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 also reduced our drilling days to 54. Dan Harrison will give a full report on our progress on the 450,000 net acre play later in the call. On March 25, the Jones family purchased an additional $100.5 million of Comstock stock that demonstrated their confidence in our business plan, including the Western Haynesville acreage acquisition. On April 2, our bondholders stepped up in our $400 million new senior notes offering. The bonds were priced tighter to Treasuries than any of our other bonds that we have issued since 1999. Then on April 30, our bank lending group reaffirmed our borrowing base of $2 billion with a $1.5 billion commitment. That has allowed us now to have $1.3 billion of liquidity. With the demand for natural gas growing in the future to service increased power generation, industrial and LNG demand as well as future demand to power AI, we are well positioned to deliver clean, responsibly produced natural gas from our 800,000 net acres in the Haynesville. We have over 30 years of drilling inventory which we are adding to as we unlock value in our 450,000 net acres in the Western Haynesville one well at a time. I want to thank you for supporting your company, Comstock Resources. On Slide 3, we'll summarize the highlights of the first quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and gas sales, including hedging, were $336 million in the quarter, and we generated cash flow from operations of $182 million, or $0.65 per share. And adjusted EBITDAX was $230 million. Our adjusted net loss was $0.03 per share for the quarter. To strengthen our balance sheet, we added $100.5 million to our liquidity with a private placement of equity with our major stockholder, Jerry Jones. We continue to have strong results from our drilling program. In the first quarter, we drilled 16 successful operated Haynesville and Bossier shale horizontal wells in the quarter, with an average lateral length of 9,845 feet, and we turned to sales 18 successful operated Haynesville and Bossier shale horizontal wells, with an average IP rate of 27 million cubic feet per day and average lateral length of 9,227 feet. We're continuing to progress in our Western Haynesville exploratory play. We added 198,000 net acres to our expansive Western Haynesville acreage position in the first quarter, increasing our total acreage position in the play to over 450,000 net acres. Since we last reported earnings, we have turned 4 additional wells to sales in the Western Haynesville and now have 12 successful wells in our new play. The Glass, Farley, Harrison, and Ingram Martin wells were all completed in the Haynesville shale, and each had IP rates of 35 million to 38 million cubic feet per day. We currently have 2 rigs running in the play, both of which are drilling on 2 well pads. We continue to lower our cost to drill these wells. In our last well, we were able to reduce the drilling days to 54 days. I'll now have Roland go over the first quarter financial results.

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. On 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. 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 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 2025, at an average swap price of $3.51, and then we added 150 million a day of collars in 2025, with a floor price of $3.50 and an average ceiling price of $3.80. We've also hedged some in 2026, and we have 250 million a day of collars that we added for 2026, which had a floor price of $3.50 and an average ceiling price of $3.98. So as a result of this activity, we're almost 50% hedged for the fourth quarter of this year, and we're about 1/3 hedged for each of 2025 and 2026. So we'll continue to look to opportunistically add to our hedge positions over time in order to get close to that 50% hedge target that we have, and we continue to put in positions that give us very meaningful floor protection, and as you can see, that's kind of sitting around the $3.50 area. On Slide 7, we detail our operating costs per Mcfe and our EBITDAX margin in the first quarter. Our operating costs averaged $0.76 per Mcfe produced, which was $0.05 lower than our fourth quarter rate. We saw some improvement in our production and ad valorem taxes, which were down 10%, but our other costs were up a little bit to slightly offset that. Our EBITDAX margin after hedging came in at 68% in the first quarter. That was a similar margin to the margin that we had in the fourth quarter, despite the fact that we had lower prices in the first quarter of this year. On Slide 8, we recap our spending on drilling and other development activity for the quarter. We spent a total of $256 million on our drilling activities, including $252 million that directly relates to the Haynesville and Bossier shale drilling program. And then we only spent $4 million on other development activity in the quarter.

