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 on 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 one one on your telephone. You'll then hear an automated message advising your hand is raised. To withdraw your question, please press star one one 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 $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 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 we turned 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 two Western Haynesville wells we recently turned to sales were, quote, "Top of the class wells," as were the other five that we turned to sell, starting with our Western Haynesville well, the Circle M, which started production April 2022. Make no mistake 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're 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, who just reaffirmed our $2 billion borrowing base and proving up a much-needed new natural resource near the expanding LNG export facilities along the Texas and Louisiana Gulf Coast. A major step in the 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'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 $0.60 per share, and adjusted EBITDA was $209 million. Our adjusted net income was $0.04 for the quarter. We continued 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, a build-out to support our Western Haynesville 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 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've set up a midstream partnership with QL to build out the system to increase the capacity fourfold will contribute the 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 we'll 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 cover the third quarter financial results. Our production in the third quarter was 1.4 BCFE per day, which is 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 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. 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 2022. 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 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 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 eight, we detail our operating cost per Mcfe produced and 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 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 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 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 million 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. Slide 11 is a breakdown of our current drilling inventory at the end of the third quarter. The drilling inventory is split between the Haynesville 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 5,000 and 8,000 feet, our long laterals at 8,000-11,000 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 Haynesville and 48% in the Bossier. 26% of the gross operated inventory, or the 455 locations, have the lateral lengths greater than 11,000 feet. 66, or two-thirds 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 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 range from 6,789 feet up to 15,333 feet, and our record longest lateral still stands at 15,726. 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 to sales on our new Western Haynesville acreage. The KZMS number one and the Lanier number one 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. Thirteen of these will be longer than 11,000 feet and eight 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 range 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 laterals from 6,789 up to 15,333 feet. Included in the quarter, again, are the sixth and seventh New Vintage wells in our Western Haynesville acreage. The KZMS, 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 number one well, which was also completed in the Bossier, was 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 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 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 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 costs 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. Now 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 turn the call back over to Jay. Okay. Thank you, Dan. Thank you, Roland. If everyone, we'll 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 Haynesville Play and continuing to add to our extensive acreage position in this prolific play. We believe that we're building a great asset in the Western Haynesville that will be well positioned to benefit from the substantial growth and demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports that 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 and production that we expect. Our industry-leading lowest cost structure is an asset in the current low natural gas price environment, as our cost structure is substantially lower than the other public natural gas producers. We 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 provide some specific guidance for the rest of the year. Ron? 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-$280 million. And also, we're seeing 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-$25 million of spending during the fourth quarter. On our combined basis, our D&C and infrastructure and other CapEx should remain within our past annual guidance of $1.02 billion-$1.28 billion. In addition to what we spend on our drilling program noted above, we now anticipate spending $30 million-$40 million in the fourth quarter for additional leasing activity. Our LOE costs are expected to average $0.24-$0.28 per Mcfe in the fourth quarter, while our gathering and transportation costs are expected to be $0.32-$0.36 per Mcfe in the fourth quarter. Production and ad valorem taxes are expected to average $0.16-$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 $5-$15 per Mcfe range, while our cash G&A is expected to remain in the $7-$9 million range for the quarter, with an additional plus or roughly $2 million of non-cash G&A. Due to the increase in SOFR rates, our cash interest expense is now expected to total $42 million-$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%-25% range, and we still expect to defer 95%-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 one, one on your telephone and wait for your name to be announced. To withdraw your question, please press star one, one 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 Stifel. Your line is now open. Thanks, good morning, all. Congrats on your partnership. Thank you. We, 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 