Comstock Resources, Inc.

Good day, and thank you for standing by, and welcome to the Q3 2023 Comstock Resources, Inc. Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there'll be a question and answer session. To ask a question during the session, you will need to press star 1-1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1-1 again. Please be advised that today's conference is being recorded. I would now like to introduce your host for today's call, Jay Allison, Chairman and CEO. Please go ahead.

Good morning, everyone. In Frisco, Texas, this morning, it's 34 degrees. The Texas Rangers took the lead in the World Series, and I saw natural gas prices were up about 20 cents 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. Report a 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 Hainesville-Boger acreage position. continued to deliver solid results from our legacy area, as well as the emerging Western Hainesville. The two Western Hainesville wells we recently turned to sales were, quote, top-of-the-class wells, as were the other five that we turned to sales, starting with our Western Hainesville well, the Circle M, which started production April of 2022. Make no mistake about it, we're extremely pleased with the results of all the Western Hainesville wells we have turned to sell so far. This year, we're focused on proving up the Western Hainesville 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 who just reaffirmed our $2 billion borrowing base improving up a much-needed new gadget resource near the expanding LNG export facilities along the Texas and Louisiana Gulf Coast. A major step in the development of our Western Hainesville play is finding the right partner for the midstream build-out needed to support our Western Hainesville drilling program, and we're 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 and downloading the quarterly results presentation. There you'll find a presentation titled Third Quarter 2023 Results. I have 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 two, please refer to slide two in our presentations and note that our discussions today include forward-looking statements within the meaning of securities laws. While we believe the expectations of 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 three, 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 $116 million or 60 cents per share and adjusted EBITDA was $209 million. Our adjusted net income was four cents for the quarter. We continue to have strong results from our drilling program. We drilled 13 or 10.2 net successful operated Hainesville and Bossier Shell 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 Hainesville exploratory play. Our sixth and seventh wells were recently turned to cells with strong initial production rates, both of which were drilled in the Bossier shell. We recently entered into a new venture with Quantum Capital Solutions to fund the midstream build out to support our Western Hainesville drilling program which I'll expand on the next slide. If everyone would turn to slide four, 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 Hainesville 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've set up a mid-spring partnership with QL to build out the system to increase the capacity fourfold. We'll contribute the pinnacle gathering and treating system to the partnership and QOL 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. It will direct its activities. Quantum receives a preferred return in 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?

All right. Thanks, Jay. On slide five, 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 billion, 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 six, we have our financial results for the first nine months of this year. Production for the first nine 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 nine 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 three quarters of this year. We reported adjusted net income of $105 million for the first three 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. 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 in the third quarter averaged $2.33, reflecting a 22-cent differential to the settlement price and a 23-cent differential to the reference price. The differential this quarter returned to more normal levels due to improvements and 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 two cents. On slide eight, we detail our operating cost per MCFE produced in our EBITDAX margin. Our operating cost averaged 85 cents 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 36 cents. And our other lifting costs were 3% lower than the second quarter rate at $0.24. Our production and ad valorem taxes increased $0.05 this quarter compared to the second quarter level. G&A came in 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 65% in the third quarter. as compared to 63% in the second quarter of this year. On slide nine, we recap our spending on drilling and other development activity for the first nine months of this year. So far, we spent $958 million on our development activities, including $919 million on our operated Hainesville and Bossier Shale drilling program. Spending on other development activity has totaled $38 million so far this year. In the first nine months of this year, we've 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 that 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.

