Good day, and thank you for standing by. Welcome to the third quarter 2022 Comstock Resources 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 this session, you'll need to press star one one on your telephone. Please be advised that today's conference is being recorded. I would now like to hand the conference over to your speaker today, Mr. Jay Allison, Chairman and CEO. Please go ahead. Good morning, everyone, and thank you. Welcome to the Comstock Resources third quarter 2022 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 entitled Third Quarter 2022 Results. I am Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, our Chief Operating Officer, and Ron Mills, our VP of Finance and Investor Relations. Please refer to slide 2 in our presentation to note that our discussions today will 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. If you'll flip over to slide 3, you know, I'd like to announce to you that Comstock Resources just posted the greatest quarterly results in our 30+ year history as a public company, with our revenues almost exclusively coming from selling natural gas. We set new corporate highs in almost all financial metrics, including operating cash flow, free cash flow, net income, EBITDAX, and oil and gas revenues. Our balance sheet has now become a fortress. We're leveraged down to 0.9 x and a quarterly dividend is now possible. You know, to have a day like today, you have to rely upon many of you and many of you that are not even on the call. We say thank you to our equity stakeholders who trust us with your hard-earned money, and especially the Jerry Jones family. We say thank you to our banks that provide us with a credit facility and our bondholders, along with all the hundreds of oil field service companies who assist us in promoting excellence in drilling and completing our Haynesville and Bossier wells. Many of you have asked about our Western Haynesville region. The Circle M Well in Robertson County started producing in April of this year and has continued to have a flat production rate of around 30 million cu ft of gas per day. We've also drilled our second well in this region, which is near the Circle M, called the Casey Black, which was successfully drilled and completed, that is expected to be turned to sales this month. Note that the Circle M Well was shut in for 30 days while we were completing the Casey Black well. The Comstock team of 240 work hard to produce tier one results, which I'll share with you starting on slide three. We cover the highlights of the third quarter on this slide three. Our operating cash flow of $533 million, or $1.92 per diluted share, was the highest in our corporate history. After funding our drilling and completion activities, we generated $286 million of operating free cash flow. This allowed us to retire $250 million of bank debt, which brought our leverage down to 0.9 x. Our adjusted net income for the quarter was $326 million or $1.18 per diluted share, and our EBITDAX for the quarter came in at $598 million, 93% higher than last year's third quarter. Revenues after hedging for the quarter came in at $692 million, 76% higher than last year's third quarter. Our Haynesville Shale drilling program is going well, as demonstrated by the 17 or 15.2 net operated wells that we reported on this quarter, with an average initial production rate of 29 million cu ft per day. I'm excited to announce the reinstatement of a quarterly dividend to common stockholders. Our Board of Directors approved a quarterly dividend of $0.125 per share to be paid to our common shareholders on December 15, representing a yield of approximately 2.5% at our current stock price. I'll now turn the call over to Roland O. Burns to comment on our financial results. Roland. Thanks, Jay. On slide four, we recap the very strong third quarter financial results we achieved. Pro forma for the sale of our Bakken properties, which was completed last October, our production increased 1% to 1.4 BCFE per day in this recently completed third quarter. Our record high EBITDAX in the quarter grew by 107% over 2021's pro forma third quarter to $598 million, driven mostly by stronger natural gas prices. We generated $533 million of cash flow during the quarter, 126% increase over 2021's third quarter on a pro forma basis. That's another corporate record. Our cash flow per share during the quarter was $1.92. It's up $1 from the third quarter of 2021. We reported adjusted net income of $326 million for the third quarter. That's more than 2.5 x higher than the third quarter of 2021, and our earnings per share came in at $1.18 as compared to $0.35 in the third quarter of 2021. We generated $286 million of free cash flow from operations in the quarter, 218% higher than the third quarter of 2021. That, the growth in EBITDAX and the retirement of $250 million of debt in the quarter, drove our leverage ratio down to under 1x as compared to 2.3x in the third quarter of 2021. Improved natural gas prices were the primary factor driving the strong financial results in the quarter. On slide 5, we provide a breakdown of our natural gas price realizations in the quarter. During the third quarter, the quarterly NYMEX settlement price averaged $8.20, and the average Henry Hub spot price averaged $7.96. During the third quarter, we nominated 77% of our gas to be sold at index prices tied to that contract settlement price, and then we sold 23% of our gas in the daily spot market. The expected NYMEX reference price for sales in the third quarter would have been $8.14. Our realized gas price during the third quarter averaged $7.72, which reflects a $0.42 differential. That was a little higher than normal due to wider regional differentials and due to, most significantly, weaker Houston Ship Channel prices, which are all due to the Freeport shutdown. Houston Ship Channel and other Texas Gulf Coast indexes are usually some of our premium markets. In the third quarter, we were also 49% hedged, which reduced our realized gas price to $5.36. We have been using some of our excess transportation in Haynesville to buy and resell third-party natural gas. This generated about $11 million of additional income in the quarter, and that added about $0.09 to our average price realization in the quarter. On slide six, we detail our operating cost per Mcfe and our EBITDAX margin. Our operating cost for Mcfe averaged $0.82 in the third quarter, $0.08 higher than the second quarter. Our gathering cost increased by $0.05, and