Comstock Resources Inc Q3 FY2022 Earnings Call

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. 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 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 in almost all financial metrics, including operating cash flow, free cash flow, net income, EBITDAX, and oil and gas revenues. Our balance sheet has now become a fortress, we are 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 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 KC Block, 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 works 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 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?

Thanks, Jay. On Slide 4, we summarize our strong financial results for the third quarter. After adjusting for the sale of our Bakken properties, which was finalized last October, our production increased by 1% to 1.4 Bcfe per day in this most recent quarter. We achieved a record EBITDAX of $598 million, which is a 107% increase compared to last year's pro forma quarter, mainly due to higher natural gas prices. Our cash flow for the quarter was $533 million, marking a 126% rise over the same period last year on a pro forma basis, setting another corporate record. Our cash flow per share reached $1.92, which is up $1 from the third quarter of 2021. We reported an adjusted net income of $326 million for the third quarter, which is more than 2.5 times higher than the third quarter of 2021. Our earnings per share stood at $1.18, up from $0.35 in the third quarter of 2021. We also generated $286 million in free cash flow from operations, which is 218% higher than the same quarter in 2021. The increase in EBITDAX and the payoff of $250 million in debt this quarter brought our leverage ratio down to 1.01x, compared to 2.3x in the third quarter of 2021. Improved natural gas prices were the main factor behind our strong financial performance this quarter. On Slide 5, we break down our natural gas price realizations. In the third quarter, the quarterly NYMEX settlement price averaged $8.20, and the average Henry Hub spot price was $7.96. We nominated 77% of our gas to be sold at index prices tied to that settlement price and sold 23% in the daily spot market. The expected NYMEX reference price for our sales would have been $8.14. Our realized gas price averaged $7.72, reflecting a $0.42 differential that was slightly higher than normal due to wider regional differentials and particularly weaker Houston ship channel prices resulting from the Freeport shutdown. Normally, Houston ship channel and other Texas Gulf Coast indexes are among our premium markets. In the third quarter, we were 49% hedged, which brought down our realized gas price to $5.36. We utilized some of our excess transportation in Haynesville to buy and resell third-party natural gas, generating around $11 million in additional income in the quarter, which added about $0.09 to our average price realization. On Slide 6, we detail our operating costs per Mcfe and our EBITDAX margin. Our operating costs per Mcfe averaged $0.82 in the third quarter, which is $0.08 higher than in the second quarter. Our gathering costs increased by $0.05 mainly due to higher fuel costs for transporting our gas and increased production from high gathering rate areas. Our lifting cost rose by $0.02, and production taxes went up by $0.01 owing to higher realized prices and an increase in the statutory severance tax rate in Louisiana that took effect in July. General and administrative costs were $0.06, consistent with our second quarter rate. Our EBITDAX margin after hedging remained at 85% in the third quarter, unchanged from the second quarter. On Slide 7, we review the first nine months of the year and our spending on drilling and development activities. In the first nine months, we spent $729 million on development, including $653 million on our operated Haynesville and Bossier shale drilling. We allocated $23 million for non-operated wells and $54 million on other development activities like production tubing installation, offset frac protection, and additional workovers. We drilled 52 or 42.5 net operated Haynesville horizontal wells and brought 53 or 44.2 net operated wells online for sales, with an average initial production rate of 27 million cubic feet per day. We also had two net non-operated wells turned to sales. In the third quarter, we spent $242 million on development and exploratory activities, which included $227 million on our operated Haynesville and Bossier Shale drilling program, alongside $4 million for non-operated wells and $11 million for other development activities. On Slide 8, we present our balance sheet at the close of the third quarter. We had $100 million drawn under our revolving credit facility at the end of the third quarter. The reduction in our debt and the growth in EBITDAX lowered our leverage ratio to 0.9x on an annualized basis, down from 2.3x in the third quarter of 2021. We aim to pay off the remaining $100 million on our revolver in the fourth quarter using our free cash flow. Therefore, we finished the third quarter with financial liquidity exceeding $1.3 billion. I'll now pass it over to Dan for a more detailed discussion on our operating results.

