Comstock Resources, Inc. (NYSE:CRK) Q3 2022 Earnings Conference Call November 2, 2022 10:00 AM ET
Company Participants
Jay Allison – Chairman and Chief Executive Officer
Roland Burns – President and Chief Financial Officer
Daniel Harrison – Chief Operating Officer
Conference Call Participants
Derrick Whitfield – Stiefel
Charles Meade – Johnson Rice
Fernando Zavala – Pickering Energy Partners
Neal Dingmann – Truist Securities
Umang Choudhary – Goldman Sachs
Phillips Johnston – Capital One
Paul Diamond – Citi
Noel Parks – Tuohy Brothers
Leo Mariani – MKM Partners
Operator
Good day and thank you for standing by, welcome to Third Quarter 2022 Comstock Resources Earnings Conference Call. At this time, all participants are in a listen-only mode. After the speaker presentation, there will be a question-and-answer session. [Operator Instructions]. 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.
Jay Allison
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 of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.
If you’ll flip over to Slide 3, 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 and 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 were leveraged down to 0.9x and a 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 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 for 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 KC Block [ph], 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 KC Block well. The Comstock team of 240 work 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 this 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 after hedging for the quarter came in at $692 million, 76% higher than last year’s third quarter. Our Haynesville Shale drilling program is going well as demonstrated by the 17 or 15.2 net operated wells that 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 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 Burns to comment on our financial results. Roland?
Roland Burns
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 2021s pro forma third quarter to $598 million, driven mostly by stronger natural gas prices. The generated $533 million of cash flow during the quarter a 126% increase over 2021s 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. And the growth and EBITDAX and the retirement of $250 million of debt in the quarter drove our leverage ratio down to 101x 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 average $7.96. So during this — 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 average $7.72, which reflects a $0.42 differential that was a little higher than normal due to wider regional differentials and due to — and most significantly due to a weaker Houston ship channel prices, which are all due to the Freeport shut down. Houston ship channel, another Texas Gulf Coast indexes are usually some of our premium markets.
In the third quarter, we’re 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 billion 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 costs per Mcfe in our EBITDAX margin. Our operating costs 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 cost increase $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 cost 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 nine months we spent $729 million on development activities including $653 million on our operated Haynesville and Bossier shale drilling program. We also spent $23 million on non-operated wells and $54 million and 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 Haynesville operated.
Net operated horizontal Haynesville wells, and then we turn to 53 or 44.2 net operated wells for sales. These wells had an averaged initial production rate of 27 million cubic feet per day. We also had an additional two net non-operated wells that we turn to sales. In the third quarter, we spent $242 million on our development, and exploratory activities including $227 million on our operated Haynesville and Bossier Shale drilling program, we also spent $4 million on non-operated wells and $11 million on other development activity.
On Slide 8, we show our balance sheet at the end of the third quarter of this year, we had $100 million drawn under our revolving credit facility at the end of the third quarter. The reduction in our debt balance and the growth of EBITDAX drove our leverage ratio down to 0.9 times in the quarter on an annualized basis, as compared to the 2.3 times that we’re 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.
Daniel Harrison
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 laterals 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 at 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 was completed today still stands at 15,291 feet. By year-end, we anticipate drilling gross wells for sales with an average lateral of 10,100 feet.
On Slide 10, the latest D&C costs ran 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 current sales were in this benchmark long lateral group. The D&C costs average $1,405 a foot in the third quarter, which represents an 11% increase from the second quarter and the 35% increase from our average 2021 full-year D&C costs.
Our drilling costs for the quarter was 597 feet. This is a 25% increase quarter-to-quarter. While our completion costs 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 in 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 only completions after the deployment of our first natural gas powered frac fleet which is playing a significant role in keeping our costs down. Our locking in long-term, our cost of horsepower and also drastically cutting our diesel usage. As we mentioned before the last call was contracted for a second natural gas powered frac fleet and we did expect to take delivery sometime late in the first quarter of 2023.
Slide 11 is a summary of the new well activity from 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 today up to 40 million cubic feet today with an average test rate of 29 million cubic feet today.
