Good day, and thank you for standing by. Welcome to the Comstock Resources, Inc., First Quarter 2024 Earnings Conference Call. [Operator Instructions] Please be advised that today's conference is being recorded. I would now like to hand the conference over to your first speaker today, Jay Allison, Chief Executive Officer. Please go ahead.

Thank you. Thank you. Welcome to the Comstock Resources First Quarter 2024 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 "First Quarter 2024 Results." I'm Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations. Please refer to Slide 2 on our presentation and note that our discussion today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you would turn to Slide 3, our corporate team of 255 strong, I want to thank you for joining the call today. We've been very active over the last 100 days, with all hands focused on continuing to batten down the hatches in order to manage our assets and continue to create value during this weak period for natural gas. Actions and achievements in the last 100 days have involved many of our stakeholders, including our bondholders, our bank group, our major stakeholder, Jerry Jones, and our service providers. On March 15, we closed on an acquisition that enabled us to add 198,000 net acres to our Western Haynesville play, which were substantially held by production, so we do not have to increase our drilling activity in order to retain the acreage. In the quarter, we turned 4 new Western Haynesville wells to sales. Each one looks fantastic. We're now drilling on 2 well pads, which will reduce our cost, and we recently…

All right. Thanks, Jay. On Slide 4, we cover our first quarter financial results. Our production in the quarter of 1.5 Bcfe per day increased 10% from the first quarter of 2023. The low natural gas prices resulted in our oil and gas sales in the quarter of $336 million declining 14% from 2023's first quarter level, despite the 10% production increase. EBITDAX for the quarter was $230 million, and we generated $182 million of cash flow during the first quarter. We reported an adjusted net loss of $8.5 million for the first quarter, or $0.03 per share, as compared to income of $92 million in the first quarter of 2023. Slide 5, we kind of break down our natural gas price realization in the quarter. During the first quarter, the quarterly NYMEX settlement price averaged $2.24, which was $0.17 lower than the average Henry Hub spot price in the quarter, or the daily prices, of $2.41. Our realized gas price during the first quarter averaged $2.06, reflecting an $0.18 differential to the settlement price and a $0.23 differential to our reference price. In the first quarter, we were 26% hedged. So this improved our realized price in the quarter to $2.40. In the volatile quarter, we also lost $800,000 in our third-party marketing activities. Slide 6, we update our hedge position. Since we last reported, we've been very busy adding some hedges to kind of build out our hedge positions for next year in 2026 as well as improving the amount that we hedged for the fourth quarter of this year. We added 300 million a day of swaps covering the period of October 2024 through December 2026, at an average price of $3.51 per Mcf. We added 75 million a day of swaps [ just for '25 ],…

Okay. Thank you, Roland. Over on to Slide 10, this is our current drilling inventory that we have, where we're at, at the end of the first quarter. Total operated inventory currently has 1,702 gross locations, 1,296 net locations, which equates to a 76% average working interest across the operated inventory. On the nonoperated inventory, we have 1,254 gross locations and 165 net locations, which represents a 13% average working interest on the nonoperated inventory. The drilling inventory is split between Haynesville and Bossier locations. We have this split down into our 4 different groups. Our short laterals are up to 5,000 foot long; medium laterals, at 5,000 to 8,500 feet; long laterals, at 8,500 feet to 10,000 feet; and then our extra long laterals, for everything over 10,000 feet. So if you look at each group in our gross operated inventory, we have 278 short laterals, 348 medium laterals, 433 long laterals and 643 extra-long laterals. This gross operated inventory is evenly split, with 51% in the Haynesville and 49% in the Bossier. 63% of our gross operated inventory has laterals longer than 8,500 feet, and 38% of our gross operated inventory, the 643 locations, have lateral lengths surpassing 10,000 feet. The average lateral length in our inventory now stands at 9,015 feet. This is up slightly from 8,971 feet that we had at the end of the fourth quarter. Based on our near-term activity levels, this inventory provides us with over 30 years of future drilling locations. On Slide 11 is a chart outlining progress to date on our average lateral lengths drilled based on the wells that we have turned to sales. During the first quarter, we turned 18 wells to sales, with an average lateral length of 9,229 feet. The individual lengths ranged from 4,228 feet…

