Comstock Resources - Q2 2024
July 31, 2024
Executive Summary
- Q2 results were pressured by sub-$2 gas: oil and gas sales including hedging fell to $278.2m, adjusted EBITDAX to $166.7m, and adjusted EPS to $(0.20), while hedged operating margin compressed to 61% from 68% in Q1 due primarily to weaker realized prices.
- Production averaged 1.4 Bcfe/d (+4% YoY), but realized gas price of $1.65/Mcf ($2.12 with hedges) drove a GAAP net loss of $(123)m (GAAP EPS $(0.43)).
- 2024 activity toggle intact: Q3 D&C CapEx guided to $135–$185m with the frac “holiday” in Q3 and resumption in Q4; full‑year D&C CapEx maintained at $750–$850m; LOE/G&T unchanged; DD&A higher for the rest of 2024 given low SEC prices; tax deferral now virtually 100%.
- Strategic positives: Western Haynesville efficiencies (days to TD cut from ~85 to 54), cost deflation emerging (pipe), and Horseshoe laterals expected to save ~23% capex per section (~$8m) over two 5k’ laterals with comparable performance, supporting medium‑term inventory quality and capital efficiency.
- Street estimates: S&P Global consensus could not be retrieved in this session; we therefore cannot assess beats/misses versus consensus (SPGI request limit reached).
What Went Well and What Went Wrong
- What Went Well
- Western Haynesville operational learning curve: drilling time reduced to as low as 54–56 days (from ~85), potentially enabling an extra well per year on the same rig fleet, with additional efficiency gains expected.
- Horseshoe lateral concept: initial test is near TD with no problems; management expects ~23% cost savings (~$8m) vs four 5k’ laterals and similar per‑unit performance to straight 10k’ laterals, expanding ability to convert short laterals into long laterals.
- Liquidity and hedging: ~$1.2bn liquidity at Q2 end; hedging ramping to ~50% of expected production starting Q4’24 and targeting ~50% for 2025–26, providing downside protection into an improving demand outlook (LNG, power, industrial).
- What Went Wrong
- Pricing headwinds: realized gas price $1.65/Mcf ($2.12 with hedges) pulled hedged operating margin down to 61% (from 68% in Q1) and drove adjusted EBITDAX and operating cash flow down Q/Q.
- Cost outlier pad: Baker 3‑well pad experienced significant drilling difficulties and multiple sidetracks, lifting D&C $/ft for the quarter; excluding Baker, management believes normalized D&C is ~$1,500/ft, trending lower into H2 as pipe prices fall.
- Weather/third‑party downtime: Hurricane Beryl‑related outages at third‑party treating facilities impacted July volumes (included in Q3 guidance), highlighting some exposure to midstream power reliability.
Transcript
Operator (participant)
Thank you for standing by, and welcome to Comstock Resources' Second Quarter 2024 Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. To ask a question during the session, you will need to press star one one on your telephone. To remove yourself from the queue, you may press star one one again. I would now like to hand the call over to Jay Allison, Chairman and CEO. Please go ahead.
M. Jay Allison (Chairman and CEO)
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 have Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide two in our presentations, and note that the discussions today will include forward-looking statements within the meaning of securities laws.
But 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 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. You know, 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 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 North America or the world than I see today. Now, we'll go to slide three, the second quarter 2024 highlights. On slide three, 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, 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 ft, 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 ft. 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, six from the Haynesville Shale and six 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 drill times to 54 days.
Daniel S. Harrison (COO)
We expect to turn the next six Western Haynesville wells to sales around the end of the year, and we currently have two rigs running in the play today. I'll have Roland go over the second quarter financial results. Roland?
Roland O. Burns (President and CFO)
Thanks, Jay. On slide four, we cover the second quarter financial results. Our production in the second quarter of 1.4 Bcf/d 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's second quarter. EBITDAX for the quarter was $167 million, and we generated $118 million of cash flow in the quarter. We reported 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 improve, those proved undeveloped reserves will be back on the books, and we'll see the DD&A rate go back to its lower, its lower levels, you know, in future quarters. On slide five, we cover our year-to-date financial results. Our production in the first six months of 2024 of 1.5 Bcf/d 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 six, 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 a $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 seven, we detail our operating costs per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.84 in the second quarter, $0.08 higher than the first quarter rate, but the same as our second quarter rate of last year. Production and ad valorem taxes were $0.14, lifting costs were $0.27, gathering costs were $0.38, and our G&A costs were $0.05 in the quarter.
Our EBITDAX margin after hedging came in at 61% in the second quarter, down from the 68% margin we had in the first quarter due to the even weaker natural gas prices. On slide eight, 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 MMcf/d.