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. And included in this group were our three most recent 15,000 foot completions. These 15K 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 included the first three wells was drilled and completed on our Nacogdoches Texas acreage since we restarted our Haynesville drilling program back in 2015. The initial test rates for these three wells exceeded our expectations with IP rates ranging from 33 million a day, up to 40 million cubic feet a day with laterals averaging 7,477 feet.
Based on the initial results on Nacogdoches acreages, we do plan that activity there later next year. And we also will continue to pursue drilling the longer laterals because 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 for exploration.
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.
Jay Allison
Thanks Dan, and just to comment for us as a final presentation, the Naci acreage was a Tier 3 set of acreage that we had initially and you can see from what Dan had to report the rates and those lateral lengths, it’s now become 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. We’re on pace to generate significantly more than our targeted $500 million free cash flow. We’ve already exceeded that at the end of the third quarter net current commodity prices of free cash flow could reach somewhere around $800 million.
Of course, the first priority is 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 nine rigs operating in our Haynesville drilling program. The two recently added rigs are expected to be active on our Western Haynesville acreage position in 2023. We should move a second rig in this area probably late November, early December, we’ll use those rigs to de-risk and delineate the play. We did budget about $65 million to $75 million for bolt-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, we’re starting return to capital program in the fourth quarter. Our Board of Directors as I said earlier is authorized for reinstating our quarterly common stock dividend.
The fourth quarter dividend is [indiscernible] a share and will be paid on December the 15th. 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 who can give some specific guidance for the rest of the year.
Roland Burns
Thanks, Jay. On Slide 13, we provide financial guidance for the fourth quarter of this year and full-year. Fourth quarter production guidance range is 1.42 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 eight to 10 of that wells and we now anticipate our 2022 full-year production guidance should be biased towards the low end of our range, due mainly to the timing of turning well 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 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 to $75 million, including both bolt on and leasing activities of which $54 million has already been spent this year. Our LOE costs there now expected to average $0.18 to $0.23 in the fourth quarter, and $0.19 to $0.24 for the full-year. While our gathering and transportation costs are expected to average $0.28 to $0.32 both in the fourth quarter and for the full-year.
Production ad valorem 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 average $0.95 to $1.05 in the fourth quarter. Our cash G&A expected to average or be $79 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 million to $40 million during the quarter, which would bring the full-year of cash interest up to about $158 million 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 analyst. Catherine. We can turn it over to Q&A.
Question-and-Answer Session
Operator
Thank you. [Operator Instructions]. Our first question comes from Derrick Whitfield from Stiefel. Your line is open.
Derrick Whitfield
Thanks, and good morning all.
Jay Allison
Good morning, Derrick.
Derrick Whitfield
With my first question, I wanted to focus on the circle end result in early indications on your second Bossier well on western Haynesville. Since the last call, what incrementally can you share with us from the potential the Circle M and your view on the repeatability of that result based on your and industry results?
Daniel Harrison
Yes, Derrick, this is Dan. So we — Jay mentioned so the wells been producing the flat at 30 million a day. Since we put it on in April, we did shut it in when we frack the KZ Black within that vicinity. We started that frack back on around October the 1st. So we had the well shut in just for precaution first 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 a lot. Any of these future wells are going to be anything less than the Circle M.
Derrick Whitfield
That’s terrific. And as my follow-up, I wanted to ask a gas egress question based on the broader weakness in Privo, Katy and Houston ship channel really more of the region with the understanding that that recent weakness has been driven by pipeline outages and Freeport. Wanted to ask if you could share your macro views at really the basin level? And more specifically, to what degree can the Haynesville production grow over the next year in your view? And how much excess takeaway do you own over current production levels?
Daniel Harrison
We — if you look at our program, we’ve 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 Haynesville in our core area, which seven rigs will be on that core area, we always project a pipeline and take away. I mean we look to see if we’re going to drill 80 wells gross a year, and maybe trying to sales 60 or so those were that takeaway is. We’ve done that, whether it’s with Williams or ATC 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 friendly tied, it may be 90%, 95% full, I think that a few VP plan had in — you’re not going to run in some of the problems that some of the smaller companies have. The other thing that we have, which it comes into play now is our expansive acreage footprint. As Montblanc were in one or two counties in Texas are 67 parishes in the Louisiana. We’re in all the above.