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 Hainesville and the Bossier and is divided into four categories with our short laterals that are up to 5,000 feet. We got our medium laterals that run between five and 8,000 feet. Our long laterals at eight to 11,000 feet and our extra long laterals beyond 11,000. The total operated inventory currently stands at 1,760 gross locations and 1,338 net locations. This equates to a 76% average working interest across the operated inventory. Our non-operated inventory has 1,265 gross locations and 153 net locations, which represents a 12% average working interest across the non-op 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 Hainesville and 48% in the Bossier. 26% of the gross operated inventory for the 455 locations have the lateral lengths greater than 11,000 feet. or two-thirds of the gross operated inventory has laterals exceeding 8,000 feet. The average lateral length in the inventory 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 lengths drilled based on the wells that we have 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 lengths ranged from 6,789 feet up to 15,333 feet. and our record longest lateral still stands at 15,726. During the third quarter, six of the 21 wells we turned to sales had laterals that exceeded 11,000 feet, and five 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 two additional wells that turned to sales on our new Western Hainesville acreage. The KZMS number one and the Lanier number one wells were both completed in the Bossier shell. These wells represent the sixth and seventh new vintage wells now producing in the Western Hainesville. 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. We had an average test rate of 29 million cubic feet a day. The average lateral length was 10,460 feet with individual levels from 6789 up to 15,333 feet. Included in the quarter again are the sixth and seventh new vintage wells in our western Hainesville acreage. The KZMS, which was completed in the Bossier, had a lateral length of 10,028 feet and was turned to cells in August. We tested the well with an IP rate of 34 million cubic feet a day. The Lanier No. 1 well, which was also completed in the Bossier, was completed with a 9,577 foot lateral, and this well was turned to cells in September. We tested this well with an IP rate of 35 million cubic feet a day. In addition to the first seven producing wells, we have one well that is currently waiting on completion, and we do expect to turn that well to sales in January. We currently have two rigs actively running on our western Hainesville 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 cells 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 cost 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 cost came in at $842 a foot, This is a 5% decrease compared to the second quarter. The decrease in completion costs mirrors the slight decline in service costs we have experienced since earlier in the year, which is associated with the lower activity levels. And to wrap up our forecasted activity levels, we're currently running seven rigs. We do expect to keep this same rig activity going into next year. And we are also running our three frack crews, and we expect to keep these three frack crews also working in the next year. I'll turn the call back over to Jay.

Thank you, Dan. Thank you, Roland. If everyone would turn to slide 15, I would direct you to slide 15, where we summarize our outlook for the rest of 2023. We remain very focused on proving up our western handful play and continuing to add to our extensive acreage position in this prolific play. We believe that we are building a great asset in the Western Hainesville that will be well positioned to benefit from the substantial growth in demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports that begins to show up in the second half of next year. Our new Western Hainesville Midstream Partnership will reduce 2024 capital expenditures that would otherwise be required to support the growth in production that we expect our industry-leading Our 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 plan to retain the quarterly dividend of 12.5 cents 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 provide some specific guidance for the rest of the year. Thanks, Jay.

On slide 16, we provide the financial guidance for the fourth quarter of 2023. The fourth quarter D&C CapEx guidance is $240 to $280 million. 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 to $25 million of spending during the fourth quarter. On our combined basis, our DNC and infrastructure and other CAPEX should remain within our past annual guidance of $1.02 to $1.28 billion. In addition to what we spent on our drilling program noted above, we now anticipate spending $30 to $40 million in the fourth quarter for additional leasing activity. Our LOE costs are expected to average 24 to 28 cents per MCFE in the fourth quarter, while our gathering and transportation costs are expected to be 32 to 36 cents per MCFE in the fourth quarter. Production and ad valorem taxes are expected to average 16 to 20 cents 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 $5 to $15 per MCFE range, while our cash G&A is expected to remain in the $7 to $9 million range for the quarter with an additional roughly $2 million of non-cash G&A. Due to the increase in SOPA rates, our cash interest expense is now expected to total $42 to $46 million in the fourth quarter. while our non-cash 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.

And thank you. As a reminder, to ask a question, please press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 11 again. Please stand by while we compile the Q&A roster. And we do ask that you limit yourself to one question, one follow-up. Again, that's one question and one follow-up. One moment for our first question. And our first question comes from Derek Whitfield from Stiefel. Your line is now open.

Thanks. Good morning, all, and congrats on your partnership. Thank you. Regarding the quantum partnership, I wanted to confirm a comment you made in your prepared remarks. If my numbers are correct, a fourfold increase suggests you're solving for TBCF per day of capacity in the Western Hainesville. If that's correct, could you comment on how you're thinking about mainline egress as well?