Slide nine 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 thirtieth, 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.
Daniel S. Harrison (COO)
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 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 ft, our medium laterals run between 5,000 ft and 8,500 ft.
Our long laterals from 8,500 ft up to 10,000 ft long, and our extra-long laterals for those over 10,000 ft. 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 ft, and 38% of the total gross operated inventory have laterals longer than 10,000 ft. The average lateral in our inventory now stands at 9,077 ft, and this is up slightly from 9,015 ft 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 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 ft. The individual lengths range from 4,222 ft up to 10,047 ft. Our record longest lateral still stands at 15,726 ft. Eight of the 12 wells turned to sales during the quarter had laterals longer than 8,500 ft. 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 ft, 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 ft on a total of 45 wells that we'll turn to sales. To recap our long lateral activity to date, we have drilled a total of 103 wells with laterals longer than 10,000 ft, and we've drilled 38 wells with laterals over 14,000 ft. 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 MMcf/d up to 31 MMcf/d, with the average test rate of 21 MMcf/d. The average lateral length was 9,802 ft, with the individual lengths ranging from 4,222 ft up to 15,303 ft. Recapping our activity, we're 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 through just after year-end. And 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 ft 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 costs 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 3 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 costs 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 will utilize the horseshoe lateral concept that has recently gained traction in the industry. While a 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 the section from a single two-well pad, drilling two 10,000-foot horseshoe laterals for $32 million in capital. This capital cost represents only a 1%-2% cost premium to a regular straight 10,000-foot lateral.
The project will deliver a 23% in 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 wellbores. 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.
M. Jay Allison (Chairman and CEO)
Okay, Dan. Thank you, Roland. Thank you. You know, Dan, you're talking about the horseshoe wells. I'm thinking about the majority owner of the stock is owns the Dallas Cowboys. So cowboys and horseshoes go together, so thank you for that report. Let's go to page 15. I 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 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, and our 2024 CapEx is expected to be down 34%-41% from the 2023 level. We suspended our quarterly dividend. That saved about $140 million a year in dividend payments. In late March, our 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, you know, we did add significantly to our hedge position starting in the fourth quarter of 2024 and extending that through the year-end 2026. We're 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 continued 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 up our Western Haynesville play and continuing to add to our extensive acreage position in this exciting play. Our Western Haynesville acreage position totals over 450,000 net acres to date.
We believe that we're building a great asset in a Western Haynesville that will be well positioned to benefit from the substantial growth and 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?
Ronald E. Mills (VP of Finance and Investor Relations)
Thanks, Jay. On slide 16, we provide some 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-$850 million. The midstream capital outlook remains unchanged, and the leasing capital for the third and fourth quarter remains in the $2 million-$5 million range. The full year moved up $5 million-$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.
Operator (participant)
Thank you. As a reminder, to ask a question, you will need to press star one one on your telephone. To remove yourself from the queue, you may press star one one again. We ask that you please limit yourself to one question and one follow-up to allow everyone the opportunity to participate. Please stand by while we compile the Q&A roster. Our first question comes from the line of Carlos Escalante of Wolfe Research.
Carlos Escalante (VP)
Hey, good morning, gentlemen. Thank you for taking my, my question.
Daniel S. Harrison (COO)
Good morning.
Carlos Escalante (VP)
Good morning. If I use the second quarter completed wells as a proxy for your drilling pace on wells under 5,000 ft, 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? Thank you.
Daniel S. Harrison (COO)
So, you know, I'll, you know, this is Dan. I'll kind of address just the short laterals. We, we did have one short lateral that we reported here. We had, we had basically really already kind of had drilled that well when we were having, you know, when we had our last call. But, you know, 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, you know, and it's bounded by other wells, where, you know, if you do, if you did decide to drill, that's... You have to drill a short lateral.
So we won't be able to convert all of them to 10K horseshoe wells, but I think, you know, a good, a good chunk of the inventory we'll be able to convert to 10Ks.
Carlos Escalante (VP)
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 25-30 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?
Daniel S. Harrison (COO)
I think this is the first of many to come, and just like with anything that's new, you know, 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, you know, 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 or the horseshoe wells. There was one drilled earlier this year that was problem-free. So you know, we and, like I said, we're almost at TD on the one that we're drilling, and it's been problem-free to date, so you know, we feel really good about it.
I think we'll we feel really good about, you know, significantly reducing the short laterals in our inventory. We'll have more 10Ks. Our average lateral length will be up. It'll our, our efficiencies will be way up. So we just need to do more, you know, where it becomes routine and, you know, to take, take some of the risk out.
