Comstock Resources Inc

NYSE:CRK

Earnings Call Analysis

Comstock Resources Faces Low Gas Prices, Plans for Future Growth

Comstock Resources experienced a challenging quarter due to weak natural gas prices, which led to a 2% decline in oil and gas sales to $278 million, despite a 4% production increase. The company reported an adjusted net loss of $58 million. To cope, Comstock has focused on reducing costs and improving efficiencies, including a 34-41% cut in CapEx for 2024, and added hedges covering 50% of projected production by year-end 2026. The company remains optimistic about future growth through its Haynesville and Western Haynesville drilling projects, expecting demand increase in natural gas, especially from LNG exports next year.

Navigating Challenges with Resilience

In the recent earnings call, Comstock Resources detailed a challenging second quarter of 2024, primarily driven by persistently low natural gas prices. Despite achieving a production increase of 4% to 1.4 billion cubic feet equivalent per day (Bcfe/d) compared to the previous year, the company's revenues fell 2% to $278 million due to weak pricing dynamics. The average realized natural gas price before hedges stood at $1.65, significantly lower than competitive benchmarks, even with some hedging efforts that bumped the price to $2.12. Adjusted net loss reached $58 million or $0.20 per share, which contrasts sharply with a net income of $1 million in the second quarter of 2023.

Operational Efficiency amid Adversity

During the first six months of 2024, Comstock's production averaged 1.5 Bcfe/d, a 6% increase over the same period in 2023, yet revenue dropped 9% to $614 million, a clear signal of the pricing pressure. EBITDAX, a crucial metric for understanding cash flow generation, totaled $396 million year-to-date. The company managed to generate $300 million in cash flow, showcasing operational resilience. Comstock's operations focused heavily on the Haynesville and Bossier plays, emphasizing the importance of operational efficiency, as illustrated by their successful drilling of 11 horizontal wells in the quarter.

A Bright Horizon with Strategic Positioning

Looking ahead, Comstock maintains optimism for future performance, buoyed by significant investments into their resource base. The company reported a strong liquidity position of approximately $1.2 billion and highlighted an additional $100 million investment from major stakeholder Jerry Jones. With over 450,000 net acres in the promising Western Haynesville area, Comstock projects strong resource potential supported by more than 1,400 net drilling locations. The recent advancements in drilling operations, which have reduced drilling times from an average of 85 days to 54 days, further enhance their outlook for efficiency and cost-effectiveness.

24-Month Capital Expenditure Outlook

For the remainder of 2024, Comstock anticipates capital expenditures on drilling and completion (D&C) to range between $750 million and $850 million for the year, with third-quarter expenditures expected between $135 million and $185 million. This planned reduction in capital expenditures reflects the company’s strategy to manage costs robustly during this low-price environment. The integration of advanced drilling techniques like lateral drilling for more efficient well development signifies Comstock’s proactive approach in capitalizing on technological advancements to lower costs.

Hedging and Long-Term Stability

Anticipating a recovery in natural gas prices, Comstock has implemented a hedging strategy covering 50% of its expected production through to the end of 2026, which serves as a cushion against price volatility in future quarters. The company’s strategy is focused on both optimizing production processes and maintaining a healthy financial position while navigating through these turbulent market conditions.

Conclusion: Preparing for Growth

Despite facing significant headwinds in the natural gas market, Comstock's management remains committed to strategic growth. Expanding its already significant asset base while maintaining a strong liquidity position and a focus on operational efficiency will likely position the company well once natural gas prices recover. The focus on drilling efficiencies and technological advancements indicates a solid foundation for future expansions and successful well completions, providing a cautiously optimistic outlook for investors.

Earnings Call Transcript 2024-Q2

[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.

[Miles Allison, executive]

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. have Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Barnes, 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 presentation 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 can 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 chilled 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 a 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 costs 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 derisking our new play and by reducing well costs in our new play. We are in a very volatile time but we have been here before, and I've never seen a broader future for natural gas in North America for the world that 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, and -- 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 and 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 Shield. We recently completed the drilling activity on both 2 well pads in the Western Haynesville play. With the drilling efficiencies from the pad drilling, we reduced the latest well drill times to 54 days. We're expected to turn the next 6 Western Haynesville wells to sales around the end of the year, and we currently have 2 rigs running in the play today. I'll have Roland go over the second quarter financial results. Roland?