that's primarily due to the impact of higher fuel cost used in the transportation of our gas, but also due to higher production from some of our higher gathering rate areas. Our lifting cost increased $0.02, and our production taxes increased $0.01 due to the combination of higher realized prices and an increase in the statutory severance tax rate in Louisiana that became effective in July. G&A costs came in at $0.06, the same as our second quarter rate. Our EBITDAX margin after hedging came in at 85% in the third quarter, the same as the second quarter. On slide seven, we recap the first nine months of this year and what we spent on our drilling and other development activity. In the first nine months, we spent $729 million on development activities, including $653 million on our operated Haynesville and Bossier Shale drilling program. We also spent $23 million on non-operated wells and $54 million on other development activity, including installing production tubing, offset frack protection, and other workovers. In the first nine months of this year, we drilled 52 or 42.5 net operated horizontal Haynesville wells, and then we turned 53 or 44.2 net operated wells to sales. These wells had an averaged initial production rate of 27 million cu ft per day. We also had an additional two net non-operated wells that we turned to sales. In the third quarter, we spent $242 million on our development and exploratory activities, including $227 million on our operated Haynesville and Bossier Shale drilling program. We also spent $4 million on non-operated wells and $11 million on other development activity. On slide 8, we show our balance sheet at the end of the third quarter of this year. We had $100 million drawn under our revolving credit facility at the end of the third quarter. The reduction in our debt balance and the growth of EBITDAX drove our leverage ratio down to 0.9 x in the quarter on an annualized basis as compared to the 2.3 x that we were at for the third quarter of 2021. We plan on retiring the remaining $100 million outstanding on our revolver in the fourth quarter using our free cash flow. We ended the third quarter with financial liquidity of more than $1.3 billion. I'll now turn it over to Dan to discuss the operating results in more detail. Okay, thanks, Roland. Over on Slide 9, this is an update on our average lateral lengths we drilled since 2017. The year-to-date average lateral length has increased slightly up to 9,797 ft. This is based on the 53 wells that we've turned to sales so far this year. This currently puts us over 1,000 ft longer than last year's 8,800-foot average lateral, and by the end of the year, we anticipate our full year average to be approximately 10,100 ft. Year-to-date, we've drilled 17 of our extra long lateral wells. That's our wells with laterals greater than 11,000 ft. Included in this group, we've had 9 wells with laterals greater than 14,000 ft. I'll add that we're actually drilling our 18th 15,000-foot lateral at this time. Our longest lateral drill completed to date still stands at 15,291 ft. By year-end, we anticipate turning 64 gross wells to sales, with an average lateral of 10,100 ft. On slide 10 is the latest D&C cost trend through the third quarter. This is for the benchmark long lateral wells with laterals longer than 8,000 ft. This quarter, 10 of our 17 wells turned to sales were in this benchmark long lateral group. The D&C cost averaged $1,405 a foot in the third quarter, which represents an 11% increase from the second quarter, and a 35% increase from our average 2021 full year D&C cost. Our drilling cost for the quarter was $597 a foot. This is a 25% increase quarter-to-quarter. While our completion cost for the quarter was $808 a foot, which represents a quarter-to-quarter increase of only 3%. The increase in our drilling costs reflects the true cost inflation numbers we have experienced year to date, and we have seen it affect all services across the space. As witnessed by our completion costs for the quarter, we've been partially protected by the high inflation costs on the completion side through the deployment of our first natural gas-powered frac fleet, which is playing a significant role in keeping our costs down, locking in long-term our cost to horsepower and also drastically cutting our diesel usage. As we mentioned before on the last call, we've contracted for a second natural gas-powered frac fleet, and we do expect to take delivery sometime late in the first quarter of 2023. Slide 11 is a summary of the new well activity for the third quarter. We've turned 17 new wells to sales since the last call. We had really strong well performance this quarter with individual IP rates ranging from 17 million a day, up to 40 million cu f t a day, with an average test rate of 29 million cu ft a day. The wells were drilled with lateral lengths ranging from 5,328 ft up to 15,210 ft long. The average lateral was 9,899 ft. Included in this group were our three most recent 15,000-foot completions. These 15 K wells tested at rates of 30 million cu ft-32 million cu f t a day, and the average length of these was 15,075 ft. The group also includes the first three wells we've drilled and completed on our Nacogdoches, Texas acreage since we restarted our Haynesville drilling program back in 2015. The initial test rates for these three wells exceeded our expectations, with IP rates ranging from 33 million a day, up to 40 million cu f t a day, with laterals averaging 7,477 ft. Based on the initial results on the Nacogdoches acreage, we do plan to add activity there later next year, and we also will continue to pursue drilling the longer laterals as they offer a hedge against inflation. Regarding our activity levels, we did add the 2 additional rigs early in the third quarter. We're now running a total of 9 drilling rigs and 3 full-time frac crews. Looking ahead in a more general sense, we plan to shift more of our drilling activity from Louisiana into Texas as we spread out the activity to maintain our takeaway capacity, maximize where we can drill the longer laterals, and to protect our acreage. I'll now turn it back over to Jay to summarize the outlook. All right, Dan. Just a comment before I start kind of the final presentation. The Nac acreage was a Tier III set of acreage that we had initially, and you can see from what Dan had reported, the IP rates and those lateral lengths. It's now become, you know, closer to a Tier I area. We'll have increased our inventory of Tier