Comstock Resources, Inc. (NYSE:CRK) Q3 2024 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q3 2024 Earnings Call Transcript October 31, 2024

Operator: Good day, and thank you for standing by. Welcome to the Third Quarter 2024 Comstock Resources Earnings Call. [Operator Instructions] Please be advised that today’s conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chairman and CEO. Please go ahead.

Jay Allison: Perfect. And welcome everyone listening in. Welcome to the Comstock Resources third quarter 2024 financial and operating results conference call. You can view a slide presentation during or after this call by going through our website at www.comresources.com and downloading the quarterly results presentation. There you’ll find a presentation entitled third quarter 2024 results. I am Jay Allison, Chief Executive Officer of Comstock and with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer and Ron Mills, our VP of Finance and Investor Relations If you would please refer to slide 2 and our presentations and note that our discussions today will include forward-looking statements within the meaning of Securities laws.

While we believe the expectations in such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. If you would turn to slide 3 before we start going over this slide, I do want to make a few comments. On Tuesday I was watching Bloomberg News and the headline was, “Big Oil sees AI Boom Driving Crazy Demand for U.S. Natural Gas”. Now by the way, I love that word crazy. Then on Wednesday I read in the Journal, “Wall Street” giants to make $50 billion bet on AI and power projects with the quote Gas is going to be at the forefront of this. “Natural gas can back up those intermittent renewables very nicely” natural gas fired plants will be critical in supplying round the clock power to data centers.

Now since those headlines came out on Tuesday, Wednesday, I know they’re not trick or treat headlines. So today is Halloween everyone. So happy Halloween. It does make you smile a little bit having a pure natural gas company report results on Halloween. I told someone I was hoping tonight I’d see a kid in my front door dressed as a flame. Either that or as a horseshoe. Either one’s good with me. Anyhow, the good news or the treat for natural gas companies is that America and the world needs more natural gas companies is that America and the world needs more natural gas in the very near future as demand for an additional 15 BCF of LNG feed gas gets nearer along with growth in power demand being driven by the growth in data centers and AI. The question is though, here’s the question is where does Comstock fit into this puzzle and how did we position ourselves over the past four years to be a difference maker in the U.S. natural gas market?

As one analyst stated on Monday, “The producing basins are facing inventory exhaustion”. You either add inventory by M&A or exploratory drilling. Comstock has chosen four years ago to grow inventory through exploration in our new Western Haynesville play. Since 2020 we have secured 450,000 net acres in a Western Haynesville and we’ve drilled 18 wells over an area of 26 miles to give birth to a major natural gas field close to the LNG demand corridor, which could potentially add decades of additional drilling inventory. I told someone that it’s like a dog chasing a car and catching it. That’s what we did in Western Haynesville. We caught the 450,000 head acres and now we’re learning how to drive the car or in our case develop the Western Haynesville well by well.

The results to date look very, very promising. So the future looks very bright. In fact, today Dan Harrison, our COO will report on our 13th Western Haynesville and give you cost per foot. And yes, number 13 is a lucky number for us today even on Halloween, that kind of makes you smile too. So on this Halloween day we’re thankful to be the treat as a corner of being is being turned for natural gas demand. So now let me go back to the presentation on slide 3. On slide 3 we summarize the highlights of the third 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 $1.90 for the quarter. As a result, our oil and gas sales including hedging were 305 million in the quarter and we generated cash flow from operations of $152 million or $0.52 per share in adjusted EBITDAX of $202 million.

Our adjusted net loss was $0.17 per share for the quarter. Given the lower completion activity that was planned for this quarter, we had only eight operated wells turned to sale since the company’s last update. These wells had an average initial production of 21 million cubic feet per day. One of those was our first horseshoe Haynesville well which had an initial IP rate of 31 million per day, which Dan will talk about later. We’re continuing to advance our Western Haynesville exploratory. Our acreage in the emerging play is now up to 453,881 net acres. Most importantly, we have substantially reduced the well cost in the Western Haynesville with our 13th well recently completed at a cost of approximately $2,814 per lateral foot. This was a single well with an 11,400 foot lateral, which did not get the cost savings that we see on a two well pad.

The next five wells in the Western Haynesville are expected to be turned to sales in late 2024 to early 2025. Four of those are on two well pads now. I’ll give it over to Roland to go to third quarter financial results. Roland?

Roland Burns: All right, thanks Jay. On Slide 4, we cover our third quarter financial results. Our production in third quarter averaged 1.4 Bcfe per day, which was 2% higher than the third quarter of 2023. Continued low natural gas prices resulted in our oil and gas sales in the quarter declining 3% to $305 million. EBITDAX for the quarter was $202 million and we generated $152 million of cash flow in the third quarter. We reported an adjusted loss of $49 million for third quarter of $0.17 per share. Higher depreciation, depletion and amortization in the quarter really accounted for the loss. The higher amortization rate driving the increase in our DD&A was caused by a decrease in improved undeveloped reserves, which had to be determined under SEC rules based on the low natural gas prices we’ve had over the last 12 months.

On slide 5, we cover our year-to-date financial results. Production in this period averaged 1.5 Bcfe per day, and that was 5% higher than the same period in 2023. Again, low natural gas prices caused our oil and gas sales in the first nine months of the year to decrease 7% to $919 million as compared to 2023. Our EBITDAX for the first nine months of this year is $598 million, and we generated $452 million of cash flow. We reported a net loss of $121 million for the first nine months of this year or $0.42 per share as compared to income of $105 million in the same period in 2023. On Slide 6, we break down our natural gas price realizations in the quarter. The quarterly NYMEX settlement price averaged $2.16 in the third quarter the average Henry Hub spot price averaged $2.09.

