Comstock Resources - Q1 2024

Executive Summary

• Q1 2024 results were pressured by weak gas prices: total revenues fell to $335.8M, diluted EPS was $(0.05), and adjusted EPS was $(0.03); hedged operating margin held at 68% despite lower realized prices.
• Liquidity strengthened via $100.5M private placement to the majority stockholder in March, a $400M senior notes offering in April, and reaffirmed $2.0B borrowing base; pro forma liquidity reached ~$1.3B.
• Western Haynesville continued to deliver strong well results (35–38 MMcf/d IP), and Comstock added 198K net acres (now >450K net) largely HBP, enabling a measured development pace through low-price conditions.
• Guidance: Q2 D&C CapEx $200–$250M; FY D&C CapEx unchanged at $750–$850M; lease acquisition outlook raised to $70–$80M for FY; cash interest expense tweaked higher post notes; tax deferral expectation increased to 98–100%.
• Near-term stock catalysts: continued Western Haynesville well performance and cost reductions, hedge additions through 2026 (~1/3 hedged for 2025–2026; ~50% in Q4’24), and disciplined activity/turn-in-line timing to optimize realizations in a “weak spot price” environment.

What Went Well and What Went Wrong

• What Went Well

  • Strong Western Haynesville well IPs and expanding footprint: four Haynesville wells with 35–38 MMcf/d IP; acreage increased by 198K net to >450K net, mostly HBP, supporting long-term inventory and controlled development.
  • Cost discipline and margin resilience: production cost per Mcfe fell to $0.76; hedged operating margin held at 68% despite lower prices; EBITDAX margin after hedging was 68%.
  • Balance sheet and liquidity actions: $100.5M equity infusion from Jones family, $400M 2029 notes, $2.0B borrowing base reaffirmed; pro forma liquidity ~$1.3B.

• What Went Wrong

  • Pricing headwinds drove GAAP and adjusted losses: realized gas price fell to $2.06/Mcf (incl. hedging $2.40), total revenues declined to $335.8M, GAAP diluted EPS $(0.05), adjusted EPS $(0.03).
  • Gas services margin turned negative in Q1: gas services revenue $47.8M vs expenses $48.7M, margin $(0.9)M versus positive margins in prior quarters.
  • Higher DD&A and interest burden: DD&A rose vs prior year; cash interest expense guide increased modestly post April notes offering.

Transcript

Operator (participant)

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 Q&A session. To ask a question during the session, you will need to press star one one on your telephone. You will then hear an automated message advising your hand is raised. To withdraw your question, please press star one one 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.

M. Jay Allison (Chairman and CEO)

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 am 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 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 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 four new Western Haynesville wells to sales.

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 net acre play later in the call. On March 25, the Jones family purchased an additional $145 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're 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 three, we'll summarize the highlights of the first quarter. The financial results continued 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 $145 million to our liquidity with a private placement of equity with our major stockholder, Jerry Jones, who continued to have strong results from our drilling program.

In the first quarter, we drilled 16 successful operated Haynesville and Bossier Shale horizontal wells in the quarter, with an average lateral length of 9,845 feet, and we turned to sales 18 successful operated Haynesville and Bossier Shale horizontal wells with an average IP rate of 27 million cubic feet per day and an average lateral length of 9,227 feet. We're continuing to progress in our Western Haynesville exploratory play. We added 198,000 net acres to our expansive Western Haynesville acreage position in the first quarter, increasing our total acreage position in the play to over 450,000 net acres.

Since we last reported earnings, we have turned four 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-38 million cubic feet per day. We currently have 2 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 result. Roland?

Roland O. Burns (President and CFO)

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 NYMEX settlement price averaged $2.24, which was 17 cents 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 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 amount that we've 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/Mcf. We added 75 million a day of swaps just for 2025 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 hedged 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 hedged positions over time in order to get close to that 50% hedged 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 cost per Mcfe and our EBITDAX margin in the first quarter. So our operating cost averaged to $0.76/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 eight, we recap our spending on drilling and other development activity.

You know, 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 operated wells to sales in the quarter. These wells had an average IP rate of 27 million per day. In the quarter, we also 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 on our credit facility, giving us $2.7 billion in total debt, including our outstanding senior notes. As Jay referenced, we 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 cost 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.

Then lastly, on April 30th, our bank group reaffirmed our borrowing base at $2 billion, and then our elected commitment of $1.5 billion remained the same. So I'll now turn the call over to Dan to discuss the operations in more detail.

Daniel S. Harrison (COO)

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 Haynesville and Bossier locations. We have it split down into our four different groups.

