Comstock Resources, Inc. (NYSE:CRK) Q2 2024 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q2 2024 Earnings Call Transcript July 31, 2024

Operator: Thank you for standing by and welcome to Comstock Resources Second Quarter 2024 Earnings Conference Call. [Operator Instructions] I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.

Jay Allison: 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 located to serve the growing natural gas demand along the Gulf coast, the future for the company has never ever 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 now. 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?

Roland Burns: 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 offset 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 for $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.

Dan Harrison: 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, have 1,300 net locations, and this equates to an average 77% average 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 foot, our medium laterals run by 5,000 and 8,500 foot, 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. 64% 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 and this 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 is a chart outlining our average lateral length drill 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. Slide 13 is a summary of our D&C cost through the second quarter for our benchmark long lateral wells that are located on our core East Texas and North Louisiana acreage position. This covers all laterals greater than 8,500 feet long and during the quarter we turned 11 wells to sales that were on our core East Texas, North Louisiana acreage and eight of the 11 wells fell into our benchmark long lateral group.

In the second quarter, our D&C cost averaged $1,730 per foot on our eight benchmark wells, which reflects a 15% increase compared to the first quarter. Our second quarter drilling costs averaged $936 a foot, which is a 31% increase compared to the first quarter. The higher drilling costs for the quarter were associated with our Baker three well pad up in the Lake Bistineau area where we encountered significant drilling difficulties. In addition, four of our eight benchmark wells were drilled inside the boundary of a gas storage facility, which requires an additional shallow intermediate casing string to be set. Our second quarter completion cost came in at $794 a foot and this is a 1% increase compared to the first quarter. We do expect our D&C costs will return to normal levels remain flat to slightly lower for the next couple of quarters.

On Slide 14 is an illustration of a new development we have planned that we utilize the horseshoe lateral concept that has recently gained traction in the industry. While the small handful of horseshoe wells have been drilled in the other basins, only one horseshoe well to date has been drilled in the Haynesville Shale basin, which was earlier this year. To test the concept, we recently spud a single horseshoe well in DeSoto Parish, Louisiana that is located on one of our isolated single section acreage blocks. The well is currently drilling. We should reach TD within the next few days. This technology will allow us to develop acreage in the future that before could only have been developed by drilling short laterals with more challenging economics.

The section portrayed on this slide would have originally been developed by drilling four 5,000 foot laterals from two pads with a $40 million capital cost. We now plan to develop a section from a single two-well pads drilling two 10,000 foot horseshoe laterals for $32 million in capital. This capital cost represents only a 1% to 2% cost premium to a regular straight 10,000 foot lateral. The project will deliver 23% cost savings or $8 million, significantly improving the economics and also providing some additional benefits, such as reducing our surface footprint and lowering the emissions from fewer well bores. We expect the well performance from the horseshoe wells will match that of our regular 10,000 foot laterals. And once this technology becomes more de-risked, we can further increase the average lateral length of our inventory by converting short laterals into long laterals and further enhancing our efficiencies.

I’ll now hand the call back over to Jay to summarize our outlook.

Jay Allison: Hi, Dan. Thank you, Roland. Thank you. Dan, you’re talking about the horseshoe wells. I’m thinking about the majority owner. The stock is — 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 where 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 now 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. That 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, 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 and a 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?

Ron Mills: 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 quarter 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 fourth — 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.

Q&A Session

Operator: [Operator Instructions] Our first question comes from the line of Carlos Escalante of Wolfe Research.

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

Jay Allison: Good morning.

Carlos Escalante: If I go — good morning. If I go — if I use the second quarter completed wells as a proxy for your drilling pace on wells under 5,000 feet, I’m getting a number that is roughly less than 10% per quarter. Bearing in mind your horseshoe concepts update, how do you all see the allocation towards a potentially successful program going into the future quarters and future years?

Dan Harrison: 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 really already kind of had drilled that well when we were having, 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, that’s you have to drill a short lateral. So we won’t be able to convert all of them to 10-K horseshoe wells, but I think a good chunk of the inventory will be able to convert to 10-Ks.

Carlos Escalante: 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 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?

