Comstock Resources, Inc. (NYSE:CRK) Q1 2024 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q1 2024 Earnings Call Transcript May 2, 2024

Comstock Resources, Inc. isn’t one of the 30 most popular stocks among hedge funds at the end of the third quarter (see the details here).

Operator: 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 this speaker’s presentation, there will be a question-and-answer session. [Operator Instructions] As a reminder, today’s program is being recorded. Now I’d like to hand the conference to your first speaker today, Jay Allison, Chief Executive Officer. Please go ahead.

Jay Allison: 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 will find a presentation titled first quarter 2024 results. I’m Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer; Dan Harrison, our Chief Operating Officer; and Ron Mills, our VP of Finance and Investor Relations. Please refer to Slide 2 on our presentation to note that our discussion today will include forward-looking statements within the meaning of securities laws.

While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you would turn to Slide 3. Our corporate team of 255 strong wants 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 bat them down the hatches in order to manage our assets and continue to create value during this weak period for natural gas. Our 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 $100.5 million of Comstock stock that demonstrated their confidence in our business plan, including the Western Haynesville acreage acquisition. On April 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 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 Haynesville. We have over 30 years of drilling inventory, which we are adding to, as we unlock value in our 450,000 net acres in the Western Haynesville one well at a time. I want to thank you for supporting your company, Comstock Resources. On Slide 3, we’ll summarize the highlights of the first quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and gas sales, including hedging, were $336 million in the quarter and we generated cash flow from operations of $182 million or $0.65 per share and adjusted EBITDAX was $230 million.

Our adjusted net loss was $0.03 per share for the quarter. To strengthen our balance sheet, we added $100.5 million to our liquidity with a private placement of equity with our major stockholder, Jerry Jones. We continue to have strong results from our drilling program. In the first quarter, we drilled 16 successful operated Haynesville and Bossier Shale horizontal wells in the quarter with an average lateral operated Haynesville and Bossier Shale horizontal wells with an average IP rate of 27 million cubic feet per day and average lateral length of 909,227 feet. We’re continuing to progress in our Western Angel Historic exploratory play. We added 198,000 net acres to our expansive Western Angel 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 Mark wells were all completed in the Haynesville Shale and each had IP rates of 35 million to 38 million cubic feet per day. We currently have two rigs running into play, both of which are drilling on two well pads. We continue to lower our cost to drill these wells, in our last well, we were able to reduce the drilling days to 54 days. I’ll now have Roland go over the first quarter financial results. Roland?

Roland Burns: All right. Thanks, Jay. On Slide 4, we cover our first quarter financial results. Our production in the quarter of 1.5 Bcfe per day increased 10% from the first quarter of 2023. The low natural gas prices resulted in our oil and gas sales in the quarter of $336 million declining 14% from 2023’s first quarter level despite the 10% production increase. EBITDAX for the quarter was $230 million and we generated $182 million of cash flow during the first quarter. We have reported an adjusted net loss of $8.5 million for the first quarter or $0.03 per share as compared to income of $92 million in the first quarter of 2023. Slide 5, we kind of break down our natural gas price realization in the quarter. During the first quarter, the quarterly NYMEX settlement price averaged $2.24, which was $0.17 lower than the average Henry Hub spot price in the quarter of the daily prices of $2.41.

Our realized gas price during the first quarter averaged $2.06 reflecting a $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 6. We update our hedge position. Since we last reported, we’ve been very busy adding some hedges to build out our hedge positions for next year and 2026 as well as improving our — 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 April, I mean October 2024 through December 2026, at an average price of $3.51 per Mcf.

We added $75 million a day of swaps just for ’25 at an average swap price of $3.50 and then we added 150 million a day of callers 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 selling price of $3.98. So, as a result of this activity, we’re almost 50% hedged for the length of 9,845 feet and returned to sales 18 successful operated Haynesville. 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 target that we have.

