Comstock Resources, Inc. (NYSE:CRK) Q3 2023 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q3 2023 Earnings Call Transcript October 31, 2023

Operator: Good day, and thank you for standing by, and welcome to the Q3 2023 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions]. I would now like to introduce your host for today’s call, Jay Allison, Chairman and CEO. Please go ahead.

Miles Allison: Good morning, everyone. In Frisco, Texas, this morning, it’s 34 degrees. The Texas Rangers took a lead in the World Series, and I saw natural gas prices were up about $0.20 this morning. So we’re all smiles here. We started out the day the right way. The world of natural gas is something that is a big part of our business. Reported profitable third quarter with a realized gas price of only $2.41 with only 18% of our gas hedged highlights our extremely low operating cost structure and our high margins. The 18 net operated wells returned to sales since our last update on our extensive Haynesville/Bossier acreage position continued to deliver solid results from our legacy area as well as the emerging Western Haynesville.

The 2 Western Haynesville wells we recently turned to sales were “top-of-the-class” wells as were the other 5 that we turn to sell starting with our Western Haynesville well, the Circle M, which started production in April of 2022. And make no say about it, we’re extremely pleased with the results of all the Western Haynesville wells we have turned to sell so far. This year, we are focused on proving up the Western Haynesville and continuing to build our extensive acreage position. During this time of weak natural gas prices, we’re providing a dividend to our stakeholders, holding our legacy production steady while being accountable to our bank lending group have just reaffirmed our $2 billion borrowing base and proving up a much-needed new get go resource near the expanding LNG export facilities along the Texas and Louisiana Gulf Coast.

A major step in development of our Western Haynesville play is finding the right partner for the midstream build out needed to support our Western Haynesville drilling program, and we are excited to partner with Quantum Capital Solutions to that end. We want to publicly thank them for entering into this new adventure with us. If you’ll go to the main slides, we welcome you to the Comstock Resources third quarter 2023 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 or downloading the quarterly results presentation. There, you’ll find a presentation titled Third Quarter 2023 results. I am Jay Allison, Chief Executive Officer of Comstock.

And with me is Roland Burns, our President and CFO; Dan Harrison, our COO; and Ron Mills, our VP of Finance and Investor Relations. If you go to Slide 2, please refer to Slide 2 in our presentations and note that our discussions today include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now if you’ll flip to Slide 3. What we’ll do is we’ll summarize the highlights of the third quarter. The financial results were heavily impacted by the continued low natural gas prices we realized in the quarter. Oil and gas sales, including hedging were $316 million in the quarter. We generated cash flow from operations of $167 million or $0.60 per share and adjusted EBITDAX was $209 million.

Our adjusted net income was $0.04 for the quarter. We continue to have strong results from our drilling program. We drilled 13 or 10.2 net successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 11,644 feet. Since the last conference call, we’ve connected 21 or 18.1 net operated wells to sales with an average initial production rate of 29 million cubic feet per day. We’re having great success in our Western Haynesville exploratory play. Our sixth and seventh wells were recently turned to sales with strong initial production rates, both of which were drilled in the Bossier shale. We recently entered into a new venture with Quantum Capital Solutions to fund the midstream have built out to support our Western Haynesville drilling program, which I’ll expand on the next slide.

If everyone would turn to Slide 4, this visibly shows our Bethel plant, which is part of the Pinnacle gathering and treating system we acquired last year. Pinnacle combined with our processing we have in the area will allow us to grow our Western Haynesville production up to 500 million cubic feet per day. Given how prolific these wells have been we see running out of capacity in this area by 2025. We’re excited to partner with Quantum Capital Solutions, an affiliate of Quantum Capital Group to build out this system to handle future growth. To that effect, we have set up a mid-spring partnership with QL to build out the system to increase the capacity fourfold, will contribute to Pinnacle gathering and treating system to the partnership and QL will contribute 100% of the capital required up to $300 million for the build out of the gathering and treating system.

We’ll operate the partnership, which will be called Pinnacle Gas Services and will direct is activities. Quantum receives a preferred return and 80% of distributions until the investment hurdle is achieved, then that reduces to 30%. I’ll now turn it over to Roland to cover the third quarter financial results. Roland?

Roland Burns: All right. Thanks, Jay. On Slide 5, we covered the third quarter financial results. Our production in the third quarter was $1.4 Bcfe per day, which was 1% higher as compared to the third quarter of last year and 3% higher than the second quarter. Low natural gas prices significantly impacted our oil and gas sales in the quarter, which came in at $316 million, which is 54% lower than the third quarter of 2022. EBITDAX was $209 million, and we generated $167 million of cash flow during the quarter. We reported adjusted net income of $12 million for the third quarter as compared to only $1 million in the second quarter of this year and then $326 million in the third quarter of last year. Slide 6, we have our financial results for the first 9 months of this year.

Production for the first 9 months averaged 1.4 Bcfe per day. That was 4% higher as compared to the same period in 2022. Oil and gas sales in the first 9 months of this year totaled $991 million, which is 42% lower than last year’s sales in the same period and EBITDAX was $685 million, and we generated $568 million of cash flow for the first 3 quarters of this year. We reported adjusted net income of $105 million for the first 3 quarters of this year as compared to $735 million for the same period in ’22. On Slide 7, we detail our natural gas price realizations that we had in the third quarter. The quarterly NYMEX settlement price in the third quarter averaged $2.55. It was very close to the average spot price in the quarter, which averaged $2.58.

Our realized gas price during the third quarter averaged $2.33, reflecting that $0.22 differential to the settlement price and a $0.23 differential to the reference price. The differential this quarter returned to more normal levels due to improvements in the Houston Ship Channel and Katy Hub prices following the restart of the Freeport LNG facility. In the third quarter, we were 18% hedged, which improved our realized gas price to $2.41. We’ve been using some of our excess transportation in the Haynesville to buy and resell third-party gas. We generated about $2.5 million of profits from this activity, which improved our average gas price realization by another $0.02. On Slide 8, we detail our operating cost per Mcfe produced in our EBITDAX margin.