[Ronald Mills, executive]

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. But 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 second quarter. EBITDAX for the quarter was $167 million, and we generated $118 million of cash flow in the quarter. We reported adjusted -- 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 have to use the very low natural gas prices required by the SEC to determine reserves accounted for much of the loss for the quarter.



As natural gas prices improve, those proved end of up reserves will be back on the books, and we'll see the DDA 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 6 months of 2024 of 1.5 Bcfe per day was 6% higher than the first 6 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 6 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 6 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 helmet 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. The -- on Slide 7, we detail our operating cost 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 was the same as our second quarter rate of last year. Production at Aperam 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 6 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 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 30, 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 will now turn the call over to Dan to discuss our operations.

[Daniel Harrison, executive]

Okay. 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. We have 1,300 net locations, and this equates to an average 77% average working interest. Our nonoperating inventory has 1,227 gross locations and 159 net locations, which represents a 13% average working interest across the nonoperated inventory. The drilling inventory is split between Haynesville and Bossier locations, and we have it split into our 4 different groups with our short laterals that go up to 5,000 foot. Our medium laterals run to 25,000 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 the outlining our average lateral weight 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 links range from 4,222 feet up to 10,047 feet. Our record longest lateral still stands at 15,726 feet. 8 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 arm lateral wells that turn to sales. One of the 12 wells turn to sales during the second quarter was on our Western Haynesville acreage. This was the Ingram Martin #1 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, and 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 own lateral activity date, we have drilled a total of 103 wells with LIBOR longer than 10,000 feet, and we drove 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 $42.22 up to 15,303 feet. Recapping our activity, we are continuing to run 5 rigs after dropping 2 rigs in the first quarter. For our completions, we have been running 2 frac crews all year since we dropped down from 3 frac crews at the beginning of the year. This month, we also temporarily released 1 of our 2 frac crews for a short 2-month to gap until we pick it up again early in the fourth quarter. Two of the 5 rigs are currently drilling in the Western Haynesville. Both of these rigs recently finished drilling our first 2-well pads on the acreage and these 2 well pads will be completed in the fourth quarter and turned to sales just after the first of the year. In the Western Haynesville, we anticipate having a total of 6 wells that will turn to sales from November just after year-end –



On Slide 13 is a summary of our D&C costs 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 8 of the 11 wells fell into our Betsmark long lateral group. In the second quarter, our D&C cost averaged $1,730 per foot on our 8 Betsmark 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 3-well pad up in the Lake Boston area where we encountered significant drilling difficulties. In addition, 4 of our 8 Betsmark wells were drilled inside the boundary of a gas storage facility, which requires an additional shallow intermediate casing stream 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 and 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 Horse lateral concept that has recently gained traction in the industry. While the small handful of Horse wells have been drilled in the other basins, only one horse 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 horse 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 can 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 4 5,000-foot laterals from 2 pads with a $40 million capital cost.



We now plan to develop a section from a single 2-well pad rolling 2 10,000-foot horse 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 for fewer wellbores. We expect the well performance from the F wells will match that of our regular 10,000-foot laterals. And once this technology becomes more derisked, 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.

[Miles Allison, executive]

Okay, Dan, thank you, Roland. Thank you. Dan, you're talking about the Horseshoe wells. I'm thinking about the majority owner of the stock is on the Dallas Cowboys. -- cowboys and horseshoes go together. So thank you for that report. Let's go to Page 15. I'll direct you to Slide 15, 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 that we released 2 of our operated drilling rigs. We reduced our rig count to 5 rigs. We also released one of our frac spreads, reducing our frac pads to 2 spreads. We no longer now have any long-term commitments for our pressure pumping services. Over those steps, and our 2020 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 has.



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 proving up our Western Haynesville play and continuing to add to our extensive acreage position in this exciting play. Our Western Atellacreage position totals over 450,000 net acres to date. We believe that we're building a great asset in a Western Hansell 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 Bob provide specifics for the rest of the year on.

[Ronald Mills, executive]

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 in an alarm, 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.

[Operator]

Thank you. [Operator Instructions]. -- our first question comes from the line of Carlos Escalante of Wolfe Research.

[Carlos Andres E. Escalante, analyst]

Question. If I go -- if I use the second quarter completed wells as a property 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 concept update, how do you all see the allocation towards a potentially successful program going into the future quarters and future years.