Okay, thanks, Roland. Over on Slide 9, 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. This currently puts us over 1,000 feet 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 completed today 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 run 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 a 35% increase from our average 2021 full-year D&C costs. Our drilling costs for the quarter were $597 feet. This is a 25% increase quarter-to-quarter, while our completion costs for the quarter were $808 a foot, which represents a quarter-to-quarter increase of only 3%. The increase in our drilling costs reflects the true cost inflation numbers we have experienced year-to-date, we have seen it affect all services across the space. As witnessed by our completion costs for the quarter, we've been partially protected by the high inflation costs 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, we contracted for a second natural gas-powered frac fleet and we 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. 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 we 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 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.

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 a 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 $0.50 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.

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 those 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 are 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 is 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 analysts.

Thank you. Our first question comes from Derrick Whitfield from Stiefel. Your line is open.

Thanks, and good morning all.

Good morning, Derrick.

With my first question, I wanted to focus on the Circle M results and early indications on your second Bossier well on western Haynesville. Since the last call, what incrementally can you share with us from the potential of the Circle M and your view on the repeatability of that result based on your and industry results?

On the second well, we'll get it turned to sales this month. We expect it to be just as good, maybe a little better than the Circle M. We don't see anything really on the horizon that 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 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?

We've added two extra rigs to our program, bringing the total to nine, a decision made several months ago. We mentioned this possibility around six months back. When we forecast production growth, especially in the Western Haynesville within our core area, we assess pipeline capacity and takeaway. We're looking to drill around 80 gross wells per year, aiming to sell about 60 of those based on takeaway capacity. We've established strong relationships with companies like Williams, ATC, and Enterprise for this purpose. Our marketing team is currently ahead of our drilling schedule. While we believe takeaway capacity is quite tight, around 90% to 95% full, we won't encounter the challenges that some smaller companies face. Additionally, we have an extensive acreage footprint, being present in multiple counties in Texas and 67 parishes in Louisiana. If you review how we manage our drilling program over time, you will notice that we concentrate on one area while pulling back in another due to takeaway issues. However, with over 400,000 acres and growing, we have significant flexibility to navigate regional challenges.

Yes, Derrick, this is Roland. I would like to add a few comments to that. We have recently increased our transportation capabilities by approximately 300 million a day. As we look ahead to our needs, we recognize various opportunities, including both Brownfield and Greenfield projects, particularly in the Haynesville region, where we are redirecting gas to the Gulf Coast markets. We continue to assess those transportation options, as we appreciate having a diverse transportation portfolio similar to our diverse acreage position. This diversity allows us flexibility in moving our gas and drilling in areas with the most capacity. Regarding your other question, we currently have about $200 million a day of spare capacity, which we are utilizing by purchasing and reselling third-party gas for our upcoming drilling program next year. We believe we are well-positioned, and we will continue to monitor the situation as Haynesville production increases along with demand, ensuring we can deliver gas to Gulf Coast users.

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

That's terrific. Sounds like you guys are well positioned.

Thank you.

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

Good morning, Jay, to you and your team.

Hello, Charles.

Jay, I wanted to ask a question about those Nacogdoches well results 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 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?

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 wanted him to color. So this is his chance.

We hadn't drilled any wells in that area since 2015, mainly because gas prices were low and it didn't justify the capital investment. We focused on wells that performed better in other regions. However, we have about 35,000 net acres there, and with improved gas prices, we needed to move a rig and implement newer fracking techniques on those wells. There has been successful activity nearby, which bodes well for us. We drilled two Haynesville wells and one Bossier well on a three-well pad, utilizing a 7,500-foot ladder. We could have extended them further if the area allowed. The lower row pressures are slightly higher due to the deeper location, around 14,000 feet. The newer fracking job has been effective, and initial performance is promising. We will need to monitor production over time to confirm future performance expectations, but early results are very encouraging.

Thank you. It seems you have about three months of data regarding this production, so it will be interesting to observe that. My second question pertains to the delays in the completion schedule that you mentioned. Can you discuss the reasons behind this, and whether these are isolated issues or indicative of a recurring service tightness that might happen again in 2023?

No, Charles, this is really just a one-time thing. We had some of our three full-time frac crews, and we took our lower-performing crew and had the opportunity to upgrade and bring in another frac crew that we believed would perform better. We made this switch in the last few weeks. However, this change pushed one of our three well pads that was scheduled to turn to sales in December back into January and affected a couple of other pads, resulting in some shuffled dates. That's essentially what caused this situation.

Got it. It is really detailed.

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.

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

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.

Great, thank you.

Thanks, Charles.