I as we move some of these rigs over to the Nac acreage. If you'll go over to slide 12, I'll direct you to slide 12, where we summarize our outlook for the rest of the year. You know, we're on pace to generate significantly more than our targeted $500 million of free cash flow. We've already exceeded that at the end of the third quarter. At the current commodity prices, our free cash flow could reach somewhere around $800 million. Of course, the first priority of the free cash flow generation has been reducing our leverage, which we've done. You know, we've retired $250 million of debt during the third quarter, and we expect, as Roland said, to repay the $100 million remaining borrowings outstanding under our bank credit facility in the fourth quarter, maybe even this week or next week. As discussed on the last conference call, and as Dan just mentioned, we have 9 rigs operating in our Haynesville drilling program. The 2 recently added rigs are expected to be active on our Western Haynesville acreage position in 2023. We should move a second rig in this area probably late November, early December. We'll use those rigs to de-risk and delineate the play. We did budget about $65 million-$75 million for both on acquisitions and leasing activities for the year, which includes the $54 million already spent in the first nine months of the year. Now that we've exceeded our leverage goals, you know, we're starting our return to capital program in the fourth quarter. Our board of directors, as I said earlier, has authorized reinstating our quarterly common stock dividend. The fourth quarter dividend is $0.125 a share, and it'll be paid on December 15. Lastly, you know, we will continue to maintain and grow our very strong financial liquidity, which totaled, again, more than $1.3 billion at the end of the quarter. With that, let me turn it over to Ron. You can give some specific guidance for the rest of the year. Thanks, Jay. On slide 13, we provide financial guidance for the fourth quarter of this year and full year. Fourth quarter production guidance range is 1.42-1.52 BCFE per day, and the full year guidance remains unchanged at the prior level of 1.39-1.45 BCFE per day. During the fourth quarter, we plan to turn to sales 8-10 net wells, and we now anticipate our 2022 full year production guidance to be biased towards the low end of the low end of our range, due mainly to the timing of turning wells to sales. For the year, we now expect to turn to sales 1-2 less net wells this year than when we last provided guidance in August. The 2022 development CapEx guidance remains $925 million-$975 million. As Dan mentioned earlier, the 2022 wells will have an average lateral length of about 14% longer than last year, which is helping to offset some of the cost inflation we've seen. In addition to the drilling program, we expect to spend up to $65-$75 million, including both bolt-on and leasing activities, of which $54 million has already been spent this year. Our LOE costs are now expected to average $0.18-$0.23 in the fourth quarter and $0.19-$0.24 for the full year, while our gathering and transportation costs are expected to average $0.28-$0.32, both in the fourth quarter and for the full year. Production ad valorem taxes are expected to average $0.20-$0.24 in the fourth quarter, partly due to commodity prices and partly due to severance tax rate in Louisiana. DD&A rate expected to average $0.95-$1.05 in the fourth quarter. Our cash G&A expected to average or be $7 million-$9 million this quarter, and total $29 million-$32 million for the full year. The non-cash compensation portion of that is approximately $2 million this quarter. The cash interest expense is now expected to total $38 million-$40 million during the quarter, which would bring the full year of cash interest up to about $158 million-$162 million. Our effective tax rate is still expected to remain in the 22%-25% range, and we continue to expect to defer 75%-80% of our taxes. We'll now turn the call back over to the operator to answer questions from analysts. Catherine, you can turn it over to Q&A. Thank you. As a reminder, to ask a question, you'll need to press star one one on your telephone. Please stand by while we compile the Q&A roster. Our first question comes from Derrick Whitfield from Stifel. Your line is open. Thanks, and good morning, all. Morning, Derrick. With my first question, I wanted to focus on the Circle M result and early indications on your second Bossier well in Western Haynesville. Since the last call, what incrementally can you share with us on the potential of the Circle M and your view on the repeatability of that result based on your and industry results? Yeah, Derrick, this is Dan. We, you know, Jay mentioned, the well's been producing flat at 30 million a day since we put it on in April. We did shut it in when we fracked the Casey Black, which was in the vicinity. We started that frack back on around October the first. We had the well shut in, you know, just for precaution for 30 days. We just recently put it back on here the last few days, and we're ramping it back up to that 30 million a day rate. Yeah, everything looks really good on the second well. We'll get it turned to sales this month. We expect it to be just as good, maybe a little better than the Circle M. We don't see anything really on the horizon on why, you know, any of these future wells are gonna be anything less than the Circle M. That's terrific. As my follow-up, I wanted to ask a gas egress question based on the broader weakness in Perryville, Katy and Houston Ship Channel, really more the region. With the understanding that recent weakness has been driven by pipeline outages in Freeport, wanted to ask if you could share your macro views at, really, the basin level and more specifically, to what degree can the Haynesville production grow over the next year, in your view, and how much excess takeaway do you own over current production levels? You know, if you look at our program, we've intentionally added the 2 extra rigs to go to 9, and we did that several months ago. We broadcast it maybe, you know, 6 months ago that we might be doing that. When we forecast our production growth, particularly with the Western Haynesville, and our core area, which is 7 rigs will be on that core area, we always project pipeline and takeaway. I mean, we look to see if we're gonna drill 80 wells gross a year, maybe turn to sales 60 or so of those. Where that takeaway is. You know, we've