All right. Thank you, Dan. Thank you, Roland. I would direct you to Slide 15, where we summarize our outlook for 2024. We've taken a number of steps in response to significantly lower natural gas prices this year. During first quarter, we released 2 of our operated rigs, as Dan said, by reducing our rig count to 5 rigs. We also released 1 of our frac spreads, reducing our frac fleet to 2 spreads. We no longer have any long-term commitments for our pressure pumping services. With those steps, in 2024, CapEx is expected to be down 33% to 41% from the 2023 level. We suspended our quarterly dividend, saving approximately $140 million a year of dividend payments. In late March, our majority stakeholder, Jerry Jones, invested an additional $100.5 million into the company through an equity private placement. Starting in late February, we've added significantly, as Roland said, to our hedge positions, starting in the fourth quarter of 2024 and extending to the end of 2026. We're targeting a hedge level of 50% of our expected production level. In early April, we further enhanced our liquidity position with a $400 million senior notes offering. We'll continue to maintain our very strong financial liquidity, which totaled just over $1.3 billion at the end of the first quarter pro forma for the recent notes offering. Our industry-leading low-cost structure is an asset in the current low natural gas price environment, as our cost structure is substantially lower than the other public natural gas producers. We remain very focused on proving up our Western Haynesville play, continuing to add to our extensive acreage position at this exciting play. At the end of the first quarter, our Western Haynesville acreage position, as we stated earlier, totaled over 450,000 net acres. We believe that…

Thank you, Jay. On Slide 15, we provide the financial guidance for the second quarter and the full year 2024. Second quarter CapEx expected on the D&C side is expect it to be $200 million to $250 million, and our full year D&C CapEx guidance remains unchanged at $750 million to $850 million. The lower D&C spending versus last year is related to the release of the 2 drilling rigs earlier this year in response to the low gas prices. With the large lease acquisitions now completed, we anticipate spending $2 million to $5 million in the second quarter and $70 million to $80 million over the course of 2024. Capital expenditures related to Pinnacle Gas Services will be funded by our partner and are expected to total $30 million to $40 million in the second quarter and $125 million to $150 million for the year, which is unchanged. On the operating costs side, our guidance for LOE, GTC and production and ad valorem taxes remain unchanged from February, as does our DD&A. The only real change on our guidance on the cost side is related to interest expense, which has been increased slightly to reflect the impact of the notes offering we completed in April. Lastly, on the tax side, we still expect the tax rate to be 22% to 25%, but now we expect to defer 98% to 100% and really almost virtually 100% of our reported taxes this year, which is up from the prior range of 95% to 100%. I'll now turn the call back over to Andrea to answer questions from analysts who cover the stock.

[Operator Instructions] Our first question comes from Derrick Whitfield, with Stifel.

I have 2 questions for you and they're both related to the Western Haynesville asset. First, given the depressed price environment we're seeing at present, I want to make sure we're properly thinking about the capital efficiency of the investment relative to the industry. If we think about your cost and recovery metrics based on the [indiscernible] provided, you've noted the Western Haynesville is being developed at a cost that's about 2x that of your legacy Haynesville, with a recovery that's about 3.5 to 4 Bcf per 1,000 foot, in that ballpark. So that's $3,000 per foot for, let's call it, 3.5 to 4 Bcf per thousand foot of EUR. So if we compare that to industry metrics of $2,000 per foot for 2 Bcf per 1,000 foot, it would seem to us you're about 50% more expensive, but you recover 75% to 100% more gas. Is that fair? And again, I'm just trying to frame the opportunity as you know it today.

Derrick, this is Roland. I don't think that's too unfair. I mean, I think the difference really is the larger reserves that we're finding in the Western Haynesville, but it also takes longer to get them out. We're not flowing the Western Haynesville wells at double the rates of the traditional Haynesville. It's possible we could, but we're choosing not to do that in this early stage, especially with the low-price environment. So we're -- I think you would really view it -- I think we think, overall, it's a very similar type of return right now compared to the best part of our traditional Haynesville and [ priced superior ] to our Tier 2, Tier 3 part of the Haynesville. But it's longer term. It's an investment in the future. And so we feel really have been very encouraged by the well performance and in the EURs that they appear to be earning with their longer-term performance.

