Comstock Resources, Inc.

Good day and thank you for standing by. Welcome to the Comstock Resources, Inc. first quarter 2024 earnings conference call. At this time, all participants are in a listen-only mode. After the speaker's presentation, there will be a question and answer session. To ask a question during the session, you will need to press star 1 1 on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star 1 1 again. 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. Here you'll find a presentation entitled First Quarter 2024 Results. I have Jay Allison, Chief Executive Officer of Gompstock, 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 Best Relations. Please refer to slide two on our presentations 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 three. Our corporate team of 255 strong 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 week 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 15th, we closed on an acquisition that enabled us to add 198,000 net acres to our Western Hainesville place 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 four new Western Angel wells to cells. Each one looks fantastic. We're now drilling on two 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 that acre played later in the call. On March the 25th, the Jones family purchased an additional $100.5 million of Comstock stock that demonstrated their confidence in our business plan, including the Western Hainesville acreage acquisition. On April the 2nd, 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 the 30th, 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're well positioned to deliver clean, responsible, produced natural gas from our 800,000 net acres in the Hainesville. We have over 30 years of building inventory, which we are adding to as we unlock value in our 450,000 net acres in the Western Hainesville, one well at a time. Want to thank you for supporting your company, Comstock Resources. On slide three, 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 65 cents per share, and adjusted EBITDAX was $230 million. Our adjusted net loss was 3 cents 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 Hainesville 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 Hainesville and Bossier Shell horizontal wells with an average IP rate of 27 million cubic feet per day and an average lateral length of 9,227 feet. We're continuing to progress in our Western Hainesville exploratory play. We added 198,000 net acres to our expensive Western Hainesville 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 four additional wells to sales in the Western Hainesville and now have 12 successful wells in our new play. The Glass, Farley, Harrison, and Ingram Martin wells were all completed in the Hainesville and each had IP rates of 35 to 38 million cubic feet per day. We currently have two rigs running into play, both of which are drilling on two 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. Thanks, Jay. On slide four, 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 five, we kind of break down our natural gas price realization in the quarter. During the first quarter, the quarterly NIMAC settlement price averaged $2.24, which was $0.17 lower than the average Henry Hub spot price in the quarter are the daily prices of $2.41. Our realized gas price during the first quarter averaged $2.06, reflecting an 18 cent differential to the settlement price and a 23 cent 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 on our third-party marketing activities. Slide six, 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 map that we've hedged for the fourth quarter of this year. We added $300 million a day of swaps covering the period of April I mean, October 2024 through December 2026 at an average price of $3.51 for MCF. We added $75 million a day of swaps just for 25 at an average swap price of $3.50. 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 had some in 2026. 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 a third 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 seven, we detail our operating costs per MCFE and our EBITDAX margin in the first quarter. So our operating cost averaged 76 cents per MCFE produced, which was five cents 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 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 eight, 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 Hainesville 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 Haines School program, and we turned 18 or 16.3 operated wells to sales in the quarter. These wells had an average IP rate of $27 million per day. In the quarter, we did have four short lateral Bossier wells, which were drilled, which probably dilute the numbers a little bit. but they were drilled to hold acreage. On slide nine, we recap our balance sheet at the end of the first quarter. We ended the quarter with $540 million in borrowings outstanding in our credit facility, giving us $2.7 billion in total debt, including our outstanding senior notes. As Jay referenced, on March 25th, we sold 12.5 million shares to our majority stockholder for $100.5 million in in a private placement. The proceeds from that offering helped offset some of the cost of our Western Hainesville 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-forum basis to $1.3 billion. Lastly, on April 30th, our bank group reaffirmed our borrowing base at $2 billion, and then our elected commitment of $1.5 billion kind of remained 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 slide 10, this is our current drilling inventory that we have where we're at at the end of the first quarter. Our 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 non-operated inventory, we have 1,254 gross locations and 165 net locations, which represents a 13% average. working interest on the non-operated inventory. The drilling inventory is split between Hainesville and Bossier locations. We have it split down into our four 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. And this gross operated inventory is evenly split with 51% in the Hainesville 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, or 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 length drilled based on the wells that we have turned to cells. During the first quarter, we turned 18 wells to cells with an average lateral length of 9,229 feet. The individual lengths range from 4,228 feet up to 14,308 feet. Our record longest lateral still stands at 15,726 feet. Twelve of the 18 wells we turned sales during the quarter had laterals exceeding 8,500 feet, including four with laterals longer than 13,500 feet. As Roland mentioned earlier, our 9,229 foot average lateral length this quarter represents a departure from the upper 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 return to sales this year. Included in our 18 wells turned to sales for the quarter are four wells that are located on our western Hainesville acreage. These four wells had an average lateral length of 9,608 feet. So to recap our longer lateral wells, we have drilled 91 wells. To date, we've 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 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 ran from 4,228 feet up to 14,137 feet. That's our last call. We have turned four additional wells to sales in the western Hainesville. The Glass, the Farley, the Harrison, and the Ingram-Martin wells achieved IP rates of 35 to 38 million cubic feet a day, and all four of these wells targeted the Hainesville shell. Regarding our current activity levels, we are now running five rigs. This is after we dropped three rigs during the first quarter, and we are running two full-time frack rigs. Two of these five rigs are currently drilling in the Western Hainesville, and both of these rigs are now drilling on the first of our two well pads, which will yield increased efficiencies. Now that we have our two Western Hainesville rigs drilling on two well pads, we will not have any additional wells turning to fells in the western hazel until early in the fourth quarter. Slide 13 summarizes our DNC calls through the first quarter for our benchmark long lateral wells. This is the wells located in our legacy core East Texas and North Louisiana acreage. Our benchmark wells cover all laterals greater than 8,500 feet long. During the quarter, we turned 14 wells to cells that were on our core acreage. Eight of these 14 wells fell into our benchmark long lateral group. In the first quarter, our BNC cost averaged $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 cost averaged $714 a foot, which is a 17% increase compared to the fourth quarter. The higher drilling costs were primarily a result of all eight of our Bitsmark long lateral wells during this quarter being concentrated in our higher drilling cost areas. Our first quarter completion cost came in at $787 a foot. This represents a 10% decrease compared to the fourth quarter. This mainly stems from the lower gas prices, which has led to the lower basin-wide completion activity and lower frack costs. As stated earlier, we did drop the two rigs during the first quarter and we are now running five rigs. Our current outlook has us holding steady at five rigs for the remainder of the year. On the completion side, we are today running the two 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 one and a half 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 two years. We reported a methane emission intensity of 0.04%, which is an 11% improvement versus 2022. and a 26% improvement over the past two years. We achieved those emissions improvements despite our increased focus on the higher intensity Western Hainesville. In addition, our turn to sales lateral feed increased by 15% in 2023. Adjusting for lateral link footage completed for our turn to sales wells, our greenhouse gas emissions per lateral foot turn to sales improved 16% last year and 21% over the past two years, while our methane emissions per lateral foot turn to sales improved at 25% last year and 38% over the past two years. We've deployed optical gas imaging and aircraft leak monitoring technology at almost 100% of our production sites, which earned us the ability to certify our gases responsibly sourced. Our natural gas dual-fuel powered frac fleets eliminated approximately 10.6 million gallons of diesel by utilizing natural gas and offsetting approximately 21,800 metric tons 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 tons of CO2 equivalent. We have installed instrument air on approximately 97% of our newly constructed production facilities, mitigating approximately 5,500 metric tons of CO2 equivalent. Emissions from equipment leaks have decreased 97% since 2021. This is from 33,664 metric tons of CO2 equivalent emissions in 21 down to just 994 metric tons in 2023. I'll now turn the call back over to Jay.