Our operating cost averaged $0.85 per Mcfe in the third quarter. It’s 1% higher than our second quarter rate. The increased unit costs relate to higher production taxes and higher ad valorem taxes imposed in the state of Louisiana. Our gathering costs were flat this quarter at $0.36 and our other lifting costs were 3% lower than the second quarter rate at $0.24. Our production in ad valorem taxes increased $0.05 this quarter compared to the second quarter level. G&A came at $0.05 per Mcfe. That was $0.01 lower than the rate we had in the second quarter. And our EBITDAX margin after hedging came in at $0.65 — 65% in the third quarter as compared to 63% in the second quarter of this year. On Slide 9, we recap our spending on drilling and other development activity for the first 9 months of this year.

So far, we spent $958 million on our development activities, including $919 million on our operated Haynesville and Bossier shale drilling program. Spending on other development activity has totaled $38 million so far this year. In the first 9 months of this year, we drilled 52 wells or 41.3 wells net to our interest in our operated drilling program, and we’ve turned 57 or 43 net operated wells to sales. The wells we turned to sales had an average IP rate of 25 million cubic feet per day. On Slide 10, we recap our balance sheet at the end of the third quarter. We ended the quarter with $345 million of borrowings outstanding under our credit facility, giving us a total of $2.5 billion in total debt. Our $2 billion borrowing base was recently reaffirmed by our bank group this month, and we ended the third quarter with financial liquidity of almost $1.2 billion.

I’ll now turn it over to Dan to discuss the operations in more detail.

Daniel Harrison: Okay. Thank you, Roland. So Slide 11 is a breakdown of our current drilling inventory at the end of the third quarter. The drilling inventory split between the Haynesville and the Bossier and is divided into 4 categories with our short laterals that are up to 5,000 feet. We got our medium laterals that run from 5,000 to 8,000 feet. Our long laterals at 8,000 to 11,000 feet and our extra long laterals, beyond 11,000. The total operated inventory currently stands at 1,760 gross locations in 1,338 net locations. This equates to a 76% average working interest across the operated inventory. Our nonoperated inventory has 1,265 gross locations and 153 net locations, which represents a 12% average working interest across the nonop inventory.

Breaking down our gross operated inventory, we have 307 short laterals, 286 medium laterals, 712 long laterals and 455 extra long laterals. The gross operated inventory is split 52% in the Haynesville and 48% in the Bossier. 26% of the gross operated inventory for the 455 locations have the lateral lengths greater than 11,000 feet, 66 or 2/3 of the gross operated inventory has laterals exceeding 8,000 feet. The average lateral length in the inventory stands at — now stands at 8,949 feet, which is up slightly from 8,947 feet at the end of the second quarter. The inventory provides us with 25 years of future drilling locations. On Slide 12 is the chart, which outlines our progress to date on our average lateral length drilled based on the wells that we’ve turned to sales.

During the third quarter, we turned 21 wells to sales with an average lateral length of 10,460 feet, thanks to the continued success of our long lateral drilling program. The individual links range from 6,789 feet up to 15,333 feet, and our record longest lateral still stands at 15,726 feet. During the third quarter, 6 of the 21 wells we turned to sales had laterals that exceeded 11,000 feet, and 5 of these exceeded 14,000 feet. To date, we’ve drilled a total of 64 wells with laterals over 11,000 feet and 33 wells with laterals over 14,000 feet. During the third quarter, we also had 2 additional wells that turned the sales on our new Western Haynesville acreage. The Cazey MS #1 and the Lanier #1 wells were both completed in the Bossier shale.

These wells represent the sixth and seventh new vintage wells now producing in the Western Haynesville. Based on our current schedule, we plan to turn another 17 wells to sales by year-end. 13 of these will be longer than 11,000 feet and 8 of the wells longer than 14,000 feet. We expect by year-end 2023, our average lateral length will be approximately 11,000 feet. Slide 13 outlines our new well activity. We’ve turned to sales and tested 21 new wells since the time of the last call. The individual IP rates ranged from 18 million a day, up to 39 million a day at an average test rate of 29 million cubic feet a day. The average lateral length was 10,460 feet with individual laterals from 6,789 up to 15,333 feet. Included in the quarter again are the sixth and seventh in new vintage wells in our Western Haynesville acreage.

The Cazey MS, which was completed in the Bossier had a lateral length of 10,028 feet and was turned to sales in August. We tested the well with an IP rate of 34 million cubic feet a day. The Lanier #1 well, which was also completed in the Bossier, is completed with a 9,577-foot lateral and this well was turned to sales in September. We tested this well with an IP rate of 35 million cubic feet a day. In addition to the first 7 producing wells, we have 1 well that is currently waiting on completion, and we do expect to turn that well to sales in January. We currently have 2 rigs actively running on our Western Haynesville acreage that are drilling our ninth and tenth wells. Slide 14 summarizes our D&C costs through the third quarter for our benchmark long lateral wells that are located on our legacy core East Texas and North Louisiana acreage.

This covers the wells having laterals greater than 8,500 feet long. During the quarter, we turned 19 wells to sales that were on our core East Texas, North Louisiana acreage, and 13 of the 19 wells were our benchmark long lateral wells. In the third quarter, our D&C cost averaged $1,561 a foot on these 13 benchmark wells, which reflects a 1% increase compared to the second quarter. Our third quarter drilling costs averaged $719 a foot, which is a 10% increase compared to the second quarter partially due to the lower average lateral length in the quarter and some drilling issues encountered in the quarter. Our third quarter completion costs came in at $842 a foot. This is a 5% decrease compared to the second quarter. The decrease in completion cost mirrors a slight decline in service costs.

We have experienced this earlier in the year, which is associated with the lower activity levels. And to wrap up our forecasted activity levels. We’re currently running 7 rigs. We do expect to keep the same rig activity going into next year. And we are also running our 3 frac crews, and we expect to keep these 3 frac crews also working in the next year. I’ll now turn the call back over to Jay.