Derrick, I'll make -- we have 11 to 12 wells turned to sales, and we've only started drilling 2 wells per pad recently. And we've only had 1 well that's been producing over 2 years. So it's early on in the play. But what we have seen so far is exemplary, whether it's IP rates, whether it's the lack of decline, whether it's EURs. And in any new play like this, I mean, I think we all agree that the resource is there. The question is, can you get it out economically. And in [ any work ] of any play, particularly like the core of the Haynesville in 2008, I mean, the more wells you drill, the lower the costs are. And I think Dan has done a good job. I mean, our first wells were 80 days to drill. Now they're -- the last one has been 54. So these costs are coming down, and I think we're getting better and better and better. Dan?

I'd just add that when you compare the 2 areas, if you look at the costs, like you mentioned, in the core, those are kind of pretty much set. We kind of know what we're going to drill them for, absent any problems. And I mean, there's -- you're making some small improvements here and there. But you compare that to the Western Haynesville, where if you look at the costs, like you mentioned, that's where we started. Those costs are coming down, right? So on the Western Haynesville side, you're seeing the costs really move down, which is changing the economics. And you're not really seeing that in the core. Those are kind of fixed, right? Because we've kind of been optimized for a while.

Derrick, the core goes anywhere from 1.2 to maybe 2.2. I mean, you may see a 2.3, but like you said, 2.0, I mean, that's a blue ribbon well in the core. I think what we're trying to derisk in the Western Haynesville is that a large portion of that acreage is competitive, if not potentially better than, the best of the best at the core. That's what we're trying to prove up.

Terrific color. And then as my follow-up, I just wanted to ask if you could help frame how we should think about the amount of activity that's required to [ HBP ], or protect the resource, in light of your recent leasing success.

On the 198,000 acres, the net acres we acquired, I'd say 95% of that is HBP; the other, say, 5%, those are round numbers, they're, like, 15-year leases. So that does not change our drilling at all as far as our schedule for 2025, '26, '27 at all. And as far as the acreage that we've leased over the last 3.5 years, we've always said that we would really like to add a rig a year. And if we do that over several years, then [ that will HBP ] that acreage. So we're not pushed at all to add rigs in a low-price environment. And even if prices are high, we're not pushed to add rigs at all to HBP that acreage. Good questions. Thank you, Derrick.

Our next question comes from Bertrand Donnes, with Truist.

Just wanted to start off asking around the kind of exciting potential data center demand. You guys already have some LNG agreements. Obviously, you have LNG corridor exposure. But you've taken the indirect benefit strategy. So just was wondering if when it comes to data center demand is there any interest at Comstock really taking a direct maybe long-term agreement with a plant or something like that? And maybe could you tie in Quantum midstream build-out for that purpose?

That's a great question. And we're really excited about the Western Haynesville as we build volumes, because it's not -- it's got -- there's a lot of potential customers that are approaching us, including recently even some data centers that really are looking to build their centers where they can have uninterrupted supply and power supply. So it's an exciting new element to kind of add to the LNG demand and other industrial users, power generators. And we do see shifting, especially our Western Haynesville. I think we'll be selling a lot of that gas in the future to our direct customers and then potentially using our relationship in the midstream venture to add some infrastructure as needed to be able to service those. So it's a really exciting area. For us, we really want to have a diverse basket of customers in the future and have much, much less sales to other marketing companies or aggregators. And LNG will be a part of it. And I think we've got some exciting relationships there developing. And then hopefully, other industrial users and utilities will be part of our customer base.

[indiscernible], if you look at that, too, 90-plus percent of our Western Haynesville is undedicated. So that's a big advantage if you're looking for gas, whether for a data center to provide power or a takeaway as a utility or LNG contracts.

That's a really good point [ on that ]. The other question, just maybe around the Jones transaction, could you maybe go into how that came together? Were they ready before you found the acreage? Was the acreage part of the push to maybe get the agreement? And I don't know, should we expect more capital and cash in the future? Or is this kind of a onetime thing?

Well, I think come August it will be 4 years that we have had a group of landmen leasing acreage in this area. And we kind of set the boundaries. And as those boundaries have expanded, we've looked at where kind of the north, south, east, west sides are. And you work all those sides to come in inward. And it just happened that this year, in 2024, we were able to pull off several of the larger transactions. We did that in 2022. There was a big acquisition in '22 that we made, and we picked up the Pinnacle plant and that 145-mile [ operational ] pipeline. And then this year, we were able to close another acquisition. But I think, in our opinion, all of the major acquisitions that we would be looking at, they're in our rear-view mirror, they're closed. And what we're doing now with our land group is just kind of cleaning up. And what we think we've secured all the parameters, we're just cleaning up the infield.

Our next question comes from Jacob Roberts, with TPH.