[Daniel Harrison, executive]

So 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 Horse concept, I think really the majority of all the wells -- short wells that we have in our inventory will convert to loan 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 didn't decide to drill, that's -- you have to drill a short lateral. So we won't be able to convert all of them to the 10-K Horse wells, but I think a good chunk of the inventory we'll be able to convert to 10-Ks.

[Carlos Andres E. Escalante, analyst]

Wonderful. And 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 plan 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, and what's the end goal here? Is it more of a resonation of what the risk may be on the concept? Or is this the first of many to come?

[Daniel Harrison, executive]

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 mature, they want to see it derisked. So I think they -- they're probably a little bit further into that process in the other basins. I think really mainly the Permian and I think a few in the Eagle Ford. -- for the Horse wells. There was one drilled earlier this year that was -- and it was problem free. So we -- and like I said, we're almost at TD on the one that we're drilling in, it's been a problem for you to date. So we feel really good about it. I think we'll -- we feel really good about significantly reducing the short laterals in our inventory. We'll have more 10-Ks, our average lateral length to be up. It will -- 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.

[Ronald Mills, executive]

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 pushed back to the latter part of our drilling inventory. But after you have these cost savings, you can bring them forward if you need to drill them.

[Miles Allison, executive]

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

[Operator]

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

[Jacob Roberts, analyst]

I 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?

[Daniel Harrison, executive]

Well, it's certainly out on the edge of our acreage footprint. That is -- we do know from past drilling up in that area, the wellbore stability is a little bit more -- the rock itself just has a little bit more instability. And so really, we had -- and normally, that are per typically drills -- the drilling cost is a little bit more expensive, maybe $1,650 to $1,700 a -- it's kind of normal, whereas back over in Texas in the Stateline area. We're in that $1,450 to $1,500 a foot. But -- so we had -- we drilled 5 wells -- two of the wells were the ones that really gave us problems. We ended up -- had 1 well drilled to TD. We lost a lateral. We tried to sidetrack it. We ended up having a side track it twice to get it drilled and we basically had another well that we had 2 sidetracks on. So on 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 onetime 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 5 wells all the way across the section. So we -- that's just a onetime 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, analyst]

... Okay. Great. I appreciate that. My second question, so the 2 2-well pad sounds like the drilling has 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?

[Daniel Harrison, executive]

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 inventory that we already have, but I think by the time we get to wells that turn the 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 costs basically come down Q3 and really further into Q4 and Q1.

[Operator]

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

[Charles Meade, analyst]

Good morning, Jay, Roland, Dan and Ron I wanted to ask a question. Again, 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. But 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 2 frac crews, you're going to let it you can let it -- you're just going to be running 1 crew for August and September. It sounds like you're going to pick it up again. Is that -- 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?

[Daniel Harrison, executive]

Well, I think the -- it's not totally that, but that's the kind of a significant driver and that's just kind of a reflection of drop in the rigs earlier in the year. I mean, obviously, we got less wells to complete. We went from 3 to 2, I think basically right at the first of the year. We've been running 2 all year. We just gapped this 1 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 costs coming down. The pipe prices are coming down significantly finally. That's kind of one of the last pieces where we've seen the prices come down. We've already seen the rig costs come down a little bit. The frac costs come down a little bit earlier this year. So just overall, the cost of service is coming down, coupled with that one frac crew being gone for 2 out of the 3 months for Q3 is the driver on CapEx.

[Charles Meade, analyst]

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

[Daniel Harrison, executive]

Yes. I think -- so we've made great progress on our drilling days to TD in the Western Haynesville. We -- now the wells have been different links 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 2 well pads were 54 and 56 days. So that's pretty significant. And I think there's still some running room there. We've still got some efficiencies we look to gain drilling in the laterals. So I think we can move that number down a little bit.

[Charles Meade, analyst]

But you might have that those the low number of days with those were long laterals... Correct...

[Daniel Harrison, executive]

Yes. And those were both. I think one of the -- we had one was a 10,000-foot lateral on was just under a 1,000 foot lateral. So those 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 say are the toughest wells that we've drilled, basically TDDs, 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.

[Ronald Mills, executive]

Well, Charles, from 16th well, you go from 85 days to 54 that's 31 days you say, that's a whole month 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. I mean we've already shaped off 6, 7 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 water wells, that's a lot of money. Got it.

[Operator]

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

[Bertrand Donnes, analyst]

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 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 2 combined wells but a lower decline? Or any thoughts there?