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? Well, I think when we looked at our footprint in the Western Haynesville, 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. And we think in the latter part of 2024, you're gonna need another 4.5-5 Bs, and then every year after that, you're gonna 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, and, you know, what is our starting block as far as this 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 two rigs to three, and then we would add another rig in 2025, and we think that's what HPP, our entire footprint. So if you, if you look at that and you look at the model for five years, and you look at the need for gas, we, we modeled it out that, that by 2028, we would, we would have, we'd have the capacity, with the takeaway, both for transportation and the gathering, with the financing from, from Quantum, to have at least 2 Bcf 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 through 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 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, you know, we publicly thank them for entering into this new venture with us because they, 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 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 gonna happen in 2027, 2028, and all that is depending upon, you know, the, the feedstock that's needed for LNG. That's where we had the announcement today, and that's where that 2 Bcf come from. You did, you did your math on that. Appreciate it, Jay, and 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 costs could improve over time? Yes, this is Dan. We've made great strides in our, you know, 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, you know, drilled the first Circle M well to kind of where we're at today. We do have some things in the pipeline, you know, a line of sight to get the costs down further that'll be coming up in the future. So we feel pretty confident about that. And then on the completion side, you know, I think that's probably doesn't have as big a, you know, 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 frac these 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 the Circle M, some of those things become a little simpler. If you drilled your seventh well and turned it to sales, now you're drilling your eighth and ninth and tenth well, and now we've, we started focusing on the Haynesville, not so much the Bossier. So I, I do, I do see that. And, some of the hand-wringing that, that was required 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, 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, you know, 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. It. We're building the company. Very helpful. Thanks for your time. Thank you. One moment for our next question. Our next question comes from Charles Meade from Johnson Rice. Your line is now open. Good morning, Jay, to you, Roland, Dan, Ron, and the whole crew there. Morning. Charles, 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 fifties down here this morning. But anyway, Jay, I wanna ask a real question about some of your business decisions here. $300 million of outside capital. That's great that you've got a you know 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 you know for them to put that much money to work, they have to have some kind of a maybe it's not a firm commitment, but some kind of commitment to the amount of volumes that you're gonna put through this system. And, you know, maybe that's a minimum volume commitment, maybe it's, 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? Charles, that's a good question, and, you know, I think that we're gonna 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. T hat we charge for all processing and transportation about $0.54 per Mcf. So that's really no change in the rate. It's the same rate that we historically have had. W e have a very small MVC that that's backed to our own subsidiary here. That's that is far less than half of what we project the production to be. So that just kind of supports the new midstream entity. Got it. If I understood you right, Roland. So, 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? That's correct. Okay, got it. Thank you. R isk- adjusted too, with the existing production that we have, Charles. I think we start out with a big risk adjustment, day one. Got it. And then, we can do the work ourselves, but between those two numbers, we should be able to figure out when that ownership reverts, or rather, you know, where they go from, whatever, 80 - 30, but we'll do that work offline. Second question, I want to ask again about the Western Haynesville. Obviously, you guys are, you know, this is a big effort for you guys. When I look at your well 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 40. So I think that aspect has been de-risked. T here's other important data points which are, you know, 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. Well, 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. So 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 Haynesville 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 Haynesville 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 type curve really looks like when these wells really start falling over, and if these bottomhole 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've drilled in the core in the Western Haynesville, these are some of the best wells we've ever touched. So Dan, you want to comment anymore? Yeah. Totally correct there. So, you know, I'll just kind of comment a little bit on the D&C cost. So, you know, we have this is a totally kind of a different casing design down here than what we have up in the core. It's 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. The first seven wells we have producing, 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 got 10 wells targeted to turn to sales next year. Eight of those are gonna be in the Haynesville, two will be in the Bossier. So, you know, we are gonna turn our focus to that. But we've, we've still got some things that we've got targeted to, you know, put to work out here in the field that's gonna get the cost down, we feel, considerable amount. And then, you know, 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 know, you're getting 6, 7, 8% less cost, just, just, you know, via multi-well pad versus these down here are single, single wells. So that alone is, 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, is gonna. We're gonna 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 