Maybe circling back to Derrick's first question, just thinking about the cost improvements on the core position over time, wondering if you could speak to some of the levers that might be pulled in the Western Haynesville that could also bring those costs down. Just looking for more specifics around what we expect to see to get those days to drill lower or costs lower.

This is -- we've got kind of a few things working in the Western Haynesville. Obviously, the depth, it's deeper. The vertical hole section has a really thick [indiscernible] section. We've made a lot of improvements with the bits that we're using, getting better ROP through that section, which takes several days. That's been part of the progress we've made. And then we have changed our casing design a little bit that saved us some time. We've also -- and in the lateral, it's really the temperature that we've said many times, and we've had a lot of really big improvements that have allowed us to handle the temperature. We're still making those improvements, and that's where we see the additional day savings moving forward from where we're at today.

We have seen that in the numbers. In other words, as we drill these wells, we have seen this cost improvement. And we've also seen a lot of upside in our EURs. So both of those metrics are going in the right direction.

And Jake, the other thing I would add is, Jay mentioned and Dan both, we're currently drilling with both of our rigs on 2 well pads. So in addition to the temperature being a key, the multi-well drilling pads should end up driving efficiencies like they do in all the plays as well.

Remember, we started out drilling Bossier. And then as we said during this call, the 4 wells that we just put on, they're Haynesville wells. So it's a little bit of a difference in drilling as you de-risk both the Bossier and the Haynesville.

Great. I appreciate the color. Maybe staying on the same topic, I was wondering if you could comment on any variation in completion design that you might have pursued of the dozen wells or so that are online and if you could offer any insight into what you think a full-scale development design might look like.

That's a really good question. I'll kind of start with the last question. Full-scale development, I'd say we haven't got too deep into thinking about that because that is kind of down the road aways, with the plan for us to drill out, basically just to drill out the acreage and get it held. We'll be drilling in -- we still have a few singles to drill, but we're drilling [ with the 2-well pads also]. On the completion design, we have pumped a larger frac design on this last well that we turned to sales, the Ingram Martin. Just a larger job. The perforations -- the cluster spacing, number of perfs and all that was the same, but just a bigger loading, more water, more sand. We just wanted to get the clock started and see how that well is going to perform versus the first 11 that we turned to sales. Nothing really too different that we're doing on the completion design down here versus in the core. We'll just kind of continue to get our production data, and we'll -- it kind of depends on what it tells us. We'll see if we need to make any changes. But right now, I think what we have works pretty well. So we're just not looking to do anything drastic right now.

Our next question comes from Ati Modak, with Goldman Sachs.

It seems like you moved to more spot frac fleets for the rest of the year. Can you provide any color on the cost savings flexibility that brings to your operations? And maybe touch on if there are any efficiency-related concerns, or not, associated with that.

Well, we dropped the 2 rigs. We didn't have a need for as many frac crews, one, but we did -- it's obviously a squeeze on the frac crews, right, with the number of rigs dropping dramatically. And we have obviously gotten some concessions on pricing just due to the frac activity. And we've got a really good relationship with the frac provider that we've got now. And so that's probably, I think, helped us a little bit with the pricing that we've been able to put into place for the rest of the year.

Got it. Understood. And then as you think about the macro here for gas prices, any updated thoughts you can provide around the capital allocation strategy and balance sheet management with the sensitivity to gas prices as you are seeing?

We continue, of course, to monitor that. And we have not only fairly volatile NYMEX prices, but also spot prices, that can be very volatile during the months based on how much gas is needed and where. So yes, there's definitely -- we strategically do some shut-ins every now and then. It's usually for a day or 2 if we don't like the spot prices. We'll continue to be able to monitor that and react to that. We've delayed turn to sales sometimes not to open them up in a spot market-type scenario, late for first of the month type. So we're trying to manage within the -- to maximize the realizations in this really weak environment. And continue to have the ability to change the amount of rigs we're running. We definitely have the ability to defer turning wells to sales. So all those are still in the tool kit as we kind of look to navigate these next upcoming 6 months of expected weakness. At the same time, wanting to preserve the company's ability to benefit from the stronger prices, which we've already started to lock into, started in the fourth quarter.

I think a key is we do have that ability. Like we said earlier in the conference call, our frac commitments, we don't have any frac commitments that are long term. So we can toggle those. And our frac providers have been very, very pro-Comstock, very -- a big backer. So if we need to delay some of those fracs until the latter part of the year, then we'll have the choice to do that.