Our next question comes from Fernando Zavala with Pickering Energy Partners. Your line is open.

Hey guys, good morning. Thanks for the time. I was wondering if you could talk a little bit about your activity levels in 2023. And how you would flex activity with perceived oversupply in the natural gas market next year?

We haven't finalized our budget for 2023 yet, and we will assess it as we approach the end of the year. We will certainly consider gas prices when determining our activity levels. We avoid drilling wells unless we believe we have strong markets for them. Additionally, one of our key initiatives at Comstock is to develop long-term supply contracts to secure direct customers and stabilize our gas markets for the future. Given our connections to various industrial users and LNG facilities, we aim to position the company to minimize reliance on day-to-day market fluctuations and instead focus on ensuring a steady supply for our customers over the long term.

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?

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 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.

Got it, that's helpful. Thanks for the time.

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

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?

Yes, Neal, this is Dan. I believe you're quite accurate with that percentage. When we look back at 2021, which was really our low point, we definitely don’t want to return to those gas prices. However, we are noticing that inflation numbers are still creeping up. Fortunately, since we started using gas, it has helped us manage costs on the completion side. Once we have our second fleet running next year, with two out of our three fleets operating on gas and the horsepower secured for the long term, we will be in a strong position. In terms of drilling, we expect costs to keep rising as long as demand remains high. We’ve observed this across all services, including the rigs and our significant use of diesel and oil-based mud for many directional tools. It’s a widespread issue. We will be challenged by these costs, but longer laterals are significantly aiding us. Drilling in Texas tends to be cheaper and faster, plus we have enough acreage there to drill longer laterals, which will certainly assist us.

If you locked in some of those rigs of the nine rigs, you have locked longer-term contracts, so many of those.

We have some medium-term contracts with our rigs, but currently, we do not have any long-term contracts secured. However, we are assessing some options at this time.

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?

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 mentioned, we're looking at take away capacity. We can't concentrate a lot of activity in any one area. We're just kind of keeping everything spread out to make sure we don't create any issues there.

Sure. Thanks Dan for the time.

Thank you.

Thank you. Our next question comes from Umang Choudhary with Goldman Sachs. Your line is open.

Hi, good morning, and thank you for taking my question. My first question was on your free cash flow allocation plans, I mean, your balance sheet has improved considerably. You have reinitiated your quarterly dividend. As we look at 2023, I would love your thoughts on free cash flow allocation 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.

That's a good question. Yes, we're going to be very cautious about how we promise to use the free cash flow. As we start to finalize our capital budget for next year, that will be our first step in determining what we need to invest in the Western Haynesville and base Haynesville. We're confident that the dividend we have set is sustainable and solid, even considering the lower gas prices reflected in the futures market. We'll be careful about any commitments regarding the dividend level and any other methods of returning capital we might consider. However, maintaining a strong balance sheet is our top priority. We have built a robust balance sheet with significant liquidity and have seen a reduction in our cost of capital. We're not willing to compromise that for anything. Hence, we will be prudent in implementing capital return strategies next year, but there is a substantial gap between the portion of free cash flow designated for the dividend and what we anticipate generating.

But even the proof of our conservative nature is 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.

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?

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 per foot went up. So when we look at that, we say if we do have a fortress on the balance sheet, if we're not looking to spend billions and billions and billions of dollars on M&A, because we don't think we have to because of the inventory that we have in the de-risking that's going on. There, we might look at hedging a 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 selling. 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 answer a little differently than it has in the past.

That's great. Well, thank you. Thank you so much.

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

Hey guys. Thank you. Maybe just to follow-up on the return of capital question, you mentioned, the $0.50 dividend is very sustainable and conservative. I guess as you get more comfortable with returning more capital over time. Can we think about that base dividend just slowly marching higher over time? Or would the first priority sort of the look to other forms of returns, whether it's variables, buybacks, et cetera?

That's a good question. We will definitely assess the dividend level. As our production base expands, we believe the dividend can be maintained sustainably at a higher rate. This will be a priority for us to examine each quarter as we move forward. We may also consider other capital return strategies, like buybacks. However, based on shareholder feedback, we are hesitant to commit to a variable dividend. Therefore, we might focus on additional debt reduction to strengthen our balance sheet and potentially a share repurchase program in the future when it makes sense.

