $167 million. Our adjusted net loss was $0.20 per share for the quarter. In the second quarter, we drilled 11 successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 11,346 feet and we turned to sales, 12 successful operated Haynesville and Bossier shale horizontal wells with an average IP rate of 22 million per day and average lateral length of 8,847 feet. We're continuing to advance our Western Haynesville exploratory play. The Western Haynesville acreage position totals more than 450,000 net acres. We currently have 12 successful producing wells in our new play, 6 from the Haynesville Shale and 6 from the Bossier Shale. We recently completed the drilling activity on both two well pads in the Western Haynesville play. With the drilling efficiencies from the pad drilling, we reduced the latest well-drilled times to 54 days. We expect to turn the next 6 western Haynesville well shales around the end of the year and we currently have two rigs running into play today. I'll have Roland go over the second quarter financial results. Roland?

Thanks, Jay. On Slide 4, we cover the second quarter financial results. Our production in the second quarter of 1.4 Bcfe per day increased 4% from the second quarter of 2023. With the very low natural gas prices offsetting this production increase, which resulted in our oil and gas sales in the quarter of $278 million, declining 2% from 2023's second quarter. EBITDAX for the quarter was $167 million, and we generated $118 million of cash flow in the quarter. We reported an adjusted net loss of $58 million for the second quarter, or $0.20 per share as compared to $1 million of net income in the second quarter of 2023. The higher DD&A in the quarter, which was attributable to the decline in proved undeveloped reserves, which results from having to use the very low natural gas prices required by the SEC to determine reserves, accounted for much of the loss of the quarter. As natural gas prices improved, those proved undeveloped reserves will be back on the books, and we'll see the DD&A rate go back to its lower levels in future quarters. On Slide 5, we cover our year-to-date financial results. Our production in the first six months of 2024 of 1.5 Bcfe per day was 6% higher than the first six months of 2023. Natural gas and oil sales in the first half of the year were $614 million, which was down 9% from 2023's first half despite the increase in production, and that's also due to the lower natural gas prices. EBITDAX for the first six months of the year was $396 million, and we generated $300 million of cash flow during the first half of the year. We reported an adjusted net loss of $67 million for the first six months of the year, or $0.24 per share, as compared to $93 million of net income for the same period in 2023. On Slide 6, we break down our natural gas price realization in the second quarter. It was a very challenging quarter as our quarterly NYMEX settlement price only averaged $1.89. The average Henry Hub spot price in the quarter was a little bit better at $2.04. Our realized gas price during the second quarter averaged $1.65, reflecting that $0.24 differential to the settlement price and a $0.30 differential to our reference price. In the second quarter, we were 28% hedged, which improved our realized gas price to $2.12. On Slide 7, we detail our operating costs per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.84 in the second quarter, $0.08 higher than the first quarter rate, but the same as our second quarter rate of last year. Production and ad valorem taxes were $0.14. Lifting costs were $0.27. Gathering costs were $0.38, and our G&A costs were $0.05 in the quarter. Our EBITDAX margin after hedging came in at 61% in the second quarter, down from the 68% margin we had in the first quarter due to the even weaker natural gas prices. Slide 8, we recap our spending on drilling and other development activity during the quarter. We spent a total of $221 million on development activities in the second quarter. Virtually all of that was spent on our Haynesville and Bossier shale drilling program. In the first six months of this year, we drilled 18 or 14.9 net horizontal Haynesville wells and 9 or 8.6 net Bossier wells. We turned 30 wells to sales, or 27.9 net operated wells, and they had an average IP rate of 25 million cubic feet per day. Slide 9 recaps our balance sheet at the end of the second quarter. We ended the quarter with $325 million of borrowings outstanding under our credit facility, giving us a total of $2.9 billion in debt, including our outstanding senior notes. In early April, we issued $400 million of additional notes due in 2029 and used the proceeds to pay down outstanding borrowings under our bank credit facility. On April 30th, our bank Group reaffirmed our borrowing base at $2 billion and our elected commitment stayed the same at $1.5 billion. So at the end of the second quarter, we had $1.2 billion of liquidity. I'll now turn the call over to Dan to discuss our operations.