reaffirmed 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 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, you know, 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. That'll be months down the road, but we'll still report to you the results, you know, on a quarterly basis, which have been really good. Jay and Dan, thank you for the added detail. Appreciate it. Thank you. Great questions. Thank you. One moment for our next question. Our next question comes from Jacob Roberts from TPH & Co. Your line is now open. Good morning, and happy Halloween! Oh, that's right. Proper call on Halloween. Trick or treat. That's right. On the, just on, on the Quantum partnership, I'm curious if you could provide your view on what the, the cadence of spend would have been if Comstock were, you know, 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, and kind of maintain the same level, or should we be expecting kind of a, 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 gonna be starting out next year at. So, you know, And we think overall, service costs and drilling rates are down a little bit. But there's a lot of signs that point to lower capital, and then, you know, we've made investments, you know, in the midstream before this partnership, and now the partnership will kind of take over that responsibility. And, you know, the build-out of the Western Haynesville midstream is gonna be phased in. We're not gonna build it all on day one to handle a huge volume. It's gonna be built layered in over a five-year period based on the well results that we achieve. We have quite a bit of capacity now because we acquired a base system, and we've 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, you know, gathering lines as we need them, as we build this out. So, you know, I think, next year, the spending for this venture, you know, is probably, you know, 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. Great. Appreciate it. I know this is a really long-term question, but Jay, you mentioned the four rigs on the Western Haynesville in 2025, and then this plan to step up to 2 Bcf 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, well, there's three questions. One, how many rigs we have to have, we think, to hold our big footprint in the Western Haynesville? And we think we probably have to have a fourth rig by 2025, so that, it's not 10 or 12 rigs, it's four rigs. t hat'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. A s the wells have performed, you know, we went from one rig to second rig, and now the wells, as Dan has said and Roland has shown in the financial results, it calls for a third rig. And 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 in February. And those are built really to drill these wells in the Western Haynesville. So, that's one question. Second question is, if you take a model and you have a JV with midstream, with the Quantum, they wanna see what we look like down the road. So we model that out through 2028, and that's where you end up with that 2 B Bcf a day. But as we get there, though, if you look at the core, we've gone from 9- 8 - 7 - 6 - 5 rigs in the core, and now we have five and two. So next year, we should have 4 in the legacy or the core and three in the Western Haynesville. 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 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, that's where we go in your guidance. It's the same rig count. Okay, thank you. Appreciate the time. And thank you. One moment for our next question. Our next question comes from Bertrand Donnes 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. 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 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? It was designed to be what we needed. It's got lots of flexibility. I t's not we're not building out any to any particular volume? We're just going to continue to to build out our, the system as the well results tell us what we need. L et's not act like we're going to spend the whole amount on day one. A nd then I think it's, it's got lots of flexibility to expand or stay at a smaller level. So we don't that's the why we really like this partnership. Comstock will operate it, make all the decisions. We, we've hired a very experienced midstream group that's going to run this project and build this out. Then Quantum will be o ur financial partner. I t'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 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 this system from Legacy Reserves, and just getting it, refurbishing it back to the state that it was. I think that's how we see it. O bviously, 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. And on third-party volumes, we own all the acreage, mostly in this play. There's not a lot of other, you know, 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 when 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 maybe we've got, we're towards the end of the program, maybe 90% or, or somewhere around there, and then 4Q looks like a, a small step up. Was that just something you saw an attractive, package maybe earlier in October, or is there, you know, maybe a rethinking there? Well, I think 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, however we classify it. So 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 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 would just be, it'll 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 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 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. It's - I think that season of land grab is coming to an end. Great. Thanks for taking my question. Thank you. One moment for our next question. Our next question comes from Phillips Johnston from Capital One Securities. Your line is now open. Hey, guys, thanks. 