Our realized gas price during the third quarter averaged to $1.90, reflecting a $0.26 differential to the settlement price and a $0.23 differential to the reference price. In the third quarter, we were 28% hedged, which improved our realized gas price to $2.28. As we look ahead to the — the fourth quarter will be 50% hedged. On Slide 7, we detail our operating cost per Mcfe in our EBITDAX margin. Our operating cost per Mcfe averaged $0.77 in the third quarter, that’s a $0.07 improvement from the second quarter rate and then our margin improved 67% in the third quarter as compared to 61% in the second quarter. A lot of that was driven by lower production and ad valorem taxes, which were down $0.05, reflecting a reduction in the statutory rate in Louisiana.

Our lifting costs were also down $0.05 in the quarter. Our gathering costs were up $0.03 in the quarter, but this is solely due to some prior period adjustments from some of our transport agreements. So we expect to see that back to kind of normal rate in the fourth quarter. Our G&A costs were unchanged from the second quarter. On Slide 8, we recap our spending on our drilling and other development activity. We spent a total of $184 million on development activities in the third quarter. And for all of the first nine months of this year, we’ve drilled 23 or 18.6 net Haynesville wells and 12 or 11.1 closer well. We’ve also turned 41 or 35.9 net operated wells to sales so far this year that had an average IP rate of 24 million per day. Slide 9 recaps our capitalization at the end of the third quarter.

We ended the quarter with $415 million of borrowings outstanding under our credit facility, giving us $3 billion of total debt, including our outstanding senior notes. Yesterday, our bank group unanimously reaffirmed our borrowing base of $2 billion, and our electric commitment still remains at $1.5 million under the bank credit facility. And given the extended period of low natural gas prices that we’ve had, our bank group approved an amendment to loosen the covenant leverage ratio that we have. The new leverage ratio under the amendment increases to less than 4 times through the first quarter of next year then steps back down to 3.75 times in the second quarter of 2025 and then to less than 3.5 times by the third quarter of 2025. At the end of the third quarter, we ended the quarter with $1.1 billion of liquidity.

I’ll now turn the call over to Dan to discuss the operations.

Daniel Harrison: Okay. Thanks, Roland. If you look over on Slide 10, this is an updated slide from our last call, which outlines the new development plan we have utilizing the horseshoe lateral concept. The test the concept, we have — we’ve successfully drilled and completed our first single horseshoe well, the Sebastian 11 #5. This is located in DeSoto Parish, Louisiana and it’s located in one of our isolated single section acreage blocks. We turned the well to sales early last week. We just recently reached an IP rate of 31 million cubic feet a day from a 9,382 foot completed lateral that is in the Haynesville Shale. Building upon this successful test, we will be pursuing additional horseshoe well projects in the future. The technology allows us to develop acreage that before presented more challenging economics by being limited to drilling short laterals.

The section we have depicted on this slide represents a project we have scheduled for late next year. This section would have originally been developed by drilling 4,000, 5,000-foot laterals from 2 well pads with a $40 million capital cost. The same section will now be developed from a single 2-well pad drilling 2 horseshoe laterals with a $32 million capital cost. And this is based on the D&C cost of $1,740 a foot, and our recently completed Sebastian well costs came in slightly lower than this. The project will deliver cost savings of 23% or $8 million, which substantially improved all our key economic performance metrics. We expect the well performance from the horseshoe wells will match that of our regular 10,000-foot laterals. And with this success, we have also optimized our drilling inventory by converting 57% of our short Haynesville locations to 64 future horseshoe locations.

We’re still in the process of evaluating our short Bossier locations for additional horseshoe view locations. On Slide 11 is our current drilling inventory as it stands at the end of the third quarter. Our total operated inventory now stands at 1,607 gross locations. And so 1,252 net locations, which equates to a 78% average working interest. The non-operated inventory now stands at 1,199 of those locations and 158 net locations, which represents a 28% average working interest. The drilling inventory split between Haynesville and Bossier locations broken down into our 4 different categories: bilateral length. The short laterals less than 5,000 foot, the medium laterals up 25,000 and 8,500 foot. Our long laterals come in 8,500 and 10,000 foot and our extra-long laterals that go past 10,000 feet.

In our gross operated inventory, we now have 180 short laterals, 331 medium laterals, 482 long laterals and 614 extra-long laterals. And inventory is split evenly basically between the Haynesville and the Bossier. The updated inventory numbers include the impact of identifying 64 horseshoe locations in the Haynesville Shale. 2/3 or 68% of the gross operated inventory as laterals longer than 8,500 feet and 38% of the gross operated inventory have laterals longer than 10,000 feet. The average lateral length now stands at 9,261-foot, and this is up slightly from our 9,077 feet, which we had at the end of the second quarter. This inventory provides us with over 30 years of future drilling locations based on this year’s activity. On Slide 12 is the chart outlining our average lateral length drilled based on wells that we turned to sales.

During the third quarter, we turned 11 wells to sales with an average length of 12,586. Individual links ranged from 8,912 feet to 15,303 feet. Our record longest laterals will still say is at 15,726 seat. All the wells we turned to sales during the third quarter had laterals longer than 8,500 feet. And furthermore, 9 of the 11 wells that turned to sales during the quarter were extra-long laterals that were over 10,000 feet. As we mentioned earlier, we did not turn to sales any wells on our Western Haynesville acreage during the third quarter. However, we do have 6 additional wells in the Western Haynesville that we plan to turn to sales by the end of the year or early January 2025. The first of these 6 wells was turned to sales last week, and we are — it’s currently being flow-tested.

