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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 also reduced our drilling days to 54. Dan Harris 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, responsible-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 [ charged 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 (sic) [ 9,229 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. And 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. Roland?

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 ], at an average swap price of $3.50 (sic) [ $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 kind of 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. So 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. We drilled 16, or 14.3 net, wells in our Haynesville program, and we turned 18, or 16.3, operating wells to sales for the quarter. These wells had an average IP rate of 27 million per day. In the quarter, we also -- we did have 4 short lateral Bossier wells which were drilled, which probably dilute the numbers a little bit, but they were drilled to hold acreage. On Slide 9, we recap our balance sheet at the end of the first quarter. We ended the quarter with $540 million in borrowings outstanding on our credit facility, giving us $2.7 billion in total debt, including our outstanding senior notes. As Jay referenced, on March 25, we sold 12.5 million shares to our majority stockholder for $100.5 million in a private placement. The proceeds from that offering helped offset some of the costs of our Western Haynesville acreage acquisition program. Just after the end of the first quarter, we issued $400 million of additional senior notes due in 2029, and we used the proceeds to pay down the borrowings under our bank facility. The bond offering increased our liquidity on a pro forma basis to $1.3 billion. And lastly, on April 30, our bank group reaffirmed our borrowing base at $2 billion. And then our [ elected ] commitment of $1.5 billion, that kind of remains the same. So I'll now turn the call over to Dan to discuss the operations in more detail.

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 up to 14,308 feet. Our record longest lateral still stands at 15,726 feet. 12 of the 18 wells we turned to sales during the quarter had laterals exceeding 8,500 feet, including 4 with laterals longer than 13,500 feet. As I mentioned earlier, our 9,229-foot average lateral length this quarter represents a departure from the upward trend we've been on for the last several years, and this is due to a handful of short laterals that were drilled on some isolated sections to preserve acreage while we're in this low gas price environment. We're not planning to drill any additional short lateral wells, and we do expect our average lateral length will exceed 10,000 feet for the remaining wells that we turn to sales this year. Included in our 18 wells turned to sales for the quarter are 4 wells that are located on our Western Haynesville acreage, and these 4 wells had an average lateral length of 9,608 feet. So to recap our longer lateral wells, we have drilled -- to date, we have drilled 91 wells with laterals over 10,000 feet, 33 wells with laterals over 14,000 feet. On Slide 12, we recap our new well activity since we last provided our well results in mid-February. We have turned to sales and tested 14 new wells since our last conference call. This group of wells had individual IP rates ranging from 9 million up 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 the individual laterals ranging from 4,228 feet up to 14,137 feet. Since our last call, we have turned 4 additional wells to sales in the Western Haynesville. The Glass, the Farley, the Harrison and the Ingram Martin wells achieved IP rates of 35 million to 38 million cubic feet a day, and all 4 of these wells targeted the Haynesville shale. Regarding our current activity levels, we are now running 5 rigs; this is after we dropped 3 rigs during the first quarter. And we are running 2 full-time frac crews. 2 of these 5 rigs are currently drilling in the Western Haynesville, and both of these rigs are now drilling on the first of our 2 well pads, which will yield increased efficiencies. Now that we have our 2 Western Haynesville rigs drilling on 2 well pads, we will not have any additional wells turn into sales in the Western Haynesville until early in the fourth quarter. Slide 13 summarizes our D&C costs through the first quarter for our benchmark long lateral wells. This is wells located in our legacy core East Texas and North Louisiana acreage. Our [indiscernible] wells cover all laterals greater than 8,500 feet long. During the quarter, we turned 14 wells to sales that were on our core acreage. 8 of these 14 wells fell into our [ benchmark ] long lateral group. In the first quarter, our D&C costs averaged relative $1,501 per foot on these benchmark wells, which reflects a 1% increase compared to the fourth quarter of last year. Our first quarter drilling costs averaged $714 a foot, which is a 17% increase compared to the fourth quarter. The higher drilling costs were primarily a result of all 8 of our benchmark long lateral wells during this quarter being concentrated in our higher drilling cost areas. Our first quarter completion costs came in at $787 a foot, and this represents a 10% decrease compared to the fourth quarter. And this mainly stems from the lower gas prices, which has led to the lower basin-wide completion activity and lower frac costs. As stated earlier, we did drop the 2 rigs during the first quarter, and we are now running 5 rigs. Our current outlook has us holding steady at 5 rigs for the remainder of the year. On the completions side, we are today running the 2 full-time frac crews, and we will stay at this level through the end of the second quarter. However, with the lower rig activity, we anticipate only working the equivalent of 1.5 frac crews during the second half of the year. On Slide 14, we highlight our continued improvement related to greenhouse gas and methane emissions. We reported a greenhouse gas intensity of 3.45 kilograms CO2 equivalent per BOE of production. This is a 1% improvement versus 2022, increasing the improvement to 4% over the past 2 years. We reported a methane emission intensity of 0.04%, which is an 11% improvement versus 2022 and a 26% improvement over the past 2 years. We achieved those emissions improvements despite our increased focus on the higher-intensity Western Haynesville. In addition, our turned to sales lateral feet increased by 15% in 2023. Adjusting for lateral length footage completed for our turned to sales wells, our greenhouse gas emissions per lateral foot turned to sales improved 16% last year and 21% over the past 2 years, while our methane emissions per lateral foot turned to sales improved 25% last year and 38% over the past 2 years. We've deployed optical gas imaging and aircraft leak monitoring technology in almost 100% of our production sites, which earned us the ability to certify our gas is responsibly sourced. Our natural gas and dual-fuel powered frac fleet eliminated approximately 10.6 million gallons of diesel by utilizing natural gas and offsetting approximately 21,800 metric tonnes of CO2 equivalent. Our dual-fuel drilling rigs eliminated approximately 460,000 gallons of diesel by utilizing natural gas and offset approximately 1,400 metric tonnes of CO2 equivalent. We have installed instrument air on approximately 97% of our newly constructed production facilities, mitigating approximately 5,500 metric tonnes of CO2 equivalent. Emissions from equipment leaks have decreased 97% since 2021. This is from 33,664 metric tonnes of CO2 equivalent emissions in '21, down to just 994 metric tonnes in 2023. I'll now turn the call back over to Jay.

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 we're building a great asset in the Western Haynesville that will be well positioned to benefit from the substantial growth in demand for natural gas in our region that is on the horizon, driven by the growth in LNG exports that begins to show up in the second half of next year. The Wall Street Journal, on January 2, 2024, tracked 120 winners and losers by looking at how selected global stock indexes, bond ETFs, currencies and commodities performed for the year 2023. NYMEX natural gas was the next-to-the-last worst performer. Now on April 1, 2024, the Wall Street Journal tracked the same group of 120. NYMEX natural gas was the worst performer for the entire group. That is stark reality over the past 15 months. So the question is how we can manage in this weak price environment and exit a much stronger company when demand for domestic as well as global natural gas arrives in 2025 and beyond. We have that answer. It is to manage our proven quality core area, continue to be a low-cost producer, continue to protect our liquidity and balance sheet and now continue to develop our 450,000 net acre Western Haynesville play that to date has shown great promise. I'll now have Ron provide some specific guidance for the rest of the year. Ron?

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.