Comstock Resources Inc (CRK) 2022 Q3 法說會逐字稿

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 will need to press star #11 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. 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 and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and 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, 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 with leverage down to 0.9x and the quarterly dividend is now possible. 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 your equity stakeholders who trust us with their hard-earned money and especially the Jerry Jones family. We say thank you to our banks that provide us with the 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 Haynesville and Bossier wells. Now 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 cubic feet of gas per day. We've also drilled our second well in this region, which is near the Circle M called the Cazey 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 Cazey Black well. The Comstock team of 240 [employees who](added by company after the call) worked hard to produce Tier 1 results, which I'll share with you starting on Slide 3.

We cover the highlights of the third quarter on Slide 3. 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 0.9x. 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 for 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 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 $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 Burns to comment on our financial results. Roland?

Thanks, Jay. On Slide 4, 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, 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 $1 from the third quarter of 2021. We reported adjusted net income of $326 million for the third quarter. That's more than 2.5x 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. 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. So during this 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 $0.42 differential. That was a little higher than normal due to wider regional differentials and due to most significantly due to a 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 6, we detail our operating cost per MCFE and our EBITDAX margin. Our operating cost per 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 costs 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 7, we recap the first nine months of this year and what we spent on our drilling and other development activity. In the first 9 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 in 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 (inaudible) net operated horizontal Haynesville 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 2 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 in 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 0.9x in the quarter on an annualized basis as compared to the 2.3x 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.

Okay. Thanks, Roland. Over on Slide 9. 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 9 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 drilling completed to date still stands at 15,291 feet. By year-end, we anticipate turning 64 gross wells to sales with an average lateral of 10,100 feet.

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 feet. So 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 costs. Our drilling costs for the quarter was $597 [per foot](corrected by company after the call). This is a 25% increase quarter-to-quarter, while our completion cost for the quarter was $800 per 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 if we have seen it affect all services across the space. And as witnessed by our completion costs for the quarter, we've been partially protected by the high inflation cost 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 a 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 3 most recent 15,000-foot completions. These 15,000 wells tested at rates of 30 million to 32 million cubic feet a day, and the average length of these was 15,075 feet. The group also includes the first 3 wells we've drilled and completed on our Nacocdoches, Texas acreage since we restarted our Haynesville drilling program back in 2015. The initial test rates for these 3 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 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. And just a comment before I'll start on the final presentation. The Nacogdoches acreage was a Tier 3 set of acreage that we had initially. And you can see from what Dan has reported the IP rates and those lateral lengths sits now become closer to Tier 1 area. So we'll have increased our inventory of Tier 1 as we move from these rigs over to the Nacogdoches acreage.

I'll direct you to Slide 12, where we summarize our outlook for the rest of the year. 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, 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. 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 will use those rigs to de-risk and delineate the play. We did budget about $65 million to $75 million for bolt-on acquisitions and leasing activities for the year, which includes the $54 million already spent in the first 9 months of the year. Now that we've exceeded our leverage goals, we are 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 will be paid on December 15. And lastly, 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.

Thanks, Jay. On Slide 13 we provide financial guidance for 2022. Our fourth quarter production guidance is 1.42-1.52 Bcfe/d 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. Our 2022 development capex guidance is $925 million 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 million to $75 million, including the %54 million already spend on both bolt-on and leasing activities. Our lease operating costs are expected to average $0.18-$0.23 in the fourth quarter. Our production taxes are expected to average $0.20 to $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 to $1.05 in the fourth quarter. Our cash G&A expected to average or would be $7 million to $9 million, of which approximately $2 million will be non-cast. Our cash interest expense is expected to total $38-$40 million in the fourth quarter and $158 million to $162 million for the year. 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.

Thank you. As a reminder, to ask a question, you'll need to press star 11 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.

Good morning all, 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?

Yes, Derrick, this is Dan. So as 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 we frac'd the Cazey Black well in the vicinity. We started that frac back around October 1. So we had the well shut in just 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 yes, 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. And we don't see anything really on the horizon of what any of these future wells are going to be anything less than the Circle M.

That's terrific. And as my follow-up, I wanted to ask a gas egress question based on the broader weakness in Perryville and Houston Ship Channel, really more of 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 Haynesville production grow over the next year in your view? And how much excess takeaway do you own over current production levels?

We -- if you look at our program, we [recently](corrected by company after the call) added the 2 extra rigs to go to 9. And we did that several months ago, we broadcasted maybe 6 months ago that we might be doing that. When we forecast our production growth, particularly with the Western Haynesville in our core area, which is 7 rigs will be in the core area. We always project pipeline and takeaway. I mean, we look to see if we're going to 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 if you plan ahead, 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 comes into play now is our expansive acreage footprint. -- it's not like we're in 1 or 2 counties in Texas or 6 or 7 parishes in Louisiana, we're in all of the above. So if you go back, Derrick, and you've looked at how we spread our program out 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. 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.