M. Jay Allison (Chairman and CEO)
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've pushed 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.
Daniel S. Harrison (COO)
Right. And, you know, some of these we've drilled because we've, you know, we've had them for a while and, some of the production gets low, so we just, just to protect our leasehold, you know, is why we'll put some of these on our drilling schedule.
Carlos Escalante (VP)
Wonderful. Thank you, gentlemen.
M. Jay Allison (Chairman and CEO)
Thank you.
Operator (participant)
Thank you. Our next question comes from the line of Jacob Roberts of TPH & Company.
Jake Roberts (Director)
Morning.
M. Jay Allison (Chairman and CEO)
Morning.
Jake Roberts (Director)
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 S. Harrison (COO)
Well, it's certainly out on the edge of, you know, our acreage footprint. That is, we do know from past drilling up in that area, that the wellbore's stability is a little bit more, you know, the rock itself just has a little bit more instability. And so really, we had, and normally that area up there typically drills, is, you know, the drilling cost is a little bit more expensive, maybe, you know, $1,650-$1,700, if it's kind of normal, whereas back over in Texas, in the state line area, you know, we're in that $1,450-$1,500 a foot. But 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 to TD. We lost the lateral.
We tried to sidetrack it. We ended up having to sidetrack it twice to get it drilled, and we had basically had another well that we had two sidetracks on. So wasn't a very pleasant experience, but, it, it's definitely an outlier. If you look at just kind of where all our acreage is, it's out on the edge. You know, we knew that area was kind of tough to drill, so just, it's just a one-time event. And it was... You know, we drilled it because the acreage was expiring. We had to drill it or lose it, and so we, we did decide to do full development and drill five wells all the way across the section. So, you know, 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.
Jake Roberts (Director)
Okay, great. I appreciate that. My second question, so the two-well pad 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?
Daniel S. Harrison (COO)
Yeah, so actually we see costs, you know, going down a little bit. We actually started seeing a big movement in pipe prices, just here 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 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 costs, you know, basically come down Q3 and really further into Q4 and Q1.
Carlos Escalante (VP)
Great. Appreciate the time, guys.
Operator (participant)
Thank you. Our next question comes from the line of Charles Meade of Johnson Rice.
Charles Meade (Senior Advisor)
Good morning, Jay, Roland, Dan, and Ron.
M. Jay Allison (Chairman and CEO)
Hey, Charles.
Daniel S. Harrison (COO)
Hi, Charles.
Charles Meade (Senior Advisor)
I wanted to ask a question. Dan, I think you partially answered this in your prepared remarks, but I just wanna 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 gonna let it, you're gonna let it, you're just gonna be running one crew for August and September, it sounds like. You're gonna pick it up again. Is that? Did I hear that right?
Is that the driver of the CapEx decline in 3Q?
Daniel S. Harrison (COO)
Yes.
Charles Meade (Senior Advisor)
What other pieces are there that maybe contribute to a wide range?
Daniel S. Harrison (COO)
Well, I think it's not totally that, but that's the kind of significant driver. We, you know, and that's just kind of a reflection of dropping the rigs earlier in the year. I mean, obviously, we've 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, you know, 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.
You know, 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, you know, cost of services coming down, coupled with that one frac crew being gone for, you know, two out of the three months for Q3 is the driver on CapEx.
Charles Meade (Senior Advisor)
Got it. That, that is helpful detail. And then, the question about the drilling times in, in the Western Haynesville. So, you guys highlighted the 54 days. Can you put that in, in some bigger context of, you know, where your, where your early wells, fell on, on how many days it took to drill, and, and also what you think is a reasonable goal for days to drill in the next 12 or 18 months?
Daniel S. Harrison (COO)
Yeah, 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 lengths, you know, so that kind of comes into play on the number of days, especially in the Western Haynesville with the higher temperatures. But we, you know, 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, you know, that's pretty significant, and I think there's some, still some running room there. We're still, you know, got some efficiencies we look to gain, you know, drilling in the laterals, so I think we'll, we can move that number down a little bit, but-
M. Jay Allison (Chairman and CEO)
You might add that those, with the low number of days, was with those were long laterals, correct?
Daniel S. Harrison (COO)
Yeah, 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-
Charles Meade (Senior Advisor)
Got it.
Daniel S. Harrison (COO)
And those were both, both in the Haynesville with the higher temperatures. So I mean, that's kind of the, you know, everything we've drilled to date, it's basically what I'd say are the toughest wells that we've drilled, you know, basically TDDs, lateral lengths, temperatures. So yeah, we've made a big, we've made a big, big, improvement there. And, you know, like I said, we still are working on a few things to work those numbers down a little bit lower.