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 Bcf a day by 2028 is mostly, if not all, Comstock volumes. I guess maybe if you could help us with the starting point. I know your current production isn't that 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? No. You know, Phillips, I think if you, if you ask me if I'm going to do a big M&A and double the size of my company, then I'd tell you a big M&A, and, I don't know what the M&A would be. If I'm out there de-risking the Western Haynesville, 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, 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, we have the type of geology that'll let us have about 2 Bcf 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 rigs throughout next year, would you expect working capital will either be a material source or use of cash next year? Well, there are two elements of a working capital change, and, you know, one of them is spending levels. And I think the spending levels, you know, have come down from where they were earlier in the year. So you see that it lags. It's like a two months really lag between cash numbers and you've seen that of impact of spending, so I would think that working capital will stay from spending, won't be a source or a use going forward because we're now kind of at this 7-rig level for a while. And then, but secondly, the other element that is all gas prices. So if gas prices are higher now, and we're still receiving gas from two months ago, that's lower priced. O bviously, it'll be a well, 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 that 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. T he 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, they're a lot better. So hopefully next year, they continue to be better. Well, going to the hedging position, we did add 100 million a day of hedges, which were swapped at $3.55. I think, Ron, it's a good number. So we did that in the last probably three or four weeks. We're 22% hedged for 2024. If you look at the perfect world of Comstock, I think we'd like to be in the 40% +. So everyone listening can know that we've, 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 the latter part of '2024, and then '2025 on, you should see it pretty consistent. That is our goal, Phillips. Okay, great. Sounds good, guys. Thanks. Thank you. One moment for our next question. Our next question comes from Leo Mariani from Roth MKM. Your line is now open. Hey, guys. Could you talk a little bit, too, 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 Haynesville? I think you alluded earlier that, maybe those would come in some. Could you give us kind of a sense? I mean, just looking at your third quarter D&C, it was up 1%, you know, like you said. So, what are you kind of seeing the, the service costs doing on the leading edge, and when do you think that starts to show up, in the financials? Leo, this is Dan. We have seen the service costs come down. They've been easing down since probably earlier this year. I'd say we've seen the biggest decrease just on the rig rates have come down. And, you know, of course, they're the ones that went up higher than anything else when they went the other direction. W e've seen the rig, the rig rates are probably down 10% since the earlier part of this year. I think on the completion side, probably not quite as much. T hat'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, in, you know, into this fourth quarter and into next year. We'll just 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 how much they continue to slide or maybe level out, or maybe even potentially pick up just a hair next year. The one comment to make, add is, Leo, when you're looking at that cost for a completed well, there's a big time difference. You know, drilling costs are the oldest cost in there, and so it, because these wells were drilled, you know, probably back a couple of quarters ago, or at least a quarter ago. Completing costs are more, you know, 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 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 start reporting more recent costs with wells that we complete, you know, 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 the, you know, 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 the spend for 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. The savings aren't here yet in that number. That's correct. Yep. Okay, that, that's helpful, guys. And then maybe just to follow up a little bit on, on just the kind of financing side. Obviously, you guys were able to mitigate some, some future CapEx with this deal. That's great to see. Certainly noticed that the revolver debt, you know, popped up, you know, a fair bit, you know, this quarter. I guess we'll, 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 kinda look to term that out? Are you kinda thinking about sort of maximum liquidity, as, as you kinda think about, you know, future, you know, funding needs, and, you know, could, 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 over, you know, 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 we had to lean into the revolver a little bit, but we see that trend reversing. Okay. Thanks, guys. Thank you, Leo. One moment for our next question. 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 of a, a bit more detail on the breakdown of the, you know, 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 sits long term, or is that something that's still kind of in flux, the development in play? Yes. Is that in relation to the Western Haynesville or just overall? Western Haynesville. Yeah. So we, we've got 7 wells that are currently, you know, producing now, as we stated. All of those are producing from the Bossier, with the exception for one. We got one Haynesville producer in that bunch. And then, you know, next year, we don't have any more wells turned into sales this year. The next one will turn to sales in January. So full, full year, next year, we'll have 10 wells that are scheduled to turn to sales, and, 8, 8 of those will be the Haynesville, which is- that's what we'd said earlier, correct, to and just two in the Bossier. 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? I mean, obviously, how the wells perform will play a role in that. I think you'll see a mix. You know, when we first kinda 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, you know, 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 still early, but I think you'll see the Haynesville will be a better. It's gonna be a better performer than the Bossier, just like up in the core. We like the Bossier. These Bossier wells look fantastic, but, you know, just like up there, we expect the Haynesville to be, you know, a little better performer. And so, you know, if you can get your cost basically the same, you know, the Haynesville wells are gonna be the better, better performing wells. Understood. Just, one quick follow-up: Is the, the lateral lengths in the Western Haynesville 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 Haynesville, given the higher pressure, how about b ack of the envelope, where do you guys think you can get to as far as lateral length in the next, you know, 18 months? Well, so we've already drilled one out to 12,700 ft. You 