We continue to put in positions that give us very meaningful floor protection. As you can see, that’s kind of sitting around the $3.50 area. On Slide 7, we detail our operating cost per Mcfe and our EBITDAX margin in the first quarter. Our operating cost averaged $0.76 per Mcfe produced, which was $0.05 lower than our fourth quarter rate. We saw some improvement in our production and ad valorem taxes which were down 10%, but our other costs were up a little bit to slightly offset that. Our EBITDAX margin after hedging came in at 68% in the first quarter, that was a similar margin that we had in the fourth quarter despite the fact that we had lower prices in the first quarter of this year. On Slide 8, we recap our spending on drilling and other development activity.

For the quarter, we spent a total of $256 million on our drilling activities, including $252 million that directly relates to the Haynesville and Bossier shale drilling program. And then we only spent $4 million on other development activity in the quarter. We drilled 16 or 14.3 net wells in our Haynesville program, and we turned 18 or 16.3 operated wells to sales in the quarter. These wells had an average IP rate of $27 million per day. In the quarter, we also – we did have four short lateral Bossier wells, which were drilled, which probably diluted the numbers a little bit, but they were drilled to hold acreage. On Slide 9. We recap our balance sheet at the end of the first quarter. We ended the quarter with $540 million in borrowings outstanding on our credit facility, giving us $2.7 billion in total debt, including our outstanding senior notes.

As Jay referenced, on March 25th, we sold 12.5 million shares to our majority stockholder for $125 million in a private placement. The proceeds from that offering have 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. And then lastly, on April 30th, our bank reaffirmed our borrowing base at $2 billion and then our elected commitment of $1.5 billion kind of remained the same. I’ll now turn the call over to Dan to discuss the operations in more detail.

Dan Harrison: Thank you, Roland. Over on Slide 10, this is our current drilling inventory that where we’re 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. Of 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 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.

If you look at each group in our gross operated inventory, we have 278 short laterals, 348 medium laterals, 433 long laterals, and 643 extra-long laterals. This gross operated inventory is evenly split with 51% in the Haynesville and 49% in the Bossier. 63% of our gross operated inventory has laterals longer than 8,500 feet and 38% of our gross operated inventory or the 643 locations have lateral lengths surpassing 10,000 feet. The average lateral length in 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 laterals still stands at 15,726 feet. 12 of the 18 wells returned 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 upward trend we’ve been on for the last several years. 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 are 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. To recap our longer lateral wells, to date, we have drilled 91 wells with laterals over 10,000 feet, 33 wells with laterals over 14,000 feet. On Slide 12, we recap our new well activity. Since we last provided our well results in mid-February, we have turned to sales and tested 14 new wells since our last conference call. This group of wells had individual IP rates ranging from 9 million up to 38 million cubic feet a day with an average test rate of 25 million cubic feet a day. The average lateral length was 8,031 feet, with the individual laterals ramped 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 last of Farley, the Harrison, and the Ingram Martin wells achieved IP rates of 3-5 million to 38 million cubic feet a day, and the Haynesville shale. Regarding our current activity levels, we are now running five rigs. This is after we dropped two 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 starting to fail in the Western Highlands until early in the fourth quarter.

Slide 13 summarizes our D&C calls through the first quarter for our benchmark long lateral wells. This is the wells located on 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 at 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 the result of all eight of our benchmark long lateral wells during this quarter and are being concentrated in our higher drilling cost areas.

Our first quarter completion cost came in at $7.87 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 second quarter. However, with the lower rig activity, we anticipate only working the equivalent of 1.5 frac crews during the second half of the year. On Slide 14, we highlight our continued improvement related to greenhouse gas and methane emissions.

We have reported a greenhouse gas intensity of 3.45 kilograms CO2 equivalent per BOE of production. This is a 1% improvement versus 2022 and increases to — increasing the improvement to 4% over the past two years. We have 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 turned-to-sales improved 25% last year and 38% over the past monitoring technology at almost 100% of our production sites, which earned us the ability to certify our gas as 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 to 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.

Jay Allison: Thank you, Ken. Thank you, Roland. I will direct you to Slide 15, where we summarize our outlook for 2024. We’ve taken a number of steps in response to significantly lower natural gas prices this year. During the first quarter, we have released two of our operated rigs, as Dan said, 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% 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. 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 where we 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 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 the next to the last worst performer. Then on April 1st, 2024, The Wall Street Journal tracked the same group of 120 NYMEX natural gas was the worst performer for the entire group.