done that, whether it's with Williams or ETC or with Enterprise, et cetera. I mean, I think our marketing group is ahead of our drilling schedule. Even though we think that the takeaway is extremely tight, it may be 95% full, I think that if you plan ahead, you know, you're not gonna run into some of the problems that some of the smaller companies have. The other thing that we have, which it comes into play now, is our expansive acreage footprint. It's not like we're in one or two counties in Texas or six or seven parishes in Louisiana. We're in all the above. If you go back, Derrick, and you've looked at how we spread our program out, you know, quarter to quarter to quarter, year to year, you can see that we'll heavily drill in one area and not another because of the takeaway issue maybe. Because we do have that 400,000+ acres and growing, we've got a lot of room to avoid some of the pipeline takeaway issues. Yeah. Derrick, this is Roland. Just to add a couple of comments to that. You know, we recently added about 300 million a day of additional takeaway to our transportation portfolio, you know, as we continue to, you know, look ahead and just see where our needs are. You know, there were a lot of brownfield projects, greenfield projects, both, you know, in the Haynesville, especially redirecting gas to the Gulf Coast markets, you know. You know, we continue to evaluate those, take out parts of those. Just like we have a diverse acreage position, we like to have a diverse transportation portfolio so we can have options, you know, to move our gas around or and to drill, you know, in areas that have the most takeaway. I think your other question was. We do have about 200 million a day of spare capacity, you know, that we actually are just, you know, actually buying and reselling third-party gas that we plan to use up. So you know, we just in next year's drilling program. we think we're pretty well positioned, but we'll continue to be front run that, you know, you know, as the Haynesville production grows and as the demand grows in the Gulf Coast and, you know, being able to get the gas down to those users. Derrick, as Roland said, we have added more firm transportation, because we think if you have interruptible, you'd probably be interrupted. We've added more firm. That's terrific. Sounds like you guys are well positioned. Thank you. Thank you. We have a question from Charles Meade with Johnson Rice & Company. Your line is open. Good morning, Jay, to you and your team. Hello, Charles. Jay, I wanted to ask a question about those Nacogdoches well results. Obviously, you put this in the presentation, those are stout rates, particularly in light of you know, the 7,700-7,800-foot lateral lengths. I'm curious, it sounds like in your prepared remarks, it sounded like that was an uptick versus your internal expectations previously. I wonder if you could talk a bit about that. Is there a different completion design? Are you targeting a different zone? Is it maybe something that you've learned from you know, Western Haynesville that you're bringing back this way? Just tell me what's going on there. Yeah, Charles, I thought maybe I'd pull that question out of you if I commented on it after Dan presented. He didn't cover it like I want him to cover it, so this is his chance. Charles, you know, we hadn't drilled any wells down there since 2015. Back when gas prices were low, you know, that was just kinda one of the areas that we did not look at spending our capital because, you know, we'd looked at the wells that had been drilled, and they just didn't really compete when you looked at the other areas where we were drilling and where we needed to maximize, you know, our performance. We do have, I think about 35,000 net acres down there. Gas prices improved. We, you know, we needed to move a rig down there and basically put a new vintage frac on those wells. There is other offset activity in the area that's showing that, you know, the results are good. We drilled 2 Haynesville and 1 Bossier. It was a 3-well pad. The footprint we had, you know, just allowed us to drill a 7,500 foot lateral. We could have drilled them a little bit longer if we had the, you know, the footprint was there. The bottom hole pressure is a little higher. That's a little bit deeper down there. It's about 14,000 foot TVD. We put the bigger vintage, you know, newer frac job on it like we've been doing everywhere else. The performance looks really good. Now, you know, we need to let them produce out for a while, obviously, and, you know, confirm that, you know, what the UR is gonna look like. Man, out of the gate, they look really good. Right. Thank you. It looks like you probably have three months of data on those productions. So that'll be interesting to follow that. My second question is on the slippage of the turn in line schedule or the completion schedule that you guys mentioned. Can you talk about, I guess what the drivers were there, with an eye or with kind of an aim at, are these one-time things, or is this representative of service tightness that has some likelihood of, You know, reappearing in 2023. No, Charles, this is really a just a one-time thing. We had some of our three full-time frac crews. We had we took our lower performing frac crew, and we had the opportunity to upgrade and pull in another frac crew that we thought was gonna be a lot better, have better performance. We made a switch here just in the last few weeks. What it did was it took one of our three well pads that was gonna turn to sales in December, and it pushed it into January. It pulled up a couple other pads. There were some dates that shuffled around, but that's basically what caused that. Got it. That's helpful detail. Yeah. It doesn't change anything long term, and it's not a sign of anything as far as, the crews or supply chain or anything like that. It was just a one-time event, swapping our lowest performing frac crew for another. Yeah. Charles, it has nothing to do with well performance or inventory. We think actually next year. Got it. That's all helpful. Yep. I think we'll see a pickup next year with the efficiencies on this other frac crew we picked up. I think it's gonna help us pull forward turn to sell dates that we had next year. You know, that'll be. That'll help out. Great. Thank you. Thanks, Charles. Our next question comes from Fernando Zavala with Pickering Energy Partners. Your line is open. Hey, guys. Good morning. Thanks for the time. I was wondering