[Miles Allison, executive]

Yes, it's a really good question. So we definitely expect the performance to be the same as the 1000 well. The only really mild difference between the horse well and a 10,000 foot across 2 sections of straight lateral is on the straight lateral, you do get complete across the section line, that 660-foot -- there's a the stage you can't perforate with the 330 foot of the lease line. So on a horse you well, you basically got 2 4,600-foot sections, 9,200 foot. We're on a 10-K. So on a straight 10-K, you get to perforate a little bit more as far as the amount that's completed across the 10-K. So -- but on a per unit basis, we expect the performance to be totally the same.

[Bertrand Donnes, analyst]

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 4 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, executive]

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 yes, 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 rise. 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, other than that, everybody else, but then has dropped a lot of rigs.

[Miles Allison, executive]

Yes. I agree with Roland. I think you'll kind of see status quo until everybody sees these gas prices move up...

[Ronald Mills, executive]

One, if you look at the core is at 9,000 square miles, what they call the core, when you drill a well there, either Bojer Haynesville, you've 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 Western answer 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.

[Operator]

Our next question comes from the line of Kevin MacCurdy of Pickering Energy Partners.

[Kevin MacCurdy, analyst]

I wanted to ask about activity toggles. Now that the debt covenant is a little less of a 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?

[Miles Allison, executive]

I think we're -- I think the frac holiday is -- I think we've pretty much got it said. 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...

[Roland Burns, executive]

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 through the very end of the year. And so to have so I think, less kind of 25 changes and nomadically. I think that's kind of what would drive our activity level in the fourth quarter.

[Miles Allison, executive]

Right. And we're not contractually obligated, obviously, with frac crews, something we can definitely set things outlook really change. I mean, obviously, we can change with it.

[Ronald Mills, executive]

And Daniel, fortunately, in the fourth quarter, we do hit our swap position where we've hedged 50% at -- so that's something that the prices do continue to deteriorate. We will at least end up in that quarter. And 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 percent hedge environment into the 50% environment.

[Kevin MacCurdy, analyst]

That's helpful. And I just wanted to ask, did any of the 2Q weather impacts go into the third quarter? Or did you guys see any impacts from the hurricane?

DAN. We did have impacts from the hurricane Basically, Hurricane Barrel. Yes, we have moved up into the -- we didn't have any impacts in our Western Haynesville area, but it moved up into our core area. There were just really spawned a ton of tomatoes. 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... In July.

[Ronald Mills, executive]

And that impact is incorporated in the third quarter guidance.

[Operator]

Our next question comes from the line of Leo Mariani of Roth.

[Leo Mariani, analyst]

I wanted to just dig in a little bit more into kind of the 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 I wanted to see if that's still roughly valid. And then with respect to fourth quarter CapEx, it 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?

[Ronald Mills, executive]

So... Good questions. There's no change on that in terms of the fourth quarter 24 versus fourth quarter of '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 2 rigs in February and March and kind of that 6- to 9-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.

[Miles Allison, executive]

And the Western really, really no wells coming on in the second half of the year for the most part. And then a lot of production coming on in 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...

[Daniel Harrison, executive]

Yes, Leo, that's a home to power the 2 dealer and else. Those are the wells we drilled on the pads, 2 per pad and then the Hodges in the miles, that's the wells really the last week of December, maybe or the first week of January 2025. That's when we modeled it to come in.

[Leo Mariani, analyst]

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, I mean 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 at adds a couple of rigs to kind of get back to the 7 rigs. Is that kind of how you're thinking about it here today to kind of bring those rigs back currently next year?

[Miles Allison, executive]

Yes. That price level is 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, we do like the way that -- what the futures market has out there, well to see if that materializes and then having a stronger hedge position will also help support that program in '25 than what we had coming into '24. Okay.

[Operator]

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

[Neil Mehta, analyst]

Yes. Two questions. The first was just your perspective on the A&D 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 a smaller scale or even medium to large term larger-sized bolt-ons?

[Miles Allison, executive]

We all -- I mean 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 acquire the acreage that we did the last quarter. But our real focus is right now is to end the outspend at 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, their utilities, their storage. There are more acreage, a little bit of acreage to clean up what we haven't leased 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 Dan Harrison focus, and that's operations, you test your geological group, and we've tested that group for 4 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 it seemed to be a little better. And the question that was asked earlier, if you can drill these wells from 54 days. Well, now if you drill 2 of those wells in 54 days, you almost had a third well compared to the 85 days that we used to drill these in. So that efficiencies and numbers, saved you a lot of lot of money like every 2 wells in the old day, 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 derisk it well by well. We're not on a big M&A binge at all. Yes.