So if you go back, Derrick, and you’ve looked at how we spread our program at quarter-to-quarter-to-quarter year-to- year, you can say that we will heavily drill in one area and not another because of the takeaway issue, maybe. But because we do have that 400,000 plus acres in growing. We’ve got a lot of room to avoid some of the pop on segway issues.
Roland Burns
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 takeaway to our transportation portfolio. As we continue to look ahead and just see where our needs are. And there are a lot of — there were Brownfield projects, Greenfield projects, both in the Haynesville, especially redirecting gas to the Gulf Coast markets. And so yes, we continue to evaluate those takeout parts of those, we like it, we 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 or — and to drill in the 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, that we actually are just actually buying and reselling third-party gas that we plan to use up. So we just in next year’s drilling program. So we think we’re pretty well positioned, but we’ll continue to be front run that as the Haynesville production grows, and as the demand grows, and the Gulf Coast being able to get the gas down to those users.
Jay Allison
And Derrick as Roland said, we have added more farm transportation. Because we think if you have interruptible, you probably be interrupted. So we’ve added more farm.
Derrick Whitfield
That’s terrific. Sounds like you guys are well position.
Jay Allison
Thank you.
Operator
Thank you. And we have a question from Charles Meade with Johnson Rice. Your line is open.
Charles Meade
Good morning, Jay, to you and your team.
Jay Allison
Hello, Charles.
Charles Meade
Jay, I wanted to ask a question about those Nacogdoches well results and obviously you put this in presentation. Those are style 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 that was an uptick versus your internal expectations previously. So I wonder if you could talk a bit about that. Is there different completion design? Are you targeting a different zone? Is it maybe something that you’ve learned from the Western Haynesville that you bring it back this way? Just kind of tell me what’s going on there?
Daniel Harrison
So yes, Charles, I thought maybe I’d pull that question out of you. If I commented on it, after Dan presented it, he didn’t cover it. Like I want him to colored. So this is his chance.
Jay Allison
Well, Charles, the — we hadn’t drilled any wells down there since 2015. That’s when we back when gas prices were low that was just kind of one of the areas that we did not look at spend on our capital, because we’d 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 where we are aligned, 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 frack on those wells. There is other offset activity in the area that’s showing that the results are good. so we drilled two Haynesville’s and one Bossier, it was a three well pad, the footprint we had, just allowed us to drill a 7,500 foot ladder. We could have drilled them a little bit longer if we had the footprint was there. But in the bottom row pressures a little higher, that’s a little bit deeper down there. It’s about 14,000 foot TVD.
So but the bigger vintage, newer frack 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 URL is going to look like. But man out of the gate, they look really good.
Charles Meade
Great, thank you. It looks like you probably have three months of data on those — this production. So that’ll be interesting to follow that. And my second question is on this slippage of the turning 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?
Roland Burns
No, Charles, this is really just a one-time thing. We had some of — our three full time frac crews, we had a, we took our lower performing frac crew, and we had the opportunity to upgrade and pull in 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 well pads that was going to turn to sales in December, and it pushed it into January, it pulled up a couple other pads. There were some dates shuffled around. But that’s basically what calls that.
Charles Meade
Got it. It is really detailed.
Jay Allison
Yes, don’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.
Roland Burns
Yes and Charles, it has nothing to do with well performance or inventory.
Jay Allison
Yes, we’ll see a pickup next year with the efficiencies on this other frac crew we picked up, I think it’s going to help us pull forward turn to sale dates that we had next year. So that’ll help out.
Charles Meade
Great, thank you.
Jay Allison
Thanks, Charles.
Operator
Our next question comes from Fernando Zavala with Pickering Energy Partners. Your line is open.
Fernando Zavala
Hey guys, good morning. Thanks for the 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?