Okay, yes, thank you, Roland. On Slide 10 is our current drilling inventory as it stands at the end of the second quarter. Our total operated inventory now has 1,698 gross locations, with 1,300 net locations, and this equates to an average 77% working interest. Our non-operated inventory has 1,227 gross locations and 159 net locations, which represents a 13% average working interest across the non-operated inventory. The drilling inventory is split between Haynesville and Bossier locations, and we have it split into our four different groups with our short laterals that go up to 5,000 feet, our medium laterals run between 5,000 and 8,500 feet, our long laterals from 8,500 feet up to 10,000 feet long, and our extra-long laterals for those over 10,000 feet. In our gross operated inventory, we currently have 258 short laterals, 352 medium laterals, 446 long laterals, and 642 extra-long laterals. The gross operating inventory is split with 52% in the Haynesville and 48% of our locations in the Bossier. Sixty-four percent of our gross operated inventory have laterals longer than 8,500 feet, and 38% of the total gross operated inventory have laterals longer than 10,000 feet. The average lateral in our inventory now stands at 9,077 feet, which is up slightly from 9,015 feet that we had at the end of the first quarter. Our inventory provides us with over 30 years of future drilling locations based on our current 2024 activity. On Slide 11, we have a chart outlining our average lateral length drilled based on the wells that we have turned to sales. During the second quarter, we turned 12 wells to sales with an average lateral length of 8,847 feet. The individual lengths range from 4,222 feet up to 10,047 feet. Our record longest lateral still stands at 15,726 feet. Eight of the 12 wells turned to sales during the quarter had laterals longer than 8,500 feet. During the second quarter, we did not have any extra-long lateral wells that turned to sales. One of the 12 wells turned to sales during the second quarter was on our Western Haynesville acreage. This was the Ingram Martin 1H well, which had a lateral length of 7,764 feet, and this well was reported on our last call. Looking ahead, we have several extra-long laterals slated to turn to sales over the remainder of the year. We do expect our average lateral length for all of 2024 will be approximately 10,150 feet on a total of 45 wells that will turn to sales. To recap our long lateral activity, we have drilled a total of 103 wells with laterals longer than 10,000 feet, and drilled 38 wells with laterals over 14,000 feet. Slide 12 outlines our new well activity since we last provided well results in late April. Since our last call, we have 15 new wells that have been turned to sales. The individual IP rates on these wells ranged from 10 million a day up to 31 million cubic feet a day with the average test rate of 21 million cubic feet per day. The average lateral length was 9,802 feet with the individual lengths ranging from 4,222 up to 15,303 feet. Recapping our activity, we are continuing to run five rigs after dropping two rigs in the first quarter. For our completions, we have been running two frac crews all year since we dropped down from three frac crews at the beginning of the year. This month, we also temporarily released one of our two frac crews for a short two-month gap until we pick it up again early in the fourth quarter. Two of the five rigs are currently drilling in the Western Haynesville. Both of these rigs recently finished drilling our first two well pads on the acreage, and these two well pads will be completed in the fourth quarter and turn to sales just after the first of the year. In the Western Haynesville, we anticipate having a total of six wells that will turn to sales from November just after year-end.

Thank you, Dan. Thank you, Roland. Thank you, Dan, for talking about the horseshoe wells. I'm thinking about the majority owner. The stock owns the Dallas Cowboys. The Cowboys and horseshoes go together. So thank you for that report. Let's go to Page 15. I direct you to Slide 15 wherever we summarize our outlook for 2024. As we stated in the last quarter, we really have taken a number of steps in response to the significantly low natural gas prices this year. During the first quarter, we announced we'd release two of our operated drilling rigs. We reduced our rig count to five rigs. We also released one of our frac spreads, reducing our frac spreads to two spreads. We no longer have any long-term commitments for our pressure pumping services. With those steps, our 2024 CapEx is expected to be down 34% to 41% from the 2023 level. We suspended our quarterly dividend, which saved about $140 million a year in dividend payments. In late March, majority stakeholder Jerry Jones invested an additional $100.5 million into the company through an equity placement that the company had. Starting in late February, we did add significantly to our hedge position starting in the fourth quarter of 2024 and extending that through the year-end 2026. We are targeting a hedge level of 50% of our expected production level through those years. In early April, we further enhanced our liquidity position with a $400 million senior notes offering, and we continue to maintain a very strong financial liquidity, which totaled just under $1.2 billion at the end of the second quarter. 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. We remain very focused on improving our Western Haynesville play and continuing to add to our extensive acreage position in this exciting play. Our Western Haynesville acreage position totals over 450,000 net acres to date. We believe that we're building a great asset in Western Haynesville that will be well positioned 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 that began to show up in the second half of next year. I'll now turn it over to Ron to provide specifics for the rest of the year. Ron?

Thanks, Jay. On Slide 16, we provide financial guidance for the third quarter and the remainder of 2024. For the third quarter, we expect our D&C CapEx to range between $135 million and $185 million, and our full-year D&C guidance range on CapEx remains $750 million to $850 million. The midstream capital outlook remains unchanged and the leasing capital for the third and fourth quarters remains in the $2 million to $5 million range. The full year moved up $5 million to $10 million just due to actual second quarter leasing costs. LOE and GTC costs both for the third quarter and full year remain unchanged from prior levels. On the production and ad valorem, the guidance range remains the same, which includes the impact of a lower severance tax rate in Louisiana, basically being offset by a higher ad valorem rate. The DD&A rate, as mentioned by Roland earlier, is expected to be higher through the remainder of the year due to the current low prices. Looking ahead though, we would anticipate that to return to our more normal level in the kind of price environment that we see in 2025. No other changes to our G&A or interest outlook that we provided in prior quarters, and we continue to anticipate deferring virtually 100% of our deferred taxes. With that, I'll turn the call over to the operator for Q&A.