I think when we looked at our footprint in the Western Hainesville, we looked at our inventory and we looked at the 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. We think in the latter part of 24, you're going to need another 4.5 to 5 Bs. And then every year after that, you're going to probably need another B a day. And that's just for LNG, exportable gas, speed 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 our 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 and that 145-mile pipeline, You know, 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 Hainesville, in the Western Hainesville next year. So we go from two rigs to three. And then we would add another rig in 2025. And we think that would HPP our entire footprint. So if you look at that, you look at the model for five years, When 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 for the financing from Quantum to have at least two bees a day that we would have available to serve America and the globe. That's where we come up with this four-fold 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, you know, Quantum, which is known for funding midstream in the Hainesville and now in the Western Hainesville, 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, you know, we publicly thanked 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 Angel well was only drilled Two years ago. We started drilling those two years ago. And we started leasing the acreage three years ago. But, you know, we really are building a company. And when you build a company, you have to look what's going to happen in 27, 28. And all that is depending upon, you know, the feedstock that's needed for LNG. That's where we had the announcement today. And that's where that two Bs come from. You did your math on that.

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

Hey, this is Dan. So we have seen, we've made great strides in our cost structure in the Western Hainesville. 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 in well, 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'll be coming up in the future. So we feel pretty confident about that. And then on the completion side, I think that probably doesn't have as big a 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 practice wells down here. So really, the efficiency gains on the completion side would come from doing multi-well pads and, you know, just typical operational improvements.

You know, I would comment on looking at Dan and the group, things that, you know, were once really complex when we drilled a circle in, some of those things become a little simpler. If you drilled your seventh well and turned it to cells, now you're drilling your eighth and ninth and tenth well, and now we started focusing on the Hanes well, not so much the Bossier. So I do see that, and... Some of the hand wringing that would require us to drill the first circle end 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, quote, you know, continuing to build this company. We're building the company.

Very helpful. Thanks for your time.

And thank you. And one moment for our next question. And our next question comes from Charles Mead from Johnson Rice. Your line is now open.

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

Morning.

Carl, it's always good to hear from you.

You should be here with us with the 34-degree weather. You'd be happier.

I would be happier. We were in the 50s down here this morning.

I know. That's bad.

I liked it. But anyway, Jay, I want to ask a real question about your business decisions here. $300 million of outside capital, that's great that you've got a high-quality partner like Quantum willing to put that kind of money into a 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 this system. And maybe that's a minimum volume commitment. Maybe it's 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?

Yeah, Charles, that's a good question. And, you know, 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. Yeah, and we charge for all processing and transportation about 54 cents, you know, per MCF. So there's really no change in the rate. It's the same rate that we historically have had. And, yeah, we have a very, you know, small NBC 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.

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, it's less than half of what you're projecting from, from this asset. That's correct. Okay. Got it.

Thank you. And then with the existing production that we have, Charles. So I think we start out with a big risk adjustment day one.

Got it. And then I guess, you know, we, we could, we can do the work ourselves, but between those two numbers, we should be able to figure out, uh, when that, uh, Ownership reverts, or rather, you know, 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 Hainesville. Obviously, you guys are, this is a big effort for you guys. When I look at your run results, you guys are, you know, clearly you guys can put up these IPs in the mid to high 30s, or even I think you've had one or two over 40s. So I think that aspect has been de-risked. But there's other important data points, which are the DNC costs. I wonder if you could share maybe not where you are now, but what your target DNC cost is on these wells, and then perhaps what the pressure drawdown is like over time, if you want to share any of that.

I'll start out, and then I'll leave it to Dan. I think, number one, we're not rigging the system with a high IP rate that's cut in half, you know, 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 one, which that's unusual. Number two, 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 three, I think the cost of any exploration play or exploitation play for the first seven wells is gonna be a little higher than normal. We always said, Charles, you take the first seven wells in the Hainesville-Bossier in the legacy footprint back in 2008 and you need a big barf bag because they look terrible. I think these seven wells will make you 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 I think we stated in our last conference call that we think that the Western Angel wells, as is where it is today, are 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 top curve really looks like when these wells really start falling over and if these bottom hole pressures will maintain where they are today. That's why we say these wells are top of class because out of the thousand wells we've drilled in the core and the Western Angle, these are some of the best wells we've ever touched. Dan, you want to comment any more?