Yes, as I said, we plan to allocate some freshness and capital that creates returns above our cost of capital. Yes, what we are going to point out again with such a big area spread, just allows us to maintain and take advantage of the lower costs we see down to the eventual drilling and production. So however you get those returns across the product mix, we are ramping up to that level smoothly, and we'll add to that.

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?

Yes, that's a great point. If we reallocate those wells back to our traditional Haynesville area, it could generate significantly more capital since we would be drilling more wells, which would lead to higher completion costs. When we made those adjustments, we factored in that drilling these wells takes longer. Therefore, considering the capital per operated rig, that number is actually going to remain lower. However, we are committed to continuing to explore and develop that area, while also responding to what the other play indicates is necessary. We will move forward based on the results, which have been impressive so far. If we keep achieving great results, we will allocate more resources. We’re cautious not to rush the play because we want to learn from each well. Each time, we’ve been improving our drilling and completion design and making adjustments as we gain insights from this play. Ultimately, we will let the results guide us, and we will be patient and not force anything. We're very enthusiastic about the potential of delineating the play.

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 further wells into the program. We're going to see the calls and I think the results 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.

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.

Sounds good, guys. Appreciate it.

Thank you.

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

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?

I think that's more of a long-term strategy. There are many opportunities we’ve been approached with, and we want to be cautious and not rush into the first one that might not be the best fit. So, we're putting considerable effort into evaluating these future markets and securing long-term customers. We have already established some of those relationships. Looking ahead, in the next six months or so, we expect to provide more insight into our perspective on our long-term markets.

Understood. Thank you. As a quick follow-up, you have outlined a plan for nine rigs, with seven in the core and some variation elsewhere. From a broader perspective, do you foresee any factors that might lead to a change in that plan? Or is it largely established for the next 12 to 18 months?

Yes, regarding our schedule, I'd say it's quite stable for the next 12 months. We have the rig lines established for a couple of years, but we do adjust our projects if necessary. It takes a bit more time in Texas to prepare wells for drilling, so we expect to bring the rig back to the acreage around the middle to late next summer. We'll also see a second rig in the Western Haynesville by the end of this month or next month, and over the next year, we can shift some operations back to Louisiana if needed. Overall, it's fairly well fixed for the next 12 months with only minimal adjustments. As mentioned earlier, we don't have long-term rig contracts, so if the market were to decline, which we don't anticipate, we are flexible. We've shown in the past that we can manage our rigs effectively, whether that means reducing our rig count or adding more as necessary. We are currently planning for nine rigs, which is what we've budgeted, and we have not provided any guidance for 2023 at this time.

Understood, thanks for the clarity.

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

Hi, good morning.

Hi, Noel.

Hey, just a 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 dollars, is this expired lease, never leased acreage, just wondering kind of what's still out there to buy?

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.

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 own. 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 budgeting for big M&A activity. That's our key.

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're 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 design to build up product inventory like, give a more ability to be opportunistic about when you bring things on?

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 lower return opportunities, we see 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.

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.

Yes, and on the question about inventory, I mean, I think that we just don't like to put that kind of investment in wells and have that a drill because 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.

Great, thanks a lot.

Thank you, Noel.

Thank you. And our last question comes from Leo Mariani with MKM Partners. Your line is open.

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?

It's a seasonal issue, as this time of year has been consistent over the last three years. October and part of November are typically challenging months due to the transition from injection to withdrawal, which is always messy, and that's not new. What's different this quarter is not just the management of the Carthage basis differentials, which we've handled well with our Gulf access. Rather, the Texas Gulf markets, previously premium markets, have changed significantly, primarily due to the Freeport situation where gas is being stored instead of used for LNG. This development has widened the Houston Ship Channel market, which is impacting us since we've been mostly insulated from other market fluctuations.

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?

I believe we have established a dividend level that ensures we can support it without the need for borrowing, even if prices were to drop significantly. This is a conservative approach, and it's worth mentioning that the dividend remains the same as it was in 2014, which brings a sense of nostalgia for us. We feel it is the right conservative level and do not anticipate any likelihood of having to borrow to maintain it. If gas prices were to fall to very low levels, we would likely make substantial cuts to our capital budget, either by reducing activity levels or by seeing service costs decrease to the levels observed back in 2020. We expect costs to adjust with prices, and they would decrease when prices go down as well. Considering all these factors, we do not foresee the scenario you suggested as being likely.

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.

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 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.

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