Our first question comes from Carlos Escalante of Wolfe Research.

Hi, good morning, gentlemen. Thank you for taking my question.

Good morning.

Good morning. If I use the second quarter completed wells as a proxy for your drilling pace on wells under 5,000 feet, I'm estimating that the number is roughly less than 10% per quarter. Considering your horseshoe concepts update, how do you foresee the allocation towards a potentially successful program in the upcoming quarters and years?

This is Dan. I'll kind of address just the short laterals. We did have one short lateral that we reported here. We had basically already drilled that well when we had our last call. But I think with the success of the horseshoe concept, I think really the majority of all the wells, short wells that we have in our inventory will convert to long laterals, but there will be a few where we've just got maybe one short lateral left, and that's all that's left to be drilled, and it's bounded by other wells where, if you do decide to drill, you have to drill a short lateral. So we won't be able to convert all of them to 10K horseshoe wells, but I think a good chunk of the inventory will be able to convert to 10Ks.

Wonderful. And then if I might follow up real quick on that same topic, I think that the fact that it's less than 10% that you're drilling at that specific length sort of emphasizes why the market may be able, or may be reticent to recognize that inventory when you say 25 to 30 years of inventory. So on that same topic, Dan, what's the end goal here? Is it more of a recognition of what the risk may be on the concept, or is this the first one for many to come?

I believe this is the first of many to follow. As is often the case with new initiatives, the public wants to see additional wells drilled. They want to see the process become routine and the risks minimized. It appears that they are making more progress in the other basins, particularly in the Permian. If we consider the Eagle Ford, there was a horseshoe well successfully drilled earlier this year without any issues. We are nearing total depth on the well we are currently drilling, and it has been free of problems thus far. We are optimistic about our ability to significantly reduce the short laterals in our inventory. We will have more 10Ks, and our average lateral length will increase, along with improvements in our efficiencies. It is important for us to continue drilling to make this process routine and mitigate some of the risks involved.

Well, like Dan said, if you save $8 million when you drill these wells, a couple of them, that does add to our inventory because some of these wells we push back to the latter part of our drilling inventory. But now if you have these cost savings, you can bring them forward if you need to drill them.

Right. We have drilled some of these wells because we've had them for a while and some of the production has declined. To protect our leasehold, we will include some of these in our drilling schedule.

Wonderful. Thank you, gentlemen.

Thank you.

Thank you. Our next question comes from the line of Jacob Roberts of TPH & Company.

Morning.

Morning.

Wanted to dig in a bit more on the Baker wells and some of the issues that you highlighted. Can you speak to any correlation between what occurred and the IP rates? Is there any impact to the EUR we might expect? And does this mean that region is something that might need to be avoided in the future?

It's certainly located at the edge of our acreage. We know from previous drilling in that area that the wellbore stability is a bit more challenging. The rock presents more instability than usual. Typically, drilling costs in that area are higher, around $15,000 to $17,000 per foot, compared to $1,450 to $1,500 per foot in the state line area in Texas. We drilled five wells, two of which faced significant challenges. One well was drilled to total depth, but we lost a lateral and had to sidetrack it twice to complete the drilling. Another well also required two sidetracks. It was not an easy process, but it was an isolated incident. Given the location of our acreage, we were aware that this area would be difficult to drill. We chose to proceed with drilling to avoid losing the acreage, which was set to expire, so we developed fully and drilled five wells across the section. Removing this situation from consideration, our average total drilling and completion cost for this quarter would be around $1,500 per foot, which is where we anticipate being for Q3 and Q4.

Okay, great. I appreciate that. My second question. So the two well pads sounds like the drilling is wrapped up. We appreciate the update on the days to drill, but can you give us a sense of where cost per foot is sitting on the drilling side of things now that you're done?

Yes. So actually we see costs going down a little bit. We actually started seeing a big movement in pipe prices just here in the last couple of months. We're working through the inventory that we already have. But I think by the time we get to wells that turn to sales in Q1 that we're completing right at the end of Q4, we're seeing some significant savings on pipe costs. And so we'll definitely see our D&C cost basically come down Q3 and really further into Q4 and Q1.

Great. Appreciate the time, guys.

Thank you. Our next question comes from the line of Charles Meade of Johnson Rice.

Good morning, Jay, Roland, Dan, and Ron.

