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spk13: 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 will be a question and answer session. To ask a question during this session, you'll need to press star 1-1 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.
spk10: 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 Investment Relations. Please refer to slide two 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 three, you know, I'd like to announce to you that Comstock Resources just posted the greatest quarterly results in our 30-plus 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 leveraged down to 0.9 times, 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 oilfield service companies who assist us in promoting excellence in drilling and completing our Hainesville and Bossier wells. Now, many of you have asked about our Western Hainesville 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 cubic feet of gas per day. We've also drilled our second well in this region, which is near the Circle M, called the KZ Black, which was successfully drilled and completed that is expected to be turned to cells this month. Note that the Circle M well was shut in for 30 days while we were completing the KC Blackwell. The Comstock team of 240 worked hard to produce Tier 1 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 for 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 times. Our adjusted net income for the quarter was $326 million, or $1.18 for 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 Hainesville Shell Drilling Program is going well, as demonstrated by the 17 or 15.2 net operated wells that were reported on this quarter with an average initial production rate of 29 million cubic feet per day. I'm excited to announce the reinstatement of a quarterly dividend to common stakeholders. Our Board of Directors approved a quarterly dividend of 12.5 cents per share to be paid to our common shareholders on December the 15th, representing a yield of approximately 2.5% at our current stock price. I'll now turn the call over to Roland Barnes to comment on our financial results. Roland?
spk16: Thanks, Jay. We recap the very strong third quarter financial results we achieved. Pro forma for the sale of our Balkan 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, a 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 a dollar from the third quarter of 2021. We reported adjusted net income of $326 million for the third quarter, That's more than two and a half times higher than the third quarter of 2021. And our earnings per share came in at $1.18 as compared to 35 cents 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. And the growth in EBITDAX and the retirement of $250 million of debt in the quarter drove our leverage ratio down to 101 times as compared to 2.3 times in the third quarter of 2021. Improved natural gas prices were the primary factor driving the strong financial results in the quarter. On slot five, 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. So 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. So 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 42-cent differential. That was a little higher than normal due to wider regional differentials and most significantly due to 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 Hainesville 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 costs per MCFE and our EBITDAX margin. Our operating costs per MCFE averaged 82 cents in the third quarter, eight cents higher than the second quarter. Our gathering costs increased by five cents. That's primarily due to the impact of higher fuel costs used in the transportation of our gas, but also due to higher production from some of our higher gathering rate areas. Our lifting costs increased two cents and our production taxes increased one cent 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 six cents, 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 Hainesville 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 frac protection, and other workovers. In the first nine months of this year, we drilled 52 or 42.5 net operated horizontal Hainesville wells, and then we turned 53 or 44.2 net operated wells to sales. These wells had an average initial production rate of 27 million cubic feet 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 Hainesville and Bossier Shale drilling program. We also spent $4 million on non-operated wells and $11 million on other development activity. On slide eight, 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 times in the quarter on an annualized basis as compared to the 2.3 times 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. So 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.
spk09: Okay, thanks, Roland. Over on slide nine, so this is an update on our average lateral lengths we drilled since 2017. So the year-to-date average lateral length has increased slightly up to 9,797 feet. This is based on the 53 wells that we've turned to sales so far this year. So this currently puts us over 1,000 foot 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 feet. Year to date, we've drilled 17 of our extra long lateral wells. That's our wells with laterals greater than 11,000 feet. Included in this group, we've had nine wells with laterals greater than 14,000 feet. And 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 feet. By year end, we anticipate turning 64 gross wells to cells with an average lateral of 10,100 feet. On slide 10 is the latest DNC cost trend through the third quarter. This is for the benchmark long lateral wells with laterals longer than 8,000 feet. So this quarter, 10 of our 17 wells turned to cells were in this benchmark long lateral group. The DNC 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 four-year DNC cost. Our drilling cost for the quarter was 597 feet. 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. 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 of horsepower and also drastically cutting our diesel usage. As we mentioned before in 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. So 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 cubic feet a day with an average test rate of 29 million cubic feet a day. The wells were drilled with lateral lengths ranging from 5,328 feet up to 15,210 feet long. The average lateral was 9,899 feet. Included in this group were our three most recent 15,000 foot completions. These 15K wells tested at rates of 30 to 32 million cubic feet a day and the average length of these was 15,075 feet. The group also includes the first three wells we've drilled and completed on our Nacogdoches, Texas acreage since we restarted our Hainesville 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 cubic feet a day with laterals averaging 7,477 feet. 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 two additional rigs early in the third quarter. We're now running a total of nine drilling rigs and three full-time frack 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.