Miles Allison: Okay. Thank you, Dan. Thank you, Roland. For everyone, we’ll turn to Slide 15. I will direct you to Slide 15, where we summarize our outlook for the rest of 2023. We remain very focused on proving up our Western Haynesville play continuing to add to our extensive acreage position in this prolific play. We believe that we are building a great asset in the Western Haynesville that we’ll be well positioned to benefit from the substantial growth in demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports that begins to show up in the second half of next year. Our new Western Haynesville midstream partnership will reduce 2024 capital expenditures that would otherwise be required to support the growth in production that we expect our industry-leading lowest cost structure is an asset in the current natural gas price environment as our cost structure is substantially lower than the other public natural gas producers.

We plan to retain the quarterly dividend of $0.125 per common share. And lastly, we’ll continue to maintain our very strong financial liquidity, which totaled almost $1.2 billion at the end of the quarter. I’ll now have Ron to provide some specific guidance for the rest of the year. Ron?

Ron Mills: Thanks, Jay. On Slide 16, we provide the financial guidance for the fourth quarter of 2023. Fourth quarter D&C CapEx guidance is $240 million to $280 million. And we’ve seen some signs of deflationary pressures on service costs relative to earlier this year. We believe most of those improvements will be seen in 2024. In terms of infrastructure and other spending, we continue to budget $15 million to $25 million of spending during the fourth quarter. On a combined basis, our D&C and infrastructure and other CapEx should remain within our past annual guidance of $1.02 billion to $1.28 billion. In addition to what we spent on our drilling program noted above, we now anticipate spending $30 million to $40 million in the fourth quarter for additional leasing activity.

Our LOE costs are expected to average $0.24 to $0.28 per Mcfe in the fourth quarter, while our gathering and transportation costs are expected to be $0.32 to $0.36 per Mcfe in the fourth quarter. Production in ad valorem taxes are expected to average $0.16 to $0.20 per unit in the fourth quarter, which is higher due to higher ad valorem taxes in Louisiana to go along with the higher production tax rate that Louisiana put into effect at the beginning of the third quarter. DD&A rate is expected to remain in the $1.05 to $1.15 per Mcfe range, while our cash G&A is expected to remain in the $7 million to $9 million range for the quarter with an additional plus roughly $2 million of noncash G&A. Due to the increase in SOFR rates, our cash interest expense is now expected to total $42 million to $46 million in the fourth quarter, while our noncash interest will remain roughly $2 million per quarter.

On taxes, the effective tax rate is still expected to be in the 22% to 25% range, and we still expect to defer 95% to 100% of our reported taxes this year. Now I’ll turn the call back over to the operator to answer questions.

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Q&A Session

Operator: [Operator Instructions]. And our first question comes from Derrick Whitfield from Stifel.

Derrick Whitfield: Regarding the Quantum partnership, I wanted to confirm a comment you made in your prepared remarks. If my numbers are correct, a fourfold in suggests you’re solving for 2 Bcf per day of capacity in the Western Haynesville. If that’s correct, could you comment on how you’re thinking about mainline egress as well?

Miles Allison: Well, I think when we looked at our footprint in the Western Haynesville, as when we look at our inventory, and we looked at the wells that we’ll be drilling between now and maybe 2028, and we look around the corner to see what type of production we may have between now and then. And a lot of that depends upon what the market needs and we think in the latter part of ’24, you’re going to need another 4.5 to 5 Bs. And every year after that, you’re going to probably need another B a day. And that’s just for LNG, exportable gas as feed gas. So when we looked around in Quantum, which is I mean, that is a Blue Ribbon financing source when we started visiting with them months ago, and they started looking at our footprint and the well performance.

We looked at, well, what do we need to do for infrastructure to build this out. We also looked at in the second quarter of 2022 when we had bought the Pinnacle facility, the Bethel in that 145-mile pipeline. What is our starting block as far as midstream company. So we evaluated all that. We looked at the rig count which, again, we will add. Our goal is to add a rig in the Haynesville — in the Western Haynesville next year. So we go from 2 rigs to 3 and then we would add another rig in 2025, and we think that’s what HPP, our footprint. So if you look at that and you look at the model for 5 years, and you look at the need for gas, we modeled it out that by 2028, we would have the capacity with the takeaway, both for transportation and the gathering with the financing from Quantum to have at least 2 Bs a day that we would have available to serve America and the globe.

That’s where we come up with this fourfold number. And it’s based upon us having about 500 million a day by kind of mid-2025 and then growing on that with investments that we would make between now and then and into the future years to 2028. That is how we backed into this, which — I think that’s a really good question because Quantum, which is known for funding midstream in the Western — in the Haynesville and now in the Western Haynesville. I mean I think they looked at everything kind of like our banks did and said, we’re really pleased with what you’ve done and we like where you’re going, and we would like to partner with you. And so we were — that’s why we publicly thank them for entering through this new venture with us. Because they give a good check mark to the rest of the world that they do approve with what we’ve been doing and where we’re going.

Remember, our first Western Haynesville well was only drilled 2 years ago. We started drilling those 2 years ago, and we started leasing the acreage 3 years ago, but we really are building the company. And when you build a company, you have to look what’s going to happen in ’27, ’28 and all that is dependent upon the feedstock that stated for LNG. That’s where we had the announcement today, and that’s where the 2 Bs come from. You did your math on that.

Derrick Whitfield: Appreciate it, Jay. Thanks for all the color, too. In the past, you guys have talked about the Western Haynesville and the asset seeing similar returns to the legacy Haynesville at kind of current operating conditions. With the understanding that you’re still in the early stages of your learning curve in the Western Haynesville, could you speak to what you’re seeing in operational efficiency gains and the degree cost could improve over time?