Hi, Charles.

Hi, Charles.

I wanted to ask a question. Dan, I think you partially answered this in your prepared remarks, but I want to ensure I heard it correctly and perhaps get more details. When I looked at your third-quarter capital expenditures, it appears to be down compared to the second quarter, but there also seems to be a considerable range between the upper and lower bounds. It sounds like you mentioned in your comments that you've recently reduced one of your two frac crews and will only be operating one crew for August and September, with plans to ramp it back up later. Did I understand that correctly? Is that the reason for the decline in capital expenditures in the third quarter, and are there other factors contributing to the wide range?

I think it's not solely that, but it's a significant factor. It's a reflection of reducing the number of rigs earlier this year. With fewer wells to complete, we went from three rigs to two at the beginning of the year and have been running two all year. We recently paused one frac crew for a couple of weeks, but we expect to resume it around the first week of October. Additionally, as I mentioned earlier, we're observing costs decreasing. Pipe prices, in particular, have dropped significantly, which is one of the last areas where we've seen price reductions. Rig costs and frac costs have already decreased somewhat earlier this year. Overall, the decline in service costs, along with the lack of one frac crew for two out of the three months in Q3, is the main factor affecting our CapEx.

Got it. That is helpful detail. And then the question about the drilling times in the Western Haynesville. You guys highlighted the 54 days. Can you put that in some bigger context of where your early wells fell on, how many days it took to drill, and also what you think is a reasonable goal for days to drill in the next 12 or 18 months?

Yes, I believe we have made significant improvements in our drilling days in the Western Haynesville. The wells vary in length, which affects the number of days, particularly in the Western Haynesville due to higher temperatures. Initially, we were around the 85-day mark, but we have reduced it to 54 and 56 days for the last couple of wells on two well pads. This is quite noteworthy, and I believe there is still potential for further improvement. We still have some areas to address, particularly in drilling the laterals, so I think we can further decrease that number.

You might add that those went to the low number of days was with those were long laterals, correct?

Yes, and those were both. I think one of them we had one was a 10,000-foot lateral. One was just under an 11,000-foot lateral. So both in the Haynesville with the higher temperatures. So, I mean, that's kind of the, everything we've drilled today, that's basically what I'd say are the toughest wells that we've drilled, basically TDs, lateral lengths temperatures. So, yes, we've made a big, big improvement there. And like I said, we still are working on a few things to work those numbers down a little bit lower.

Well, Charles, from first well to the 16th well, you go from 85 days to 54 days. That's 31 days you save. That's a whole bunch of drilling. Even if you use 26, 27. That means that the wells that we're drilling now, I mean, we've saved half the time if it's 54 days, and we've already shaved off 26, 27 days. So these wells, you'll probably end up drilling another well per year because of our drilling efficiencies with the same number of rigs, it could equate to that. That is huge savings. And your questions are on cost savings. 31 days of drilling with these deeper, hotter wells, that's a lot of money.

Got it. Thank you. That's helpful context. Jay and Dan.

You bet. Thanks, Charles.

Thank you. Our next question comes from the line of Bertrand Donnes of Truist.

Hi, good morning, guys. Just staying on the horseshoe wells. The example you give looks very promising on the cost side. I know it's early, but are there any expectations on the productivity of these wells? Do you get the full amount that you would have gotten from the two shorter laterals, or do you kind of lose like 5% of the recoveries? And how does the shape of that well look like? Is it a lower pro forma IP than maybe the two combined wells, but a lower decline or any thoughts there?

Yes, that's a really good question. So we definitely expect the performance to be the same as the 10K well. The only really mild difference between the horseshoe well and a 10,000-foot across two sections of straight lateral is on the straight lateral; you do get complete across the section line. That 660-foot, there's a state you can't perforate within 330-foot of the lease line. So on a horseshoe well, you basically got two 4,600-foot sections. 9,200-foot. We're on a 10K. So on a straight 10H, you get to perforate a little bit more as far as the amount that's completed across the 10K, but on a per unit basis, we expect the performance to be totally the same.

That's great color. Thanks. And then shifting gears on the private side of the Haynesville, we can see some of the data on our side. It looks like there's been some drops on the rig side throughout the year, but over the last four months or so, it's been kind of stable. I'm just wondering if you have a temperature check, maybe on the private operators in your discussions with them. Do you get the impression that they've already settled into a steady program or are they also looking at the strip right now and actively debating, maybe dropping some activity?

Well, we really don't have a lot of insight other than kind of knowing how we coordinate our schedules with the other operators, but I think the private operators cut rigs back very dramatically, and they kind of kept that same rate. So we haven't seen any increase in activity that's on the horizon. I think they're waiting to really see when gas prices kind of justify that. And so the higher rig count has been on the public side, mainly with the southwestern. Yes, I think other than that, everybody else but them has dropped a lot of rigs.