All right. Thank you, Ken. Thank you, Roland. I would direct you to slide 15 where we summarize our outlook for 2024. Now, we've taken a number of steps in response to significantly lower natural gas prices this year. During the first quarter, we released two of our operated rigs, as Dan said, reducing our recount to five rigs. We also released one of our frac spreads, reducing our frac fleet to two 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 position starting in the fourth quarter of 2024 and extending through 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 it. 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 Angel play, continuing to add to our extensive acreage position at this exciting play. At the end of the first quarter, our Western Angel Acres position, as we stated earlier, totaled over 450,000 net acres. We believe that we're building a great asset in the Western Angel 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 the 2nd, 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 next to the last worst performer. Then on April 1st, 2024, the Wall Street Journal tracked the same group of 120 NIMEX 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 Hainesville play that is, 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 16, we provide the financial guidance for the second quarter and the full year 2024. The second quarter capex, expected on the DNC side is expected to be $200 to $250 million, and our full year DNC CapEx guidance remains unchanged at $750 to $850 million. The lower DNC spending versus last year is related to the release of the two drilling rigs earlier this year in response to the low gas prices. With the large lease acquisitions now completed, we anticipate spending $2 to $5 million in the second quarter and $70 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 to $40 million in the second quarter and $125 to $150 million for the year, which is unchanged. On the operating cost 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.