spk10: All right, Dan. And just a comment before I start the final presentation. The NAC acreage was a Tier 3 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 Tier 1 area. So, we'll have increased our inventory of Tier 1 as we move some of these rigs over to the NAC acreage. If you 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. And at the current commodity prices, a 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 nine rigs operating in our Hainesville drilling program. The two recently added rigs are expected to be active on our western Hainesville 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 to delineate the play. We did budget about $65 to $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, we are starting a return to capital program in the fourth quarter. Our board of directors, as I said earlier, is authorized reinstating our quarterly common stock dividend. The fourth quarter dividend is 12.5 cents a share and will be paid on December the 15th. And 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. So with that, let me turn it over to Ron. You can give some specific guidance for the rest of the year.
spk06: Thanks, Shea. 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 to 1.52 BCFE per day, and the full year guidance remains unchanged at the prior level of 1.39 to 1.45 BCFE per day. During the fourth quarter, we plan to turn to sales 8 to 10 net wells, and we now anticipate our 2022 full year production guidance to be biased towards 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 one to two less net wells this year than when we last provided guidance in August. The 2022 development CapEx guidance remains $925 to $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 to $75 million, including both photon and leasing activities, of which $54 million has already been spent this year. Our LOE costs are now expected to average 18 to 23 cents in the the fourth quarter in 19 to 24 cents for the full year, while our gathering and transportation costs are expected to average 28 to 32 cents both in the fourth quarter and for the full year. Production ad valorem taxes are expected to average 20 to 24 cents 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 to $1.05 in the fourth quarter. Our cash G&A expected to average or be $7 to $9 million this quarter in total $29 to $32 million for the full year. And the non-cash compensation portion of that is approximately $2 million this quarter. Cash interest expense is now expected to total $38 to $40 million during the quarter. which would bring the full year of cash interest up to about $158 to $162 million. Our effective tax rate is still expected to remain in the 22 to 25% range, and we continue to expect to defer 75 to 80% of our taxes. We'll now turn the call back over to the operator to answer questions from analysts. Catherine. We can turn it over to Q&A.
spk13: Thank you. As a reminder, to ask a question, you'll need to press star 11 on your telephone.
spk15: Please stand by while we compile the Q&A roster. Our first question comes from Derek Whitfield from Stiefel.
spk13: Your line is open.
spk07: Thanks, and good morning, all. Morning, Derek. With my first question, I wanted to focus on the Circle M result and early indications on your second Bossier Well and Western Hain tool. 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?
spk09: Yeah, Derek, this is Dan. Jay mentioned the well has been producing flat at $30 million a day. since we put it on in April. We did shut it in when the Casey Black was in the vicinity. We started that frack back on around October the 1st. So we had the well shut in 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. But 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 of why any of these future wells are going to be anything less than the Circle M. That's terrific.
spk07: 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 that recent weakness has been driven by pipeline outages in Freeport, I wanted to ask if you could share your macro views at really the basin level, and more specifically, to what degree can the Hainesville production grow over the next year in your view, and how much excess takeaway do you own over current production levels?
spk10: If you look at our program, we intentionally added the two extra rigs to go to nine, and we did that several months ago. We broadcasted maybe six months ago that we might be doing that. When we forecast our production growth, particularly with the Western Hainesville in our core area, which seven rigs would be on that core area, we always project a pipeline and takeaway. 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. 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. So even though we think that the takeaway is extremely tight, it may be 90, 95% full. I think that if you plan ahead, You know, you're not going to run into some of the problems that some of the smaller companies have. But 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. So if you go back, Derek, 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 a takeaway issue maybe. But because we do have that 400,000 plus acres and growing, we've got a lot of room to avoid some of the pipeline takeaway issues.
spk16: Yeah, and Derek, this is Roland, just to add a couple of comments to that. We recently added about 300 million a day of additional takeaway to our transportation portfolio. Um, you know, as we continue to, you know, look ahead and just see where our needs are and yeah, there are a lot of, uh, there were brownfield projects, greenfield projects, both, you know, in the Hainesville, especially redirecting gas to the Gulf coast markets, you know, and so, you know, we continue to evaluate those take out parts of those. We'd like, we'd like to have, just like we have a diverse acreage position. We'd like to have a diverse transportation portfolio. So we have options, you know, to move our gas around and to drill, you know, in areas that have the most takeaway. So I think your other question was, and 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. So we think we're pretty well positioned, but we'll continue to front run that, you know, as the Hainesville production grows and as the demand grows in the Gulf Coast and, you know, being able to get the gas down to those users.