Yes. And Derrick, this is Roland. Just to add a couple of comments to that. We recently added about 300 million a day of additional take away to our transportation portfolio as we continue to look ahead and to see where our needs are. And there are a lot of -- there were brownfield projects and greenfield projects, both in the Haynesville, especially redirecting gas to the Gulf Coast markets. And so we continue to evaluate those, take out parts of those. We'd like to have -- just like we have a diverse acreage position, we like to have a diverse transportation portfolio. So we have options to move our gas around and to drill in areas that have the most takeaway. So -- and we -- I think your other question was -- and we do have about 200 million a day of spare capacity that we actually are actually buying and reselling third-party gas that we plan to use up just in next year's drilling program. So we think we're pretty well positioned, but we'll continue to front-run that. As the Haynesville production grows and as the demand grows in the Gulf Coast being able to get the gas down to those users.

And Derrick, as Roland said, we have added more firm transportation because we think if you have interruptible, you'd probably be interrupted. So we've added more firm.

That's terrific... So guys are well positioned...

Thank you. And we have a question from Charles Meade with Johnson Rice, Your line is opened.

Good morning Jay, You and your team.

Hello Charles

Jay, I wanted to ask a question about those Nacogdoches well results. And obviously, you put this in the presentation, those are stout rates, particularly in light of the 7700-7800-foot lateral lengths. And I'm curious, it sounds like in your prepared remarks, it sounded 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 it maybe something that you've learned from the Western Haynesville that you're bringing back this way? Just tell me what's going on there?

So yes, 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 wanted to so this is his chance.

Well, Charles, the -- we hadn't drilled any wells down there since 2015. That -- when we -- back when gas prices were low, that was just kind of one of the areas that we did not look at spending our capital because we looked at the wells that have been drilled. And they just didn't -- they didn't really compete when you looked at the other areas we're drilling and where we needed to maximize our performance. So we do have, I think, about 35,000 net acres down there. So gas prices improved. We -- basically, 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 the results are good. So we drilled 2 Haynesville in 1 Bossier. It was a 3-well pad. The footprint we had just allowed us to drill a 7,500-foot lateral. We could have drilled them a little bit longer. If we had the footprint was there. But the bottom hole pressure is a little higher. That's a little bit deeper down there. It's about 14,000 foot TVD. So we put the bigger vintage, newer frac job on it like we've been doing everywhere else, and the performance looks really good. Now we need to let them produce out for a while, obviously, and confirm that what the EUR is going to look like. But out of the gate, they look really good.

Right. It looks like you probably have 3 months of data on that productions. So that will be interesting to follow that. And my second question is on the -- 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.

No, Charles, this is really just a one-time thing. We had 3 full-time frac crews. We took our lower-performing frac crew, and we had the opportunity to upgrade 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 3-well pads that was going to turn to sales in December, and it pushed it into January. It pulled up a couple of other pads. There were some dates that shuffled around, but that's basically what caused that.

Got it.

Yes, 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...

Yes. And Charles, it has nothing to do with well performance or inventory.

I think that's all...

Yes. I think we'll see a pickup next year with the efficiencies on the other frac crew we picked up. I think it's going to help us pull forward turn to call dates that we had next year. So that will 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 your time. I was wondering if you could talk a little bit about your activity levels in 2023 and how you would flex activity with perceived oversupply in the natural gas market next year?

Well, we really haven't set our '23 budget yet. And yes, that's something we evaluate as we get -- as we kind of get towards the end of the year here. But I think, yes, 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 what I think is one of our big initiatives at Comstock is to really start to build up long-term supply contracts where we're going to -- 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 have and not rely on the day-to-day market or the clearing market, but more -- have a much better outlook on -- like we know our customers want this gas and supply them on a long-term basis.

Makes sense. And I know you're focusing on trying to prove up that Western Haynesville acreage. So is there like any price point where that 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 delineation wells, and we've got the rigs that we need to drill the Western Haynesville. We've got them scheduled with pad sites -- we have take-away for all those wells that are planned in 2023. And we have completion crews, as Dan had mentioned, in place to handle a 9-rig program with 7 rigs in the core area and to delineating the Western Haynesville. As Roland said, I mean, we're now 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 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. 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 1,600-plus locations, the very high margins, low cost we have predictability we had and again, is just lack of leverage. So I think we have all the earmarks for LNG exposure when it appears and we're ready for it.

thank you, We have a question from Neal Dingmann with Truist. Your line is open.