That is a 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?

Roland Burns: Thanks, 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 to $250 million and our full-year D&C CapEx guidance remains unchanged at $750 million to $850 million. The lower D&C spending versus last year is related to the release of the 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 to $5 million in the second quarter and $70 million to $80 million over the course of 2024. Capital expenditures related to Pinnacle Gas Services will be funded by our partner and are expected to total $30 million to $40 million in the second quarter $125 million 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.

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Q&A Session

Operator: Thank you. [Operator Instructions]. Our first question comes from Derrick Whitfield with Stifel. Please go ahead.

Derrick Whitfield: Good morning, Roland. Thanks for your time.

Roland Burns: Good morning.

Derrick Whitfield: I have two questions for you and those relate to your Western Haynesville asset. First, given the depressed price environment we’re seeing at present, I want to make sure we’re properly thinking about the capital efficiency of the investment relative to the industry. If we think about your cost and recovery metrics based on the breadcrumbs provided you’ve noted the Western Haynesville is being developed at a cost. It’s about 2X out of your legacy Haynesville with a recovery that’s about three and a half to four bcf per thousand foot in that ballpark. So that’s 3000 per foot or let’s call it 3.5 to four bcf per thousand foot of EUR. So if we compare that to industry metrics of 2000 per foot or two bcf per thousand 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.

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

Jay Allison: Derek, I’ll comment. We have 11 to 12 wells turned to sales and we’ve only started drilling two wells prepared recently. We’ve only had one well that’s been producing over two years. 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. 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 life, particularly like the core of the Haynesville in 2008, I mean, the more wells you drill, the lower the costs are. I think Dan has done a good job. I mean, our first wells were 80 days to drill. Now there the last one has been 54. These costs are coming down. I think we’re getting better and better and better. Dan?

Dan Harrison: Yes. I’ll just add that, when you compare the two areas, if you look at the costs like you mentioned in the core, those are pretty much set. We kind of know what we’re going to drill them for, absent any problems. You are 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? On the Western Haynesville side, you are seeing the cost really move down, which is changing the economics and you are not really seeing that in the core. Those are kind of fixed, right? We’ve been optimized for a while.

Roland Burns: Derek, the core goes many more from 1.2 to maybe 2.2. I mean, you may see 2.3, but like you said, 2.0, that’s a Blue Ribbon well in the core. I think what we’re trying to derisk in the Western Haynesville is that a large portion of that acreage is competitive, if not potentially better than the best of the best at the core. That’s what we’re trying to prove up.

Derrick Whitfield: Terrific, color. And then as my follow-up, I just wanted to ask if you could help to 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.

Roland Burns: Yes. 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, ’26, ’27 at all. And then as far as the acreage that we’ve leased over the last 3.5 years, we’ve always said that we would really like to add a rig at year. If we do that over several years, then at least we’d see that acreage. We’re not pushed at all to add rigs in a low-price environment. Even if prices are high, we’re not pushed to add rigs at all to HBP, that acreage.

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

Bertrand Donnes: 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 have LNG corridor exposure, but you’ve taken the indirect benefit strategy. Just was wondering if when it comes to data center demand, is there any interest at Comstock really taking direct maybe long-term agreement with a plant or something like that? And maybe could you tie in Quantum midstream build-out for that purpose?

Jay Allison: Yes. That’s a great question. We’re really excited about the Western Haynesville build volume because its got, there is a lot of potential customers that are approaching us, including recently even some data centers that really are looking to build their centers, where they can have uninterrupted supply and power supply. It’s an exciting new element to kind of add to the LNG demand and other industrial users power generators and we do see shifting, especially our Western Haynesville, I think we’ll be selling a lot of that gas in the future to our direct customers and then potentially using our relationship in the midstream venture to add some infrastructure as needed to be able to service those. So, it’s a really exciting area for us.

We really want to have a diverse basket of customers in the future and have much, much less sales to other marketing companies or aggregators and LNG will be a part of it. 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.

Roland Burns: If you look at that too, 90% plus of our Western Haynesville is dedicated. 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.