Daniel Harrison: Yes, this is Dan. So we have seen — we’ve made great strides in our cost structure in the Western Haynesville. Like you mentioned, it is early. We’re on the steep part of the learning curve still. We’ve probably cut off, I’d say, around 20 days on our drill times from when we drilled the first Circle M well to kind of where we’re at today. We do have some things in the pipeline, a line of sight to get the cost down further that will be coming up in the future. So we feel pretty confident about that. And then on the completion side, I think that’s probably doesn’t have a big potential for cost savings because it’s pretty much the same thing we do day in and day out. It’s a little bit higher horsepower cost to frac these wells down here. So really the efficiency gains on the completion side would be — would come from doing multi-well pads and just typical operational improvements.

Miles Allison: I would comment on looking at Dan and the group, things that were once really complex when we drilled the Circle M. Some of those things become a little simpler. If you drilled your seventh well and turn it to sales, now you’re drilling your eighth and ninth and tenth well, and now we started focusing on the Haynesville, not so much to Bossier. So I do see that. And some of the hand-wringing that would require us to drill the first Circle M well. I don’t think we have as much of that. We do have it going forward. But I do think that, that shows you where Quantum comes in and has seen the well results and performance and what the future looks like as far as our inventory, and that kind of answers your question. We think the cost can come down. We think our focus is on lasting worth, not near-term kind of wealth. It’s more of a lasting long-term goal, as we continuing to build this company. We’re building the company.

Operator: And our next question comes from Charles Meade from Johnson Rice.

Charles Meade: Good morning Jay, to you, Roland, Dan, Ron, and the whole crew there.

Miles Allison: It’s always good you to hear from you. You should be here with us with the 34-degree weather. You’d be happier.

Charles Meade: I would be happier. We were in the 50s down here this morning. I like it. But anyway, Jay, I want to ask a real question about your business decisions here. $300 million from — of outside capital. That’s great that you’ve got a high-quality partner like Quantum willing to put that kind of money into JV. I’m curious about what you can share about the way they looked at this, and I’m imagining that for them to put that much money to work, they have to have some kind of — maybe it’s not a firm commitment, but some kind of commitment to the amount of volumes that you’re going to put through the system? And maybe that’s a minimum volume commitment, maybe something else? And also, can you talk about the rate that you’re going to be paying per Mcf is usually the way that’s denominated, but just in general, how are you as the producer going to pay that midstream entity Pinnacle gas?

Roland Burns: Yes, Charles, that’s a good question. And I think that we’re going to continue to charge the same rate that we’ve been charging since the first wells went on to the system that we acquired last year. And we charge for all processing and transportation, about $0.54 per Mcf. So there’s really no change in the rate. It’s the same rate that we historically have had. And yes, we have a very small MVC that’s back to our own subsidiary here that is far less than half of what we project the production to be. So that kind of — just kind of supports the new midstream entity.

Charles Meade: Got it. So that’s — if I understood you right, Roland. So as far as midstream rates, it’s just consistent with what you guys are already paying and that there was some volume commitment, but it’s less than half of what you’re projecting from this asset?

Roland Burns: That’s correct.

Charles Meade: Okay. Got it.

Miles Allison: Just with the existing production that we have, Charles, so I think we start out with a big risk adjustment day 1.

Charles Meade: Got it. And then I guess we can do the work ourselves. But between those 2 numbers, we should be able to figure out when that ownership reverts or rather where they go from whatever, 80% to 30%, but we’ll do that work offline. Second question, I want to ask again about the Western Haynesville, obviously, you guys are — this is a big effort for you guys. When I look at your own results, you guys are — clearly, you guys can put up these IPs in the mid- to high 30s or even I think you’ve had 1 or 2 over 40. So I think that aspect is being derisked. But there’s other important data points, which are the D&C costs. I wonder if you could share what your — maybe not where you are now, but what your target D&C cost is on these wells? And then perhaps what the pressure drawdown is like over time, if you want to share any of that?

Miles Allison: Well, I’ll start out and then I’ll leave it to Dan. I think, number 1, we’re not rigging the system with a high IP rate that’s cut in half. The second that you don’t need an IP rate. I mean these IP rates are real rates that we’re flowing these wells at. I think that’s number 1, which that’s unusual. Number 2, I think the EURs, as we said, in the wells that we’re drilling, I mean, they may be double what the EUR is in a typical legacy well. So those are big game changers. Number 3, I think the cost of any exploration play or exploitation play for the first 7 wells is going to be a little higher than normal. We always said, Charles, you take the first 7 wells in the Haynesville/Bossier in the legacy footprint backend in 2008, and you need a big barf bag because they look terrible.

I think these 7 wells will make a smile. Dan already said that he’s cut the drilling days down by at least 20 days and the costs have come down on these wells. And we — I think we stated in our last conference call that we think that the Western Haynesville wells as is where it is today or fairly competitive, if not equal to, the legacy wells that we’re drilling. I think the thing that you don’t know and we won’t know for a while is what the type curve really looks like when these wells really start falling over and if this bottle hole pressures will maintain where they are today. That’s why we say these wells are top of class because out of the 1,000 wells we drilled in the core and the Western Haynesville, these are some of the best wells we’ve ever touched.

So Dan, do you want to comment anything?

Daniel Harrison: Totally correct there. So I’ll just kind of comment a little bit on the D&C cost. So we have — this is a totally kind of a different casing design down here than what we have up in the core. It just takes a lot more days to drill the vertical part of the hole. And basically, the laterals get a lot more heat. We’ve made a lot of headway of the first 7 wells we have produced and we targeted the Bossier, not entirely due to temperature, but partially due to temperature we’ve gotten a lot better at drilling at the higher temps. We’ve got — of the next — I think we’ve got 10 wells targeted to turn to sales next year. 8 of those are going to be in the Haynesville, 2 will be in the Bossier. So we are going to turn our focus to that.