Totally correct there. So I'll just comment a little bit on the D&C call. 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 lateral's got a lot more heat. We've made a lot of headway. Of the first seven wells we have produced, we targeted the bosier. 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. Eight of those are going to be in the Hainesville. Two will be in the Bossier. So, you know, we are going to turn our focus to that. But we've still got some things that we've got targeted to, you know, put to work out here in the field, it's going to get the cost down, we feel, a considerable amount. 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 two or three well pads. You're getting six, seven, eight percent less cost just via multi-well pad versus these down here are single wells. That alone is, you know, driving our cost up a little bit. But Jay's totally right. I mean, you're looking at EURs definitely potentially double what we have up in the core. And then the cost, you know, we're going to make a lot of improvements on that going forward in the future.

I think, Charles, you know, the really answer is if, you know, our borrowing base is reaffirming for that $2 billion. So the 17 or so banks that support us, I mean, they've 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 that confusion that we had two 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 a good enough sample set. And that'll be months down the road but we'll still report you the results on a quarterly basis, which have been really good.

Jay and Dan, thank you for the added detail. I appreciate it.

Thank you. Great questions.

And thank you. And one moment for our next question. And our next question comes from Jacob Roberts from TBH and Company. Your line is now open. Good morning and happy Halloween.

Oh, that's right. Copper fall on Halloween. Trick or treat.

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?

Well, yeah, we started out with more rigs, you know, talking about the CapEx, you know, at the beginning of this year than we're going to be starting out next year at. So, you know, we would – and we think overall – service costs and drilling rates are down a little bit. So 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. And the build-out of the Western Hainesville midstream is going to be phased in. We're not going to build it all on day one to handle a huge volume. It's going to be layered in over a five-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 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. You know, I think, you know, next year, you know, the spending for this venture, you know, is probably, you know, between $100 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.

Great. Appreciate it. And looking – I know this is a really long-term question – Jay, you mentioned the four rigs on the Western Hainesville in 2025 and then this plan to step up to two bees 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?

Well, as we go, there's really two questions. One, really three questions. One, how many rigs do we have to have do we think to hold our big footprint in the Western Hainesville? We think we probably have to have a fourth rig by 2025, so it's not 10 or 12 rigs, it's four rigs. I mean, that's the beauty of the play, how we leased this starting over three 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 four 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 one rig to the 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 three new cactus rigs built. One we 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 Hainesville. That's one question. Second question is, if you take a model and you have a JV with mid-frame 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 two Vs a day. As we get there, though, if you look at the core, we've got We've gone from nine to eight to seven to six to five rigs in the core. And now we have five and two. So next year we should have four in the legacy of the core and three in the Western Hainesville. That's still that seven rig count that we talked about and that Dan mentioned earlier in his presentation. So we don't see adding any, quote, gross numbers of rigs. We keep our seven rigs. We just deploy them in different areas for 2024. Now we see what happens in 2024 with the results of the Western Angle and commodity prices. So that's where we go in guidance. It's the same rig count.

Okay. Thank you. Appreciate the time.

And thank you.

And one moment for our next question. And our next question comes from Bertram Doness from Truist.

Your line is now open. Hey, good morning. And Jay, I just want to start off and say thanks for not putting out your press release on Halloween night for us with young children.

You get some of that caramel corn.

Exactly, exactly. And then the first question just, you know, 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'm going with that, is there any interest in eventually allowing third-party gas into the system?

Yeah, I think it was kind of designed to be what we needed. It's got lots of flexibility. So, you know, we're not building out any particular volume, you know, we're just going to continue to build out the system as the well results tell us what we need. So, you know, let's not act like we're going to spend a whole amount on day one. So we're, you know, and then I think it's got lots of flexibility to expand or, you know, stay at a smaller level. So, you know, that's why we really like this partnership. Comstock will operate it, make all the decisions. We we've hired a very experienced, the midstream group that's going to run this project and build this out. And then quantum will be our, you know, kind of our financial partner. So, you know, it's got lots of flexibility as far as, you know, how much we spend and we're going to spend based on what the wells tell us we need. And so that's, that's, you know, that's, we've got a nice base system. Like I said earlier, that's gives us a lot of flexibility. And we, we, didn't have to spend a lot of capital. We made just a phenomenal acquisition last year of buying this system from Legacy Reserve and just getting it, refurbishing it back to the state that it was. And, you know, so I think that's how we see it. And, you know, obviously if it needs, if we need a lot more capacity, you know, I think we have the flexibility to expand the relationship or also contract it if we don't need to use all those funds. So that's why we really like this overall partnership.