Jay Allison
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 toward 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 the comp and yes 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 going to, 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 be relied 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, this gas and supply them on a long-term basis.
Fernando Zavala
It makes sense. And I know you’re focusing on trying to prove up that Western Haynesville A grade, 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?
Jay Allison
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 the pad sites. We have takeaway for all those wells that are planned in 2023. And we have a completion crews as Dan had mentioned in place to handle a non-rig program with seven rigs in the core area and two delineating the Western Haynesville. As Roland said, I mean, we went out looking at maybe some menus for chemicals or industrial users that may want to contract to gas. Well, they have it. So once the LNG demand if any work on, eight 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 might be Comstock would 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 cost, we have predictability we had 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.
Fernando Zavala
Got it, that’s helpful. Thanks for the time.
Operator
Thank you. We have a question from Neal Dingmann with Truist. Your line is open.
Neal Dingmann
Good morning. My first question is on well costs specifically, I think expected cost per foot. Looking here, it looks like your presentation suggests that 22 costs per foot are up about 45% year-over-year. And I’m just wondering, what 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?
Daniel Harrison
Yes, Neal, 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 were still seeing, we’re still seeing the inflation numbers move on up a little bit. We’ve been, 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, two out of our three fleets 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 it was where we are going to see obviously, the costs are going to continue to move up as long as the demand is there.
We’ll see that just across all services, I mean, obviously, we’ve seen it with the rigs, we’ve seen the — we’ve seen it in obviously the diesel, we use a lot of diesel, and oil based mud, see many directional tools. I mean, it’s just really a kind of across the board. And 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 along laterals, so that’s going to help us there.
Neal Dingmann
If you locked in some of those rigs of the nine rigs, you have locked longer-term contracts, so many of those.
Daniel Harrison
So we have — we’ve got some medium term contracts with 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.
Neal Dingmann
Okay, and then maybe to Dan, just my second question on pretty general of in broad strokes. Just wondering when you turn more towards, you mentioned turning more towards wells in Texas next year versus a lot of that. Nice Louisiana wells you’ve done this year. Any just early thoughts on well returns, you think it’d be pretty comparable as you start drilling and completing some of those?
Daniel Harrison
I think they’re going to be pretty comparable. I mean the better, 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 to get 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 missed it, we’re looking at take away capacity. We can’t concentrate a lot activity in any one area. We’re just kind of keeping everything spread out to make sure we don’t create any issues there.
Neal Dingmann
Sure. Thanks Dan for the time.
Daniel Harrison
Thank you.
Operator
Thank you. Our next question comes from Umang Choudhary with Goldman Sachs. Your line is open.
Umang Choudhary
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 have reinitiated, your quarterly dividend. As we look at 2023, I would love your thoughts on around free cash flow location towards balance sheet reduction any further form of capital turns, which are contemplating? And if there’s any additional free cash flow, which you’re marking for the Western Haynesville area.
Daniel Harrison
But that’s a good question. 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 of budget for next year, that’s going to be the first step and understanding what we need to invest in the Western Haynesville and the base Haynesville. And then, I think we’re very comfortable that the dividend we put in is a sustainable dividend, that’s, 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 that we may want to employ.
But again, the balance sheet definitely has always come first. So, we’re not going to work, we’ve got this new fortress balance sheet with tremendous liquidity, seen 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’s a — there 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.
Jay Allison
But even the proof of our conservative natures that, we broadcast at 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.
Umang Choudhary
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’ll see, gas prices really paid 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?
Jay Allison
We know on the gas price, I mean gas footprint from $9.85 to $6.30, or whatever it is, it hit my apologies differently, 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 greater percentage than it cost 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 in the de-risking that’s going on. There, we might look at hedging and little different classes. Our 2020 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 hedge with half of our prior production hedged at a $3 for almost $10 sailing.
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 a percent hedge all the time. But I think our liquidity and our free cash flow numbers will drive that that that that answer a little differently than it has in the past.
Umang Choudhary
That’s great. Well, thank you. Thank you so much,
Jay Allison
Yes sir. Thank you.