Dan Harrison: I think this is the first of many to come. And just like with anything that’s new, I think the public wants to see more of them drilled. They want to see it become routine, they want to see it de-risked. So I think they’re probably a little bit further into that process in the other basins, I think really mainly the Permian. And I think if you — the Eagle Ford for the horseshoe wells, there was one drilled earlier this year that was, and it was problem free. So, we, like I said, we’re almost at TD on the one that we’re drilling and it’s been problem free to date. So, we feel really good about it. I think we feel really good about significantly reducing the short laterals in our inventory. We’ll have more 10-Ks. Our average lateral length will be up, it’ll — our efficiencies will be way up. So we just need to do more where it becomes routine and to take some of the risk out.

Jay Allison: 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.

Dan Harrison: Right. And some of these we’ve drilled because they — we’ve had them for a while and some of the production gets low. So just to protect our leasehold is why, we’ll put some of these on our drilling schedule.

Carlos Escalante: Wonderful. Thank you, gentlemen.

Roland Burns: Thank you.

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

Jacob Roberts: Morning.

Roland Burns: Morning.

Jacob Roberts: 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?

Jay Allison: Well, it’s certainly out on the edge of our acreage footprint. That is, we do know from past drilling up in that area that the well bore’s stability is a little bit more. The rock itself just has a little bit more instability. And so really we had normally that area up there typically drills, the drilling cost is a little bit more expensive maybe $16,000 — $15,000 to $17,000 a foot is kind of normal, whereas back over in Texas, in the state line area, we’re in that $1,450 to $1,500 a foot. So, we had — we drilled five wells. Two of the wells were the ones that really gave us problems. We ended up had one well-drilled, the TD, we lost a lateral, we tried to sidetrack it. We ended up having to sidetrack it twice to get it drilled.

And we basically had another well that we had two sidetracks on. So wasn’t a very pleasant experience. But it’s definitely an outlier. If you look at just kind of where all the — where all our acreage is, it’s out on the edge. We knew that area was kind of tough to drill. So it’s just a one-time event. And it was, we drilled it because the acreage was expiring. We had to drill it or lose it. And so we did decide to do full development and drill five wells all the way across the section. So, we, that’s just a one-time event. I think if you do pull that out, we’re back around that $1,500 a foot total D&C cost for this quarter, which is where we’ll be at for Q3 and Q4.

Jacob Roberts: 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?

Jay Allison: 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 cost. And so we’ll definitely should see our D&C cost basically come down Q3 and really further into Q4 and Q1.

Jacob Roberts: Great. Appreciate the time, guys.

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

Charles Meade: Good morning, Jay, Roland, Dan and Ron.

Jay Allison: Hi, Charles.

Roland Burns: Hi, Charles.

Charles Meade: I wanted to ask a question. Dan, I think you partially answered this in your prepared remarks, but I just want to make sure I heard it right, maybe get an elaboration. When I was looking at your 3Q CapEx, it was — it’s both down versus 2Q, but it’s also a pretty wide range on the upper and lower bound. At least it seems that way to me. And so, Dan, I think I heard you say in your prepared comments that you recently dropped one of your two frac crews. You’re going to let it — you’re just going to be running one crew for August and September. Sounds like you’re going to pick it up again. Did I hear that right? Is that the driver of the CapEx decline in 3Q and what other pieces are there that maybe contribute to a wide range?

Dan Harrison: Well, I think there’s — it’s not totally that but that’s the kind of significant driver. That’s just kind of a reflection of dropping the rigs earlier in the year. I mean, obviously, we got less wells to complete. We went from three to two, I think basically right at the first of the year. We’ve been running two all year. We just gapped this one frac crew probably a couple of weeks ago. We’re slated to pick it up around like the first week of October. So, but we also, just like I mentioned earlier, we see the cost coming down. The pipe prices are coming down significantly. Finally, that’s kind of one of last pieces where we’ve seen the prices come down. We’ve already seen the rig costs come down a little bit, the frac cost come down a little bit earlier this year. So just overall, the cost of services coming down coupled with that one frac crew being gone for, two out of the three months, for Q3 is the driver on CapEx.

Charles Meade: 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?

Dan Harrison: Yes, I think, so, we’ve made great progress on our drilling days, the TD and the Western Haynesville. We — now, the wells have been different lengths, so that kind of comes into place on the number of days, especially in the Western Haynesville with the higher temperatures. But we generally were around like that 85-day mark when we started. And we’ve shaved it down to these last couple of wells on these two well pads were 54 and 56 days. So, that’s pretty significant. And I think there’s still some running room there. We’re still, got some deficiencies. We look to gain, drilling in the laterals. So I think we’ll — we can move that number down a little bit. But…

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

Dan Harrison: 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.