M. Jay Allison (Chairman and CEO)
Well, Charles, from the first well to the sixteenth well, you know, you go from 85 days to 54 days. That's 31 days you save. That's a whole month's drilling. You know, 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, seven days, so these wells, you, 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, you know, your questions are on cost savings. 31 days of drilling with these deeper, hotter wells, that's a lot of money.
Charles Meade (Senior Advisor)
Got it. Thank you. That's helpful context, Jay and Dan.
Daniel S. Harrison (COO)
You bet. Thanks, Charles.
Operator (participant)
Thank you. Our next question comes from the line of Bertrand Donnes of Truist.
Bertrand Donnes (Financial Analyst)
Hey, 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, you know, 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, you know, pro forma IP than maybe the two combined wells, but a lower decline, or any thoughts there?
Daniel S. Harrison (COO)
Yeah, that's a really good question. So, you know, we, we definitely expect the performance to be the same as the 10K well. You know, the only really mild difference between a horseshoe well and a, you know, a 10,000-foot, you know, across two sections, a straight lateral, is on the straight lateral, you do get complete across the section line, you know, that 660-foot. You know, there's a, you know, the, the state, you can't perforate within 330-foot of the lease line. So on a horseshoe well, you know, you basically got two, 4,600-foot sections, 9,200-foot. We're on a 10K, so on a straight 10K, you get to perforate a little bit more, you know, as far as the, the, amount that's completed across the 10K.
But on a per unit basis, we expect the performance to be totally the same.
Bertrand Donnes (Financial Analyst)
That's great all. Thanks. And then, shifting gears, on the private side of the Haynesville, you know, 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. You know, 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 O. Burns (President and CFO)
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, yeah, the private operators, you know, cut rigs back very dramatically, and they kind of kept that same rate, you know. So we haven't seen any increase in activity that's on the horizon. I think they're waiting to really see, you know, when gas prices, you know, kind of justify that. And so yeah, the higher rig count has been on the public side, you know, mainly with the, with Southwestern.
Bertrand Donnes (Financial Analyst)
Yeah, I think-
Roland O. Burns (President and CFO)
You know, other than that, everybody else but them has dropped a lot of rigs.
Daniel S. Harrison (COO)
Yeah, I, I agree with Roland. I think, I think you'll basically, you'll kind of stay status quo until everybody sees these gas prices move up.
M. Jay Allison (Chairman and CEO)
Well, if you look at the core, is that 9,000 sq mi, what they call the core, when you drill a well there, either Bossier or Haynesville, you've got a 40% decline in the first year. So you need to be real careful about drilling at a $1.90 gas price. Whereas in, like, in the Western 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 (Financial Analyst)
That's a great point. Thanks, guys.
Operator (participant)
Thank you. Our next question comes from the line of Kevin McCurdy of Pickering Energy Partners.
Kevin McCurdy (Managing Director)
Hey, 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?
Daniel S. Harrison (COO)
I think the frac holiday is. I think we've pretty much got it set. I don't really see it extending further into Q4. You know, 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 pretty, pretty set.
Roland O. Burns (President and CFO)
We look at it all the time, so we can obviously pull those levers if we, if we see that you still see gas prices improving as you get to the very end of the year. And so, you know, to have, you know, so I think unless, unless kind of 2025 changes and-
Daniel S. Harrison (COO)
Yeah.
Roland O. Burns (President and CFO)
dramatically, I think that's kind of what would drive our activity level in the fourth quarter.
Daniel S. Harrison (COO)
Right. And we're, you know, we're not contractually obligated, obviously, with the frac crews. So I mean, we could definitely, you know, if things, you know, the outlook really changed, I mean, obviously, we can change with it.
M. Jay Allison (Chairman and CEO)
You know, fortunately, in the fourth quarter, we do hit our swap position, where we're hedged 50% at that $3.50. So, that's something that if prices do continue to deteriorate, we will at least end up in that quarter. And then, you know, we have—I think we've adequately hedged for 2025, 2026 so far, with 35% of our production hedged at the $3.50+ range. And as we said in the opening, you know, our goal is to hedge at least 50% of all of the 2025, 2026 production. So we are getting out of the 20%+ hedge environment into the 50% environment.
Kevin McCurdy (Managing Director)
Thanks for that. That's helpful. 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?