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 ft. And, if you look at the wells that we got planned to turn to sales next year, that group of ten, we're gonna probably be at 10,000 - 10,500 ft 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 know, you never know where you can end up sometimes. You know, you get 2 or 3, 4 years down the road with the technology improvements, so I wouldn't totally rule it out. But I think, you know, that 10,000-foot mark is pretty much gonna be our target. Understood. Thanks for the clarity. That's all for me. Thank you. One moment for our next question. Our next question comes from Noel Parks from Tuohy Brothers Investment Research. Your line is now open. Hi, good morning. Good morning. So we 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 the negotiation process you went through with Quantum. Just curious, you know, as they were looking at their returns and you, you're looking out fairly long term, you know, what did you do for scenarios of interest rates? And if we have greater volatility in gas prices as a result of LNG coming into the mix, wonder if you've given any thought to, you know, just how that might affect your returns or your planning or even your own leverage longer term? But that's a good comment on that. Yeah, interest rate environment, you know, the interest rates are up a lot. Yeah, that's showing up in both long-term rates, and then obviously the floating rates, you know, 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 the new midstream we have a low rate that's also kind of fixed. W e don't think the company's stock's too exposed to the higher interest rates as we look forward, at least over the next 3-4 years. And hopefully, we'll get to an environment sometime in after that period where rates kind of calm back down. Right. Great, thanks. And one thing I wanted to verify you. Sorry, just catching up on my note here. O ne 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 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. And we've had a big initiative that we put in place, you know, 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 Louisiana Gulf Coast, where there's a lot of new construction for, you know, industrial demand that's not LNG related, in addition to the LNG users. And, you know, they are all, 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. You know, they, they offer maybe even stronger pricing for us and probably more very reliable customers. They can really predict what their demand is. You know, I think as we go forward, you, 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, a portfolio of all those users and, you know, as we go forward, that we can directly connect to, you know, either from our new growing Western Haynesville play or our, our base play, you know, in, in Louisiana, where we're the, you know, the anchor shipper on Acadian, and we can get a lot of gas down to that market. And just, 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, 5 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, 3-10 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 too, 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 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, you know, have kind of a blank canvas, you know, for our new gas in the Western Haynesville, where it's not committed, you know, to a lot of other long-term contracts. Great. Thanks a lot. Ian, thank you. One moment for our next question. 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 Haynesville into the Western Haynesville next year, do you think your legacy Haynesville 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 4 rigs. You know, we are gonna be looking at maybe high-grade some of that to the, 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 Haynesville starts to build a nice production base, and then it has a, a much lower, you know, it, it. You know, that, that production, you know, even though, the, like, like Dan said, when we kind of IP those, you know, that's almost like what we produce them at for a long period of time. That production becomes, you know, very stable part of the base, so with lower decline. So I think longer term, you know, I think that, you know, we'll have, we can lower our corporate decline rate as the Western Haynesville 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. Makes sense. All right, thanks. Thank you. One moment for our next question. Our next question comes from Gregg Brody from Bank of America. Your line is now open. Hey, guys, and thanks for fitting me in. Yes, sir. So you mentioned the $300 million of capital coming from, from Quantum, about $100 million-$200 million, you said, will be spent next year. To get to the 2 Bcf per day, is there a need to raise more capital? And is-- or is the $300 million enough, or are there, 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 the entity will become self-financing as after it gets go. 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 got lots of flexibility. Yeah, that will be set up in a unrestricted subsidiary, so that will kind of have its own, you know, potential financing base. 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. You said it's unrestricted. Does Comstock has not guaranteed any of that? That's correct. Yeah, Comstock, Comstock is not guaranteeing, you know, 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, very unlevered basis. It's kind of the immediate plans here. And then, yeah, its own cash flow 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 actually, we can expand with additional approval up to $500 million. That's really helpful. But the $300 is initial committed part of the investment. You know, it's based on, obviously, the budgets that that's approved out there and, et cetera. That's really helpful. Thank you, guys. Thank you. Thank you. 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, 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, even, you know, even with weak natural gas prices, we've 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 a midstream in the Western Haynesville. We want to maintain an eye on appraising all of our Western Haynesville wells, and, you know, 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, 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 a dance is it? Is it a Texas two-step? Is it a jitterbug? Is it a Cotton Eye Joe? What we hope it is, over the years to come, is that 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, you know, 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.