[Neil Mehta, analyst]

That's great perspective. And then the follow-up is just -- one question we get asked a lot is sort of the breakevens 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 or Henry Hub equivalent?

[Roland Burns, executive]

Well, yes, of course, it's evolving in the Western Haynesville as we're continuing to work down the drilling and completion costs. But kind of where we see the cost be in with an efficient program that we'll have next year with 4 rigs and kind of with the pad drilling that makes puts it more -- start to get it more on par with our traditional Haynesville -- we actually -- the 2 areas are going to be very similar as far as internal rate of return and a 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 what -- 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 6 months. But then the second 6 months, you'll get a lot more production out of Western Haynesville well because the way we're producing them with a much tighter show. 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. So -- and we're very pleased with that.

[Miles Allison, executive]

Well, I think to add on to that, if you look at this inventory depletion, which will happen, if 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're run out of Tier 1s. So if our Western Heynesville is compared to Tier 1, and we have all this acreage and we derisked our inventory is going to be materially stronger than you have if you did a big M&A. M&A is just acquired more in the same area.

[Operator]

Our next question come from the line of Phillips Jungwirth of Capital One Securities.

[Phillip Jungwirth, analyst]

It's really a follow-up to Leo's question. The 25 is obviously very much TBD. But if you do stay at 5 rigs for the balance of the year and 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?

[Daniel Harrison, executive]

Will be up, but those Western Haynesville wells coming on. Yes.

[Operator]

Our next question comes from the line of Noel Parks of Tuohyy Brothers Investment Research.

[Noel Parks, analyst]

It's No. Good job 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 was wondering if you could talk a bit about where things stand with the instruments and tools that I understand had had some adaptation to be able to work at those levels. Just where are you -- any of that you're doing proprietary anything that you're going to be implementing in the next slate of wells?

[Daniel Harrison, executive]

This is Dan. So we basically use the same tools in the Western Haynesville that we use in the core we basically -- how we apply them 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 are some of our providers up in the core 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 in the core. So same tools.

[Noel Parks, analyst]

Got it. And you just mentioned -- or Roland just mentioned how you produce the Western Haynesville wells and effect that might have on declines and so forth. And have you -- just wondering what are your thoughts were going so far about joking and how that might influence production rates, shape of the curve, et cetera.

[Roland Burns, executive]

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 -- we started out very conservative, very low drawdowns. And so we're -- we've kind of just -- we're slowly kind of starting up maybe pulling them just a little bit harder and get a little bit better production rates, which they can definitely do it. We just want to -- we just want to watch the drawdowns and make sure we don't get ahead of ourselves a source trying to pull them too hard. But everything looks really good. We're just kind of taking our time in that process.

[Miles Allison, executive]

And we produce the tubing over that.

[Daniel Harrison, executive]

Yes. And we do everything that we complete up in the core, we flow of 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 in what the wellhead, what 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 tubing. 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're flowing up casing, the surface pressures were. But that's probably the biggest difference as far as downhole. All the Western Haynesville wells are tubed up, all the core wells flow up casing.

[Miles Allison, executive]

And you're asking about the drilling. If you look at our efficiencies and Dan is 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 you said that 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 would 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 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 effect when you can perfect it, then you can lower those costs and you create real well, 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.

[Operator]

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

[Paul Diamond, analyst]

Just a quick one. I want to drill down on the opportunity set across these theories wells. When your inventory you had about, call it, 6-odd-percent below 5,000 foot. I'm just 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?

[Miles Allison, executive]

Yes, it'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 the 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 -- you have to have 2 of the 5,000 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 horse candidate. But other than that, I think every -- if you got 2 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 we'll -- that's short. 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 leaseholder 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, analyst]

Understood. That actually kind of portends into my follow-up. Assuming our under current assumptions you guys are working with, how would a horseshoe 20, 5,000 foots compare economically to an existing 10,000 foot?

[Daniel Harrison, executive]

So yes, it's substantial. 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 5,000 laterals. So it just drives all the key parameters significantly higher. So like I said, the cost. So the cost to drill a straight 10-K to drill a horse well is essentially the same. I said 1% to 2% premium. But I mean, that's within the plus modest of any well we drill on kind of where our costs are going to end up. So we look at the economics for Horse to be essentially the same as all of our other 10-K laterals.