Roland Burns: 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.

Charles Meade: Got it. Thank you. That’s helpful context. Jay and Dan.

Dan Harrison: You bet. Thanks, Charles.

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

Bertrand Donnes: 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?

Dan Harrison: Yes, that’s a really good question. So we definitely expect the performance to be the same as the 10-K 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 10-K. So on a straight 10-H, you get to perforate a little bit more as far as the amount that’s completed across the 10-K, but on a per unit basis, we expect the performance to be totally the same.

Bertrand Donnes: 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?

Roland Burns: 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.

Jay Allison: Yes, I agree with Roland. I think you’ll basically receive, you’ll kind of stay status quo until everybody sees these gas prices move up.

Dan Harrison: 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 horse shoe 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.

Bertrand Donnes: Great point. Thanks, guys.

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

Kevin McCurdy: 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 4Q or are there any other changes you would consider this year to activity levels?

Roland Burns: I think we’re — I think the frac holiday is, I think we pretty much got it set. I don’t really see it extending further into Q4, just based on what we know today and where we see prices going. And so, I mean, really kind of a short answer there, but I think our schedule, we kind of look at it.

Jay Allison: 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 kind of ’25 changes and yes, dramatically, I think that’s kind of what would drive our activity level in the fourth quarter.

Ron Mills: And we’re not contractually obligated, obviously, with frac crews. So, I mean, we could definitely, few things the outlook really change. I mean, obviously, we can change with it.

Roland Burns: And then, fortunately, in the fourth quarter, we do hit our swap position where we’re hedged 50% at that 350. 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 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.

Kevin McCurdy: Thanks for that. That’s helpful. And just wanted to ask, did any of the 2Q weather impacts spill into the third quarter, or did you guys see any impacts from the hurricane?

Jay Allison: We did have impacts from the hurricane, basically. Hurricane Beryl. Yes, when it moved up into the — we didn’t have any impacts in our Western Haynesville area, but when it moved up into our core area, there were just, it really spawned a ton of tornadoes. And really, the thing that hurts us is not necessarily our operations, but all the treating, third-party treating facilities that we flow to basically, they go down on lost power. So it really does, it really hurts our production. We’re just kind of at their mercy. And we did have that for approximately a week to 10 days.

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

Roland Burns: Yes, correct.

Kevin McCurdy: Appreciate it. Thank you.

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

Leo Mariani: 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?

Roland Burns: So, good questions. There’s no change on that in terms of the fourth quarter ’24 versus fourth quarter ’23. It looks like, 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.

Leo Mariani: Okay.

Jay Allison: Well, in the Western Haynesville, but really, really, no wells coming out in the second half of the year for the most part, and then a lot of production coming on the Western Haynesville right around the end of the year, maybe a few wells are on right before that and a lot in early January. But we actually like the way that lines up with the gas market and all that. So–

Roland Burns: Yes, Leo, that’s a hoax about the two deer analysis, those are our — the wells we drilled on the pads are two per pad. And then the Hodges and the Miles, that’s the wells, really the last week of December maybe, or the first week of January 2025. That’s when we’ve modeled it to come in.

Leo Mariani: 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?

Jay Allison: 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. It will also help support that program in ’25 than what we had coming into ’24.

Leo Mariani: Okay. Thanks, guys.

Ron Mills: Thanks, Leo.

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

Neil Mehta: 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?

Roland Burns: We all — remember we have incoming opportunities all the time. We look at all of them and some of them we react to and go forward in like acquiring the acreage that we did the last quarter. But our real focus is right now is to end the outspend and get our production going up, not going down. So we need to take care of that. Our inbound calls that we have, they’re mainly data centers that want to do business with us. They’re utilities. They’re storage. There are more acreage, a little bit of acreage to clean up what we have, at least. And Ron has budgeted for that. So, like we said in the very beginning, our goal is if the M&A market is about inventory, inventory, inventory, our goal is that with the 450,000 plus net acres in Western Haynesville, we should have incredible inventory adds that goes with the 1,400 locations that we have in our core.