if you could talk a little bit about, you know, your activity levels in 2023 and how you would flex activity with, you know, perceived oversupply in the natural gas market next year. Well, we really haven't set our 2023 budget yet. Yeah, that's something we evaluate, you know, as we kinda get toward the end of the year here. I think, yeah, we'll definitely be looking at the strength of gas prices to determine our activity level, and looking at, you know, where we have takeaway. We don't drill wells that we don't think we have good markets for. So that's to come. You know, we'll monitor that. You know, I think one of our big initiatives at Comstock is to really start to build up long-term supply contracts where we're looking to lock in direct customers and really stabilize the markets for our gas in the future. Given our connectivity to a lot of the industrial users and LNG facilities, that's kinda how we're looking to position the company, you know, in the future to really have, you know, not be reliant on the day-to-day market or the clearing, you know, clearing market, but more have a much better outlook on, like, we know our customers, you know, want this gas and supply them on a long-term basis. Makes sense. I know you're focusing on trying to prove up that Western Haynesville acreage. Is there, like, any price point where that, you know, would shift, and maybe you would move one of those rigs back to your core Haynesville? No, we don't see that happening at all. We see, you know, delineation wells. We've got the rigs that we need to drill the Western Haynesville. We've got them scheduled with, you know, pad sites. We have takeaway for all those wells that are planned in 2023. We have completion crews, as Dan had mentioned, in place, you know, to handle a nine-rig program with seven rigs in the core area and two delineating the Western Haynesville. You know, as Roland said, I mean, we now, you know, looking at maybe some end users for chemicals or industrial users that may want to contract to buy our gas, so they have it. Once the LNG demand of anywhere from, you know, 8-11 Bs matures by 2026, some of the end users locally along the Gulf Coast, I mean, they'll have gas provided by someone, and maybe that may be Comstock, so we'd sell directly to them. At the same time, we'll kind of reach out and see what the LNG market is, because we have. Remember, we're very predictable with our 1,600+ locations, the very high margins, low cost we have, predictability we add, and again, this lack of leverage. I think we have all the earmarks for LNG exposure when it appears, and we're ready for it. Got it. That's helpful. Thanks for the time. Thank you. We have a question from Neal Dingmann with Truist. Your line is open. Morning, all. My first question is on well cost, specifically, I think, expected cost per foot. Looking here, it looks like your presentation suggests that 2022 costs per foot are up about 45% year-over-year, and I'm just wondering, one, is that am I correct in that 45%? Then secondly, maybe more importantly, I know you don't have 2023 guide out yet, but how you're thinking about 2023 on a cost per foot given you know inflationary pressures I think everybody's experiencing, but also obviously the nice longer laterals and other things you all are doing. Yeah. Neal, this is Dan. We definitely, I think you're pretty close on that percentage number. I mean, if you just compare it to where we were at 2021, which was really the low point. I mean, obviously, we don't wanna go back to that, where the gas prices were. We're still seeing the inflation numbers move on up a little bit. We've been, you know, really, when we picked up this gas frac fleet, we were really fortunate there. That has really kept us in check on the completion side. I think when we get that second fleet next year, you know, two out of our three fleets running on gas and with the horsepower locked in for the long haul, we're gonna be in good shape there. The drilling side, I think was where we're gonna see obviously, the costs are gonna continue to move up as long as the demand's there. You know, we're seeing it just across all services. I mean, obviously we've seen it in the rigs. You know, we've seen it in the diesel. We use a lot of diesel, you know, in oil-based mud, you know, cementing, directional tools. I mean, it's just really a kind of across the board. That's, you know, that's where we're gonna be battling, you know, those costs. The longer laterals are helping tremendously. You know, the wells in Texas are a little bit cheaper to drill over there. We drill faster in Texas. We've got the acreage in Texas to drill a lot of long laterals, so you know, that's gonna help us there. Have you locked in some of those 9 rigs? Do you have longer term contracts on any of those? We have we've got some medium-term contracts on some of our rigs, but we don't have any of them currently locked in at long-term, but we are evaluating some at the moment. Okay. Maybe Daniel, just my second question on pretty general, I mean, broad strokes. Just wondering, you mentioned turning more towards wells in Texas next year versus a lot of the, you know, nice Louisiana wells you have done this year. Any just early thoughts on well returns you think they'll be pretty comparable, you know, as you start drilling and completing some of those? I think they're gonna be pretty comparable. You know, I mean, the better high profile wells are on the Louisiana side. I mean, that's why, you know, the drilling activity was concentrated there in the past few years. The Texas wells typically will IP lower. They'll make a little more water, but they got a little flatter decline. The D&C cost is lower in Texas, so I think, you know, maybe it could be just slightly less, but I think it's pretty comparable overall when you package the, you know, the lower D&C costs, you know, compared to the Louisiana wells. You know, then, like we mentioned, you know, we're looking at takeaway capacity. We can't, you know, we can't concentrate a lot of activity in any one area. We're just kinda keeping everything spread out to make sure we don't create any issues there. Sure. Thanks, Dan, for the time. Thank you. Thank you. Our next question comes from Umang Choudhary with Goldman Sachs. Your line is open. Hi. Good morning, and thank you for taking my question. My first question was on your free cash flow allocation plans. I mean, your balance sheet has improved considerably. You've reinitiated your