Yes, I agree with Roland. I think it will basically stay status quo until everybody sees these gas prices move up.

Well, if you look at the core, that 9,000 square miles, what they call the core, when you drill a well there, either Bossier or Haynesville, you got a 40% decline in the first year. So you need to be real careful about drilling in $1.90 gas price, whereas in like in the horseshoe in Haynesville, we hadn't seen that type of decline. So that would be another reason, whether you're private or public, that you don't aggressively drill these wells.

Great point. Thanks, guys.

Thank you. Our next question comes from the line of Kevin McCurdy of Pickering Energy Partners.

Hi, good morning, guys. I wanted to ask about activity toggles. Now that the debt covenant is of less of concern, just given the state of gas prices, is there any situation which would result in the FRAC holiday extending into Q4, or are there any other changes you would consider this year to activity levels?

I believe we've got the frac holiday figured out. I don't expect it to extend into Q4, based on our current knowledge and the price trends we're observing. That's a straightforward response, but we are monitoring our schedule closely.

We look at it all the time. So, we can obviously pull those levers if we see that you still see gas prices improving as you get to the very end of the year. And so, to have, so I think unless '25 changes significantly, I think that's kind of what would drive our activity level in the fourth quarter.

And we're not contractually obligated, obviously, with frac crews. So, I mean, we could definitely, if things change really, we can change with it.

And then, fortunately, in the fourth quarter, we do hit our swap position where we're hedged 50% at $3.50. So that's something that if prices do continue to deteriorate, we will at least end up in that quarter. And then we have, I think we've adequately hedged for '25, '26 so far, with 35% of our production hedged at the $3.50 plus range. And as we said in the opening, our goal is to hedge at least 50% of all of the '25, '26 production. So we are getting out of the 20% plus hedge environment into the 50% environment.

Thanks for that. That's helpful. And just wanted to ask, did any of the Q2 weather impacts spill into the third quarter, or did you guys see any impacts from the hurricane?

We experienced some effects from Hurricane Beryl. While our Western Haynesville area was unaffected, the hurricane moved into our core area and caused numerous tornadoes. The main issue for us wasn't our operations directly, but rather the third-party treating facilities we rely on, which went offline due to power loss. This situation adversely affected our production, and we faced these challenges for about a week to ten days.

And that impact is incorporated in the third quarter guidance, correct?

Yes, correct.

Appreciate it. Thank you.

Thank you. Our next question comes from the line of Leo Mariani of ROTH.

Yes, guys. Wanted to just dig in a little bit more into kind of expectations heading into the fourth quarter. I think you guys have previously talked about fourth quarter production being down around 10% year-over-year. I know a couple of wells kind of slipped into January potentially. So, wanted to see if that's still roughly valid. And then with respect to fourth quarter CapEx, looks like that's getting ready to maybe move a little higher as the frac crew comes back. Just trying to get a sense, should 4Q CapEx look more like second quarter of '24 CapEx?

So, good questions. There's no change on that in terms of the fourth quarter '24 versus fourth quarter '23. It looks like it can be down about 10%. And as we've talked about, that's a function of the timing of dropping those two rigs in February and March and kind of that six to nine-month lag between dropping activity and seeing it show up in production. And then you're absolutely right. The CapEx level in the fourth quarter will return more to the level that you mentioned. A lot of that is a function of what we've discussed earlier with the frac holiday, all occurring in the third quarter. That's why the third quarter and fourth quarter are so different in terms of CapEx levels.

In the Western Haynesville, there are generally no wells expected to come online in the second half of the year, with significant production anticipated toward the end of the year. A few wells might start before that, with more coming in early January. We believe this aligns well with the gas market.

Yes, Leo, regarding the two deer analysis, we have drilled two wells per pad. The Hodges and Miles wells are expected to come online in the last week of December or the first week of January 2025, based on our modeling.

Okay. That's very helpful color. And then I know obviously 2025, a little early here for that today, but just trying to get a sense and looking at strip prices for next year, kind of 3.25 to 3.30 currently. As you look out, is that the right level that you think for Comstock to kind of get back to where it was and add the couple of rigs to kind of get back to the seven rigs? Is that kind of how you're thinking about it here today, is to kind of bring those rigs back kind of way next year?

Yes, that price level is a real, obviously, it definitely works well for Comstock. And it's still early, like I said, we don't really set our activity for next year until we get more into the fourth quarter and then November, even December and make those decisions. But I mean, yes, we do like the way that what the futures market has out there. We'll just see if that materializes, and then having a stronger heads position will also help support that program in '25 than what we had coming into '24.

Thanks, guys.

Thank you. Our next question comes from the line of Neil Mehta of Goldman Sachs.