spk10: And Derek, as Roland said, we have added more farm transportation because we think if you have interruptible, you'll probably be interrupted. So we've added more farms.
spk07: That's terrific. Sounds like you guys are well positioned.
spk14: Thank you.
spk13: Thank you. And we have a question from Charles Mead with Johnson Rice. Your line is open.
spk11: Good morning, Jay. To you and your team.
spk10: Hello, Charles.
spk11: Jay, I wanted to ask a question about those Naganocha's well results. Obviously, you put this in presentation. Those are stout rates, particularly in light of the 7,700, 7,800-foot lateral lengths. And I'm curious. It sounds like in your prepared remarks, it sounds like that was an uptick versus your internal expectations previously. So I wonder if you could talk a bit about that. Is there a different completion design? Are you targeting a different zone? Is there maybe something that you've learned from the –
spk09: from the uh you know western haynesville that you're that you're bringing back this way just tell me what's going on there yeah so yeah charles i thought maybe i'd pull that question out of you if i commented on it after dan presented he didn't color it like i wanted to color it so this is his chance well so charles the uh you know we hadn't drilled any wells down there since 2015 that when we back when gas prices were low you know that was just kind of 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 we were drilling and where we needed to maximize, you know, our performance. So we do have, I think, about 35,000 net acres down there, so gas prices improved. We, you know, basically just We needed to move a rig down there and basically put a new vintage frack on those wells. There is other offset activity in the area that's showing that, you know, the results are good. So we drilled two Hanesels in one bozer. It was a three-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. But in the bottom hole, pressure's a little higher. That's a little bit deeper down there. It's about 14,000-foot TBD. So, you know, we put the bigger vintage, you know, newer frag job on it like we've been doing everywhere else. And, you know, 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 going to look like. But, man, out of the gate, they look really good.
spk11: Right, thank you. It looks like you probably have three months of data on those productions, so that'll be interesting to follow that. And my second question is on this 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 reappearing in 23?
spk09: No, Charles, this is really just a one-time thing. We had some of our three full-time frat crews. We took our lower-performing frat crew, and we had the opportunity to upgrade our and pulling another frac crew that we thought was going to be a lot better, have better performance. And we made a switch here just in the last few weeks. But what it did was it took one of our three-wheel paths that was going to turn to sales in December, and it pushed it into January. It pulled up a couple other paths. There were some dates that shuffled around, but that's basically what caused that. Got it. So really – 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 frack crew for another.
spk10: Yeah, and Charles, it has nothing to do with well performance or inventory.
spk09: We think actually next year, yeah, I think we'll see a pickup next year with the efficiencies on this other frack crew we picked up. I think it's going to help us pull forward, turn to sell dates that we had next year. So, you know, that'll help out.
spk11: Great. Thank you.
spk09: Thanks, Charles.
spk13: Our next question comes from Fernando Zavala with Pickering Energy Partners. Your line is open.
spk05: 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 perceived oversupply in the natural gas market next year?
spk16: Well, we really haven't set our 2023 budget yet. And, you know, that's something we evaluate, you know, as we get, as we kind of get toward the end of the year here. But I think, yeah, we'll definitely be looking at the strength of gas prices to determine our activity level. and looking at where we have takeaway. We don't drill wells that we don't think we have good markets for. So that's to come and we'll monitor that. 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 kind of how we're looking to position the company in the future to really not be relied on the day-to-day market or the clearing market, but have a much better outlook on, like we know our customers want this gas and supply them on a long-term basis.
spk05: Makes sense. I know you're focusing on trying to prove up that Western Hainesville acreage. Is there any price point where that would shift and maybe you would move one of those rigs back to your core Hainesville?
spk10: No, we don't see that happening at all. We see delineation wells and we've got the rigs that we need to drill the Western Hainesville We've got them scheduled with, you know, pad sites. We have takeaway for all those wells that are planned in 2023. And we have completion crews, as Dan had mentioned, in place, you know, to handle a non-rig program with seven rigs in the core area and two delineating the western Hainesville. You know, as Roland said, I mean, we're 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. So once the LNG demand of anywhere from 8 to 11 bees 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 might 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-plus locations, the very high margins, low costs we have, predictability we have, and, again, this lack of leverage. So I think we have all the earmarks for LNG exposure when it appears and we're ready for it.