[Operator]

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

[Gregg Brody, analyst]

Update. As the credit guy I've started to see these oral wells pop up in 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 growing on one lateral in a U-shape that seems like physics suggest we can do that now.

[Daniel Harrison, executive]

Right. Sometimes, the old say necessity is the mother of invention, I mean we -- you drill a 90-degree turn to drill these laterals already, right? So you do the 90-degree turn, you're drilling the lateral. So the same tools, it's the same motors that we run, you just make another turn and you just -- 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 drill in the horseshoe well, and you got to get casing around the curve. You have to get -- when you're complete 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 is pretty small. The industry kind of already has shown it in the Permian and I think the Eagle Ford to 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 ultimate becomes a little bit more routine and the risk is greatly diminished.

[Ronald Mills, executive]

Well example, on our first well, I mean we're pretty close to TD, and that will let night. I know

[Daniel Harrison, executive]

We're probably within 500 foot at TD, and we have had 0 problems drilling

[Ronald Mills, executive]

Yes, that's my point, first well, no problems were than 500 feet of TD in it.

[Gregg Brody, analyst]

And that's -- when I looked at -- you were being asked earlier about how much potential of your locations can be converted. Should we think that it's just the ones that are in the up to 5,000 feet? Or is it -- should we think also about the 5,000 to 8,500 feet that could be converted -- and 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?

[Daniel Harrison, executive]

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 15,000 horseshoe yet. Now we're not ready to kind of out there and do that yet. But 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 the 500. 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 2 sections or 3 sections, like typically, we'll just drill a 15,000 straight lateral. We're not going to do a bunch of 7,500-foot horse 15,000 laterals. You know what I mean, that's -- 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 links 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 that adds more drag, tripping in and out of the hole. So a 10,000-foot horseshoe you well may is kind of maybe more like the equivalent of a 15,000-foot straight level when you look at the drag going in and out of the hole, if that makes sense.

[Gregg Brody, analyst]

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 see you getting your 34 today. I think you're okay for next quarter to get into 3 to 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?

[Roland Burns, executive]

Yes, Greg, I think we looked with Chris, obviously, the gas prices -- 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 in a kind of remember it's a kind of a fold fourth quarter calculation in one quarter. But 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% would likely be stayed there. So we'll bono it in the third quarter as hard as we monitor it 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. In fact, we'd like to get back to levels that we were seeing back in '22 and fact we got to under -- closer to 1x leverage.

[Ronald Mills, executive]

We were really monitoring the second quarter. And again, we did take in 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, you got to really monitor the third quarter and 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 that we're kind of going to that valley right now. It's a good question.

[Operator]

Our next question comes from the line of Jeff Jay of Daniel Energy Partners.

[Jeff Jay, analyst]

Just a real quick one for me. Earlier, you said you thought you see -- you would expect to see D&C costs go down to something like normal levels. I guess I'm 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 will trend given the service cost deflation that's out there and the efficiencies you're achieving?

[Roland Burns, executive]

So we think our... 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 maybe will come back and add some additional information here and show you here's the real drilling costs 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. So -- and also, if you have a certain group of wells that are different and more costly that happened to be the ones turned to sales, they dominate the numbers. As the case this quarter, you had these Lake Vista wells that have a lot of -- at the high-cost area period and plus ethos 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.

[Miles Allison, executive]

We got less wells to average it down.

[Roland Burns, executive]

But yes, we'll probably try to maybe provide some supplemental 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.

[Operator]

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

[Miles Allison, executive]

Thank you again. We've gone over an hour. But as you know, the company, we've always had a vision. I think Greg asked about, do you drill these horsey wells that are 7,500-foot type to 15,000 feet. And the answer is we have a vision. 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 6 or 7 weeks, and that gas storage level was -- is about 38% above the 5-year average. Well, week after week after week, that's come down, it's like 16% above the 5-year average. So it's coming the right way. We're coming into the 345 weeks of what we call real the mid of the summer. So we do see that. We see LNG at over 13 Bs 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 and Buckman. So we see a strong fourth quarter of 24 runs 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 the balance sheet. And again, I want to compliment the Jones is for writing the $100 million trick for the acreage that we've been acquiring. I think that acreage as we're fortunate, and they were willing to backstop that and run 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.