My first question is on well cost, specifically, I think, expected cost per foot. Looking here, it looks like your presentation suggests that 3Q22 costs per foot are up about 45% year-over-year. And I'm just wondering on, is that -- am I correct in that 45%? And then secondly, maybe more importantly, I know you don't have 2023 guidance out yet, but how you're thinking about 2023 on a cost per foot given inflation pressures, I think everybody is experiencing, but also, obviously, the nice longer laterals and other things you all are doing.

Yes. No, this is Dan. 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 -- we're still seeing the inflation numbers move on up a little bit. We've been -- 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. And I think when we get that second fleet next year, 2 out of our 3 fleets are running on gas and with the horsepower locked in for the long haul, we're going to be in good shape there. The drilling side, I think, was where we're going to see, obviously, the costs are going to continue to move up as long as the demand is there. We're seeing it just across all services. I mean, obviously, we've seen the rigs. We've seen it in, obviously, the diesel. We use a lot of diesel in oil-based mud, cementing, directional tools. I mean it's just really kind of across the board. And that's where we're going to be battling those costs. The longer laterals are helping tremendously. 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 that's going to help us there.

Have you locked in some of those or the 9 rigs if you like to have longer-term contracts, so many of those.

So 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. And then maybe Dan this is my second question on pretty general in broad strokes. I am just wondering, when you turn more to, you mentioned turning more towards wells in Texas next year versus a lot of the nice Louisiana wells you have done this year. Any just early thoughts on well returns you think they'll be pretty comparable as you start drilling and completing some of those?

I think they're going to be pretty comparable. I mean the better higher profile wells are on the Louisiana side. I mean, that's why 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 maybe it could be just slightly less, but I think it's pretty comparable overall when you package the lower D&C costs compared to the Louisiana wells. And then 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 read any issues there.

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 [reinstated](corrected by company after the call) your quarterly dividend. As we look to 2023, I would love your thoughts around 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 Haynesville area?

That's a good question. And yes, we're going to be very conservative on promising what we do with the free cash flow. So as we kind of 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 Haynesville and in the base Haynesville. And then 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 that we have now in the futures market. And so we'll be conservative on promising -- what the level of dividend is and then what other forms of return of capital we may want to employ. But again, 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 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 for the dividend and what we expect to generate...

Even proving up our conservative nature is that we broadcasted 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 free cash flow. We'll be very conservative with it.

Great. That's very helpful color. And then I guess on the next question, like you said, the macro environment has been very volatile. You have seen gas prices really trade off recently. I was wondering how you're thinking about your hedging strategy as you think towards next year. I noticed that you didn't add any hedges this quarter.

We know on the gas price. I mean gas went from $9.85 to $6.30 or whatever it is. So 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 foot went up. So when we look at that, we say, if we do have a fortress in 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 that we may look at hedging through a little different glasses. Our 20/20 vision may be different than others. We feel like once we get into 2023 at this point in time, as of today, we're probably properly hedged with half of our production hedged at a $3 floor of almost $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 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 50% hedged 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.

Thank you so much.

Yes sir, Thank you.

We have a question from Phillips Johnston from Capital One. Your line is open.

Hey guys, Thank you. Maybe just a 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 slowly marching higher over time? Or would the first priority sort of be to look to other forms of returns, whether it's variables, buybacks, et cetera?

That's a good question. I think definitely, we'll evaluate the level of the dividend. And to the extent that we see that 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 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 that most of the shareholder feedback we've got has not been very favorable on variable dividends. So I think we'd be looking at maybe additional debt reduction, just to continue to strengthen the balance sheet and then potential share repurchase program in the future when we think that makes sense.

Yes. Okay. And then I guess, just the decision to allocate a couple of 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. 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 rig relative to this year?

Yes, that's a great observation because to the extent that you reallocated those wells back to our traditional Haynesville, they would create a lot more capital because they would drill a lot more wells. So they would be more completion costs. So I think when we added those, we took that into account, that yes, the wells take longer to drill. So actually looking at the amount of capital per operated rig, they're going to keep that number lower. But now we're very dedicated to continuing to delineate that play. But yes, the play will tell us what's needed. We'll proceed based on results. And 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 that's -- we don't want to push the play too hard because we want to learn from each well. Each well, I think we continue to improve the drilling and completion design, made changes to things as we're learning about this play. But 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.

Yes. 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 2 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 costs have come down. So we're pretty confident we'll see that in the near future.

You know Philip, we've spud and even set some pipe even on our third well, the Campbell well. So we've got one that's been producing the Circle M. We've got one that we expect to turn to sales this month. And then we've started drilling a third well to 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 that will be in February.

Sounds good, guys. Appreciate it.

Thank you...

We have a question from Paul Diamond with Citi. Your line is open.