Thank you, Roland. On Slide 10, we present our current drilling inventory at the end of the first quarter. We currently have a total operated inventory of 1,702 gross locations and 1,296 net locations, which yields a 76% average working interest. For our non-operated inventory, there are 1,254 gross locations and 165 net locations, resulting in a 13% average working interest. The drilling inventory is divided between Haynesville and Bossier locations, categorized into four groups: short laterals up to 5,000 feet, medium laterals from 5,000 to 8,500 feet, long laterals from 8,500 to 10,000 feet, and extra long laterals over 10,000 feet. In our gross operated inventory, we have 278 short laterals, 348 medium laterals, 433 long laterals, and 643 extra-long laterals. This inventory is fairly split, with 51% in the Haynesville and 49% in the Bossier. 63% of our gross operated inventory features laterals longer than 8,500 feet, and 38% of the inventory, comprising 643 locations, has lateral lengths exceeding 10,000 feet. The average lateral length in our inventory now measures 9,015 feet, which is a slight increase from 8,971 feet at the end of the fourth quarter. Given our immediate activity levels, this inventory offers us over 30 years of future drilling sites. Slide 11 provides a chart showing our progress on average lateral lengths drilled for the wells we have turned to sales. In the first quarter, we turned 18 wells to sales, achieving an average lateral length of 9,229 feet, with individual lengths ranging from 4,228 feet to 14,308 feet. Our record for the longest lateral still stands at 15,726 feet. Out of the 18 wells we turned to sales this quarter, 12 had laterals exceeding 8,500 feet, including four with lengths longer than 13,500 feet. As previously mentioned, our average lateral length of 9,229 feet this quarter indicates a shift from the previous upward trend due to a few short laterals drilled in isolated sections to preserve acreage amidst low gas prices. We do not plan to drill any more short lateral wells, and we anticipate that our average lateral length will exceed 10,000 feet for the remaining wells we turn to sales this year. Among the 18 wells we turned to sales this quarter, four located on our Western Haynesville acreage had an average lateral length of 9,608 feet. To summarize our longer lateral wells, we have drilled 91 wells with laterals exceeding 10,000 feet and 33 wells with laterals over 14,000 feet. Slide 12 recaps our new well activity since our last update in mid-February. We have turned to sales and tested 14 new wells since the last conference call, which had individual IP rates from 9 million to 38 million cubic feet a day, with an average test rate of 25 million cubic feet a day. The average lateral length was 8,031 feet, with individual laterals ranging from 4,228 feet to 14,137 feet. Since our last call, we've turned 4 additional wells to sales in the Western Haynesville. The Glass, Farley, Harrison, and Ingram Martin wells achieved IP rates between 35 million and 38 million cubic feet a day, all targeting the Haynesville shale.

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 expected 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 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 data 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. The main difference lies in the larger reserves we're discovering in the Western Haynesville, but it takes more time to extract them. We're not producing the Western Haynesville wells at twice the rates of the traditional Haynesville. We could potentially do that, but we are opting not to in this early stage, particularly in the current low-price environment. Overall, we believe the returns are quite similar right now when compared to the best parts of our traditional Haynesville, and the pricing is superior to our Tier 2 and Tier 3 areas of the Haynesville. However, it's a longer-term investment for the future. We are genuinely encouraged by the performance of the wells and the estimated ultimate recoveries they seem to be achieving over the long run.

Derrick, we currently have 11 to 12 wells producing, and we've only recently started drilling 2 wells per pad. Furthermore, we have only had 1 well that has been in production for over 2 years. It's still early in this play, but what we have observed so far is impressive, whether we look at initial production rates, the minimal decline, or estimated ultimate recoveries. In any new play, I think we can all agree that the resource exists. The real question is whether we can extract it economically. In any development work in a play like the core of the Haynesville back in 2008, more wells drilled generally lead to reduced costs. Dan has done a commendable job; our initial wells took 80 days to drill, but the most recent one only took 54 days. Costs are decreasing, and we're improving continuously.

I’d like to point out that when you compare the two areas, the costs in the core are relatively stable. We have a good understanding of what those costs will be, assuming there are no issues. While there are minor improvements being made, the situation is different in the Western Haynesville, where the initial costs have decreased significantly. This reduction in costs is positively affecting the economics there, whereas the core costs remain somewhat fixed since we've been optimizing 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 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 held-by-production; 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 protect 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 protect that acreage. Good questions. Thank you, Derrick.

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 increase volumes. We have a lot of potential customers approaching us, including some data centers looking to establish operations with reliable supply and power. This adds an exciting new dimension to the LNG demand and other industrial users, such as power generators. We anticipate significant shifts, especially with respect to our Western Haynesville, as we expect to sell a lot of that gas directly to customers and potentially leverage our midstream partnerships to develop necessary infrastructure. This area is very promising for us, and we aim to build a diverse customer base while reducing sales to marketing companies or aggregators. LNG will be an important part of this strategy, and we are cultivating promising relationships there, along with engaging other industrial users and utilities as part of our customer base.

If you look at that, too, over 90% 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 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 one-time 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. We think we've secured all the parameters, we're just cleaning up the infield.

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.

We have several developments in the Western Haynesville. The depth is greater, and the vertical hole section features a significantly thick formation. We have improved the bits we use, which has enhanced our rate of penetration in that area, even though it takes several days. This has contributed to our progress. Additionally, we have adjusted our casing design slightly, which has saved us some time. In the lateral section, we've consistently mentioned how temperature plays a crucial role, and we have seen significant advancements that enable us to manage the temperature effectively. We are still refining these improvements, and we anticipate further reductions in drilling days as we move forward from our current position.