spk14: Got it. That's helpful. Thanks for the time.
spk15: Thank you.
spk13: We have a question from Neil Dingman with Truist. Your line is open.
spk08: 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 22 cost per foot are up about 45% year over year. And I'm just wondering, one, is that, am I correct in that 45%? And then secondly, maybe more importantly, I know you don't have 23 guide out yet, but how you're thinking about 23 on a cost per foot given inflationary pressures like everybody's experiencing, but also obviously the nice longer laterals and other things you all are doing.
spk09: Yeah, no, that's a dance. So we definitely, I think you're pretty close on that percentage number. I mean, if you just compare it to where we're at 2021, which was really the low point. I mean, obviously we don't want to go back to that where the gas prices were, but 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 practically, we were really fortunate there. That has really kept us in check on the completion side. And I think when we get that second fleet next year at know two out of our three fleets running on gas and with the uh horsepower locked in for for the long haul we're gonna be in good shape there uh 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 uh you know we're seeing it just across all services i mean obviously we've seen it the rigs we've seen the uh you know we've seen it in obviously 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 kind of across the board. And that's, you know, that's where we're going to 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 going to help us there.
spk08: Have you locked in some of the nine rigs? Do you have longer-term contracts on any of those?
spk09: 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.
spk08: Okay. And then maybe, Dan, sticking with you, just my second question on Pretty general in broad strokes, just wondering, when you turn more towards, you mentioned turning more towards wells in Texas next year versus a lot of the nice Louisiana wells you've done this year, any just early thoughts on well returns you think will be pretty comparable as you start drilling and completing some of those?
spk09: I think they're going to be pretty comparable. The better, higher 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 DNC cost is lower in Texas. So I think, you know, maybe it could be, you know, just slightly less, but I think it's pretty comparable overall when you package the, you know, the lower DNC cost, you know, compared to the Louisiana wells. And, you know, then like Like we mentioned, we're looking at takeaway capacity. We can't concentrate a lot of activity in any one area. We're just kind of keeping everything spread out to make sure we don't create any issues there. Sure. Thanks, Dan, for the time.
spk14: Thank you.
spk15: Thank you. Our next question comes from Humane Country with Goldman Sachs.
spk13: Your line is open.
spk01: 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, I would love your thoughts on free cash flow allocation towards balance sheet reduction, any further form of capital returns which you're contemplating, and if there's any additional free cash flow which you're earmarking for the Western Hainesville area.
spk16: That's a good question. We're going to be very conservative on promising what we do with the free cash flow. As we approach and formalize our capital budget for next year, that's going to be the first step and understanding what we need to invest in the western Hainesville and the base Hainesville. And then, 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. And so, you know, we'll be conservative on, you know, promising, you know, you know, what the level of dividend is and then what other forms of return of capital we may want to employ. But, you know, again, yeah, the balance sheet definitely has always come first. So we're not going to, we've got this new fortress balance sheet with tremendous liquidity, seeing a much lower cost of capital. And we're not going to sacrifice that for anything. So that's going to 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. But there is, 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.
spk10: Well, I'd even prove up our conservative natures 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 initiate the dividend. So those actions tell you what we're going to try to do with the pre-cash flow. We'll be very conservative with it.
spk01: Great. That's very helpful, Kala. And then 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 think towards next year. Notice that you didn't add any hedges this quarter.
spk10: 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. And I'm looking over here at Dan's cost per foot. and the price of natural gas went up a whole lot, a greater percentage than the cost per foot went up. So 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 and billions and 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 little different glasses Our 2020 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, you know, hedged at a $3 floor, almost a $10 ceiling. I think as we get into the December, see what the winter looks like, see what the storage really looks like. and see what happens across the oceans as far as the need for this gas and see where prices end up. And we'll always look at that because we typically have a percent hedge all the time. But I think our liquidity and our free cash flow numbers will drive that answer a little differently than it has in the past.
spk01: That's great, Claude.
spk14: Thank you. Thank you so much. Yes, sir. Thank you.
spk15: Thank you.
spk13: We have a question from Philip Johnston from Capital One. Your line is open.