Yes. Good morning, team. Thanks for taking the time. Two questions. The first was just your perspective on the A and B market and how do you think about both acquisitions or potential proceeds from divestitures as we make our way over the course of the next year? Are there opportunities to optimize on a smaller scale or even medium to larger size bolt-ons?

We have continuous incoming opportunities that we evaluate, responding to some, like acquiring acreage last quarter. Our main focus now is to control our spending and increase our production. We need to address that. Most of our inbound inquiries come from data centers, utilities, and storage companies. We also have the opportunity to clean up additional acreage, which Ron has budgeted for. Our aim is to build inventory; with over 450,000 net acres in the Western Haynesville, we expect significant inventory growth alongside our 1,400 core drilling locations. This aligns with our operational focus. We've tested our geological group for four years with successful outcomes, leading to new acreage acquisitions. The performance of our wells has steadily improved, and drilling efficiency has enhanced, allowing us to drill more wells in a shorter time. If we maintain the quality of our geology and the performance of our wells, we are positioned to generate substantial value when the market demands more gas for power generation, LNG, and industrial use. We have invested significantly in establishing a strong presence in the Western Haynesville, and our goal is to mitigate risks with each well drilled. We are not pursuing a large-scale acquisition strategy.

Yes, that's great perspective. And the follow-up is just one question we get asked a lot is sort of the breakeven of the Western Haynesville. When you think of your cost of supply to earn a cost of capital return fully burdened for G&A and interest and all the ancillary, what is that breakeven in your mind for Henry Hub equivalent?

The situation in the Western Haynesville is evolving as we continue to reduce drilling and completion costs. With our efficient program planned for next year, utilizing four rigs and implementing pad drilling, we expect costs to align more closely with our traditional Haynesville operations. The two areas will be quite similar in terms of internal rate of return and cost per reserves discovered. While we invest more money in a Western Haynesville well, the reserves are significantly higher, with reserves being double compared to the traditional play. The approaches to production differ as well. Initially, traditional Haynesville wells produce more within the first six months, but after that, Western Haynesville wells yield greater production due to our tighter choke method. Ultimately, the returns, especially as we transition into a more development-focused stage, are very comparable, and we are pleased with where we're heading.

Well, I think to add on to that, if you look at this inventory deflation, which will happen, you run out of tier 1, you go to tier 2s. So the bang for the buck is not quite there in tier 2 or 3 because you run out of tier 1s. So if our Western Haynesville is compared to Tier 1 and we have all this acreage and we de-risk it, our inventory will be materially stronger than you would have if you did a big M&A. M&A is just acquiring more in the same area.

Thank you, team.

Thank you. Our next question comes from the line of Phillips Johnston of Capital One Securities.

Hi, thanks for taking the question. It's really a follow-up to Leo's question. The '25 plan is obviously very much TBD, but if you do stay at five rigs for the balance of the year, you bring that frac crew back in Q4. As you look out into the first few months of next year, just from a momentum perspective, would you expect your volumes to be directionally flat, up or down versus Q4 levels?

That would definitely be up with those Western Haynesville wells coming on. Yes.

Yes. Okay, that's all. Thanks, Ron.

Thank you, Phillip.

Thank you. Our next question comes from the line of Noel Parks of Tuohy Brothers Investment Research.

Hi, it's Noel. Good to talk to you. Just had a couple I want to run by. So in terms of the Western Haynesville with the greater depth and heat and pressure and so forth. I just wonder if you could talk a bit about where things stand with the instruments and tools that I understand had some adaptation to be able to work at those levels. Just where are you, just any of that you're doing proprietary, anything new that you're going to be implementing in the next slate of wells?

This is Dan. So we basically use the same tools in Western Haynesville that we use in the core. We basically, how we apply them is a little bit differently. But as far as our MWD tools, our motors, essentially the same providers for the Western Haynesville that we have in the core. Now, there's some of our providers up in the core of that, can't, doesn't have the full breadth of tools to be able to work in the Western Haynesville. But the same guys we have working down there working the core also, so same tools.

Got it. And you just mentioned, or Roland just mentioned how you produce the Western Haynesville wells and the effect that might have on declines and so forth. Just what are your thoughts? What have you learned so far about choking and how that might influence production rates, shape of the curve, etc.?

We initially approached production in the Western Haynesville cautiously, using much lower drawdowns compared to our established practices in the core area, where we have extensive experience. In the Western Haynesville, we are just beginning to learn how to optimize production. As we progress, we are gradually beginning to enhance our drawdowns to improve production rates, which we know is possible. However, we are being careful not to overdo it and are closely monitoring the drawdowns to avoid pushing too hard too soon. Overall, everything is looking promising, and we're taking a measured approach in this process.