Our short laterals are up to 5,000 feet long, medium laterals at 5,000-8,500 feet, long laterals at 8,500-10,000 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 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, 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 sales. During the first quarter, we turned 18 wells to sales 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.

12 of the 18 wells we turned to sales during the quarter had laterals exceeding 8,500 feet, including four with laterals longer than 13,500 feet. As I mentioned, Roland 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, 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 four wells that are located on our Western Haynesville 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 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 four additional wells to sales in the Western Haynesville. The Glass, Farley, the Harrison, and the Ingram Martin wells achieved IP rates of 35 million-38 million cubic feet a day, and all four of these wells targeted the Haynesville Shale. Regarding our current activity levels, we are now running five rigs, and this is after we dropped three rigs during the first quarter, and we are running two full-time frac crews. Two of these five rigs are currently drilling in the Western Haynesville, 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 Haynesville rigs drilling on two well pads, we will not have any additional wells turning to 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 benchmark 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, and eight of these 14 wells fell into our benchmark long lateral group. In the first quarter, our D&C 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 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. 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 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 kg of CO2 equivalent per BOE of production. This is a 1% improvement versus 2022, and 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 Haynesville. In addition, our turn-to-sales lateral feet increased by 15% in 2023. Adjusting for lateral length 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 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 gas as responsibly sourced.

Our natural gas and 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 2021, down to just 994 metric tons in 2023. I'll now turn the call back over to Jay.

M. Jay Allison (Chairman and CEO)

All right, thank you, Dan. 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, by reducing our rig count 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%-41% from the 2023 level. We suspended our quarterly dividend, saving approximately $140 million a year of dividend payments.

In late March, our majority stockholder, 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. 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 and 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. Then 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 is, to date, has shown great promise.

I'll now have Ron provide some specific guidance for the rest of the year. Ron?

Ronald E. Mills (VP of Finance and Investor Relations)

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 D&C side is expected to be $200 million-$250 million, and our full year D&C CapEx guidance remains unchanged at $750 million-$850 million. The lower D&C 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 million-$5 million in the second quarter and $70 million-$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-$40 million in the second quarter and $125 million-$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%-25%, but now we expect to defer 98%-100% and really almost virtually 100% of our reported taxes this year, which is up from the prior range of 95%-100%. I'll now turn the call back over to Andrea to answer questions from analysts who cover the stock.

Operator (participant)

Thank you. At this time, we will conduct a Q&A session. As a reminder, to ask a question, you will need to press star one one on your telephone and wait for your name to be announced. To withdraw your question, please press star one one again. Please stand by while we compile the Q&A roster. Our first question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield (Managing Director)

Good morning, all, and thanks for your time.

M. Jay Allison (Chairman and CEO)

Morning.

Derrick Whitfield (Managing Director)

I have two 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 wanted 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 Haynesville is being developed at a cost that's about 2x out of your legacy Haynesville, with a recovery that's about 3.5-4 Bcf per 1,000 foot in that ballpark. So that's 3,000 per foot for, let's call it, 3.5-4 Bcf per 1,000 foot of EUR.

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%-100% more gas. Is that fair? And again, I'm just trying to frame the opportunity as we know it today.

Roland O. Burns (President and CFO)

Yeah, 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 to not 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 type of return right now compared to the best part of our traditional Haynesville and priced superior to our tier two, tier three part of the Haynesville. But it's longer-term. It's an investment in the future. And so 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.

M. Jay Allison (Chairman and CEO)

Yeah, and Derrick, I'd comment, you know, we have 12, 11-12 wells turned to sales, and we've only started drilling 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? And in any birth 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. These costs are coming down, and I think we're getting better and better and better. Dan?

Daniel S. Harrison (COO)

Yeah, I'd just add that, 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, absent any problems. And 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 cost, like you mentioned, that's where we started. Those costs are coming down, right? So on the Western Haynesville 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 for a while.

M. Jay Allison (Chairman and CEO)

Well, Derek, the core goes from anywhere from 1.2 to maybe 2.2, and 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 de-risk in the Western Haynesville 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.

Derrick Whitfield (Managing Director)

Terrific color. 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?

M. Jay Allison (Chairman and CEO)

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 2020, 2025, 2026, 2027, 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 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.

Derrick Whitfield (Managing Director)

Very helpful. Thanks for your time.

M. Jay Allison (Chairman and CEO)

Yeah, good question. Thank you, Derrick.

Operator (participant)

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

Bertrand William Donnes III (Financial Analyst)

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 really taking a direct, maybe long-term agreement with, you know, a plant or something like that? And maybe could you tie in Quantum, a midstream build-out for that purpose?