But we’ve still got some things that we’ve got targeted to put to work out here in the field, it’s going to get the cost down. We feel considerable amount. And then the one thing I want to emphasize is we’re drilling single wells here. So when you look at the cost up in the core, everything up there is a multi-well pad. Either 2 or 3 well pads. So you’re getting 6%, 7%, 8% less cost, just via a multi-well pad versus these down here are single wells. So that alone is driving our cost up a little bit. But Jay is totally right. I mean you’re looking at EURs definitely potentially double what we have up in the core. And then the cost is going to — we’re going to make a lot of improvements on that going forward in the future.

Miles Allison: I think, Charles, the really answer is, if our borrowing base is reaffirmed for that $2 billion. So the 17 or so banks that support us, I mean, they looked at that. I think Quantum has looked at it. I think where we are right now with where we’re going, we see a lot of clarity and some of the confusion that we had 2 years ago when we first drilled the Circle M. Some of that is easing off. And as we drill the wells, they will tell us what the EUR is, and then you’ll see what the real cost to drill and complete these wells are once we’ve had to get enough sample set and that will be months down the road, but we’ll still report to you the results on a quarterly basis, which have been really good.

Operator: And our next question comes from Jacob Roberts from TPH & Company.

Jacob Roberts: Happy Halloween.

Miles Allison: That’s right. offer fall on Halloween.

Jacob Roberts: That’s right. On the Quantum partnership, I’m curious if you could provide your view on what the cadence of spend would have been if Comstock were entirely responsible. And then just on that comment on Slide 15 that this will reduce capital outlays. Are you able to comment on how we should be thinking about 2024 CapEx relative to 2023? Is this going to be offset somewhere else and kind of maintain the same level? Or should we be expecting kind of a lower number?

Roland Burns: Well, we started that with more rigs. Talking about the CapEx. At the beginning of this year, then we’re going to be starting out next year at. So we would — and we think, overall, service cost and drilling rates are down a little bit. So we — there’s a lot of signs that point to lower capital. And then we’ve made investments in the midstream before this partnership and now the partnership will kind of take over that responsibility. The build out of the Western Haynesville midstream is going to be phased in. We’re not going to build it all on day 1 to handle a huge volume. It’s going to be layered in over a 5-year period based on the well results that we achieved. We have quite a bit of capacity now because we acquired a base system, and we made upgrades to that this year.

And so we have a great kind of — great starting toolkit here. And then what we’ll do is we’ll start to add additional treating capacity, additional gathering lines as we need them as we build this out. So I think next year, the spending for this venture is probably between $100 million and $200 million. So that would have been part of our base CapEx, and so now we’ll kind of be funded from this other source.

Jacob Roberts: Great. Appreciate it. And looking — I know this is a really long-term question. But Jay, you mentioned the 4 rigs on the Western Haynesville on 2025 and then this plan to step up to 2 Bs a day in 2028. Can you talk a little bit about the rig count you think you might need to get to that level by 2028?

Miles Allison: Well, as we go — it’s really 2 questions. One — rather 3 questions. One, how many rigs we have to have, we think, to hold our big footprint in the Western Haynesville. We think we probably have to have a fourth rig by 2025. So that — it’s not 10 or 12 rigs. It’s 4 rigs. I mean that’s the beauty of the play how we lease this starting over 3 years ago, how we leased it because we needed to look at the rig count. We think depending upon the laterals and unitization, we probably need 4 rigs at some point in time to hold all that acreage. That’s all of the acreage. So as the wells have performed, we went from 1 rig to a second rig. And now the wells, as Dan has said and Roland has shown in the financial results, it calls for a third rig.

Remember, we had 3 new Cactus rigs built. One, we’ve started using several months ago, we’ll get another one in November and get another one, I think, in February. And those are built really to drill these wells in the Western Haynesville. So that’s 1 question. Second question is, if you take a model, and you have a JV with midstream with a quantum. They want to see what we look like down the road. So we model that out to 2028, and that’s where you end up with that 2 Bs a day. So as we get there, though, if you look at the core, we’ve got — we’ve gone from 9 to 8 to 7 to 6 to 5 rigs in the core. And now we have 5 and 2. So next year, we should have 4 in the legacy or the core and 3 in the Western Haynesville. That still has 7 rig count that we talked about, and Dan mentioned earlier in his presentation.

So we don’t see adding any gross numbers of rigs. We keep our 7 rigs. We just deploy them in different areas for 2024. And then we see what happens in 2024 with the results of the Western Haynesville and commodity prices. So that’s where we go in guidance. It’s the same rig count.

Operator: And our next question comes from Bertrand Donnes from Truist.

Bertrand Donnes: Jay, I just want to start off and say thanks for not putting out your press release on Hollywood — Halloween night for us with young children.

Miles Allison: I guess on that [indiscernible].

Bertrand Donnes: Exactly, exactly. And then the first question, just on the agreement. Were there talks to go beyond $300 million to start or was that just kind of a happy medium for both parties to get a little more data and then expand it. And maybe where I am going with that, is there any interest in eventually allowing third party gas into the system?

Roland Burns: I think it was kind of designed to be what we needed. It’s got lots of flexibility. So it’s not — we’re not building out any particular volume. We’re just going to continue to build out our — the system as the well results tell us what we need. So let’s not act like we’re going to spend the whole amount on day 1. So we’re — and then I think it’s got lots of flexibility to expand or stay at a smaller level. So that’s the — why we really like this partnership. Comstock will operate it, make all the decisions. We’ve hired a very experienced midstream group that’s going to run this project and build this out. And then Quantum will be kind of our financial partner. So it’s got lots of flexibility as far as how much we spend.

And we’re going to spend based on what the wells tell us we need. And so that’s — we’ve got a nice base system, like I said earlier, that gives us a lot of flexibility, and we didn’t have to spend a lot of capital. We made just a phenomenal acquisition last year of buying the system from legacy reserve and just getting it — refurbishing it back to the state that it was, and I think that’s how we see it. And obviously, if it needs — if the — we need a lot more capacity, I think we have the flexibility to expand the relationship or also contracted if we don’t need to use all those funds. So that’s why we really like this overall partnership.