Looking ahead, we have several extra-long laterals slated to turn to sales over the remainder of the year, and we expect our average lateral length for all of 2024 will be approximately 10,100 feet on a total of 48 wells turned to sales. To recap on our long lateral activity to date, we’ve now drilled 109 wells, collaterals longer than 10,000 feet, and we have drilled 40 wells with laterals over 14,000 feet. Slide 13 outlines our new well activity since we last provided the well results at the end of July. Since our last call, we have 8 new wells that have turned to sales. The individual IP rates on these range from 10 million cubic feet a day up to 31 million cubic feet a day with an average test rate of 21 million cubic feet a day. The average lateral weight was 12,391 feet with the individual laterals that range from 9,382 feet up to 15,272 feet.

This list includes our first horse shoe well, the Sebastian 11 #5, turned to sales last week that achieved an IP rate of 31 million cubic feet a day. Recapping our activity levels, we’re currently running 5 rigs and 2 frac crews, our second frac crew returned in late September following a 70-day frac holiday during the third quarter. We currently have 2 of the 5 rigs drilling in the Western Haynesville. We also have both of our frac fleets currently working in the Western Haynesville where we’re in the process of fracking our first 2-well pads. Most of our pads will be completed in the fourth quarter and turn to sales at year-end. In addition to these 2 well pads, we also have 2 single wells that turn to sales by year-end, which generates the total 6 Western Haynesville wells turning to sales between now and year end.

On Slide 14 is the summary of our D&C costs through the third quarter for our benchmark long lateral wells that are located on our core East Texas and North Louisiana acreage. This covers our wells with laterals greater than 8,500 feet long. And during the quarter, all 11 wells that we turned to sales were located on our core East Texas, North Louisiana acreage at all 11 wells fell into our benchmark long-lateral group. We’re now providing the drilling cost per foot based on the date the wells reached TD. This provides a better view of the current drilling environment and the growing cost environment and just to be better aligned with the timing of when we — when the drilling dollars are actually being spent. The completion cost per foot continues to use the turn to sales to date.

So in the third quarter, our drilling costs averaged $642 a foot. This is a 3% increase compared to the second quarter. Our third quarter completion costs came in at $776 per foot, which represents a 6% decrease compared to the second quarter. When we kind of look out ahead to the next couple of quarters, we do see our D&C cost remaining flat to going slightly lower. I’ll now turn the call back over to Jay to summarize the 2024 outlook.

Jay Allison: Okay, Roland. Thank you, Dan. Thank you, if you would, I’ll direct you to Slide 15, where we summarize our outlook for 2024. As we stated last quarter, we’ve taken a number of steps in response to the significantly low natural gas prices this year. During the first quarter, we released 2 of our operated drilling rigs reducing our rig count to 5 rigs, and we also released 1 of our frac spreads reducing our frac fleet to 2 spreads. We no longer have any long-term commitments for our pressure pumping services. With those steps, our 2024 CapEx expected to be down 25% to 35% from the 2023 level. We suspended our quarterly dividend, saving approximately $140 million of dividend payments. In late March, our majority shareholder, Jerry Jones, and invested an additional $100.5 million into the company through an equity private placement.

Starting in late February, we have added significantly to our hedge position starting in the fourth quarter of 2024 and extending through the end of 2026. We’re targeting a hedge level of 50% of our expected production level. In early April, we further enhanced our liquidity position with a $400 million senior notes offering. We are evaluating our planned activity level in 2025 based upon the outlook for natural gas demand and we’ll adjust our drilling program as needed to a response to the natural gas prices. We’ll continue to maintain our very strong financial liquidity, which totaled just under $1.1 billion at the end of the third quarter. Our industry-leading lowest cost structure is an asset in the current low natural gas price environment as our cost structure is substantially lower than the other public natural gas producers.

We remain very focused on proving 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. We believe that we are building a great asset in the Western Haynesville that will be well positioned to benefit from the substantial growth in demand for natural gas in a region that is on the horizon, driven by the growth in LNG exports that begins to show up in the second half of next year. I will now have Ron to provide some specific guidance for the rest of the year. Ron?

Ronald Mills: Thanks, Jay. On Slide 16, we provide our fourth quarter guidance. The fourth quarter production expected to remain in the 1,325 to 1,375 million cubic feet per day range, which is down approximately 10% from the fourth quarter of 2023 as expected and as has been discussed on prior calls, that’s related to the impact of the timing of dropping the 2 rigs in — late in the first quarter. The D&C CapEx guidance for the quarter is $225 million to $275 million due to the timing of bringing wells online. We now expect 43 net wells to be turned to sales in 2024 versus the original expectation of 38 to 39 wells when we provided our original guidance. Those wells are coming on at the very end of the year. So there’s not much production impact, but we do bear the full brunt of that capital expenditure.

We continue to anticipate leasing CapEx of $2 million to $5 million per quarter, and CapEx related to Pinnacle Gas Services, which is funded by our partner, Quantum, is expected to be $50 million to $90 million during the quarter. On the cost side, LOE is expected to average $0.24 to $0.28 per Mcfe, while GTC costs are expected to average $0.34 to $0.40 per Mcfe. Production and ad valorem taxes is expected to average $0.14 to $0.18, while the DD&A is expected to remain in the $1.40 to $1.55 range. G&A side, cash G&A remains in the $6 million to $8 million per quarter range with about $3 million to $4 million of noncash G&A expenses expected. With the current SOFA rates in the April notes offering, we now anticipate our cash interest expense to be $54 million to $56 million during the quarter, and our noncash interest in the quarter will be $3 million to $4 million.

Effective tax rate remains in the 22% to 25% range, and we still expect to defer roughly almost 100% of those taxes. I’ll now turn the call back over to Jill to answer questions.

Q&A Session

Operator: [Operator Instructions] First question comes from [Indiscernible] with Bank of America. Please go ahead. Your line is open.