That’s really our goal. Our goal is like a Dan Harrison focus, and that’s operations. You test your geological group, and we’ve tested that group for four years. We’ve had successful wells, and with success, we’ve added new acreage. And each of the wells seems to be a little bit better. They’re a little different, but seem to be a little better. And the question that was asked earlier, if you can drill these wells in 54 days, well, now, if you drill two of those wells in 54 days, you almost add a third well compared to the 85 days that we used to drill these in. So that sufficiency’s in numbers saves you a lot of money. Like every two wells in the old days, now you get a third well for the same amount of money. That’s the efficiencies that we see.

So if we continue to prove up the geology, continue to test the seismic that we have in the area, and the wells continue to perform like they have and clean up like they have, I think our goal is just to prove that we created great wealth when the market comes to us with this great gas demand for power generation and LNG and industrial demand. That’s our focus. We spent a lot of money putting together this world class footprint in the Western Haynesville. And now we just want to de-risk it well by well. We’re not on a big M&A binge at all.

Neil Mehta: 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?

Jay Allison: Well, of course, it’s evolving in the Western Haynesville as we’re continued to work down the drilling and completion cost. But kind of where we see the cost being with an efficient program that we’ll have next year with four rigs and kind of the pad drilling that starts to get it more on par with our traditional Haynesville, we actually — the two areas are going to be very similar as far as internal rate of return and cost per reserves found. I mean, the difference is we have a lot more money in a Western Haynesville well, but we have a lot more reserves. I mean, the reserves are double. So it’s a different type of play. The declines are different. So there’s — we’re still trying to figure out how to produce the Western Haynesville wells.

And so there’s a difference there that you get probably a little bit more production out of a traditional Haynesville well in the first six months. But then the second six months, you’ll get a lot more production out of Western Haynesville well, because the way we’re producing them with a much tighter choke, but in the end, they’re very comparable. And as far as returns, especially where we see the cost getting to now that we’re kind of getting into a more development stage, and we’re very pleased with that.

Roland Burns: 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 is going to be materially stronger than you would have if you did a big M&A. M&A is just acquired more in the same area.

Neil Mehta: Thank you, team.

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

Phillips Johnston: Hi, thanks for taking the question. It’s really 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 fact through 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?

Ron Mills: That would definitely be up with those Western Haynesville Wells coming on. Yes.

Phillips Johnston: Yes. Okay, that’s all. Thanks, Ron.

Ron Mills: Thank you, Phillip.

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

Noel Parks: 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?

Dan Harrison: 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.

Noel Parks: 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, et cetera?

Dan Harrison: Well, we definitely started off in the Western Haynesville being much more conservative with how we were producing the wells compared to how we produce them in the core. Obviously, we’ve got years and years and years of history in the core. We know, how we can produce them and how hard we can pull them. But in the Western Haynesville, we’re just on the tip of that learning curve. So we started out very conservative, very low drawdowns. And so, we’re kind of just — we’re slowly kind of starting to maybe pull on them just a little bit harder and get a little bit better production rates, which they can definitely do it. We just want to be — we just want to watch the drawdowns and make sure, we don’t get ahead of ourselves as far as trying to pull them too hard. But everything looks really good. We’re just kind of taking our time in that process.

Jay Allison: And we produce the tubing.

Dan Harrison: 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, down hole 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.

Jay Allison: 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.

Noel Parks: Great, thanks a lot.

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

Paul Diamond: Hi, good morning. Thanks for taking my call. Just a quick one. Want to drill down on the opportunity set across these theoretical horseshoe wells. In your inventory, you get about, call it 16% odd of below 5.000 foot. I was trying to understand how much of the — how much of those, given current expectations you think you might be able to convert and where that would place them, kind of in the larger production cadence or drilling cadence.

Jay Allison: 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 probably 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 5-K 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 has 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.

Paul Diamond: 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 foots compare economically to an existing 10,000 foot?

Roland Burns: 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 5-K laterals. So it just drives all the key parameters significantly higher. Like I said, the cost. So the cost to drill a straight 10-K 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 10-K laterals.

Paul Diamond: Understood. Thanks for your clarity.

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

Gregg Brody: 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?

Roland Burns: 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 the — I mean look, there is a little bit more risk to drilling a horseshoe well. And you 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 mean that’s — 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 for these other areas. But I think you just got 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.

Jay Allison: Well, example on our first well, I mean we’re pretty close to TD in that well. Last night. I know we’re —

Dan Harrison: We’re probably within 500 foot of TD and we have had zero problems drilling.

Jay Allison: Yes, that’s my point. First well, no problems. We’re in 500 feet of TD in it.