Bertrand Donnes: And then potentially…

Miles Allison: I think it provides what we need for the short term, but we keep an eye out on the obvious long-term for natural gas. So it gives us flexibility for the longer term, too. That’s what a Tier 1 partner does for you.

Roland Burns: Yes. On third-party volumes there, we own all the acreage mostly in this plant. There’s not a lot of other third-party volumes available out there?

Miles Allison: Well, that’s why the value of the Pinnacle plant was created. It’s the volumes that we have, which we didn’t have those volumes and we bought that in 2022.

Bertrand Donnes: That’s great, guys. And then just a follow-up is on the acreage acquisition dollars, I think last quarter, the update was, hey, maybe we’ve got — we’re towards the end of the program, maybe 90% or somewhere around there. And then 4Q looks like a small step up. Was that just something you saw an attractive package maybe in earlier in October? Or is there maybe rethinking there?

Miles Allison: Well, I think as we go back over 3 years ago and we have a footprint and we expand it and then we get what we call Tier 1, 2, 3 acreage over we classified. I would tell you that even with the expansion that we have, which is nominal and it goes over into kind of not core acreage at all. That 90% of all the acreage that we set out to get as of 3 years ago or 2 years ago or 1 year ago, we have that. In other words, anything that we get from this point on would just be an additive. It will not be the core of the core at all. It will just be rounding out where we would like to add some more acreage if we can get it. But no, at the end of this year, I think the big land grab that we’ve had for 3 years, that is open with in the mineral loaners that we would like to lease from, majority of those we’ve already communicated with — and we’ll see if we can finalize those leases or not.

That’s where we are. It’s — I think that seasonal land grab is coming to an end.

Operator: And our next question comes from Phillips Johnston from Capital One Securities.

Phillips Johnston: My question was on third-party volumes as well, but it does sound like this ramp sort of the 500 and then ultimately up to 2 Bs a day by ’28 is mostly, if not all, Comstock volumes. I guess maybe if you could help us with the starting point. I know your current production is that’s significant because it’s relatively early, but — and it’s not broken out. But — are you able to say approximately what your gross volumes are in the play today?

Miles Allison: No. Phillips, I think if you ask me if I’m going to do a big M&A and double the size of my company, then I’d do a big M&A. And I don’t know what the M&A would be. If I’m out here derisking the Western Haynesville and you know we’re going to add a third rig next year, we have to see how these wells hold up. We have to see how the new wells perform. So that is where we try to keep it simple. We try to show you that if these volumes do grow between now and 2028, we think we have the type of geology that let us have about 2 Bs a day. But we throw that out there just because that is in the model that we have with Quantum, that is not something anyone should be focused on between now and then that’s a long way down the road.

Phillips Johnston: Sure. Yes. Okay. And then maybe a question for Roland. In the first half of the year, you guys were helped by some fairly sizable working capital cash inflows and some of that, of course, reversed here in Q3. Just wondering what that might look like in Q4? And if we assume you continue to run 7 rigs throughout next year, would you expect working capital will either be a material source or use of cash next year?

Roland Burns: Well, there’s 2 elements of the working capital change. And one of them is spending levels, and I think the spending levels have come down from where they were earlier in the year. So you see that it lags, it’s like a 2 month — I mean 2 months really lag between cash numbers and — so I think you’ve seen that impact of spending. So I would think that working capital will stay from spending will be kind of — won’t be a source or use kind of going forward because we’re now kind of at the 7 rig level for a while. And then — but secondly, the other element of that is all gas prices. So if gas prices are higher now and we’re still receiving gas from 2 months ago that’s lower priced. I mean obviously, it will be a — that lag will be part of the working capital change.

So obviously, we’re hoping that gas prices keep going up and you’ll continue to see a little bit of a negative effect of working capital adjustment as you continue to see higher gas prices from the quarter before. And that’s what you’re seeing. With the lowest gas prices we had for the year were, in the second quarter, third quarter, they were a little bit better. In fourth quarter, they’re a lot better. So hopefully, next year, they continue to be better.

Miles Allison: I think that we’ll go into the hedging position. We did add $100 million a day of hedges, which were swapped at 355, I think Ron, is a good number. So we did that in the last probably 3 or 4 weeks. We’re, I think, 22% hedged for 2024. If you look at the perfect world of Comstock, I think we’d like to be in the 40%-plus. So everyone listening to know that we’re still looking to do that. We think we should add those extra hedges just to mitigate some risk as we go through 2024. We think the demand for the gas will really appear in the latter part of ’24 and then ’25 on, you should see it pretty consistent. So that is our goal, Phillips.

Operator: And our next question comes from Leo Mariani from Roth MKM.

Leo Mariani: Could you talk a little bit to kind of what you’re seeing in terms of leading-edge service costs and kind of the traditional kind of Eastern core Haynesville. I think you alluded earlier that maybe those have come in some. Could you give us kind of a sense? I mean, just looking at your Third quarter D&C was up 1%, like you said. So what do you kind of see in the service cost doing in the leading edge and when do you think that starts to show up in the financials?

Daniel Harrison: So Leo, this is Dan. We have seen the service costs come down. They’ve been easing down probably — I mean, earlier this year, but we — I’d say we’ve seen the biggest decrease just on the rig rates have come down. And of course, they are the ones that went up higher than anything else when they went the other direction. But we’ve seen the rig rates are probably down 10% since back — earlier part of this year. I think on the completion side, probably not quite as much. I mean that’s driven really just by our frac cost. That’s probably more like a 5%, 6%, 7% decrease since earlier in the year. I think we’ll see that continue to trend down into this fourth quarter and into next year. We’ll just kind of have to wait and see really what these gas prices, how they materialize next year. And with the activity in the Permian also which affects us if — how much they continue to slide or maybe level out or may even potentially pick up just here next year.