Unidentified Analyst: Hey good morning guys. Thanks for getting me on. I guess I’d like to start with the elephant in the room, which is the planned outspend for 4Q. To bring it up a little bit, I think we’re all pleased to see that you guys have the waiver. But I think some of the market to that tripping the coming in will lead you back to more of a free cash priority. From our perspective, I think we get it, we see you trying to stabilize production and division for maybe a better 2025. Just hoping that you can kind of talk through your motivations to outspend through this soft pricing and then maybe articulate your plans to manage the balance sheet in 2025?

Roland Burns: Yes, that’s a good question. I think really that when we originally had the plan in place and by the time you kind of execute the plan, prices were a little bit stronger, and we figured it would really cover those expenditures planned for this year. And I think the only there’s a little higher expenditure level only because the drilling days have been quicker and the Western Haynesville, so a lot of the completion work that was going to cross over — some of that is going to cross over into 2025. It’s kind of now expected to be mostly in the quarter. So on a — other than looking at an individual quarter, I think if you looked at it on a longer period, there hasn’t really been much change at all in the plans. It’s just how the how the costs end up being reported.

So our goal for 2025 is again to with a higher hedge level I think it will be easier to achieve and take some of the risk out of gas prices is to try to balance the capital we invest back into with the cash flow we generate through operations.

Unidentified Analyst: Got it. So it’s really timing and your plan to keep activity continue to progress forward. Maybe my next question is really on the Western Haynesville. Maybe this is for Dan. Cost per foot on the Hodges is better than our high-end estimate. And it’s just one well. You’ve got a 2-well pad coming up, so maybe those costs are getting better. Maybe I have been aside if you can discuss those drilling costs, we’ll take that. But more broadly, with the amount of wells that you have online, the data points on cost, maybe you have an event path ahead. When can we expect a more fulsome update on the Western Haynesville in 2025?

Daniel Harrison: Well, I think we’re going to be probably next year, early next year on the next call. We’re going to be coming forward with obviously a lot more information on the Western Haynesville. You’re right, this 2,814 foot, which is a big milestone for us, was a single well. And above the wells we drill today, of course, this is the port thing to well, we turn to sales. This was the fastest 1 we’ve drilled to TD 51 days. If you go back a few years, we started out drilling these things in 75, say, 70 to 80 days. And now this one comes in at 51 days, so a massive improvement, and we’re kind of still working a few days off. But we had really good execution on this particular well, the Hodges #1, drilling just all phases of the operation went really well.

We’ve got some pretty good frac pricing in place also right now. The well frac is really good. I’ll also point out one of the big drivers is the lateral length and the length on this and over 11,400-foot or 405-foot. So that obviously is very important in that cost per foot number. Now the numbers that we typically — the numbers that we’re kind of putting out on kind of our targets, you mentioned $3,000 a foot. It is all kind of normalized to a 10,000-foot lateral. So any time you have a 11,000 to 12,000 foot lateral is going to generate a little bit better cost per foot and vice versa if you are at 8,500 to 9,000 foot lateral, it’s going to be a little bit higher cost per fit.

Unidentified Analyst: Thanks for that. We are watching with interest guys.

Daniel Harrison: Thank you.

Operator: Thank you. One moment for our next question. The next question comes from Carlos Escalante with Wolfe Research. Go ahead, Carlos. Your line is open.

Carlos Escalante: Good morning guys. Thank you for taking my call. Well, first of all, the — I’d like to start with the horseshoe results because they are certainly encouraging. And I think directionally, this is what the investment community wants to see. Now I do think that we need to rationalize how this translates into free cash flow generation. So my question and bearing in mind because you guys know this better than I do, that not all acreage is created equal. What’s the geographical spread of the 64 locations that you think are candidates for this across your Haynesville locations? Thanks.

Daniel Harrison: Good question. So that is 64 just in the Haynesville. And you’re right, all the start off. We’re very happy with the results on the Sebastian well. We didn’t — we had no issues to drilling the well. I’m going to say maybe 2 extra days, if you compare that to just drilling a straight 10,000-foot lateral. Just didn’t have any issues. And the frac it fracked, if you just — if you didn’t know that it was a horseshoe you well, you can’t — we couldn’t tell any difference in fracking those straight 10,000-foot lateral and frac in the horseshoe. The well did frac really good again. So results look fantastic. So we’re super excited about it. As far as the spread of the locations, I’d say they’re pretty evenly kind of spread across if you look at that acreage position and just kind of from south to north, I think we’ve got them — they’re just pretty much all across the basin.

So we’ve got them in the 16 B per thousand we got them in the [Indiscernible] type curve areas up to the 2. So I think kind of the answer for you is really is just spread out across all the acreage. Not really in any specific spot

Carlos Escalante: Sure. That certainly helps. I guess your answer provided me with another question, if you will, on that same topic. And maybe this is a bit too early because the Western Haynesville is still, by all means, an exploration play. But do you feel like you will come across the geometry, lease line issues that you have in the Haynesville and the traditional Haynesville in the Western Haynesville. And then just to finish up my second question, which is also in the Western Haynesville. What do you expect to be the average lateral length for your program going forward, bearing in mind that you have a hard reservoir and it’s more difficult to drill?

Daniel Harrison: Okay. So I think your first question maybe is maybe I can find will be with lease lines in the Western Haynesville versus Louisiana. So really, the big difference between in Louisiana, we deal with square mile sections, right? Every section is a unit. So we’re usually either confined to drilling a 5,000-foot to 10,000-foot or 15,000-foot or later on in the play, we did 7,500-foot laterals. Now we’ve got the ability to turn the wellbore around and then horseshoe you. And so we deal — the lease lines are the section lines. In Texas, you don’t have sections. Abstract surveys, you pretty much can build your units. They’re more customized. They’re more — much more regular and shape and size. And so you’re going to have laterals in Texas that are kind of any different links between, say, 5,000 and 10,000 feet, you can have some at 9, you can be at 8, you can be at 6,500, 11,500, not really Louisiana, you’re in those kind of specific 5, 10 or 15 or 7,500-foot groupings, but — so really, that’s kind of the difference in drilling in one state versus the other.