Our next question comes from Noel Parks, with Tuohy Brothers.

A lot of interesting questions that got me thinking. And I was wondering, with you're being at the 2-year mark, I guess, a little beyond, for your first Western Haynesville well, I'm just wondering whether there are any surprises in the type curve as you've gotten more data? And with the tweaks you've made to drilling completions since then, do you foresee that first well's type curve as being kind of representative of what you're going to see in the more recent wells? I just -- it comes to whether you're at the point you kind of think you have a working benchmark for going forward.

When we started drilling the first well over 2 years ago, 2.5 years ago, we felt comfortable, Noel, that the resource was there, that there was a major field of all this acreage that we now have secured. It's a major field, a gas field. That's why the Pinnacle plant is here and the 145-mile operational line was there. The question was kind of like it was in '07-'08: can you use this technology there to really drill a shale play with the Bossier and the Haynesville? And we've proved that it was in '08-'09 in the core. Now I think we've seen kind of a mirror image of that. We have started to see that materialize in the Western Haynesville, but you don't know, right? I mean, the jury is still out. So as you had this Circle M well producing 8 months, and our outside reservoir group gives us some reserves, and then the next year they continue to be a little better and the next year a little better, it does give you a lot of confidence that the resource is there, one. And then when you listen to Dan, he gives you confidence that the questions are, how have you changed your drilling? Have you changed your completion? We're getting better and better and better. Again, remember, no group has drilled and completed more Haynesville/Bossier wells, period, than we have. So our confidence is really strong right now because we have seen this happen back in the core in '08, '09, '10, '11. If you were to look at those first wells, you'd have an upset stomach. They weren't very good wells in '08, '09. And if you compare the results there versus our first 12 here, I mean, these look exemplary compared to what those wells looked like in '08. So that's why we went out to secure our footprint. We went out, and we didn't try to push on reserves. We just said this is what we think EURs are. And so far, they've held up really solid, and, in fact, we've seen improvements on them. So that's what we're saying. Costs, down. EURs, steady, maybe going up. That gives us this hope as we say this is our business plan to continue well by well to add inventory and to de-risk our big footprint, which now we do control.

And Noel, I would add, our first wells were Bossier field wells, because we were targeting a little shallower, a little less complex to drill. But we've gotten the confidence to drill the Haynesville. And we think our latest wells, being Haynesville wells, I mean, we think they're coming out of the gate stronger. But yes, they don't have the 2 years of proof that the first Bossier well has, but that's what really excites us, is the fact that the Haynesville -- just like the Haynesville is better in Louisiana, too. It always seems to be a little bit better. It's a better rock. It definitely completes better than the Bossier. So we're excited about the potential that the next batch of Haynesville wells has. And we're really focused. You can see most of the wells we focus now on the Haynesville formation in the play, versus the Bossier. I think we have, what, 6 Bossier wells in -- I think we're almost half and half of the 12.

Yes, that would be right. To date, turned to sales, we basically are about half and half on Bossier and Haynesville. So we will have a -- I'll say we've leaned in heavier on the Haynesville wells this year. I think we're going to have a total of 9 wells turn to sales this year: 7 of those will be Haynesville; just 2 will be Bossier. But part of that early on was we obviously concerned with the high temperatures and increasing our chance of success and have a better drilling performance, we targeted the Bossier early on. But we've made such great progress with dealing with the temperatures that we now basically don't see the Haynesville as so much of a challenge compared to the Bossier.

Great. And I was just wondering, with the formation being [ deeper ], does that affect the spacing at all? Is there a lot of question about what ultimately sort of density you would be pursuing in the Western Haynesville?

Sure. I mean, obviously, these wells are expensive, and you're going to have to be really careful not to get them too close together and have a lot of interference between wells. I mean, you're not going to have as big of a margin for error for that in a play where you're deeper and you've got more expensive wells. But we've got -- I mean, some of the stuff is really thick. Somebody asked earlier, it was a really good question about how we're going to, how we're thinking about the future development of this play. And because we do, we're blessed with that task to solve, is how many can we stack on top of each other? And what's the spacing going to be? Part of that is we wanted to get this last well pump a bigger frac and see what kind of recovery we get, because that obviously will also affect the spacing. But really to answer your question, we do not know what that exact spacing is going to be for the future. We'll just have to see what these type curves show us, what they look like and where we end up with that.