quarterly dividend. As you look to 2023, would love your thoughts on free cash flow allocation towards balance sheet reduction, any further form of capital returns which you're contemplating. If there's any additional free cash flow which you're earmarking for the Western Haynesville area. Well, that's a good question. You know, yeah, we're gonna be very conservative on promising you know what we do with the free cash flow. As we kind of approach and formalize our capital budget for next year, that's gonna be the first step. Understanding what we need to invest in the Western Haynesville and the base Haynesville. You know, I think we're very comfortable that the dividend we put in is a sustainable dividend that's rock solid, even with a much lower gas price you know that we have now in the futures market. You know, we'll be conservative on you know promising how you know what the level of dividend is and then what other forms of return of capital we may wanna employ. You know, again, you know, the balance sheet definitely has always come first. We've got this new fortress balance sheet with tremendous liquidity, seeing a much lower cost of capital. We're not gonna sacrifice that for anything. That's gonna continue to be the top priority, and then we'll be very prudent and careful on, you know, on return of capital that we put in place next year. There's a, as you identified, a very large gap between how much of the free cash flow we've earmarked, you know, for the dividend and, you know, what we expect to generate. Well, I'd even prove up our conservative nature is that, you know, we broadcast that once we get leverage less than 1.5, which we did that in the last quarter, we still waited another quarter in order to, you know, initiate the dividend. Those actions tell you what we're gonna try to do with the free cash flow. We'll be very conservative with it. Great. That's very helpful color. I guess on the next question, like you said, the macro environment has been very volatile. You've seen gas prices really trade off recently. I was wondering how you're thinking about your hedging strategy, as you would think towards next year. Notice that you didn't add any hedges this quarter. Well, you know, on the gas price, I mean, gas went from $9.85 to $6.30 or whatever it is. It might have fallen significantly, but it's up significantly from where it was. I'm looking over here at Dan's cost per foot. The price of natural gas went up a whole lot, a greater percentage than the cost per foot went up. When we look at that, we say if we do have a fortress on the balance sheet, if we're not looking to spend billions of dollars on M&A, because we don't think we have to because of the inventory that we have and the de-risking that's going on, then we may look at hedging in a little different way. Our 20/20 vision may be different than others. You know, we feel like once we get into 2023, at this point in time, you know, as of today, we're probably properly hedged with half of our production hedged at a $3 floor or almost a $10 ceiling. I think as we get into the December, see what the winter looks like, see what the storage really is, it looks like, and see what happens, you know, across the oceans as far as the need for this gas and see where prices end up. We'll always look at that, because we, you know, we typically have a percent hedged all the time. I think our liquidity and our free cash flow numbers will drive that answer a little differently than it has in the past. That's great color. Thank you. Thank you so much. Yes, sir. Thank you. Thank you. We have a question from Phillips Johnston from Capital One. Your line is open. Hey, guys. Thank you. Maybe just to follow up on the return of capital question. You mentioned the $0.50 dividend is very sustainable and conservative. I guess, as you get more comfortable with returning more capital over time, should we think about that base dividend just, you know, slowly marching higher over time? Or would the first priority sort of be to look to other forms of returns, whether it's, you know, variables, buyback, et cetera? That's a good question. I think definitely, you know, we'll evaluate the level of the dividend. As to the extent that, you know, we see the production base is larger and then that dividend is very sustainable at a higher rate, I think that's something that will be the first thing to look at, you know, each quarter as we progress. You know, and I think we would look at other, you know, potential return to capital strategies such as buybacks. I don't think that a variable dividend is something that we think is something that we wanna commit to, given most of the shareholder feedback we've got has not been very favorable on variable dividends. I think we'd be looking at, you know, maybe additional debt reduction just to continue to strengthen the balance sheet and then, you know, potential, you know, share repurchase program in the future when we think that makes sense. Yeah. Okay. I guess just the decision to allocate a couple rigs to the Western Haynesville next year. I think those wells take a little bit longer to drill than the wells in your traditional area of development. Can you maybe talk about just the balancing act between wanting to delineate, I guess, that area on one hand with sort of the trade-off of maybe a less efficient capital program in the near term, just in terms of wells per rigs relative to this year? Yeah, that's a great observation because the extent that you reallocated those wells back to the, you know, our traditional Haynesville, they would create a lot more capital because, you know, they would drill a lot more wells, so there would be more completion costs. I think when we added those, we took that into account that, yeah, the wells take longer to drill. So in actuality, looking at the amount of capital per operated rig, you know, they're actually gonna keep that number lower. But now we're very dedicated to continuing to delineate that play. But yeah, the play will tell us, you know, what's needed. You know, we'll proceed based on results. So far, the results have been excellent. If we continue to have excellent results, we'll continue to put in, you know, the resources if, you know. That's, you know, we don't wanna push the play too hard because we want to learn from each well. Each well, I think we've continued to improve the drilling and completion design, made changes to things as we're learning about this play. You know, again, we're