Ron Mills: So the one comment I may add is, Leo, when you’re looking at that cost per completed well that there’s a big time difference. Drilling costs are the oldest cost in there. And so there — because these wells were drilled probably back a couple of quarters ago or at least a quarter ago. Completion costs are more in the quarter, but even all of them lag because we can’t report this until the well is completed. So there’s a disconnect between the drilling costs, which are older numbers that get reported this quarter. So you’ll see the drilling cost comes down last. So I do — I think what we would expect to see as you get kind of — if you go out and look in the future to what this chart may look like, we should see drilling costs continue to come down because we’ll get — we’ll start reporting more recent costs with wells that we complete, probably more first quarter.

I think that’s when we really see, I think, that the current costs we’re seeing now show up in this particular scorecard.

Daniel Harrison: Yes, that’s a really good point. I mean if you look at — if you — we report by wells when they turn to sales. So the [indiscernible] of wells that turned to sales in 3Q, a lot of that drilling cost was done back in Q1 as far as when we’re actually drilling the wells. So..

Roland Burns: Savings aren’t here yet in that number. That’s correct.

Leo Mariani: Okay. That’s helpful, guys. And then maybe just to follow up a little bit on just the kind of financing side. Obviously, you guys were able to mitigate some future CapEx with this deal, that’s great to see. So we noticed that the revolver debt popped up a fair bit this quarter. I guess we’ll see what gas prices do going forward. But I guess to the extent that, that revolver debt were to climb a little more, would you guys kind of look to term that out? Are you kind of thinking about sort of maximum liquidity as you kind of think about future funding needs and could we see some term out on some point in the near future?

Roland Burns: I would doubt it, Leo. I mean, we see repaying that as gas prices get back up over a — little bit over $3. I mean I think that kind of puts us back in a good balance. The second and third quarter had these very low gas prices, that had to lean into the revolver a little bit, but we see that trend reversing.

Operator: And our next question comes from Paul Diamond from Citi.

Paul Diamond: Could I just get a bit of a bit more detail on the breakdown of your development plans for Haynesville versus Bossier. I know you talked about 8 and 2 next year. Is that roughly where you guys think it fits long term? Or is that something that’s still kind of inflects the development of the play?

Daniel Harrison: Yes. So you — is that in relation to the Western Haynesville or just overall?

Paul Diamond: Western Haynesville.

Daniel Harrison: Yes. So we’ve got 7 wells that are currently producing now as we stated. All of those are producing from the Bossier with the exception for 1. We got 1 Haynesville producer in that bunch. And then next year, we don’t have any more wells turned into sales this year and that makes all turn to sales in January. So full year next year, we’ll have 10 wells that are scheduled to turn to sales and 8 of those will be the Haynesville, which is — that’s what we had said earlier, correct, and just 2 in the Bossier.

Paul Diamond: And is that something we should expect to continue going forward? Or is that still kind of being felt out as the — on how the wells perform?

Daniel Harrison: I mean, obviously, how the wells perform will play a role in that. I think you’ll see a mix. We — when we first kind of entered the play, we knew obviously that this is a high bottom hole temp play. We specifically targeted the Bossier early on just to kind of increase our chances of success. And we’ve leaned in — since that time, we’ve got a lot better at dealing with the temperature. So we’ve leaned in more on drilling the Haynesville. I think — it’s still early, but I think you’ll see the Haynesville will be a better — it’s going to be a better performer than the Bossier just like up in the core. We like the Bossier, these Bossier wells look fantastic. But just like up there, we expect the Haynesville to be a little better performer. And so if you can get your cost basically the same, the Haynesville wells are going to beat the better performing wells just …

Paul Diamond: Understood. Just 1 quick follow-up. Is the lateral length in the Western Haynesville are kind of sitting around 10,000 feet. I know there’s been efforts to kind of extend that in the core. Over in Western Haynesville, given the higher pressure, how about — I guess, where is your kind of back of the envelope, where do you guys think you can get to as far as lateral length in the next 18 months?

Daniel Harrison: Well, so we’ve already drilled 1 out to 12,700 feet. Maybe, that was the third well we drilled in the play that was the Bossier well. So if you look at the first 7, our average lateral length right now looks — is about 9,400 feet. And if you look at the wells that we got planned to turn the sales next year, that group of 10, we’re going to probably be at 10,000 to 10,500 feet average lateral length on those wells. So I don’t really see us getting a whole lot longer out here just due to the temperature. But you never know where you can end up sometimes, you get 3, 4 years down the road with the technology improvement. So I wouldn’t totally roll it out. But I think that 10,000-foot mark is pretty much going to be our target.

Operator: And our next question comes from Noel Parks from Tuohy Brothers Investment Research.

Noel Parks: So I wanted to ask a bit about one of the big factors that’s changed in this cycle and that’s the interest rate environment. So I was curious, thinking about negotiation process you went through with Quantum. Just curious as they were looking at their returns and you’re looking out fairly long term. What did you do for scenarios with interest rates? And if we have greater volatility in gas prices as a result of LNG coming to the mix. I wonder if you’ve given any thought to just how that might affect your returns or your planning or even your own leverage longer term?

Roland Burns: Well, that is a good comment on that interest rate environment. The interest rates are up a lot, that’s showing up in both long-term rates and then obviously, the floating rates have been up a lot this year raising the cost of debt across the board. We’re very fortunate to have so much of our interest rates fixed at a very attractive rates. And then we have — in the new midstream, we have a low rate that’s also kind of fixed. So we don’t think the company — the Comstock is too exposed to the higher interest rates as we kind of look forward at least over the next 3 to 4 years. And hopefully, we’ll get to an environment sometime after that period where rates kind of come back down.

Noel Parks: Right. Great. And 1 thing I want to — sorry, just catching up on my note here. One thing we’re hearing about in other parts of the country, and it sort of depends a lot on just individual sort of grid operators and regulation given part of the country. But aside from LNG, I just wondered if you were getting many inquiries about DAS contracts with industrial users, maybe with an eye to some of the micro grid technology we’ve seen, it’s still small, but getting share just as people get more worried about either being able to expand their access to the grid or reliability of the grid. So I just wondered if you were hearing anything — getting any feelers out for customers that might be looking to do something like that?