And Noel, with our big acreage position, I mean, it could be a decade or more before we do any aggressive infill drilling.

Our next question comes from Paul Diamond, with Citi.

I just want to touch quickly, staying in the Western Haynesville, once you move beyond held-by-production needs, where do you see your pad size going? I guess, how much does that impact economics over the longer term?

I didn't catch the full question there.

Sorry. When you get beyond the held-by-production needs, you can -- how big do you see the pad size getting out of the Western Haynesville?

Pad size. Well, I mean, everything that we have drilled to date in the core and in the Western Haynesville for multi-well pads. I mean, we're -- I think the biggest pad we built is, like, 500 by 700 foot for multi-well pads. Occasionally, we'll come back and add on to those if we come back to drill additional wells off the pad.

You probably just didn't have any wells per pad to look at. Obviously, you had both the Bossier and the Haynesville play. And then given our vast acreage, we're able to go both directions from the pad, versus just one. So we're kind of -- at least it seems like we're really targeting 10,000-foot laterals here as kind of an optimal area. So I think 10,000-foot laterals, multiple benches in maybe each of the Haynesville and Bossier potentially and then going from both directions from a pad. So quite a few wells could be on a pad in the future, which obviously creates a lot of efficiencies for everything, including the midstream hookup.

Yes, everything that we've got targeted today is for 2-well pads. And where we can do it, we do drill in opposite directions to hold the maximum amount of acreage. But we do have them built. We'll come back and drill on these pads in the future with additional wells.

Kind of along this same line is takeaway, are we going to have enough takeaway in the Western Haynesville, and that's where we came in last year with Pinnacle, which is backed by Quantum. So we are planning, as we drill these wells, we're planning on takeaway literally years ahead, not that we have to drill those wells at all because most of it is HBP, but we can plan our own path for takeaway. So that's very rare. And big acreage positions like this that don't have an aggressive drill schedule is very rare, too. So if you've captured this amount of acreage at, say, $500 or $600, or less, that's typically when you make your money. So we have captured that. And then the question is, do you aggressively have to drill it? The answer is no. And then you say, well, is the [indiscernible] thickness there? The answer is, we think, yes. And has the well performance been positive? The answer is yes.

Understood. Just one quick follow-up, shifting back to the core. For the rest of the 2024 operational plan, I guess, what percentage is likely to include additional wells similar to the 4 Bossier ones you drilled in Q1 that are kind of required to hold the acreage?

Can you ask that again?

Sure. On the 2024 operational plan, so in the first quarter there were 4 of those Bossier wells, shorter laterals required to hold the acreage. How much of that should we expect to...?

There's no more.

So interestingly enough, we do have some additional sections that will come up. We've actually got a -- we're actually going to drill 1 of these horseshoe wells later this year. I'll go ahead and look at that. That's kind of something that we're looking forward to trying. But we don't have many of these isolated sections left where we'll have any of those issues.

And I think the key to that is, if you don't think they're valuable, you don't drill them. And we think they're valuable enough to drill them. So even if they're shorter, I mean, they're very economic.

We're excited about the horseshoe design, in that it could eliminate these stranded shorties, as we like to call them, the 5,000-foot lateral wells. It has the potential to allow you to eliminate those and turn it into a horseshoe well and have a long lateral well on one section. So that will be kind of an exciting thing to do here later in the year. Because we do believe that shorter laterals in the basic Haynesville are definitely our lowest-return projects, just because of so much cost into the well and the reserves you recover with only those shorter laterals. So the ability to eliminate a lot of those out of our inventory and turn them into long, it will be very enhancing.

Thank you. I'm showing no further questions at this time. I'd now like to turn it back to Jay Allison for closing remarks.

Perfect. Again, I know everybody's time is valuable, and we thank you for sharing your time with us. At Comstock, we do recognize the growing need for natural gas around the world. I mean, our long-term goal, as we've said over and over and over, is to be a significant supplier to the growing LNG market that's developing really several hundred miles from our Haynesville shale operations, including our Western Haynesville area. So we're going to be good stewards with your money. We want to thank the bondholders. We want to thank our banks that support us. We want to thank the Jones that support us and the other stakeholders and the service companies. Everybody over the last 100 days has kind of teamed up and has helped Comstock. So we're thankful for that. Thank you for your time.

Thank you for your participation in today's conference. This concludes the program. You may now disconnect.