Daniel S. Harrison (COO)
We did have impacts from the hurricane. Basically, Hurricane Beryl. Yeah, 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, you know, spawned a ton of tornadoes. And really, the thing that hurts us is not necessarily our operations, but all the treating, you know, third-party treating facilities that we flow to, basically, you know, they go down and lost power. So it really does, you know, 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.
Roland O. Burns (President and CFO)
That impact is incorporated in the third quarter guidance?
Daniel S. Harrison (COO)
Yep. Yeah, correct.
Kevin McCurdy (Managing Director)
Appreciate it. Thank you.
Operator (participant)
Thank you. Our next question comes from the line of Leo Mariani of Roth.
Leo Mariani (Managing Director and Senior Research Analyst)
Yeah, 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%, you know, year-over-year. I know a couple of wells kind of slipped, you know, into January, potentially. So wanted to see if that's still, you know, 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 2024 CapEx?
Ronald E. Mills (VP of Finance and Investor Relations)
So, good questions. There's no change on that in terms of the fourth quarter of 2024 versus fourth quarter of 2023. You know, it looks like it can be down about 10%, and, you know, we've 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-nine month lag between dropping activity and seeing it show up in production. And then you're absolutely right. The, the, the CapEx level in the fourth quarter will return more to the, the level you-- that you mentioned. A lot of that is, is a function of, of what we've discussed earlier with the, the frack holiday all occurring in, in the third quarter. That's why the, the third quarter and fourth quarter are so different in terms of CapEx levels.
Roland O. Burns (President and CFO)
Well, and in the Western Haynesville, yeah, but, but really the part, really, no wells coming on in the second half of the year for the most part, and then a lot of, you know, a lot of production coming on in the Western Haynesville right around the end of the year.
Ronald E. Mills (VP of Finance and Investor Relations)
Mm-hmm.
Roland O. Burns (President and CFO)
You know, maybe, maybe a few wells are online right before that and a lot in early January. But, we actually like the way that lines up with, you know, the gas market and all that, so.
M. Jay Allison (Chairman and CEO)
Yeah, Leo, that's the Hogue, the Powell, the two-year analysis. Those are our, the wells we drilled on the pads, the two per pad, and then the Hodges and the Myers. That's the wells, you know, 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 (Managing Director and Senior Research Analyst)
Okay, now that's, that's very helpful color.
M. Jay Allison (Chairman and CEO)
Mm-hmm.
Leo Mariani (Managing Director and Senior Research Analyst)
And then I know, obviously, you know, 2025, you know, 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-$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 a couple 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, you know, kind of early next year?
Roland O. Burns (President and CFO)
Yeah, that price level, yeah, obviously, is definitely works well for Comstock. And, you know, 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, yeah, we do like the way that, you know, what the futures market has out there, and we'll just see if that materializes. And then having a stronger hedge position, you know, will also help support that program, you know, in 2025 than what we had, you know, coming into 2024.
Leo Mariani (Managing Director and Senior Research Analyst)
Okay. Thanks, guys.
M. Jay Allison (Chairman and CEO)
Thanks, Leo.
Operator (participant)
Thank you. Our next question comes from the line of Neil Mehta of Goldman Sachs.
Neil Mehta (Managing Director)
Yeah, good morning, team. Thanks for taking the time. Two, 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 on a smaller scale or even medium to larger term, larger size bolt-ons?
M. Jay Allison (Chairman and CEO)
You know, we all—I mean, we have incoming opportunities all the time. We look at all of them, and-
Roland O. Burns (President and CFO)
Mm-hmm
M. Jay Allison (Chairman and CEO)
You know, 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, you know, 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, they're more acreage, a little bit of acreage to clean up what we have at least, and Ron has budgeted for that.
So, as 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+ 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 know, 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.
You know, 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 we used to drill these in. So that's efficiencies in numbers, saves you a lot of, lot of money. Like, every two 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 out 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've 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've 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 (Managing Director)
Yeah, that, that's great perspective. And the follow-up is just, you know, 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 to capital return, fully burdened for G&A and interest and all the ancillary, what, what is that breakeven in your mind for Henry Hub equivalent?
Roland O. Burns (President and CFO)
Well, yeah, of course, it's evolving in the Western Haynesville as we're, you know, continuing to work down the drilling and completion costs. But kind of where we see the costs being, you know, with a efficient program that we'll have next year with four rigs and kind of, you know, with the pad drilling, that makes- puts it more, starts to get it more on par with our traditional Haynesville. We actually- the two areas are gonna 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-
Neil Mehta (Managing Director)
Mm-hmm
Roland O. Burns (President and CFO)
-the declines are different. So, you know, 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, you know, six months. But then, you know, the second six months, you'll get a lot more production out of a Western Haynesville well, 'cause the way we're producing them with a much tighter choke. But in the end, they're very comparable. And, you know, 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 we're very pleased with that.