spk02: Hey, guys. Thank you. Maybe just to follow up on the return of capital question, you mentioned the 50-cent 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?
spk16: That's a good question. I think definitely, you know, we'll evaluate the level of the dividend and the extent that, you know, we see the production base is larger and then that dividend is higher. very sustainable at a higher rate. I think that's something that will be the first thing to look at each quarter as we progress. And I think we would look at other potential return of capital strategies such as buybacks. I don't think that a variable dividend is something that we think is something that we want to commit to given the Most of the shareholder feedback we've got has not been very favorable, unbearable dividends. So 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.
spk02: Yeah, okay. And then I guess just the decision to allocate a couple of rigs to the Western Angels next year. I think those wells take a little bit longer to drill than the wells in your traditional area of development. So 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?
spk16: Yeah, that's a great observation because the extent that you reallocated those wells back to the, you know, our our traditional Haynesville, they would create a lot more capital because they would drill a lot more wells, so there would be more completion costs. So I think when we added those, we took that into account that, yeah, the wells take longer to drill. So looking at the amount of capital per operated rig, they're actually going to keep that number lower. But now we're very dedicated to continuing to donate that play. But the other play will tell us what's needed. We'll proceed based on results. And so, so far, the results have been excellent. And so if we continue to have excellent results, we'll continue to put in the resources. And so we don't want to push the play too hard because we want to learn from each well. Each well, I think we've We continue to improve the drilling and completion design, made changes to things as we're learning about this play. Again, we're going to let the results tell us what's needed, and we're going to be patient and not push it too hard, but we're very excited about delineating the play.
spk09: 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, we're going to see the cost. And I think the drill times and all that are going to speed up and the cost will come down. So we're pretty confident we'll see that in the near future.
spk10: You know, Phillip, we're budding. We've set some pipe even on our third well, the Gamble well. So we've got one that's been producing, the Circle M. We've got one that we expect to turn to cells this month and then we started drilling a third well, the Campbell. So as Dan has commented on drilling results, I think we've learned from all of these wells. And quite frankly, I think we're getting better on all of them. Hopefully we can report on the Campbell at the next call. We'll see what happens. It'll be in February.
spk14: Sounds good, guys. Appreciate it. Thank you.
spk13: We have a question from Paul Diamond with Citi. Your line is open.
spk12: 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?
spk16: I think that's more of a long-term strategy. I mean, I think that is the The shift, I mean, there are a lot of opportunities out there that we've been approached with, and we don't want to 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 locking up longer-term customers. I mean, we definitely have done some of those already, but I think over the next six months, I think that's when you could maybe expect us to come back and provide more color on where we see our long-term markets.
spk12: Understood. Thank you. Just a quick follow-up. You guys have laid out a nine-rig plan, seven in the core, and then some split between Harrison and Doshas. 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 12, 18 months?
spk09: Yes, our schedule, I'd say, 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 are built out for a couple of years, but we move projects around as needed if something arises, but we We've got the Nacogdoches acreage. It takes a little bit longer lead time in Texas to get wells drill ready, so probably middle to late next summer, a rig returning back on the Nacogdoches acreage. We'll have a second rig in the Western Hainesville, what we mentioned earlier, probably late this month or next month and in the next year or so. We definitely have the ability to move some things, you know, some stuff back over to Louisiana. But I would say to answer your question, really, it's fairly well fixed for the next 12 months with some minimal moving around.
spk10: Well, as we commented earlier, we don't have any long-term rig contracts. So, 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. So, we're in the fair way of the nine rigs as we budget and we haven't given any guidance for 2023, you know, as of today.
spk12: Understood. Thanks for the clarity.
spk14: Thank you.
spk15: Our next question comes from Noel Parks with Tuohy Brothers.
spk13: Your line is open.
spk04: Hi, good morning. I know. Just a couple things. In your leasing budget, I think it was about $54 million you've leased here today. Just curious what you're picking up with those leased dollars. Is this expired leases, never leased acreage? Just wondering kind of what's still out there to buy.
spk16: All of the above, I guess. Again, that includes maybe our our acquisition that we made, you know, so it's a combination of, you know, maybe we acquired hell by production, uh, properties that have the deep right still available, hadn't been developed. That's actually, you know, uh, you know, some of the chunkier parts of that and then, you know, new primary leases. Um, so it's, it's, it's all the above. We have a, we've really grown our land department this year and, and to focus on, you know, exploiting these opportunities that we see in the Hainesville. So, you know, we've, We've added a lot of personnel, have a lot of activity going on at the ground floor.