As far as average lateral length in the Western Haynesville, I think we’re looking at about 10,000 foot average. We’ve got a lot better had on the bottom of temperature. So that’s really not an issue. I think probably the bigger driver there is not the temperature. It’s just — there are some minor faults here and there, so that there’s just certain. There’s some geo hazards in certain places. You just — we can’t drill across and have to stop. And so that’s really kind of the only driver there. Obviously, we’re trying to drill the longest laterals we can now that we’re holding acreage. But I see — I think 10,000 is a pretty good number looking out ahead of what our average lateral rate will be. So we drilled a 12,700-foot max already. And I think our shortest lateral right now is, I want to say, 700, 800 feet.

So we’re not having any issues drilling these 10,000, 11,500-foot laterals. It’s just limited by, like I said, for hazards or other factors.

Carlos Escalante: Wonderful. Thank you guys.

Operator: Thank you. Stand by for our next question. The next question comes from Charles Meade with Johnson Rice. Go ahead, Charles. Your line is open.

Charles Meade: Good morning, Jay, Roland and then whole Comstock team there. I want to go back to the Sebastian well. You can’t help but notice that it’s the shortest lateral with the highest IP on the quarter. So I know it’s early, but do you think this is just luck of the draw? Or is there something else going on here perhaps?

Daniel Harrison: It’s not luck of the draw. I’d say all of the horseshoe we do in Louisiana were pretty much going to be about the same lateral length unless we — and maybe I think someday, we’ll probably reach out an attempt to do a horse that’s maybe 7,500 foot and 7,500 back. That’s way out, and that’s we’re getting out ahead of ourselves. But this is kind of about what we would expect from a well in the area where we drill this oil on this acreage. So we’re not surprised at all.

Charles Meade: Got it. Got it. That’s good. It’s good to have your opinion on that. And then going back to Western Haynesville. I think you’ve discussed this a bit. It’s great to see what you’ve done with that Hodge as well. But as you think of repeating that or trying to deliver repeat on that, leaving aside the lateral length, the pieces of the — what are the pieces of the whole well construction and completion pulse that you’re going to be most focused on to try to get a repeat of that dollar per foot metric?

Daniel Harrison: Well, I think first of all, we got to be — and we have become more consistent. We’ve had some really good showings, but we have — in the early wells, we didn’t have the consistency. So we’re becoming much more consistent at basically the really good performance. And so we figure we always get a 5% to 7% cost reduction on pad drilling versus a single well pad. So this is a pretty good number for a single well pad. This well on the longer later, like I mentioned just a little bit ago, helps with that number. That’s going to always move the number down a little bit when you start going over 10,000 feet, okay. And this one was 11,400 feet. So had this exact same well. Like I said, we had great execution across all phases.

If this would have been a 9,000-foot lateral, this would have been — the cost per foot would have been a little bit higher. And if we would have been 12,000 foot a little bit lower than this. So we definitely see the costs we start doing pad drilling, with this performance, we’re going to generate numbers lower than this $2,800 per foot.

Charles Meade: That’s great. Thank you.

Operator: Thank you. Stand by for our next question. The next question comes from Jacob Roberts with TPH & Co. Jacob, go ahead. Your line is open.

Jacob Roberts: Good morning. I believe you’ve all previously contemplated adding a few rigs next year. And I understand it might be a little bit early to talk about 2025. But given where the commodity price is today, how are you thinking about the timing of those rig adds, if at all? And then maybe as well, if I could tack on what you might consider a balanced program in terms of those rigs at current commodity prices?

Roland Burns: Yes, it’s a good question. It is kind of early because we will really be watching the gas market, how — if we have a winter or not, those would be a lot of factors, especially driving gas prices in the first half of 2025 as the second half of 2025, we kind of see some increased demand. So that’s something we’re looking at really hard and deciding when we bring back the 2 rigs that we dropped in the first quarter of this year. And as we do have a lot of flexibility and when we do that, we think we can line up the services when needed, and we have a lot of services weekend with short notices drop. So again, I want to be very responsive to whatever environment we have in 2025. And target having a higher hedge percentage in 2025, that 50% level is kind of what we’re going to target.

We’re 40% almost hedged now for 2025. So we have a little work to do there. But that should help. That should help us stay more on track than were this year if the first 3 quarters, we were a little bit less than 30% hedged.

Jacob Roberts: Thanks. I appreciate the color. Maybe if we could look at the Western Haynesville and particularly the midstream. Can you frame the current runway you have what the Q2 2025 addition will add to that runway maybe in terms of quarters or wells that you ultimately see being able to handle being able to be handled?

Ronald Mills: Yes, it’s a good question. As we — with these 6 wells coming on that will go into our Pinnacle system there that are coming on and we’ll be at a pretty good rate by the — in January. We start to really hit the treating capacity, not the pipeline capacity of our Bethel treating plant. And we do have quite a bit of backup capacity where we could offload to a couple of other midstream companies that we have contracted capacity and a good rate on. So we could definitely do that. We just would prefer to have it in our own facility. And so that’s where the key. A lot of the expenditures that we are incurring now, especially in the fourth quarter, and early in the first quarter of next year is really to open up a new gas treating plant at Marquee, which will be on the other end of our Western Haynesville footprint.

And then that’s going to add 400 million a day of treating capacity. So then we’ll be — have a lot of capacity to handle the growth out there. So as that one comes online, we do have the ability to offload and process under these arrangements we put in place. So we definitely won’t have any restraints as far as actually producing what we do. So — and then as we evaluate the program and add more rigs, that’s where we’re continuing to look and say, do we want to build out additional capacity for the play.