M. Jay Allison (Chairman and CEO)
Well, and I think to add on to that, if you look at this inventory depletion, which will happen, you know, you run out of tier ones, you go to tier twos, so the bang for the buck is not quite there in tier two or three because you run out of tier ones. So if our Western Haynesville is compared to tier one, and we have all this acreage, and we de-risk it, our inventory is gonna be materially stronger than you would have if you did a big M&A. M&A is just acquiring more in the same area.
Neil Mehta (Managing Director)
Thank you, team.
Operator (participant)
Thank you. Our next question comes from the line of Phillips Johnston of Capital One Securities.
Phillips Johnston (Senior E&P Analyst)
Hey, thanks for taking the question. It's really a follow-up to Leo's question. The 2025 plan is obviously very much TBD, but you know, if you do stay at five rigs for the balance of the year, and you bring that crew back in Q4, you know, 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?
Roland O. Burns (President and CFO)
That would definitely be up with those Western Haynesville wells coming on.
Phillips Johnston (Senior E&P Analyst)
Yep.
Roland O. Burns (President and CFO)
Yeah.
Phillips Johnston (Senior E&P Analyst)
Okay. That's all. Thanks, Roland.
M. Jay Allison (Chairman and CEO)
Thank you, Phillips.
Operator (participant)
Thank you. Our next question comes from the line of Noel Parks of Tuohy Brothers Investment Research.
Noel Parks (Managing Director, Energy Research)
Hey, it's Noel. Good to talk to you. Just had a couple I wanted to run by you. So in terms of the Western Haynesville with the greater depth and the 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 have had to have some adaptation to be able to work at those levels. Just where are you? Any of that you're doing proprietary, anything new that you're gonna be implementing in the next slate of wells?
Daniel S. Harrison (COO)
No, this is Dan. So, you know, we basically use the same tools in the Western Haynesville that we use in the core. You know, we basically, you know, how we apply them, you know, is a little bit differently. But, you know, as far as our MWD tools, our motors, you know, essentially the same providers, you know, for the Western Haynesville that we have, you know, that we have in the core. Now, there's some, you know, there's some, there are some of our providers up in the core that, you know, can't, you know, doesn't have the full breadth of tools to be able to work in the Western Haynesville, but, you know, the same guys we have working down there work in the core also. Same tools.
Noel Parks (Managing Director, Energy Research)
Got it. And you just mentioned, or Roland just mentioned, how you produce the Western Haynesville wells and the effect that might have on the clients and so forth. I don't know. I mean, just what are your thoughts? What have you learned so far about, you know, choking and how that might influence, you know, production rates, shape of the curve, et cetera?
Daniel S. Harrison (COO)
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, you 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, you know, very low drawdowns. And so, you know, we've kind of just, we're slowly kind of starting to 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 be, we just want to watch the drawdowns and make sure, you know, we don't get, we don't get ahead of ourselves as far as trying to pull them too, too hard. But, everything looks really good. We're just kind of taking our time, you know, in that process.
Roland O. Burns (President and CFO)
We produce through tubing, you meant, over that.
Daniel S. Harrison (COO)
Yeah, and we do. Everything that we complete up in the core, you know, we flow up the casing for quite a long time. We don't come back and tube up those wells for, you know, in some cases, maybe a couple of years, you know, later. But in the Western Haynesville, just because of the very high initial, you know, flowing pressures than what the wellhead, with the casing, you know, 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, you know, downhole before you reach the surface.
So, you know, the pressures obviously would be a lot higher if we were flowing up casing, the surface pressures would. So but that's, that's probably the biggest difference, you know, as far as, you know, downhole. All the Western Haynesville wells are tubed up, all the core wells flow up casing.
M. Jay Allison (Chairman and CEO)
You know, and you're asking about the drilling. If you look at, at our efficiencies, and Dan's right, I mean, some of the tools in the casing, if 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 can 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. And 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 a footprint, at very low cost, and with most of it being held by production. So that's the difference in this play.
Noel Parks (Managing Director, Energy Research)
Great. Thanks a lot.
Operator (participant)
Thank you. Our next question comes from the line of Paul Diamond of Citi.
Paul Diamond (Equity Research Analyst)
Hi, good morning. Thanks for taking my call. Just a quick one. Wanted to drill down on the opportunity set across these, the theoretical horseshoe wells. In your inventory, you had about, call it 16-odd% of, you know, below 5,000 ft. I'm just trying to understand how much of the, how much of those, you know, given current expectations, you think you might be able to convert, and where that would place them kind of in the, in the larger, production cadence or drilling cadence?