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 start with the last part. We haven't gone too deep into planning full-scale development since that is still some time away. Our plan is to drill out the acreage to secure it. We have a few single wells left to drill, but we are also drilling with 2-well pads. For the completion design, we used a larger fracking design on the last well we turned to sales, the Ingram Martin. It was a larger job. The perforation cluster spacing and the number of perforations remained the same, but we increased the loading with more water and more sand. We wanted to start the clock and see how this well performs compared to the first 11 we turned to sales. There are no significant changes in our completion design here versus in the core area. We will continue to gather production data and see what it indicates. Depending on the data, we may need to make adjustments, but for now, I think our current approach is working well, so we are not planning any drastic changes at this time.

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.

We dropped two rigs because we didn't need as many frac crews. It's a challenge with the number of rigs decreasing significantly, and we've managed to negotiate better pricing due to the reduced frac activity. We have a strong relationship with our current frac provider, which has likely contributed positively to the pricing we've established for the remainder 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 to keep a close eye on the situation. We are dealing with not just fluctuating NYMEX prices, but also spot prices that can change significantly based on gas demand and location. We occasionally implement strategic shut-ins for a day or two if the spot prices are unfavorable. We will keep monitoring and responding to these situations. At times, we have postponed turning wells to sales to avoid unfavorable market conditions at the beginning of the month. Our aim is to manage effectively and maximize our returns in this challenging environment. We still have the flexibility to adjust the number of rigs we are operating and defer well turnarounds. These options are part of our strategy as we prepare for the anticipated weakness over the next six months, while also wanting to maintain the ability to benefit from higher prices, which we have already started to secure 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 long-term frac commitments. So we can toggle those. And our frac providers have been very, very pro-Comstock, 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.

There have been a lot of interesting questions that made me think. Now that you are a little beyond the two-year mark for your first Western Haynesville well, I'm curious if there have been any surprises in the type curve as you've gathered more data. Considering the adjustments you've made to drilling completions since then, do you anticipate that the type curve of the first well will be representative of what you expect to see in the more recent wells? I'm just trying to understand if you feel like you've established a working benchmark moving 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.

Noel, I would like to mention that our initial wells were from the Bossier field because we aimed for a slightly shallower and less complex drilling process. However, we have gained the confidence to drill in the Haynesville area. We believe our latest Haynesville wells are performing better from the start, although they don't yet have the two years of performance data that our first Bossier well does. What excites us is that the Haynesville seems to perform better overall in Louisiana. The rock quality is superior, and the completions are more effective than those in the Bossier. We are enthusiastic about the potential of our upcoming Haynesville wells. Currently, we are mainly focusing on the Haynesville formation rather than the Bossier, and I believe we have around six Bossier wells, making it almost even with the twelve.

Yes, that's correct. So far, we are about evenly split between Bossier and Haynesville in terms of wells turned to sales. However, we have focused more on the Haynesville wells this year. We expect to have a total of 9 wells turn to sales this year, with 7 of those being Haynesville and only 2 being Bossier. Initially, we were concerned about the high temperatures, so we targeted the Bossier wells to increase our chances of success and improve drilling performance. But now, we've made significant progress in managing the temperatures, making the Haynesville a much less challenging option 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?

These wells are costly, and it's important to avoid placing them too closely together to minimize interference. The margin for error is tighter in deeper plays with more expensive wells. We have seen some promising thickness in the formation. A good question was raised earlier about our plans for future development, specifically regarding how many wells we can stack and the appropriate spacing. We are eager to obtain results from our last well with a larger fracking job to understand what recovery we can achieve, as this will influence spacing as well. However, we cannot definitively determine the exact spacing for future wells at this moment; we need to analyze the type curves and the results we gather.

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

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?

Regarding pad size, we have drilled at multi-well pads in the core and Western Haynesville area. The largest pad we've constructed is approximately 500 by 700 feet. If we decide to drill more wells from those pads in the future, we can expand them as needed.

You probably just didn't have any wells per pad to look at. Obviously, you had both the Bossier and the Haynesville play. Given our vast acreage, we're able to go in both directions from the pad, rather than just one. It seems like we're really targeting 10,000-foot laterals as an optimal area. I think there will be 10,000-foot laterals and multiple benches in each of the Haynesville and Bossier, potentially allowing us to drill from both directions from a pad. This means we could have a significant number of wells on a pad in the future, which creates many efficiencies, including for midstream hookups.

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 formation 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.

We do have some additional sections that will come up. We are going to drill one of these horseshoe wells later this year, and we're looking forward to trying that. However, we don't have many of these isolated sections left where we anticipate any 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 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, 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.