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.

Yeah, and third-party volumes, we own all the acreage mostly in this plant. There's not a lot of other third-party volumes available out there.

Well, that's why the value of the pinnacle plant was created. It's the volumes that we have, which you didn't have those volumes, and we bought that in 2022.

That's great, guys. And then just to follow up is on the acreage acquisition dollars, I think last quarter the update was, hey, maybe 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 increase package maybe in earlier in October, or is there, you know, maybe you're rethinking there?

Well, I think it's, you know, as we go back over three years ago and we have a footprint and we expand it, and then we get what we call tier one, two, three acres every week, you know, we classify it. I would tell you that even with the expansion that we have, which is nominal, and it goes over into kind of not core acres at all, that 90% of all the acres that we set out to get as of three years ago or two years ago or one year ago, we have that. In other words, anything that we get from this point on will just be an additive. It will not be the core of the core at all. It'll just be rounding out where we would like to add some more acres if we can get it. But no, at the end of this year, I think the big land grab that we've had for three years, That is over with, and the mineral owners 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. I think that season of land grab is coming to an end. Great.

Thanks for taking my question.

And thank you. And one moment for our next question. And our next question comes from Philip Johnston from Capital One Securities. Your line is now open.

Yeah, thanks. My question was on third-party volumes as well, but it does sound like this ramps sort of the, you know, 500 and then ultimately up to 2Bs 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 at that That's significant because, you know, it's relatively early, and it's not broken out. But are you able to say approximately what your gross volumes are in the plate today?

No. You know, Phillip, 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 there de-risking the Western Angels, then 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 top geology that'll let us have about two bees 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. Sure.

Yeah. 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 seven regs throughout next year, would you expect working capital will either be a material source or use of cash next year?

Well, there's two elements of a working capital change. And, you know, one of them is spending levels. And I think the spending levels, you know, you know, have come down, you know, from where they were earlier in the year. So you see that, you know, it lags. It's like a two month, I mean, two 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, you know, won't be a source or use kind of going forward because we're now kind of at the seven rig level, you know, for a while. And then, but secondly, the other element that is all gas prices. So if gas prices, you know, are higher now and, you know, we're still receiving gas, you know, from two months ago, that's lower priced. I mean, you know, obviously it'll be a, you know, that lag will be part of the working capital chain. So obviously we're hoping that gas prices keep going up and you'll continue to see, you know, a little bit of a negative effect of working capital adjustment as you continue to see higher gas prices, you know, from the quarter before. And that's what you're seeing. You know, 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, you know, they're a lot better, so hopefully next year they continue to be better.

I think that will 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. We did that in the last probably three or four weeks. We're, I think, 22% hedged for 2024. If you look at the perfect world of golf talk, I think we'd like to be in the 40% plus, so So everyone listening can know that we're still looking to do that. We think we should add those extra edges just to mitigate some risk as we go through 2024. We think the demand for the gas will really appear at the latter part of 24 and then 25 on. You should see it pretty consistent. So that is our goal, Phillip.

Okay, great. Sounds good, guys. Thanks.

And thank you. And one moment for our next question. And our next question comes from Leo Mariani from Roth MKM. Your line is now open.

Hey, guys. Could you talk a little bit to kind of what you're seeing in terms of leading edge, you know, service costs and kind of the traditional kind of eastern, you know, core Hainesville? 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 DNC, it was up 1%, you know, like you said. So what do you kind of see in the service costs doing in the leading edge, and when do you think that starts to show up in the financials?

So, Leo, as Dan, we have seen the service costs come down. They've been easing down since, you know, probably, I mean, you know, 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're 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 frack 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. And, you know, into this fourth quarter and into next year, we'll just kind of have to wait and see, you know, really what these gas prices, how they materialize next year. And, you know, with the activity in the Permian also, which affects us if, you know, how much they continue to slide or maybe level out or maybe even potentially pick up just to here next year.