Roland O. Burns (President and CFO)

Yeah, that's a great question. And we're really excited about the Western Haynesville as we build volumes, because it's got, there's a lot of potential customers that are approaching us and, 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, because, yeah, to our direct customers.

And then potentiallyusing 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, so.

M. Jay Allison (Chairman and CEO)

Well, if you look at that, too, 90+% of our Western Haynesville is undedicated. So that, 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.

Bertrand William Donnes III (Financial Analyst)

That's a really good point about. On 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?

M. Jay Allison (Chairman and CEO)

Well, I think come August, it'll be four years that we've had a group of landmen leasing acreage in this area. 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 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. That was a big acquisition, 2022, that we made, and we picked up the Pinnacle plant and that 145-mile high-pressure pipeline. And then this year, we're 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 rearview mirror, they're closed. 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.

Bertrand William Donnes III (Financial Analyst)

I appreciate the answers. Thanks, guys.

Operator (participant)

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

Jake Roberts (Director)

Morning.

M. Jay Allison (Chairman and CEO)

Morning.

Jake Roberts (Director)

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 could expect to see to get those days to drill lower or cost lower.

Daniel S. Harrison (COO)

Yeah, this is, we've got kind of two things working in the Western Haynesville. You know, obviously, the depth, it's deeper. The vertical hole section has 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, 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.

M. Jay Allison (Chairman and CEO)

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. Both of those metrics are going in the right direction.

Roland O. Burns (President and CFO)

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 the temperature being a key, the multi-well drilling pads will should end up providing efficiencies like they do in all the plays, as well.

M. Jay Allison (Chairman and CEO)

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 Haynesville wells. So you're, it's a little bit of the difference in drilling as you de-risk both the Bossier and the Haynesville.

Jake Roberts (Director)

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 12 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.

Daniel S. Harrison (COO)

Oh, that's a really good question. You know, I'll kind of start with the last question. Full field development, that's, I'd say 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 doing. We still have a few singles to drill, but, we're drilling as many two well pads as possible. On the completion design, we did, we have pumped a larger frack design on this last well that we turned to sales, the Ingram Martin, just a larger job.

The perforation, the cluster, the cluster spacing, number of personnel, 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's gonna perform versus the first 11 that we turned to sales. Nothing really, 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 kind 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 we're just not looking to do anything drastic right now.

Jake Roberts (Director)

Thank you very much. Appreciate the time.

M. Jay Allison (Chairman and CEO)

Thank you.

Operator (participant)

Thank you. One moment for our next question. Our next question comes from Ati Modak with Goldman Sachs. Please go ahead.

Atidrip Modak (VP of Energy Services)

Hi, good morning, team, and thanks for taking my question. It seems like you moved more, 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?

M. Jay Allison (Chairman and CEO)

Well, we've dropped the two rigs. We didn't have a need for as many frac crews, but we did, you know, it's obviously a squeeze on the frac crews, right? With the number of rigs dropping dramatically. We have obviously gotten some concessions on pricing just due to the frac activity. 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.

Atidrip Modak (VP of Energy Services)

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?

Roland O. Burns (President and CFO)

We continue, of course, to monitor that, and we've had, we have, not only, fairly volatile NYMEX prices, but also spot prices that can be, you know, very volatile during the months based on, yep, how much gas is needed and where. So, yeah, there, there's definitely, we strategically do some shut-ins every now and then. It's usually for a day or two, 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 and wait for a 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 kind of look to navigate these next upcoming six months of expected weakness. At the same time, wanting to preserve the company's, preserve company's ability to benefit from the stronger prices, which we've already started to lock into starting in the fourth quarter.

M. Jay Allison (Chairman and CEO)

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

Atidrip Modak (VP of Energy Services)

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

Operator (participant)

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

Noel Parks (Managing Director of CleanTech and E&P)

Hi, good morning.

M. Jay Allison (Chairman and CEO)

Hi, Noel.

Noel Parks (Managing Director of CleanTech and E&P)

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

M. Jay Allison (Chairman and CEO)

Well, when we started drilling the first well over two years ago, two and a half years ago, we felt comfortable, Noel, that the resource was there. 'Cause there was a major field, all this acreage that we now have had secured. It's 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 2007, 2008, can you use this technology there to really drill a shale play with the Bossier and Haynesville? And we've proved that it was in 2008, 2009 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'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 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 2008, 2009, 2010, 2011. If you were to look at those first wells that you, you'd have an upset stomach. They weren't very good wells in 2008, 2009. 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 2008. 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, 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.