gonna let the results tell us what's needed, and we're gonna be patient and not push it too hard, but we're very excited about, you know, delineating the play. Thank you. Yeah, this is Dan. I'll just add, we are on a pretty good learning curve. We've learned actually quite a bit on these first two wells. We totally expect as we just get a few further wells into the program, you know, we're gonna see the costs, and I think the drill times and all that are gonna speed up, and the costs will come down. You know, we're pretty confident we'll see that in the near future. You know, Phillips, and you know, we're spudding, and we've set some pipe even on our third well, the Campbell well. We've got one that's been producing, the Circle M. We've got one that we expect to turn to sales this month. You know, we've started drilling a third well, the Campbell. As Dan has commented on drilling results, I think we've learned from all of these wells. Quite frankly, I think we're getting better on all of them. You know, hopefully, we can report on the Campbell at the next call. We'll see what happens. It'll be in February. Sounds good, guys. Appreciate it. Thank you. We have a question from Paul Diamond with Citi. Your line is open. Good morning, all. Thanks for taking my call. First one I wanted to jump into was just about, kind of circling back on the potential timing and progress you guys have made on those, kind of longer-term contracts. Is that something we should expect in the next few months, or is that more of a long-term strategy? I think that's more of a long-term strategy. I mean, I think that is the shift. I mean, there are a lot of opportunities out there that we've been approached with, and we don't wanna jump on the first one and find out that that's not the best opportunity. So we're putting a lot of effort into evaluating these future markets and you know, locking up you know, longer-term customers. I mean, we have definitely done some of those already. Then we you know but I think over the next you know, six months or so, you know, I think that's kinda when you could maybe expect us to kinda come back and provide more color on kinda where we see our long-term markets. Understood. Thank you. Just a quick follow-up. You guys have kind of laid out a you know 9-rig plan you know 7 in the core and then some split between Harrison and Nacogdoches. From a macro perspective, is there anything you guys can foresee that would cause a shift in that, or is that pretty much set in stone for the next you know 12-18 months? Yeah. Our schedule, I'd say it. I mean, we always shuffle things around as needed, but I would say it's pretty well fixed for the next 12 months. I mean, we've got the rig lines, you know, are built out for a couple of years. You know, we move projects around as needed if something arises. We, you know, we've got the Nacogdoches acreage. It takes a little bit longer lead time in Texas to get wells drill-ready, so probably, you know, middle to late next summer, you know, a rig returning back on the Nacogdoches acreage. You know, we'll have a second rig in the Western Haynesville, like we mentioned earlier, probably late this month or next month and, you know, into next year. We definitely have the ability to move some things, you know, some stuff back over to Louisiana. I would say to answer your question, really, it's fairly well fixed for the next 12 months with some minimal moving around. Well, as we commented earlier, we don't have any long-term rig contracts. You know, if for some reason the market crashed, which we don't see that, we're pretty nimble. You've seen us in the past. We need to get rid of some rigs. We can do that. If we need to add a rig or two, you can see we're pretty nimble to do that too. We're in the fairway of the nine rigs. That's what we budgeted, and we haven't given any guidance for 2023, you know, as of today. Understood. Thanks for the clarity. Thank you. Our next question comes from Noel Parks with Tuohy Brothers. Your line is open. Hi. Good morning. Hi, Noel. Hey. Just a couple things. In your leasing budget, I think it was about $54 million you've leased year to date. Just curious what you're picking up with those lease dollars. Is this expired leases, you know, never leased acreage? Just wondering kind of what's still out there to buy. All of the above, I guess. You know, again, that includes remember our acquisition that we made, you know. It's a combination of, you know, maybe we acquired held by production properties that have the deep rights still available, hadn't been developed. That's actually, you know, some of the chunkier parts of that. You know, new primary leases. It's just all of the above. We've really grown our land department this year and to focus on, you know, exploiting these opportunities that we see in the Haynesville. You know, we've added a lot of personnel, have a lot of activity going on at the ground floor. Yeah. Noel, we add to the acreage. You know, if we can extend the lateral length of these wells, you know, we still have dollars budgeted for that. If we can pick up any deeper rights, like Roland said, it's HBP that we think it is in a fairway of where we have gathering, then we'd look at that aggressively too, particularly if it can extend the lateral lengths to some of the acreage we already own. That's the budget. I think the more important part of that budget is, you know, when you're looking at the analyst reports, we're not budgeting for big M&A activity. That's the whole key. Right. Thanks. Talking about just as with all the liquidity you have and the free cash flow you'll be generating, I guess I was wondering about a couple areas. Just wondering if you had any thoughts about sort of non-operated holdings in the region. There's been quite a bit of trading of non-op interest kind of across the industry. Was that something you would be willing to pick up or something you'd wanna try to get away from? Also wondering if we do face sort of an uncertain gas environment next year, any appetite for taking some of your liquidity and sort of, you know, consciously deciding to build up a DUC inventory to, like, give you more ability to be opportunistic about when you bring things on? Yeah, those are some good questions. On the non-operated activity, I mean, you know, it is a very active area, a lot of buying and selling non-operated interest. We're more of a seller there. We really don't like to be in properties that aren't operated by us. I