Hey Good morning, thank you for taking my call. First one, I wanted to jump into 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 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. And then -- but I think over the next 6 months or so, I think that's kind of when you could maybe expect us to kind of come back and provide more color on kind of where we see our long-term markets.

Understood. Thank you and just a quick follow-up. You guys have kind of laid out a 9-rig plan, 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 12 to 18 months?

Yes. So 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 that are built up for a couple of years, but we moved projects around as needed if something arises, but 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. And we'll have a second rig in the Western Haynesville, 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, 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.

One, as we commented earlier, we don't have any long-term rig contracts. So 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 2, you can see we're pretty nimble to do that, too. So we're in the fairway of the 9 rigs since we budgeted, and we haven't given any guidance for 2023 as of today.

understood, thanks you.

thank you...

Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.

Hi good morning,

hello...

Just a couple of 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 lease dollars? Is this expired leases, never leased acreage? Just wondering kind of what's still out there to buy.

All the above, I guess. Again, that includes our acquisition that we made. So it's a combination of maybe we acquired held by production properties that have the deep rights still available, hadn't been developed. That's actually some of the chunkier parts of that and then new primary leases. So it's just all the above. We have -- we've really grown our land department this year and to focus on exploiting these opportunities that we see in the Haynesville. So we've added a lot of personnel have a lot of activity going on at the ground floor.

Yes.

ohh,

We had the acreage. If we can extend the lateral length of these wells, we still have dollars budget for that. If we can pick up any deeper rights like Roland said under PDP that we think that is in a fairway of where we have 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 when you're looking at the analyst reports, we're not budgeting for big M&A activity. That's the whole key.

Right. Right. Thanks. And talking about just as to liquidity you have and the free cash flow you'll be generating. I guess I was wondering about a couple of areas, just wondering if 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 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 consciously deciding to build up DUC inventory like give you more ability to be opportunistic about when you bring things on.

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. And so we typically trade interests with adjacent operators. So we can each have our own operated projects to extent that we see there's a very active market for participants. They like to buy non-operated interest in the Haynesville. 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 because we want to make sure that we protect our very low cost structure and our very good margins. And we feel like they're the best in the industry. So most of the other projects that we see from other operators have inferior returns in that area, although the gas prices have been high. So it's not like those aren't very profitable projects. We just want to 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 an 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 Roland said, we have accounts daily come in that would like to buy all the non-op interests. 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 get the budget numbers to try to use those dollars the best we can to create the grades return we can with our own operations group. So we're pretty selfish on that front.

Yes. And on the question about DUCs, I mean, I think that we just don't like to put that kind of investment in wells and have wells that are drilled because we don't think it's the right way to manage the business. So from the -- both from the landowner standpoint as far as drilling the well and not putting it on production, I just think that's something that we ever look at as a good strategy. And so we've never 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 and our last question comes from Leo Mariani with MKM Partners. 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?

Well, it's a seasonal issue, too, because this time of year is just -- it's the last 3 years in a row, October and part of November is always wider. It's kind of the shoulder mind, the transition from the injection into withdrawal. And it's always sloppy and so that's nothing new. I think what's newer in this quarter is not so much -- we managed the Perryville and Carthage differentials very well with our Gulf Access. I think what's different this quarter is that the Texas Gulf markets, which have been premium markets, 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 using it for LNG. So that event, I think, since that happened has really turned that Houston Ship Channel Katy market into a wider market, and that's what's affecting us really because we're protected against the other ones for the most part.

Okay. That's helpful. And then just on the dividend, it looks like it's a decent sized commitment from you folks here, (inaudible), almost $140 million year. Is that something that you did see some weakness in gas for a couple of quarters next year, would you guys be willing to borrow in the short term to pay the dividend? Or would that be a time where you might drop away or something?

Well, I think that we've set that dividend level where we just don't see without just an absolute complete collapse in prices that we can't support that without borrowing. So it's a very conservative dividend. So 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. But so we think it's the right conservative level, and I don't think that we foresee any real probability that we could maintain that without borrowing. I mean I think that to the extent that gas 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 service cost would retreat to the low levels that they were back when prices were lower in 2020. So we think they are natural -- a lot of costs will track prices and they'll also contract when prices go the other way. So we think given -- taking that account, we just don't see that scenario that you mentioned being that possible.

Yes. In fact, the board asked that we run a model at $2.50-$3.00 gas. At $3 gas, and you don't cut back your CapEx budget, which we would cut back that budget. In all those runs that we looked at, we didn't ever see 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. The quarter has been great. I look at natural gas prices are solid. Our production is solid. Our drilling locations are solid. We never had more locations. The Western Haynesville, as Dan has mentioned, has 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 will have in the future. So things for good. Natural gas is needed. So thank you for your time.

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