Roland O. Burns (President and CFO)

Noel, I would add, our first wells were Bossier Shale wells because we were targeting, that we, a little shallower, a little less complex to drill. But we've got the confidence to drill the Haynesville, and we think that our latest wells, being Haynesville wells, I mean, we think they're coming out of the gate stronger. But, yeah, they don't have the, they don't have the two years of proof that the first Bossier well has. But that's what really excites us, is the fact that the Haynesville. Just like it, the Haynesville's better in Louisiana, too. It's 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 well has, and we're really focused.

You can see most of the wells, we're focused now on the Haynesville formation and the play, versus the Bossier. I think we have, what, six Bossier wells? And I think we're almost half and half, of the 12.

Daniel S. Harrison (COO)

Yeah, that'd be right. To date, turned to sales, we basically are about half and half on Bossier and Haynesville. So we will have, I'll say we will, we've leaned in heavier on the Haynesville wells this year. I think we're gonna have a total of nine wells turned to sales this year. Seven of those will be Haynesville, just two will be Bossiers. 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.

Noel Parks (Managing Director of CleanTech and E&P)

Great. Thanks for the detail. I was just wondering, is it the formation being deeper, I noticed, does that affect the spacing at all? Is there a lot of question about what, ultimately, sort of, sort of the density you would be pursuing in the Western Haynesville?

Daniel S. Harrison (COO)

Sure. I mean, obviously, these wells are expensive, and, you, you, you're gonna 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 gonna have as big of a margin for error for that in a play where you're deeper and got more expensive wells. But, we've got, I mean, some of this stuff is really thick. And 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, with that task to solve is, how many, how many, 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, because that obviously will also affect the spacing. But really, to answer your question, we do not know what that exact spacing is gonna 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.

M. Jay Allison (Chairman and CEO)

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

Noel Parks (Managing Director of CleanTech and E&P)

Wow! Okay. Great point. Thanks a lot.

Operator (participant)

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

Paul Diamond (Equity Research Analyst)

Thank you, and good morning, all. Thanks for taking my call. I just wanna touch quickly, staying in the Western Haynesville. Once you move beyond, held by production needs, where do you see the pad size going? And I guess, how much does that impact economics over the longer term?

Daniel S. Harrison (COO)

I didn't catch the full question there.

Paul Diamond (Equity Research Analyst)

Oh, sorry. When you get beyond the held by production needs, and you can, how big do you see the pad size getting out in Western Haynesville?

Daniel S. Harrison (COO)

Oh, pad size?

Paul Diamond (Equity Research Analyst)

Yeah.

Daniel S. Harrison (COO)

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, our pad. 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.

Roland O. Burns (President and CFO)

He's probably interested in how many wells per pad could we look at. Obviously, you have 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, 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 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.

Daniel S. Harrison (COO)

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, and 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.

M. Jay Allison (Chairman and CEO)

Along those same line is takeaway. Were 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 that's 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 we've you know, if you capture this amount of acreage, it's, say, $600 or less. So 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. But then you say, "Well, is the pay thickness there?" The answer is, we think yes. And, has the well performance, been positive? And the answer is yes.

Paul Diamond (Equity Research Analyst)

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 are you likely to include additional wells, similar to the four Bossier ones you drilled in Q1, that are kind of required to hold the acreage?

M. Jay Allison (Chairman and CEO)

Can you ask that again?

Paul Diamond (Equity Research Analyst)

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

Daniel S. Harrison (COO)

There's no more. So, yeah. 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 gonna drill one of these, horseshoe wells later this year. I'll go ahead and kind of tell you that. That's kind of something that we're looking forward to trying, but, we don't have many of the, we don't have many of these isolated sections left where we'll have any of those issues.

M. Jay Allison (Chairman and CEO)

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.

Roland O. Burns (President and CFO)

We're excited about the horseshoe design, and it could eliminate the 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's, that'll be kind of an exciting thing to do here later in the year.

Paul Diamond (Equity Research Analyst)

Understood. Thanks for the clarity.

Roland O. Burns (President and CFO)

'Cause we do believe that shorter laterals in the basin, Haynesville are definitely our lowest return projects, just because of the so much cost into the well and the reserves you recover with only the shorter lateral. So that, so the ability to eliminate a lot of those out of our inventory and turn them into long is, it will be very enhancing.

Paul Diamond (Equity Research Analyst)

Much appreciated.

Operator (participant)

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.

M. Jay Allison (Chairman and CEO)

Hey, 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 Haynesville Shale operations, including our Western Haynesville area. So, we're gonna 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 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 Comstock, so we're thankful for that. Thank you for your time.

Operator (participant)

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