Jacob Roberts: Great. Appreciate the time.

Operator: Thank you. Stand by for our next question. The next question comes from Greta Droshky [ph] with Goldman Sachs. Greta, go ahead. Your line is open.

Unidentified Analyst: Hi, good morning and thank you for taking my question. I was just wondering if you could spend a bit more time on the Horseshoe wells. And the benefits you’re realizing there. Is there a proportion of your overall operations that you hope to apply this technique to over time? And do you see potential for any upside to your 64 horseshoe locations that you’ve outlined? Thank you.

Daniel Harrison: Good question. So we do definitely see an upside as far as the number of locations that will get converted. So the 64 that we’ve got converted in the inventory so far is just on the Haynesville side. We’re still working through the Bossier. All of our Bossier sticks, and we’ll probably have a number on that. I’m sometime in the first quarter. As far as the number of horseshoe, kind of pushing into our development program. I mean, being that this news is pretty fresh. We obviously are going to do more and want to do more for right now in our drilling program. Obviously, we’ve got a lot of things in place, and it takes a lot of time, obviously, to get things drill ready and to move around, just a lot of lead time.

So our next we have a single horseshoe that’s coming up early next summer is the next project. We got a 2-well pad horse, which is the one we talked about on the slide here. That is later next year and we also have a triple. We got a triple horse well pad that will come up behind that in 2026. So like I said, we love the results. it’s just that it’s hard to add — push a bunch of these into our drilling program that’s already been set along short notice. But I can see more than what we have scheduled now maybe get pushed into the program as we get a little bit more data on this well. And have some time to just get the drilling program revised a little bit, which takes a little bit of work.

Jay Allison: My comment would be, if you — we always high-grade our inventory our 1,400 locations, etcetera. And now the horseshoe will be accelerated to the front of that, as Dan had said. So that’s a good thing based upon the recent results, we just have in this painful well. And again, we may have that many or more in the Bossier as we keep putting that in the first quarter of 2025.

Roland Burns: So some of the other indirect positives from the horseshoe, especially as we get through the Bossier inventory, in our reserves, we will move these up with much higher economic results. And so even in low prices, some of these can come very economic. And so yes, we see the IRRs and the horseshoe wells being to 3 times better than a short lateral Haynesville well. Dan Harrison says 3 times better. So that’s a — it makes a lot more of that inventory very economic at lower gas prices. So you’ll see some impact and improve — just be able to bring some — a lot more of the inventory into the proved undeveloped reserves.

Daniel Harrison: Yes. I think I didn’t really answer that part of your question. So I mean, as far as the performance versus the single 50s, our return rate is basically it triples the return on the wells. Our payouts will be less than half. If you just look at the 2 single 500 versus the horseshoe, we’re going to generate $5.5 million to $6million additional PV-10 value. And so pretty substantial.

Unidentified Analyst: That’s really helpful. And then my second question is I was wondering if you could speak about the outlook for M&A in the Haynesville. Do you expect consolidation to continue more broadly? And do you see opportunities for bolt-on M&A either in the Western or legacy Haynesville for Comstock from here?

Daniel Harrison: Well, yes, we’re continue to keep a good eye, especially in the Western Haynesville, where we’ve had great opportunity to partner with other companies that want the shallow production or the existing production, and we’ve been able to acquire the deep rights and actually have acreage held by production. So those opportunities interest us a lot in that area, and there’s been — it’s a fairly — the older vertical wells are fairly mature, so they are being divested of the larger companies that own them. And so we continue to work that part of the M&A cycle. And there are still private operators that have plan to divest. So we expect to see those private companies probably over time, be consolidated over the next several years. And probably the, as gas prices get to more attractive levels, it’s probably what kind of fuels to start up again in earnest.

Unidentified Analyst: Thanks all of you. Thank you.

Operator: Thank you. One moment for our next question. The next question comes from Noel Parks with Tuohy Brothers Investment Research. Go ahead, your line is open.

Noel Parks: Hi, good morning. Just had a couple. I was just wondering, you mentioned it being important to avoid faulting in the Western Haynesville. I was wondering to what degree you can anticipate those, I don’t know if it’s seismic or legacy penetrations or anything. So just curious in how you’re handling that.

Daniel Harrison: We do have 3D seismic over almost the entire acreage position that we have. And so we’ve got a really good look on mapping of where everything is and got everything pretty much identified. So I don’t see — we don’t really see that as any kind of an issue for us. It’s just something that we do when we plan where we’re going to lay out our sticks in the development. Obviously, that’s very important factor. But we do have 3D, good data. So we’ve got a pretty good picture of what it looks like.

Noel Parks: Great, thanks. And I — sort of a macro top it. Just any seasoning I heard another gas producer sort of affirm a point that you’ve made in the past, which is the lower for longer nat gas pricing and therefore, lower levels of activity is likely to make for a tougher ramp-up of industry activity and then possibly get that get reflected in higher peaking gas prices when we see them come back. So with just another quarter under our belts with places where they are a little better heading into winter. But just wonder about your perception of that and maybe a weak winter versus normal winter perspective on maybe where that peak might occur?

Roland Burns: Yes, that’s a great question. That’s the challenge of the natural gas industry is there is a lot of demand on the horizon that comes in pretty large increments. And — but it’s not here today. And so near-term gas prices are going to be really dependent on what’s the demand of for heating in the winter. And that’s something we all have to see how it plays out. So in the short term, especially the first half of 2025 is going to be really tied to that winter, although. I think we have two factors that are in our favor there. One is there is start-up of new demand on the LNG side, it’s sets us up to when even today at the highest rate it’s been. And two, the rig count has been very low. And so production declines will also be there to help tighten the supply.