The one comment to add is, Leo, when you're looking at that graph, costs for a completed well that there's a big time difference. Drilling costs are the oldest cost in 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. you'll see the drilling cost comes down last. So I think what we would expect to see, 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 start reporting more recent costs with wells that we complete, probably more first quarter. I think that's when we really see, I think, a that the current cost we're seeing now show up in this particular scorecard.

Yeah, that's a really good point. I mean, if you look at, we report by wells when they turn to sales, so this group of wells that turn to sales in 3Q, a lot of that drilling cost was done back in Q1 as far as when we were actually drilling the wells. That's why the savings aren't here yet in that number. That's correct, yep.

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. Certainly noticed that the revolver debt popped up a fair bit this quarter. I guess we'll see, you know, what gas prices do going forward. But, you know, I guess to the extent that that revolver debt, you know, 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, you know, future, you know, funding needs? And, you know, could we see some term out at some point in the near future?

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

Okay. Thanks, guys.

Thank you, Leo. And one moment for our next question. And our next question comes from Paul Diamond from Citi. Your line is now open.

Thank you. Good morning, all. Thanks for taking my call. Could I just get a bit more detail on the breakdown of your development plans for Hainesville versus Bossier? I know you talked about 8-2 next year. Is that roughly where you guys think it sits long-term, or is that something that's still kind of in flux with the development of the play?

Yes. Is that in relation to the Western High School or just overall? Western Antel. Yeah, so we've got seven wells that are currently producing now, as we stated. All of those are producing from the Mosier, with the exception for one. We've got one Hainesville producer in that bunch. And then next year, we don't have any more wells turn into sales this year. The next one will turn to sales in January. So for your next year, we'll have Ten wells that are scheduled to turn to sales, and eight of those will be the Hainesville, which is what we said earlier, correct, in just two in the Bossier.

And is that something we should expect to continue going forward, or is that still kind of being felt out on how the wells perform?

I mean, obviously how the wells perform will play a role in that. I think you'll see a mix. We, you know, when we first kind of entered the play, we knew obviously that, you know, this is a high bottom hole temp play. We, you know, specifically targeted the Bossier early on just to kind of, you know, increase our chances of success. And we've leaned in ever 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 Hainesville is 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 Hainesville to be a little better performer. If you can get your cost basically the same, the Hainesville wells are going to be the better performing wells. Understood.

Just one quick follow-up. The lateral lengths in the Western Hainesville are kind of sitting around 10,000 feet, but I know there's been efforts to kind of extend that in the core. Over in Western Hainesville, given the higher pressure, where do you guys think you can get to as far as lateral length in the next 18 months?

Well, so we've already drilled one out to 12,700 feet. Remember, that was the third well we drilled in the play. That was the Bossier well. So if you look at the first seven, our average lateral length right now is about 9,400 feet. And if you look at the wells that we got planned to turn to sales next year, that group of 10, we're going to probably be at 10 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 two or three, four years down the road with the technology improvements, so I wouldn't totally rule it out, but I think that 10,000-foot mark is pretty much going to be our target.

Understood. Thanks for the clarity. That's all from me.

Thank you. One moment for our next question. And our next question comes from Noel Parks from Dewey Brothers Investment Research. Your line is now open.

Hi, good morning. Good morning.

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 into 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.

That's 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 rate. And then we have in the new midstream, we have a low rate that's also kind of fixed. So we don't think that CompSoc's too exposed to the higher interest rates as we kind of look forward, at least over the next three to four years. and hopefully we'll get to an environment sometime after that period where rates kind of calm back down.

Right. Great. Thanks. And one thing I wanted to run by you, sorry, just catching up on my note here. You know, one thing we're hearing about in in other parts of the country, and it sort of depends a lot on just individual sort of grid operators and regulation in different parts of the country. But aside from LNG, I just wondered if you were getting many inquiries about gas contracts with industrial users, maybe with an eye to some of the microgrid 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.