mean, so we typically, you know, trade interest with adjacent operators, so we can each have our own operated projects. To the extent that we see, there's a very active market for participants. They like to buy non-operated interest in the Haynesville. We, you know, we've sold some interest to them, especially where we see a lower return, you know, project compared to other projects in our portfolio. We're probably more of a seller of that non-op. We certainly aren't a buyer. We, you know, we would never be interested in buying non-operated projects 'cause, you know, we wanna make sure that, yeah, we protect our very low cost structure and our very good, you know, margins. You know, we feel like they're the best in the industry, so most of the other projects that we see from other operators, you know, have inferior, you know, in that area. Although, you know, the gas prices have been high, so it's not like those aren't very profitable projects. We just wanna protect our numbers. Well, Noel, I think we like to control where we spend our money. The good thing is we've got such a large acreage footprint that we do have a lot of AFEs coming in as a non-op. So the question is, do we participate in those? Maybe we participate because we wanna find out what's going on in that area. Or, again, like Roland said, we have accounts daily come in that would like to buy all the non-ops. So they're very easy to sell down right now. We balance that with how much, you know, what is our budget for the year to try to hit the budget numbers, to try to use those dollars the best we can to create, you know, the greatest return we can with our own operations group. We're pretty selfish on that front. Yeah, on the question about building up DUCs, I mean, I think that we just don't like to put that kind of investment in wells and have that are drilled because, you know, we don't think it's the right way to manage the business, you know. You know, from both the, you know, the landowner standpoint as far as, you know, drilling the well and not putting it on production, you know, I just think that's not something that we ever look at as a good strategy. We've never, you know, done that on purpose. Every now and then, you have a few DUCs that get created, because of some issue, but, it's rare. Great. Thanks a lot. Thank you, Noel. Thank you. Our last question comes from Leo Mariani with MKM Partners. Your line is open. Hey, guys. Wanted to follow up a little bit on the recent basis issues that you've been, you know, experiencing. I mean, it certainly looks like the Haynesville as a basin is kinda continuing to grow in the next couple years. Do you guys foresee this could become a larger issue in 2023? I guess, do you have any maybe strategies to mitigate that if it does? Well, Leo, you know, it's a seasonal issue too, because this time of year lasts three years in a row. You know, October and part of November is always wider. It's kinda the shoulder month, the transition from you know, from the injection into withdrawal. It's always sloppy, you know, and that's. So that's nothing new. You know, we you know, I think what's newer in this quarter is not so much, you know, we manage the Perryville Carthage basis differentials very well with our Gulf access. I think the real what's different this quarter is that the Texas Gulf markets, which have been premium markets, you know, maybe some of the best premium markets, have really turned around because mainly because of the Freeport, where they're putting all that gas into storage versus sending it, you know, using it for LNG. So that event, I think that happened, has really turned that Houston Ship Channel Katy market into, you know, a wider market. That's what's affecting us really, 'cause we're protected against the other ones for the most part. Okay, that's helpful. Just on the dividends, you know, it looks like it's a decent size commitment, you know, from you folks here. You know, rough math, almost $140 million a year. Is that something that, you know, if you did see some weakness in gas for a couple quarters next year, would you guys be willing to borrow in the short term to kind of pay the dividend or would that be a time where you might drop a rig or something? Well, I think that we've set that dividend level where, you know, we just don't see, without just like absolute complete collapse in prices, that we can't support that without borrowing. You know, so it's a very conservative dividend. That's why we set it. It's actually the exact same dividend we had in 2014, so it's a little nostalgic for us. You know, so we think it's the right conservative level and, you know, I don't think that we foresee, you know, any real probability that, you know, that we couldn't maintain that without borrowing. I mean, I think that, you know, to the extent that gas prices or prices were that low, we'd see pretty significant reductions in our capital budget, either from us dropping activity because it didn't make sense or because, you know, service costs would retreat to the low levels that they were back when prices were low in 2020. You know, we think they're a natural, you know, a lot of costs will track prices and, you know, they'll also contract when prices, you know, go the other way. Yeah, taking that into account, we just don't see that scenario that you mentioned, you know, being that possible. Yeah. In fact, The Board asked that, you know, we run a model at, you know, a $2.53 gas, a $3 gas, and, you know, you don't cut back your CapEx budget, which we would cut back that budget. In any and all those runs that we looked at, you know, we didn't ever foresee us using the bank credit facility for dividend payments at all. Okay. Thanks, guys. Appreciate it. Thank you, Leo. I'm showing no further questions in the queue. I'd like to turn the call back to Mr. Jay Allison for any closing remarks. Sure. Again, it's been a wonderful hour. You know, it's the quarter's been great. I look at that, natural gas prices are solid, our production's solid, our drilling locations are solid. We've never had poor locations. The Western Haynesville, as Dan has mentioned, I mean, it's been performing like clockwork, so we're very positive on that. We're just gonna continue to protect our liquidity and deliver on the news so that we project we'll have in the future. Things are good. Natural gas is needed. Thank you for your time. This concludes today's conference call. Thank you for participating. You may now disconnect.