spk10: Yeah, no, we add to the sacred. 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 rots, like Roland said, it's HPP. We think this isn't a fair way of where we have a gathering. And we've looked at that aggressively too, particularly if we can extend the lateral lengths of some of the acreage we already own. But 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.
spk04: Right. Right. Thanks. And 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. And was that something you considered? be willing to pick up or something you want to try to get away from. And I'm 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 consciously deciding to build up a duct inventory to give you more ability to be opportunistic when you bring things on?
spk16: Those are some good questions. On the non-operated activity, I mean, 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, and 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 area. So we've sold some interest to them, especially where we see a lower return opportunity. We see a lower return project compared to other projects in our portfolio. So we're probably more of a seller of that non-op. We certainly aren't a buyer. We would never be interested in buying non-operated projects. We want to make sure that we protect our very low cost structure and our very good you know, margins, and, 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, have inferior in that area. Although, you know, gas prices have been high, so it's not like those aren't very profitable projects. We just want to protect our numbers.
spk10: Well, Anol, 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 AFPs coming in as a non-op. So the question is, do we participate in those? Maybe we participate because we want to find out what's going on in that area. Or again, like Robin 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. And we balance that with how much, 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 the greatest return we can with our own operations group. So we're pretty selfish on that front.
spk16: Yeah, and on the question about building up ducts, I think that we just don't like to put that kind of investment in wells that are drilled because we don't think it's the right way to manage the business. So You know, from the, both from 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. And so we've never, you know, done that on purpose. Every now and then you have a few ducks that get created because of some issue, but it's rare. Great.
spk14: Thanks a lot. Thank you, Noel.
spk15: Thank you.
spk13: And our last question comes from Leo Mariani with MKM Partners. Your line is open.
spk03: I wanted to follow up a little bit on the recent basis issues that you've been experiencing. I mean, it certainly looks like the Haynesville as a basin is kind of continuing to grow in the next couple of years. Do you guys foresee this could become a larger issue in 2023? And I guess, do you have any maybe strategies to mitigate that if it does?
spk16: Well, Leo, it's a seasonal issue too because this time of year is just – it lasts three years in a row. October and part of November is always wider. It's kind of the shoulder month, the transition from the injection into withdrawal. It's always sloppy, so that's nothing new. I think what's newer in this quarter is not so much, you know, we manage the Perryville-Carthage basis differences very well with our Gulf access. I think 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 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 KD market into a water market. And that's what's affecting us, really, because we're protected against the other ones for the most part.
spk03: Okay, that's helpful. And then just on the dividend, you know, it looks like it's a decent-sized commitment, you know, from you folks here. You know, rough math, almost $140 million bucks you know, 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 rate or something?
spk16: Well, I think that we've set that dividend level where, you know, we just don't see without just an absolute complete collapse in prices that we can't support that without borrowing. You know, so it's a very conservative dividend. It's a And so that's why we said it's actually the exact same dividend we had in 2014. So it's a little nostalgic for us. But, 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 could maintain that without borrowing. I mean, I think that our, you know, looking at, 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. So, you know, we think they're a natural, you know, a lot of costs will track prices and they'll also contract when prices, you know, go the other way. So we think, taking that account, we just don't see that scenario that you mentioned, you know, being that possible.
spk10: Yeah, in fact, the board asked that, you know, we run a model that, you know, a $253 gas, a $3 gas, and, you know, you don't cut back your CapEx budget, which we would cut back that budget. And in any of all those runs that we looked at, you know, we didn't ever see us using the bank credit facility for dividend payments at all.
spk03: Okay. Thanks, guys. Appreciate it.
spk16: Thank you, Leo.
spk13: I'm showing no further questions. In the queue, I'd like to turn the call back to Mr. J. Allison for any closing remarks.
spk10: Sure. Again, it's been a wonderful hour. The quarter's been great. I look at the natural gas prices are solid. Our production's solid. Our drilling locations are solid. We've never had poor locations. The western Hainesville, as Dan has mentioned, I mean, it's been performing like clockwork, so we're very positive on that. And we're just going to continue to protect our liquidity and deliver on the news that we project we'll have in the future. So things are good. Natural gas is needed. So thank you for your time.
spk13: This concludes today's conference call thank you for participating you may now disconnect.
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