Roland Burns: That’s a great question. No. We’ve had a big initiative that we really — we put in place a new team there and to really reach out to more industrial users. We luckily can access kind of the growing area along the Gulf Coast, the best Louisiana Gulf Coast, where there’s a lot of new construction for industrial demand that’s not LNG related in addition to the LNG users. And they all see the big demand pull coming in the area. And so where gas supply was relatively easy to get. It’s now being contracted up by the large LNG users. So we’re seeing a lot of interest from long-term supply contracts to those type users, and they offer maybe even stronger pricing for us and probably more very reliable customers. They have a — they can really predict what their demand is.

And I think as we go forward, you’ll see more and more of our sales are directly tied to either LNG shippers or industrial users. We would like to have a portfolio of all those users as we go forward that we can directly connect to either from our new growing Western Haynesville play or our base play in Louisiana, where we’re the anchor shipper on Acadian, and we can get a lot of gas down to that market.

Noel Parks: And just I’m sure nothing is really final or signed until it’s done. But when you have those discussions or do that outreach, what sort of terms are people thinking about 5 years, 20 years or just something more market tied where there wouldn’t be long contracts at all?

Roland Burns: I think the interest is 3 to 10 years as far as supply contracts. I mean 3 is very, very common. Longer-term contracts, obviously, because they’re — I think people are worried about the short-term contracts and just all of a sudden, the market being everybody pulling on gas at the same time. So yes, we’re seeing an interest in longer-term contracts from the end users. The key is us acquiring the transportation or getting — be able to directly connect to these parties. And that’s something we’ve been working on a lot and continue to work on, especially as we have kind of a blank canvas for our new gas in the Western Haynesville, where it’s not committed to a lot of other long-term contracts.

Operator: And our next question comes from Fernando Zavala Pickering Energy Partners.

Fernando Zavala: Just a quick one for me. With the plan to move to 1 rig — to move 1 rig from your legacy Haynesville into the Western Haynesville next year. Do you think your legacy Haynesville production can be held flat with that rate cadence? Or do you think it declines a little bit with a 4 rig program?

Roland Burns: I think it’s a good chance that it will be hard to hold it flat with just 4 rigs. We are going to be looking at high grade maybe — we can high grade some of that to the most prolific part. We also look at where we have the best markets and the best transport to utilize that. But I think the — as the Western Haynesville starts to build a nice production base, and then it has a much lower — that production, even though like Dan said, when we kind of IP those, that’s almost like what we produce them at for a long period of time. That production becomes a very stable part of the base, so — with lower declines. So I think longer term, I think that we’ll have — we can lower our corporate decline rate as the Western Haynesville takes over a more meaningful part of that production base. In short term, we’ll have to kind of see how to balance the two.

Operator: And our next question comes from Gregg Brody from Bank of America.

Gregg Brody: So you mentioned the $300 million of capital coming from Quantum. About $100 million to $200 million you said will be spent next year. Is there — to get to the 2 Bcf per day, is there a need to raise more capital? And is the $300 million enough? Or is there plans to raise a revolver down to that facility? Maybe you can kind of fill in there. It seems like you might need more than $300 million, but maybe I’m wrong about that.

Roland Burns: Well, I think the entity will become self-financing after it gets going. We think that, that’s the amount of equity capital that has to come in. We don’t really plan to put much leverage on those assets at this time. So a lot of it is — we do see that, that is adequate based on kind of how we’re seeing it build up. But there’s a lot of the future still to be written on that. So we’ve got lots of flexibility. That — that will be — that is set up in an unrestricted subsidiary, so that will kind of have its own potential financing base. So in the future, if it makes sense, it could have its own — it could have its own credit facility, but that’s not anticipated to do right out of the box here.

Gregg Brody: Did you have — you said it’s unrestricted, does — Comstock doesn’t have — has not guaranteed any of that. It’s…

Roland Burns: That’s correct. Yes. Comstock is not guaranteeing anything that’s in that subsidiary, right? And the commitment company from Quantum will be kind of equity dollars coming in. And so we tend to run it at a very kind of an unlevered basis. It’s kind of the immediate plans here. And then its own cash flow will help also be reinvested into the build-out.

Gregg Brody: Yes, that makes sense. And then last question for you. Just $300 million of capital. Is there — is it all available to you at your discretion? Or is there some approval process to get access to certain tranches of it?

Roland Burns: That part is available. And then it actually, we can expand with additional approval up to $500 million. But the $300 million is an additional committed part of the investment. And it’s based on, obviously, the budgets that’s approved out there and et cetera.

Operator: And I’m showing no further questions. I would now like to turn the call back over to Jay Allison for closing remarks.

Miles Allison: Perfect. Again, I want to thank everyone for spending time. That’s probably your most valuable asset. So thank you for spending the time with us. As I was listening to the Q&A and our presentation, even with weak natural gas prices, we reported solid results for the Western Haynesville shale drilling program. And just to clarify, our goal is we want to keep the dividend. We want to manage the balance sheet. We want to be a great partner to Quantum as we build the midstream in the Western Haynesville. We want to maintain an eye on appraising all of our Western Haynesville wells and we want to turn that play from exploitation to developmental drilling. And we want to adjust the risk by adding some hedges for 2024 if that opportunity arises.

As I was reading all the analyst reports, I know one of them was titled finding a dance partner for the Western Haynesville. Well, I would expand upon that on the dance floor. I think on the dance floor for Comstock right now, we have the Jones family and we have all the equity stakeholders with the Jones family. We have our bank sponsors. We have our bond holders and now we have Quantum. So the question is, what kind of dance is it? Is it a Texas 2-step? Is it a Jitterbug? Is it a Cotton Eye Joe? Well, we hope it is, over the years to come, is that old deal walls across Texas. That’s our goal. We may not be perfect with our feet every day, but that is our goal, and we’re pleased — the people around the globe and the consumers in America that need this gas.

That’s our goal. Thank you for that headline. And thank you for your participation today.

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