That's a great question, though. We've had a big initiative that we really put in place, a new team there, and to really reach out to more industrial users You know, we're luckily can access kind of the growing area along the Gulf Coast, especially the 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, you know, 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 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 Hainesville 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.

I'm sure nothing's 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, you know, five years, 20 years, or just something more market-tied where there wouldn't be long contracts at all?

I think the interest is, you know, three to ten years, you know, as far as supply contracts. I mean, three is very, very common. Longer-term contracts, obviously, because they're I think people are worried about the short-term contracts and just, you know, all of a sudden the market being everybody pulling on gas at the same time. So, yeah, we're seeing an interest in longer-term contracts from the end users. The key is, you know, us acquiring the transportation or being 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, you know, have kind of an a blank canvas for our new gas in the Western Hainesville where it's not committed to a lot of other long-term contracts. Great. Thanks a lot.

And thank you. And one moment for our next question. And our next question comes from Fernando Zavala. Pickering Energy Partners, your line is now open.

Hey, guys. Good morning. Just a quick one from me. With the plan to move to one rig, to move one rig from your legacy Hainesville into the Western Hainesville next year, do you think your legacy Hainesville production can be held flat with that rig cadence, or do you think it declines a little bit with a four-rig program?

I think it's a good chance that it'd be hard to hold it flat, you know, with just, just four rigs. You know, we are going to be looking at hard, maybe hot, we can high grade some of that to the most prolific part. We'll also look at where we have the best markets and the best transport to, you know, to utilize that. But I think the, as the Western Hainesville starts to build a nice production base, and then it has a much lower, you know, it, 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 with lower decline. So I think longer term, I think that we can lower our corporate decline rate as the Western Hainesville takes over a more meaningful part of the production base. In short term, we'll have to kind of see how to balance the two.

All right. Thanks. And thank you. And one moment for our next question. And our next question comes from Greg Brody from Bank of America. Your line is now open.

Hey, guys, and thanks for fitting me in. Yes, sir. So you mentioned there's $300 million of capital coming from Quantum, about $100 to $2 million you said will be spent next year. To get to the two BCF per day, is there a need to raise more capital? Or 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.

Well, you know, I think that, you know, the entity will become self-financing after it gets – 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, you know, a lot of it is, you know – we do see that that is adequate, you know, based on kind of how we're seeing it build up. But, you know, there's a lot of the future still to be written on that, so we've got lots of flexibility. You know, that is set up in an unrestricted subsidiary, so that will kind of have its own, you know, potential financing base. So in the future, if it makes sense, it could have its own credit facility, but that's not anticipated to do right out of the box here.

Did you have – you said it's unrestricted. Comstock doesn't have – has not guaranteed any of that. That's correct.

Yeah, Comstock is not guaranteeing anything that's in that subsidiary, right? And the commitment coming in from Quantum will be kind of equity dollars coming in, and so we tend to run it at a very kind of unlevered basis is kind of the immediate plans here. And then, yeah, its own cash flow – you know, will help also be reinvested into the build-out.

Yes, that makes sense. And then last question for you, just the $300 million of capital, is it all available to you at your discretion, or is there some approval process to get access to certain tranches of it?

That part is available, and then it actually, if you... Yeah, actually, we can expand with additional approval, you know, up to $500 million. But the $300 is the additional committed part of the investment. And, you know, it's based on, obviously, the budgets that's approved out there and et cetera.

That's really helpful. Thank you, guys.

Thank you.

And thank you. And I'm showing no further questions. I would now like to turn the call back over to Jay Allison for closing remarks.

Perfect. Again, I want to thank everyone for spending time. That's probably your most valuable asset, so thank you for spending that time with us. You know, as I was listening to the Q&A and our presentation, you know, even with weak natural gas prices, we've reported solid results. for the Western Hainesville Shell 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 a midstream in the Western Hainesville. We want to maintain an eye on appraising all of our Western Hainesville 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 Hainesville. 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. 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 two-step? Is it a jitterbug? Is it a Cotton Eye Joe? Well, we hope it is over the years to come. Is it an old deal waltz across Texas? That's our goal. We may not be perfect with our feet every day, but that is our goal, and we'll please 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.

This concludes today's conference call. Thank you for participating. You may now disconnect.