As you can see, even for Comstock, we’ve actually had — even though we cut our activity back in the first quarter, it’s not really to the fourth quarter that we really start to see the decline. And we were on of the first to really cut back activity in the Haynesville. We worked the last. And I think you’ll see that a lot of — especially private operators followed several months later, and you’ll see the first quarter just a lot of that decline really showing up in the Haynesville. So help — I think to help us kind of balance that supply and demand during the period compared to last year when we had the opposite or coming into this year, we had the opposite situation we had a really high activity level and a warm winter. And the 2 kind of created the big drop in gas prices that we’ve suffered this year.

So it’s going to be, I think, a more volatile gas market. And I think you could have — trying to balance the market, they balance it with price. That’s just how the gas market works. So if there’s a little bit too much gas, the price drops a lot, if there’s not enough gas, the price goes up a lot. And I think we’re going to have a lot of volatility in 2025 as different these different factors kind of play against each other.

Jay Allison: And then, Noel, I comment on the defaulting question. I mean, we have major control points for almost all of our 450,000 net acres. I mean we do have those points. And as Dan said, we’ve got 3D seismic on the majority of it. And if you look at M&A, a lot of M&A was done $4, $5 gas price and the Holy Grail is inventory you typically do M&A or inventory ever now in its size, if you’re small, but a lot of the M&A is inventory. The Holy Grail is inventory. So I think what we were able to do, we were able to go take an old gas field, which is now we call the Western Haynesville, we went deeper, just like we did in the core of the Haynesville/Bossier. And we figured out that technically that we can drill to complete these wells and make it competitive with our core.

So it’s all about the right geographic spot it’s about the right drill bit performance is about the right EUR. And then all of a sudden, you throw in our horseshoe that makes it a little bit more exciting because as Dan and Roland said the IRR on the horseshoes 3 times better than your typical Haynesville as well. So then you get to the banks, the 17 banks looking at us and they look at the whole company and they look at the future, and that’s why we had unanimous approval. It all makes a lot of sense. Just to your point, you have to weather this storm in order to be there when the broad light and sun comes back out, and we are more than well positioned to do that.

Operator: Thank you. One moment for our next question. Next question comes from Bertrand Donnes with Truist. Please go ahead. Your line is open.

Bertrand Donnes: Hey team. I just wanted to follow up on the rig count commentary. You did a great job of notifying your rigs late last year to get them dropped by, I think, the end of the first quarter. So it seems like you have a big — pretty good bit of flexibility on those. Do you have an updated estimate on that? Maybe how many months it would take for you to drop or pick up rigs? And maybe just logistically, do you have to do it around December? Or is it just as easy for you to do it, say, summer or fall?

Roland Burns: Yes. There’s no room time frame. Typically, we’ve got a about half the rigs that are in our fleet that are really just require a 45-day notice. So we have to plan around that. And then obviously, logistics of moving the rig out. Obviously, not going to just pull it out in the middle of a project or a middle of a multi-well pad. So it’s really all about planning for it. So that’s obviously something we looking at very hard as we’re pondering our 2025 budget in the right activity level and kind of see how things play out. But it’s typically December when we really make these final decisions like we did last year and then hopefully have a good plan to get it in place quickly like we’re able to do for the 2024 year.

Jay Allison: The one thing that we’ve tried to do is we try to have all of our rigs be capable of drilling in the Western Haynesville. So even if they’re drilling in the legacy area, we want them to be qualified, if you need to move them over to the Western Haynesville.

Bertrand Donnes: That makes sense. And then switching gears to the land leasing program. It seems to continue to be strong. It seems like every time you think you have an idea of how much is out there, you keep finding more attractive opportunities. Is that because of the movement in gas prices? Or is the leasing team just kind of hitting their stride? Or is your view on the long-term value changing? Just why do you keep surprising to the upside on that?

Jay Allison: Well, if you spent 4 years looking at 3D and at long and well results, and you have an area kind of like I said, it’s like we were chasing this big footprint, and we actually caught it. So if there’s a little bit extra out there, I mean, you keep your land group busy to clean up around where you’re already leased. And if there’s anything else that you would need to add to expand a little bit. But I’d give you is 90% of our leasing program is in a rearview mirror. And I think if you look at our balance sheet, the debt that we’ve incurred, that’s like a big M&A event. I mean, we have acquired the acreage. We’re now drilling it. We control the midstream with Pinnacle and you see the well costs are coming down. And as I said, the Holy Grail is inventory.

If we’ve got 14 other locations, the majorities of those in our legacy I mean just think of the upside they would have on the 450,000 net acres in the Western Haynesville. That is the goal. So we just keep cleaning it up. But you shouldn’t expect any quarter where we spend this $50 million, $100 million like we had done in the past. Those days are behind us. And the reason we were successful at acquiring that acreage is because gas was low, nobody was out there doing it.

Bertrand Donnes: Very well, said. And then I just wanted to clarify something. I think I heard a triple horseshoe pad in 2026. Is that 3 horseshoe wells? Or is that 3 sets of 2 horse wells for a total of 6? Thanks guys.

Daniel Harrison: So that is 3 horseshoe wells, which would be prior to that would have been 6, 5000-foot laterals.

Bertrand Donnes: Makes sense. Thanks.

Operator: One moment for our next question. The next question comes from the line of Geoff Jay with Daniel Energy Partners. Please go ahead. Your line is open.

Geoff Jay: Hey guys. Thanks for taking the questions. Real quick for me. Looking at the Horseshoe D&C of about $1,700 a foot versus kind of, I guess, traditional laterals of that length at about kind of 1,400, 1,500. Is there any reason that you’re — as you do more of these and get better at them that you couldn’t — those 2 couldn’t sort of get closer together? Or is there something about horseshoe drilling that’s always going to be a little more expensive? Thanks.