Thank you. At this time, we will conduct the question and answer session. As a reminder, to ask a question, you will need to press star 1-1 on your telephone and wait for your name to be announced. To withdraw your question, please press star 1-1 again.

Please stand by while we compile the Q&A roster. Our first question comes from Derek Whitfield with Stiefel. Please go ahead.

Good morning, Owen. Thanks for your time. Morning. I have two questions for you, and they're both related to the Western Haines 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 industry. If we think about your cost and recovery metrics based on the breadcrumbs provided, you've noted the Western Hainesville is being developed at a cost that's about 2x out of your legacy Hainesville 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 1,000 foot of EUR recovery. So if we compare that to industry metrics of 2,000 per foot or 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 we know it today.

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

Yeah, and Derek, I'd comment, you know, we have 12, 11 to 12 wells turned to cells, and we've only started drilling, you know, two wells per pad recently, and we've only had one well that's been producing over two 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? In any birth of any play, particularly like the core of the Ainswell in 2008, I mean, the more wells you drill, the lower the cost are. I think Dan has done a good job. I mean, our first wells were 80 days to drill. Now the last one has been 54. these costs are coming down. I think we're getting better and better and better.

Dan? Yeah, I'll just add that, you know, when you compare the two areas, if you look at those, 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, you know, absent any problems. And there's, I mean, there's, you're making some small improvements here and there, but you compare that to the Western Hainesville where, if you look at the costs, like you mentioned, you know, that's where we started. Those costs are coming down, right? So, On the Western Hainesville side, you're seeing the cost really move down, which is changing the economics. And you're not really seeing that in the core. Those are kind of fixed, right? We've kind of been optimized, you know, for a while.

Well, Derek, the core goes from anywhere from 1.2 to maybe 2.2. I mean, you may see the 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 de-risk in the Western Angel is that a large portion of that acreage is competitive, if not potentially better, than the best of the best of the core. That's what we're trying to prove up.

Terrific, Keller. 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?

Yeah, on the 198,000 acres, the net acres we acquired, I'd say 95% of that's 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, 6, 7 at all. And then as far as the acres that we've leased over the last three and a half 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 at least we'd be that acreage. So we're not pushed at all to add rigs in low price environment. And even if prices are high, We're not pushed to add rigs at all to HPP that acreage.

Very helpful. Thanks for your time.

Yeah, good questions.

Thank you, Derek.

Thank you. One moment for our next question. Our next question comes from Bertrand Dons with Truist. Please go ahead.

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

Yeah, that's a great question. And, you know, we're really excited about the Western Haines cells. We build volumes because it's not – it's got – there's a lot of potential customers that are approaching us and including, you know, 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 Hainesville, 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, you know, 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, you know, 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.