And we produce via tubing.

Yes. And we do everything that we complete up in the core, we flow up the casing for quite a long time. We don't come back and tube up those wells for in some cases, maybe a couple of years later. But in the Western Haynesville, just because of the very high initial flowing pressures and what the well had with the casing, the burst pressure rating is on our casing strings, we tube those up while we're completing the well. So the day that they turn to sales, all those wells are flowing up to me. So it's a little bit different production profile. You get a lot more pressure drop, downhole before you reach the surface. So, the pressures obviously would be a lot higher if we were flowing up casing. The surface pressures would. But that's probably the biggest difference. As far as down the hole, all the Western Haynesville wells are tubed up; all the core wells flow up casing.

And you're asking about the drilling. If you look at our efficiencies, and Dan's right, I mean, some of the tools and the casing, we do use that in the core, but it's how you use it. What type of intermediate do you set? Do you tube the wells up? What type of completions do you have? What kind of drill pipe do you have? I mean, there's a lot of ingredients in the kitchen and not everybody produces the same final product. So, it'd be very difficult if you're drilling your first 19,000-foot vertical and 10,000-foot lateral well to come in there and have the success that we've had. When you've got a really good operations group and it took them 85 days the first time, well, now you're at 54 days. So a lot of that skill set, you have to spend a lot of money to perfect it. When you can perfect it, then you can lower those costs and you create real wealth and you have to have the footprint to do that in. And we captured the footprint at very low cost with most of it being held by production. So that's the difference in this play.

Great, thanks a lot.

Thank you. Our next question comes from the line of Paul Diamond of Citi.

Hi, good morning. Thanks for taking my call. I wanted to ask about the opportunity related to the theoretical horseshoe wells. In your inventory, approximately 16% is below 5,000 feet. I'm interested in knowing how many of those you believe you could potentially convert based on current expectations and how that would fit into your overall production or drilling schedule.

Yes, that's a really good question. So you're right, we do have about 15% or 16% of our total inventory is the short laterals. And we're actually currently working through that process right now of how many of those we think we can convert over to long laterals. I think the majority of them that we can. I don't really have a real fixed number I can give you today, but I'd say the majority of them are looking at moving over. And like I said, the only reason that we could not would just be because, I mean, obviously, you have to have two of the 5K laterals kind of side by side, right, to have the horseshoe opportunity. Some of our short sticks in our inventory, you just got one stick basically. So obviously that wouldn't be a horseshoe candidate. But other than that, I think every if you got two of them side by side, every one of those is a horseshoe candidate. So we're working through that process right now, seeing which one of those we can convert. They'll go into our long lateral bucket, which right now that's about 26% of our inventory. So we'll significantly boost that up above 25%, 26%. And that percentage in the short laterals will get a lot lower, which will be great. I mean, that opens up a lot more wells that have really good economics that we can basically decide to put on our drill schedule or should we, for some reason, for a leasehold reason or whatever, we kind of need to drill it. It'll still fit in with what we normally would be drilling with good economics.

Understood. That actually kind of portends into my follow-up. Assuming your undercurrent assumption you guys are working with, how would a horseshoe two 5,000 foot compare economically to an existing 10,000 foot?

So yes, substantial, but I don't have the numbers in front of me, but yes, substantial rate of return, substantial improvement. I mean, you're going to save $8 million, $4 million per basically off those 5K laterals. So it just drives all the key parameters significantly higher. Like I said, the cost. So the cost to drill a straight 10K to drill a horseshoe well is essentially the same. I said a 1% to 2% premium, but I mean, that's within the plus-minus of any well we drill on kind of where our costs are going to end up. So, we look at the economics for horseshoe well to be essentially the same as all of our other 10K laterals.

Understood. Thanks for your clarity.

Thank you. Our next question comes from the line of Gregg Brody of Bank of America.

Hi, hello, good afternoon guys. Thanks for all the update. As the credit guy, I've started to see these horseshoe wells pop up a few places and I realize there's some data; there's been a number of them in other basins. I'm just curious, is there something that we should think about that is tricky about these, or it really is just drilling a lot of lateral in a U shape that seems like physics suggests we can do that now?

Right. Sometimes the old saying, necessity is the mother of invention. I mean, we - you drilled a 90-degree turn to drill these laterals already, right? So you do the 90-degree turn, you're drilling the lateral. So it's the same tools, it's the same motors that we run. You just make another turn, and you just stay with it until it goes all the way around 180 degrees. Now, I think until you kind of have to do it or you're looking at your inventory improvement, a lot of people probably just kind of don't push to go there. But really, I mean look, there is a little bit more risk to drilling a horseshoe well. And you've got to get casing around the curve. You have to get, when you're completing and pumping your perforating guns down and plugs for all your frac stages, all those have to get pumped around the curve. I mean, but really, I think the risk of that's pretty small. The industry kind of already has shown it in the Permian, and I think the Eagle Ford, these other areas. But I think you just got to prove it out and you just basically got to show people the results. And I think, after you do more of them, it becomes a little bit more routine and the risk is greatly diminished.