Daniel Harrison: On the completion side is really not any more expensive. So it’s really on just the drilling side. And it’s really just the cost of — if you have a great execution, it’s just the cost of drilling — doing a 180-degree turn. Obviously, that — if you just equate that distance to drilling straight, it’s going to take you longer to drill that distance, bending back around at 180 degrees, you’re just constantly — I mean we’re using conventional tools you’re just constantly sliding and turning back around. So that’s going to take an extra day or 2, and that’s really about the only difference.

Roland Burns: Potentially after that number that’s kind of reported on that slot. So I think that’s a fairly conservative estimate too…

Daniel Harrison: It is. So we — this was what we projected before we drilled the Sebastian well. So the Sebastian well right now we got projected coming in slightly less than 1,700 a foot versus we had 1,740 is what we had modeled and what we had on this slide deck here.

Geoff Jay: Got it. Thank you guys.

Jay Allison: Yes, that well. I mean, literally, it got IP-ed yesterday.

Daniel Harrison: And that was a single. I mean that’s a single horse you well. So really, if you do 2 horsewells, you get that 5% to 7% additional savings from pad drilling, really, that were, say, 1,680 a foot on the Sebastian, if you do a 2-well pad, we should be able to drop that cost even lower.

Geoff Jay: Got it.

Operator: Thank you. One moment for the last question. The question comes from the line of Paul Diamond with Citi. Go ahead. Your line is open.

Paul Diamond: Thank you good morning. Thanks for taking the call. Just a quick question for you on the 2025 hedging book. It’s currently breaking down pretty evenly per quarter and with the curve currently sitting at around low 3s. I guess how do you guys think about the timing and opportunity of kind of trenching in those last little bit to bring you up to the 50% target?

Roland Burns: Well, in it is our — yes, we will work diligently to bring that to get to the $0.50 level. That’s kind of our target, and we add a little bit post the third quarter. Gas prices have been weaker here lately. So it’s really up to kind of finding good spots to do that. And they’ve got good structures to do that. But potentially, if we’re going to really try to — like you said, we haven’t evenly spread out. But our production next year will be potentially weighted more toward the end of the second half of the year. So potentially, there’s a point where we can kind of focus on the latter part of 2025 to hit our goals where there’s a little bit stronger pricing available.

Jay Allison: I think what we do, we advertise to you whether you’re a bank or a bondholder, an equity owner analysts that our goal if that window opens up before we can hedge 50%, that’s our goal and we’ll be leaning into that window. So…

Paul Diamond: Understood. Appreciate the clarity. And Dan, another quick one. You talked about the 57% conversion of Haynesville locations to horseshoe. I just want to get some idea of where the other 43% kind of sits — are those — have been rolled out? Or is that just haven’t got to them yet or still under evaluation?

Daniel Harrison: Well, they’re always under evaluation, but the — we can’t convert all of them to horseshoe wells because they’re — some things have to work out to be able to convert. First of all, you have to have 2 — you have to have 2 sticks together, right? So if you have. In a lot of places, we just have 1 stick. And so can — obviously can’t do anything with that. But you also have to have A lot of this is on these isolated sections where we still have some sticks left. And it’s also in areas where we’ve got quite a bit of development may be mostly developed and we have a few sticks kind of left to infill. So the spacing has to be right. So you can’t have 2 of your sticks on opposite side of the section that are too far apart to be able to accomplish the horseshoe. So when you kind of factor in all of those different things that you have to have to make it work, that’s kind of — that we ended up with just 57% of that inventory that got converted.

Paul Diamond: Got it. So it would be a reasonable read-through that you probably run into similar types of issues in the Bossier acreage as well?

Daniel Harrison: That would be correct. And on the Bossier side, if you if you just look at the acreage and you lay out nothing but Bossier sticks, we got a little bit more of a clean slate to work with, obviously, because it’s not as drilled up as the Haynesville. So we’ll still have a lot of ability to drill the long laterals in the Bossier whereas in the Haynesville, we got a lot of those drilled and some of these horses are connecting the short. We skipped over and then drill the short laterals, and we were doing the development because just because of the economics. And so now that we can come back and you’ve got 2 of them there, you can hook them up. So maybe in the future, we get a little bit more comfortable with maybe how wide we can space the horseshoe.

We can maybe convert a few. We just need to get a little bit further down the road on what our abilities are going to be. I’m talking about how wide, maybe right now, they’re 1,000, 1,200 feet apart between each side, but if we can — we may be able to drill them 2,000 feet apart, where you have 2 sticks that are left to be drilled 2,000 feet apart, where you can do a big wide turn and hook them up. So I think that number will move in the future. We just need to get a little bit further down the road on what kind of we can do that’s kind of within the reason.

Paul Diamond: Got it. Appreciate the color.

Operator: Thank you. I’m showing no further questions at this time. I would now like to turn it back to Jay Allison for closing remarks.

Jay Allison: First of all, I want to thank everybody for staying on the line for a little over an hour. With natural gas prices ranging between $1.65 and $1.90 for the last 6 months, it’s a difficult time for pure natural gas company. That’s just the fact. But what happens in those months really test our resolve, I want to acknowledge three groups over the past 6 months that consistently have stood for first our 255 employees who create the exceptional results in both our legacy and Western Haynesville area. Second, our 17 banks we reaffirmed our $2 billion borrowing base and gave us unanimous approval on our bank amendment to loosen the leverage covenants. Third, the Jones family through in the month of August made open market purchases of 13.5 million shares of our stock for $138 million.

I want to thank each of you as well as our bond and our equity owners. I can assure you we are on the exact right path to be positioned for the growth in natural gas demand that is just around the corner. Thank you for your time.

Operator: Thank you for your participation in today’s conference. This does conclude the program. You may now disconnect.