Well, if you look at that too, 90 plus percent of our Western Angels are undedicated. So that's a big advantage if you're looking for gas, whether for a data center to provide power or take away as utility or LNG contracts.

That's a really good point about 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 cowboy cash in the future or is this kind of a one-time thing?

Well, I think come August will be four years that we have had a group of landmines leasing acreage in this area. And we kind of set the boundaries. And as those boundaries have expanded, we've looked at where the 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, big acquisition in 22 that we made. We picked up the pinnacle plant and that 145-mile high-pressure pipeline. And this year, we're able to close another acquisition. But I think all of the, in our opinion, all of the major acquisitions that we would be looking at, they're in our rearview 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 infill.

I appreciate the answers. Thanks, guys.

Thank you. One moment for our next question. Our next question comes from Jacob Roberts with TPH. Please go ahead.

Morning.

Morning. Maybe circling back to Derek'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 Hainesville that could also bring those costs down. Just looking for more specifics around what we could expect to see to get those days to drill lower or cost lower.

Yeah, this is, you know, we've got kind of two things working in the Western Hainesville. You know, obviously the depth, it's deeper. The vertical hull section has, you know, a really thick Travis Peak section. We've made a lot of improvements with the bits that we're using, getting better ROPs 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, you know, 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.

And 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 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 two well pads. So in addition to, you know, the temperature being a key, the multi-well drilling pads should end up providing efficiencies like they do in all the plays as well.

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

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-field development design might look like.

That's a really good question. You know, I kind of start with the last question. Full-field development, that's, I'd say... You know, we haven't got too deep into thinking about that, because that is kind of down the road a ways 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 as many two-well pads as possible. 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 perforation, 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 ourselves. Nothing really too different that we're doing on a completion design down here versus in the core. We'll just kind of continue to get our production data and we'll of depend 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 you know we're just not looking to do anything drastic right now thank you very much appreciate the time thank you thank you one moment for our next question our next question comes from ati modak with goldman sachs please go ahead hi good morning team and thanks for taking my question

It seems like you moved 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, you know, we dropped the two rigs. We didn't have a need for as many frac crews as one, but we did, you know, 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 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?

Yeah, we continue, of course, to monitor that. And we've had, you know, we have not only fairly volatile, you know, NYMEX prices, but also spot prices that can be, you know, very volatile during the months based on, you know, you know, how much gas is needed and where. So, yeah, there's definitely, you know, we strategically do some shut-ins every now and then. It's usually for a day or two. If we don't like 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 and wait for first of the month type. So we've tried 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 toolkit as we look to navigate these next upcoming six 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 starting in the fourth quarter.

I think the 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 provider has been very, very pro-Gomstock, 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.

All right. I appreciate you taking the questions. I'll turn it over.

Thank you. One moment for our next question. Our next question comes from Noel Parks with Tuohy Brothers. Please go ahead.

Hi, good morning. Hi, Noel.

A lot of interesting questions that got me thinking. And I was wondering, with your being at the two-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 completions, drilling completions since then, do you foresee that first wells type curve as being kind of representative of what you're going to see in the more recent wells? I just, in a sense of whether you're at the point you kind of think you have a working benchmark for going forward.

Well, you know, when we...

When we started drilling the first well over two years ago, two and a half years ago, we felt comfortable knowing that the resource was there. Because there was a major field, all these acres that we now have secured, it was a major field, gas field. That's why the pinnacle plant was there and the 145 mile high pressure line was there. The question was, kind of like it was in 07, 08, can use this technology there to really drill a shell play with a Bossier and a Hainesville. 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 Hainesville. But you don't know, right? I mean, the jury's still out. So as you have the Circle M well, producing eight 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 resources there, one, and then when you listen to Dan, he gives you confidence that the questions are, you know, have you changed your drilling? Have you changed your completion? We're getting better and better and better. Again, remember no group has really completed more Hainesville-Bosier 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 the 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, cost down, EUR 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, you know, our first wells were Bossier fill wells because we were targeting, you know, a little shallower, a little less complex to drill. But we've got the confidence to drill the Hainesville, and we think that our latest wells, being Hainesville wells, I mean, we think they're coming out of the gate stronger. But, yeah, they don't have the two years of proof that the first Bossier well has, but that's what really excites us, the fact that the Hainesville, just like the Hainesville's 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 Hainesville Well House, and we're really focused, you know, you can see most of the wells, we're focused now on the Hainesville formation in the play versus the Bossier. I think we have, what, six Bossier wells in Hainesville? I think we're almost half and half, you know, of the 12.