Operator
Thank you. We have a question from Phillips Johnston from Capital One. Your line is open.
Phillips Johnston
Hey guys. Thank you. Maybe just to follow-up on the return of capital question, you mentioned, the $0.50 dividend is very sustainable and conservative. I guess as you get more comfortable with returning more capital over time. Can we think about that base dividend just slowly marching higher over time? Or would the first priority sort of the, to look to other forms of returns, whether it’s variables, buybacks, et cetera?
Daniel Harrison
That’s a good question. I think definitely, we’ll evaluate the level of the dividend. And as to the extent that, we see the production base is larger, and then that dividend is very sustainable at a higher rate. I think that’s something that will be the first thing to look at 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 my 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 on variable dividend. So I think that 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.
Phillips Johnston
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 in 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 with maybe a less efficient capital program in the near-term, just in terms of wells for rigs, relative to this year?
Daniel Harrison
Yes, that’s a great observation. Because to the extent that you reallocated those wells back to the — our traditional Haynesville, they would create a lot more capital, because they would drill a lot more well, so they would be more completion costs. So I think as we when we added those, we took that into account that the wells take longer to drill. So an actual looking at the amount of capital per operated rig, they’re actually going to keep that number lower.
But now we’re — yes, we’re very dedicated to continuing to delineate that play, but the other play will tell us what’s needed. Yes, 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 if, 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’ve continued 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.
Roland Burns
Yes, thanks, Dan. I’ll just say, we are on a pretty good learning curve. We’ve learned actually quite a bit on these first two wells. We totally expected we just get a few a few further wells into the program. We’re going to see the calls and I think the [indiscernible] and all that are going to speed up the calls to come down. So we’re pretty confident we’ll see that in the near future.
Jay Allison
Phillip, and we were funding and we would set some pop even on our hard well the gamble well. So we’ve got one that’s been producing the circle, and we’ve got one that we expect to turn to sales this month. And then, we’ve started drilling a third well, the gamble. 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 gamble at the next call. We’ll see what happens it’ll be in February.
Phillips Johnston
Sounds good, guys. Appreciate it.
Jay Allison
Thank you.
Operator
We have a question from Paul Diamond with Citi. Your line is open.
Paul Diamond
Good morning. Hello. Thanks for taking my call. First of all, I wanted to jump into which is 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?
Daniel Harrison
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 lock it up longer-term customers. And we have definitely done some of those already. And then we — but I think over the next six months or so, I think that 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 on our long-term markets.
Paul Diamond
Understood. Thank you. And just a quick follow-up, you guys have kind of laid out a nine rig plan, seven in the core, and then some split between [indiscernible]. From a macro perspective, is there anything you guys can perceive that would cause a shift in that? Or is that pretty much set in stone for the next 12 to 18 months?
Daniel Harrison
Yes, for our schedule, I’d say it — I mean, we always shuffle things around as needed. But I would say it’s pretty well fixed for the next 12 months. I mean, we’ve got the rig lines are built out for a couple of years. But we move projects around as needed if something arises, but we’ve got the [indiscernible]. It takes a little bit longer lead time in Texas to get wells drill ready. So probably middle to late next summer, rig returning back on the acreage. And we’ll have 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. Well, as we commented earlier, we don’t have any long-term rig contracts. So if for some reason that 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 fairway of the nine rigs. That’s what we budgeted, and we haven’t given any guidance for 2023 as of today.
Paul Diamond
Understood, thanks for the clarity.
Jay Allison
Thank you.
Operator
Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.
Noel Parks
Hi, good morning.
Jay Allison
Hi, Noel.
Noel Parks
Hey, just couple of things. In your leasing budget, I think it was about $54 million you’ve leased year-to-date. Just curious what you’re picking up with those lease dollar, is this expired lease, never leased acreage, just wondering kind of what’s still out there to buy?
Jay Allison
All the above, I guess. Again, that includes maybe our acquisition that we made, so it’s a combination of, maybe we acquired held by production properties that have the deep right, 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 really grown our land department this year and to focus on exploiting these opportunities that we see in the Haynesville. So, we’ve had a lot of personnel, have a lot of activity going on at the ground floor.