Gregg Brody: And that’s when I looked at you were 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.

Jay Allison: 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.

Gregg Brody: 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?

Ron Mills: Yes, Gregg, I think we look, obviously that the gas prices are, if we knew exactly what they were, we could answer the question exactly. The gas prices and where they end up being will be a big driver in the EBITDAX, which is the biggest part of that ratio. And it’s also, remember, it’s kind of a full four-quarter calculation assessment in one quarter. But yes, we stay pretty close to that level. We do think it’s — we can get a temporary waiver if we needed it, but we didn’t need it, so we didn’t go out and get it. So things kind of came in exactly as we thought they would. We knew we were going to get to that 3, 4. Luckily we stayed there. So we’ll monitor it in the third quarter as hard as we monitor in the second quarter.

And then the dividend, obviously, I think we’re not really talking about a dividend, until we kind of get the leverage way down and looking off in the future. So it’s much, I think our first priority, is to get back to generating good free cash flow, and then that will be used for some debt reduction to get the leverage ratio, back to — we’d like to get back to levels that we were seeing back in ’22. And after we got to under closer to 1 times leverage.

Roland Burns: 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 after that, I think we’re going to have some big production growth so that we’re kind of going through that valley right now. It’s a good question.

Gregg Brody: I appreciate the time, guys, and the education.

Ron Mills: Thank you, Gregg.

Operator: Thank you. Our next question comes from the line of Geoff Jay of Daniel Energy Partners.

Geoff Jay: Hi, guys, just a real quick one for me. Earlier, you said you thought you would expect to see D&C cost go down to something like normal levels. I guess I’ve kind of forgotten what normal looks like, given all the inflation we’ve seen over the last year or so. Where do you kind of think those well trend, given the service cost inflation that’s out there and the efficiencies you’re achieving?

Ron Mills: Well, we think our legacy, Haynesville main product, will trend back to that a little bit below 1,500. That 1,500 –1,400 to 1,500 is kind of an area. And I think the way we report this is kind of when wells are completed, and they — but it’s not really a good indication of where things are now because some of the wells we completed this quarter were actually finished drilled last year. And so we might be able to come back and add some additional information here and show you, here’s the real drilling cost being incurred each quarter, and here’s the completion cost being incurred. They’ll be on different wells, but they’d be more indicative of where costs are versus the process here of scoring is costs that were incurred in different periods than the one you’re hearing about.

And also, if you have a certain group of wells that are different and more costly that happen to be the ones turned to sales, they dominate the numbers. As the case this quarter, you had these Lake Bistineau wells that have a lot of, it’s a high cost area period. And plus, you throw some drilling problems in, and those wells kind of really distorted what would have been just looked pretty comparable to the other quarter if they weren’t in there.

Roland Burns: You got less wells to average it down.

Jay Allison: But, yes, we’ll probably try to maybe provide some supplemental deal. That will allow you to see the current cost in the quarter, how they’re trending, versus seeing something that occurred, maybe even last year.

Geoff Jay: Excellent. Well, thank you for that.

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

Jay Allison: All right. Thank you, again. We’ve gone over our hour, but as the company, we’ve always had a vision. I think Gregg asked about, do you drill these horseshoe wells that are 7,500 foot times two 15,000 feet? And the answer is, we have a vision, and we had a vision to step out of 100 miles and see if we could rebirth a major gas play, which is now the Western Haynesville. We have a vision, and then we always monitor where gas supply is. If you look, we’ve been looking for the last probably six or seven weeks, and that gas storage level was about 38% above the five-year average. Well, week after week after week, that’s come down, it’s like 16% above the five-year average. So, it’s coming the right way, and we’re coming into the three, four, five weeks of what we call real the meat of the summer.

So we do see that. We see, LNG at over 13 fleet a day right now. So it’s back. Freeport is back. And then we look past September, October, and you see the startups of Corpus Stage 3 at [indiscernible]. So we see a strong fourth quarter of ’24 run from the LNG fleet, and that goes into 2025. So we are committed to manage, we’re committed to sharing everything that we can share in all of our areas and to protect our balance sheet. And again, I want to complement the Jones’ for writing the $100 million check for the acreage that we’ve been acquiring. I think that acreage is worth a fortune, and they were willing to backstop that and write the check. So we’re going to be in good shape there. So thank you for your time. We appreciate it.

Operator: This concludes today’s conference call. Thank you for participating. You may now disconnect.