Daniel S. Harrison (COO)
Yeah, that's a really good question. So you're right, we do have about 15% or 16% of our total inventory is, you know, 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, you know, fixed number I can probably give you today, but, I'd say the majority of them we're looking at moving over. And, you know, like I said, we're the only reason that we could not would just be because, I mean, obviously, you have to have two, you know, you have to have two of the 5K laterals kind of side by side, right, to have the horseshoe opportunity.
Some of our short sticks in our inventory, you know, you just got one stick, basically. So obviously, that wouldn't be a horseshoe candidate. But, you know, other than that, I think every, you know, 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, you know, convert. They'll go into our long lateral bucket, which right now, we, you know, that's about 26% of our inventory. So we'll significantly boost that up above, you know, 25%-26%. And, you know, we'll, we'll-- that short, that percentage in the short laterals will get a lot lower, which will be great.
I mean, that, that opens up a lot more wells that has really good economics that we can basically, you know, decide to put on our drill schedule, or should we, you know, for some reason, for a leasehold reason or whatever, we kind of need to drill it, you know, it'll still, you know, it'll still fit in with, you know, what we normally would be drilling with good economics.
Paul Diamond (Equity Research Analyst)
Understood. That actually kind of portends into my follow-up. Assuming or under current assumptions you guys are working with, how would a horseshoe, you know, 25,000-foot compare economically to an existing 10,000-foot?
Daniel S. Harrison (COO)
So yes, substantial. I don't have the numbers in front of me, but yes, substantial, you know, rate of return, substantial improvement. I mean, you're gonna save $8 million bucks, $4 million bucks, per basically off those 5K laterals. So, you know, it just drives all the key parameters significantly higher. Like I said, the cost. So the cost to drill a straight 10K, to drill a horseshoe well is essentially the same. You know, I said a 1%-2% premium, but I mean, that's within the plus minus of any well we drill on kind of where our costs are gonna end up. So, you know, we look at the economics for a horseshoe well to be essentially the same as all of our other 10K laterals.
Roland O. Burns (President and CFO)
Understood. Thanks for your clarity.
Operator (participant)
Thank you. Our next question comes from the line of Gregg Brody of Bank of America.
Gregg Brody (High Yield Research Analyst)
Hey, good day, good afternoon, guys. Thanks for all the update. As the credit guy, I've started to see these horseshoe 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 drilling our lateral in a U shape that seems like physics suggests we can do that now?
Daniel S. Harrison (COO)
Right. You know, sometimes, you know, you know, the old saying, necessity is the mother of invention. I mean, we- you know, you drill a 90, a 90-degree turn to drill these laterals already, right? So, you know, 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, you know, you just stay with it until it goes all the way around 180 degrees. Now, I think, you know, until you kind of have to do it, you know, or, you know, you're, you're looking at your inventory, how can I improve it?
You know, a lot of people probably just kind of don't push to go there, but really, I mean, look, there is a little bit more risk to drilling a horseshoe well, and you know, you got to get casing around the curve. You have to get, you know, when you're completing and pumping your perforating guns down and plugs, you know, for all your frack stages, you know, 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 Ford, these other areas. But, you know, I think you just got to prove it out, and you just basically got to show people the results.
I think, you know, after you do more of them, it becomes a little bit more routine, and the risk is, you know, greatly diminished.
M. Jay Allison (Chairman and CEO)
Well, for example, on our first well, I mean, we're pretty close to TD in that well. Last night, I know we were-
Daniel S. Harrison (COO)
We're probably within 500 foot of TD.
M. Jay Allison (Chairman and CEO)
Yeah.
Daniel S. Harrison (COO)
We have had zero problems drilling the well.
M. Jay Allison (Chairman and CEO)
Yeah, that's my point. First well, no problems. We're within 500 ft to TD in it.
Gregg Brody (High Yield Research Analyst)
And that's, when I look 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 ft, or is it—should we think also about the 5,800 ft-8,500 ft that could be converted?
Daniel S. Harrison (COO)
What, really?
Gregg Brody (High Yield Research Analyst)
Just trying to get a sense of how much of that... You didn't quantify it. I know it's early days, but-
Daniel S. Harrison (COO)
Yeah.
Gregg Brody (High Yield Research Analyst)
I'm curious if you have a range that you would think about there.
Daniel S. Harrison (COO)
Well, that's a really good question, and we've already kind of had some internal discussions about that. You know, 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. 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 a 5K, so the rush to start doing 15K horseshoes is not really gonna be there right now.