Yeah, that'd be right. We're, to date, turned to cells. We're basically about half and half on Bossier and Hainesvilles. We will have a, you know, I'll say we will, we've leaned in heavier, you know, on the Hainesville wells this year. I think we're going to have a total of nine wells turned to cells this year. Seven of those will be Hainesville. Two will be Bossier. But part of that early on was we, you know, obviously, you know, 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 Hainesville as so much of a challenge compared to the Bossier. Great. Thanks for the detail.

And I was just wondering, is it the formation being defray on those, does that affect the spacing at all? Is there a lot of question about what ultimately density you would be pursuing in the western Hainesville?

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

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

Wow. Okay.

Great point. Thanks a lot.

Thank you. One moment for our next question. Our next question comes from Paul Diamond with Citi.

Please go ahead.

Thank you, and good morning. Thanks for taking my call. I just want to touch quickly staying in the Western Hainesville. Once you've moved beyond the help by production needs, where do you see the pad size going? I guess how much does that impact economics over the longer term? I didn't catch the full question there. Oh, sorry. When you get beyond the help by production needs, how big do you see the pad size getting out in Western Hainesville?

Oh, pad size? Well, I mean, everything that we have drilled to date in the core and in the western Hainesville, you know, for multi-well pads. I mean, I think the biggest pad we built is like 500 by 700 foot, you know, for multi-well pads. You know, occasionally we'll come back and add on to those if we come back and drill additional wells off the pad.

He's probably interested in how many wells per pad could we look at. Obviously, we have both the Bossier and the Hainesville 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, 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, and maybe each of the hay and swan bosier 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.

Yeah, I'm sorry. I didn't get that. Yeah, everything that we've got targeted today is for two-well pads 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.

You know, kind of all along that same line is, Are we going to have enough takeaway in the Western Angels? 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's HPP, 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 capture this amount of acreage, let's say five 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 paint thickness there? The answer is we think yes. And has the well performance been positive? And the answer is yes.

Understood. Thanks for the clarity. Just one quick follow-up, shifting back to the core. For the rest of the 2024 operational plan, I guess what percentage of liquid include additional wells similar to the four Bozier ones you drilled in Q1 that are kind of required to hold the acreage? Can you ask that again? Sure. The 2024 operational plan, so in the first quarter there were four of those bozier wells, shorter laterals required to hold the acreage. How much of that should we expect to... There's no more.

I'll tell you, so interestingly enough, we do have some additional sections that will come up. We've actually got a... We're actually going to drill one of these horseshoe wells later this year. I'll go ahead and So 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.

Yeah, 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 horse you designed. And 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'll be kind of an exciting thing to do here later in the year. Understood. Thanks for clarity. Because we do believe that shorter laterals in the basic cane sale are definitely our lowest return projects just because of so much cost into the well and the reserves you recover with only that shorter lateral. So the ability to eliminate a lot of those out of our inventory and turn them into long will be very enhancing. Much appreciated.

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.

Jay, perfect. Again, I know everybody's time is valuable, and we thank you for sharing your time with us. 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 Hainesville shell operations, including our Western Hainesville area. So we're gonna be good stewards with your money. We wanna thank the bondholders. We wanna thank our banks that support us. We wanna thank the Joneses 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 God's talk. 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.