We are very close to reaching total depth on our first well. Last night, I was aware of the situation.

We're probably within 500 foot of TD and we have had zero problems drilling.

And that's when I looked at you being asked earlier about how much potential of your locations could be converted. Should we think that it's just the ones that are in the up to 5,000 feet, or should we think also about the 5,000 to 8,500 feet that could be converted? Trying to get a sense of how much of that you didn't quantify it. I know it's early days, but I'm curious if you have a range that you would think about there.

Well, that's a really good question, and we've already kind of had some internal discussions about that. Can you take a 7,500-foot lateral and turn it into a 15K horseshoe? Now we're not ready to kind of jump out there and do that yet. Look, the industry gets better with time. They get faster, they get longer. Tools get better. If you have the demand for tools and the demand for certain services, in time they show up and they get developed and they get refined. So I think in time. I think, yes, I think that the industry will maybe go there. I mean, look, a 7,500-foot lateral has a lot better economics than a 5,000. So the rush to start doing 15,000 horseshoes, it's not really going to be there right now. But I do see, and it's what your acreage, it's how it's laid out and what your options are. I mean, if you can drill up, if you got two sections or three sections, like we'll typically, we'll just drill a 15K straight lateral. We're not going to do a bunch of 7,500-foot horseshoe 15K laterals, what I mean? So but it's a very good question. And I think, yes, I think in time in the future, I think there'll probably be some people that will probably try to push the horseshoe lengths a little bit further. They do have a little bit more torque and drag. I mean, obviously, when you're pushing and pulling pipe around the 180-degree bend, it adds more drag push tripping in and out of the hole. So, a 10,000-foot horseshoe will maybe it's kind of, maybe more like the equivalent of a 15,000-foot straight lateral when you look at the drag going in and out of the hole, if that makes sense.

That does. And then just to come back to my credit routes, just a few follow-ups that you might get for some credit guys. I don't think you see you getting, you're a 3, 4 today. I think you're okay for next quarter to get into 3, 5 or not going through the 3, 5. Is that fair? And if not, is it just a pretty easy amendment that you would get? And then just as part of that, I know the dividend was suspended this year. Just as you look out in the future, how do you think about that today?

Yes, Gregg, I think it's clear that the gas prices play a crucial role in determining our EBITDAX, which is a key component of that ratio. The gas prices will significantly impact where we land. It's important to note that we assess this over a full four-quarter period within any single quarter. However, we are consistently monitoring our position. We had anticipated reaching that 3, 4 level, and we were fortunate to maintain it. We'll keep a close eye on it in the third quarter just as we did in the second quarter. Regarding the dividend, we are not considering it until we reduce our leverage significantly and look further ahead. Our primary focus is on generating strong free cash flow, which will be used for debt reduction to bring our leverage ratio closer to the levels we experienced in 2022, ideally under 1 times leverage.

We were really monitoring the second quarter. And again, we did stay fine in the third quarter. We didn't expect gas to be $1.90 on Monday. So you do look at that price and say, well, okay, so you got to really monitor the third quarter. And then in the fourth quarter, we would expect a little price appreciation and the hedges come in and help. And then we have, I think we've adequately hedged for '25, '26 so far, with 35% of our production hedged at the 350 plus range. And as we said in the opening, our goal is to hedge at least 50% of all of the '25, '26 production. So we are getting out of the 20% plus hedge environment into the 50% environment.

I appreciate the time, guys, and the education.

Thank you, Gregg.

Thank you. I would now like to turn the conference back to Jay Allison for closing remarks. Sir.

Thank you for your time. We've run over our scheduled hour, but as a company, we've always had a vision. Regarding the drilling of the horseshoe wells at 15,000 feet, we aim to reinvigorate a significant gas play, which is currently the Western Haynesville. We actively monitor gas supply levels, which have been trending down recently. Over the past several weeks, gas storage levels have dropped from 38% above the five-year average to about 16% above. We're entering a critical time in summer, and we notice that LNG is now over 13 fleet per day, and Freeport is operational again. Looking beyond September and October, we anticipate the startup of Corpus Stage 3, suggesting a strong fourth quarter in 2024 for the LNG fleet, which will extend into 2025. We are dedicated to managing our resources effectively while safeguarding our balance sheet. I also want to acknowledge the Jones for their significant investment in the acreage we've been acquiring, which I believe has substantial value. Thank you again for your time. We truly appreciate it.

This concludes today's conference call. Thank you for participating. You may now disconnect.