Daniel Harrison
Yes, we had this acreage, if we can extend the lateral length of these wells. We still have dollars budgeted for that, if we can pick up any deeper ones 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 to particularly pick and extend the lateral lengths to some of the acreage we already on. But that’s the budget. I think the more important part of that budget is, when you’re looking at the Analyst report, we’re not budging for big M&A activity. That’s our key.
Noel Parks
Great, great, thanks. And then talking about just as it was all the liquidity you have and the free cash flow you will 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 interests, 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 sort of consciously designed to build up product inventory like, give a more ability to be opportunistic about when you bring things on?
Jay Allison
So 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 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. So, we’ve sold some interest to them, especially where we see a lower return opportunities, we see a lower return project compared to other projects in our portfolio.
So, we’re probably more of a seller of that non-operated, 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 in that area. Although that gas prices have been high. So, it’s not like those aren’t very profitable projects. We just want to protect our numbers.
Daniel Harrison
I think we’d like to control where we spend our money. The good thing is, we’ve got such a large acreage footprint that we do have a lot of AFEs coming in as a non-op. So, the question is, do we participate in those? Maybe we participate because we 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-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.
Roland Burns
Yes, and on the question about [indiscernible] I mean, I think that we just don’t like to put that kind of investment in wells and have that a drill because and we don’t think it’s the right way to manage the business. So from the landowner standpoint, as far as drilling the well and not putting on production. I just think that’s not 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 ducts that get created, because of some issue, but it’s rare.
Noel Parks
Great, thanks a lot.
Jay Allison
Thank you, Noel.
Operator
Thank you. And our last question comes from Leo Mariani with MKM Partners. Your line is open.
Leo Mariani
Hi guys, wanted to follow-up a little bit on the recent basis issues that you’ve been experiencing. I mean, 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 can become a larger issue? And in 2023, and I guess, do you have any new strategies to mitigate that if it does?
Jay Allison
Well, it’s a seasonal issue, too, because this time of year is just, all last three years in a row. October and part of November is always water, it’s kind of the shoulder month of the transition from the injection into withdrawal, it’s always sloppy, and that’s — so that’s nothing new. I think what is the — I think what’s newer in this quarter is not so much, we’ve managed the [indiscernible] Carthage basis differentials very well, with our Gulf access, it I think they’re real. 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 sending it, using it for LNG, so that event I think that happened has really turned that Houston ship channel market into a wider market and that’s what’s — that’s what’s affecting us really because we were protected against the other ones for the most part.
Leo Mariani
Okay, that’s helpful. And then just on the dividend, looks like it’s a decent sized commitment for new folks here, rough math almost $140 million a year? Is that something that, if 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 come pay the dividend or would that be a time we might drop a rig or something?
Jay Allison
I think that we’ve set that dividend level where, we just don’t see that just an absolute complete collapse in prices, that we can’t support that without borrowing. So it’s a very conservative dividend, it’s 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 yes, so we think it’s the right conservative level. And I don’t think that we foresee any real probability that we can maintain that without borrowing. I mean, I think that looking at, to extent that gas prices or prices were that low, we’d see a 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 low in 2020.
So, we think they’re natural. There’s a lot of costs, we’ll track prices, and they’ll also contract when prices go the other way. So we take — taking that account, we just don’t see that scenario, that you mentioned, being that possible.
Roland Burns
Yes, in fact the board, I asked that we run a model that $253 of gas, and $3 gas and you don’t cut back your CapEx budget, which we would cut back that budget, and then any and all those runs that we looked at, we didn’t ever see us using the bank credit facility for dividend payments at all.
Leo Mariani
Okay, thanks, guys. Appreciate it.
Jay Allison
Thank you, Leo.
Operator
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.
Jay Allison
Sure, again, it’s been a wonderful hour. The quarter has been great. I looked at that 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, it 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 so that we project we will have in the future. So thanks for good natural gas. So thank you for your time.
Operator
This concludes today’s conference call. Thank you for participating. You may now disconnect.
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