But I do see, you know, and it's what your acreage, it's how it's laid out and what, you know, your options are. You know, I mean, you, if you can drill—if you got two sections or three sections, you know, like we'll typically, we'll just drill a 15K straight lateral, we're not gonna do a bunch of 7,500-foot horseshoe 15K 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 lengths a little bit further. The one, you know, they do have a little bit more torque and drag.
I mean, obviously, when you're pushing and pulling pipe around a 180-degree bend, it adds more drag, you know, push, you know, tripping in and out of the hole. So, you know, a, a 10,000-foot horseshoe well may- 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 (High Yield Research Analyst)
That does. And then just to come back to my credit roots, just a few follow-ups that you might get for some credit guys. I don't see you getting. You're a three-four today. I think you're okay for next quarter to get into three-five or not, not going through the three-five. Is that fair? And if not, is this a pretty easy amendment that you would get? And then just as part of that, you know, I know the dividend was suspended this year. Just as you look out in the future, how do you think about that today?
Roland O. Burns (President and CFO)
Yeah, Gregg, I think we'll look, of course, obviously, the gas prices are, you know, we're, you know, we knew exactly what they were. We could answer the question exactly. That, you know, that 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, and, you know, it's also, remember, it's a kind of a four-quarter type calculation assessed in one quarter. But, yeah, we stay pretty close to that level. We do think we can get a temporary waiver if we needed it, but we didn't need it, so, you know, we didn't go out and get it. So, things kind of came in exactly as we thought they would.
We knew we were gonna get to that three-four, but luckily, we stayed there. So we'll, but we'll monitor it in the third quarter, you know, as hard as we monitored it in the second quarter.
Gregg Brody (High Yield Research Analyst)
Okay.
Roland O. Burns (President and CFO)
Then on the dividend, obviously, I think we're, you know, we're not really talking about a dividend, you know, until we kind of get the leverage way down and, yeah, looking off in the future. So it's much I think our first priority, you know, 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, you know, back to... We'd like to get back to levels that we were seeing, you know, back in 2022. And, you know, like, we got to under, you know, closer to one times leverage.
M. Jay Allison (Chairman and CEO)
You know, 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, you know, we would expect a little price appreciation and the hedges come in and help. Then after that, I think we're gonna have some big production growth. So that... We're kind of going through that valley right now. It's a good question.
Gregg Brody (High Yield Research Analyst)
I appreciate the time, guys, and the education.
Roland O. Burns (President and CFO)
Thank you, Gregg.
Operator (participant)
Thank you. Our next question comes from the line of Geoff Jay of Daniel Energy Partners.
Geoff Jay (Partner)
Hey, guys, just a real quick one for me. Earlier, you said you thought you would expect to see D&C costs 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 will trend, given the service cost inflation rate that's out there and the efficiencies you're achieving?
Roland O. Burns (President and CFO)
Well, we think our legacy Haynesville, you know, main product, you know, will trend back to that, you know, a little bit below $1,500. That's $1,500, $1,400-$1,500 is kind of an area, you know. And I think, you know, the way we report this is kind of when wells are completed, and they. But, you know, 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, well, maybe we'll 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 costs 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, you know, different periods than the one you're hearing about. So, and also, if you have a certain group of wells, you know, that are different and they're 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, you know, what have been just looked pretty comparable to the other quarter if they weren't in there.
Gregg Brody (High Yield Research Analyst)
We got less wells to average it down.
Roland O. Burns (President and CFO)
But, yeah, we'll probably try to maybe provide some supplemental deal. That will allow you to see the current cost of the quarter, how they're trending, you know, versus seeing something that occurred maybe, you know, even last year.
Geoff Jay (Partner)
Excellent. Well, thank you for that.
Operator (participant)
Thank you. I would now like to turn the conference back to Jay Allison for closing remarks. Sir?
M. Jay Allison (Chairman and CEO)
All right. Thank you again. We've gone over our hour, but as you know, the company, we've always had a vision. I think Gregg asked about, you know, do you drill these horseshoe wells that are 7,500ft x2, 15,000 ft? And the answer is, we have a vision, and we had a vision to step out 100 mi 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, is about 38% above the five-year average. Well, week after week after week, it'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, you know, the three, four, five weeks of what we call real, the meat of the summer. So we do see that. We see, you know, 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 at the Corpus Stage 3 and Plaquemines. So we see a strong fourth quarter of 2024 run from the LNG fleet, and that goes into, you know, 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.
Again, I wanna compliment the Joneses for, you know, 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 gonna be in good shape there. Thank you for your time. We appreciate it.