Comstock Resources, Inc. (NYSE:CRK) Q4 2023 Earnings Call Transcript

Comstock Resources, Inc. (NYSE:CRK) Q4 2023 Earnings Call Transcript February 14, 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: Thank you for standing by and welcome to the Comstock Resources Fourth Quarter 2023 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. And now I’d like to introduce your host for today’s program, Jay Allison, Chairman and CEO. Please go ahead, sir.

Jay Allison: All right, Jonathan. I love that broadcasting voice, kind of starts the day off right. Our corporate team of 255 strong, I want to thank you for joining the call this morning and we wish you a Happy Valentine’s Day. Being a pure-play natural gas company in a sub $2 natural gas market, calls for decisive actions to weather the volatility, and at the same time, continue positioning Comstock to benefit from the longer term growth in natural gas demand in the foreseeable future. America will need to deliver an additional 10 billion cubic feet of natural gas per day to the LNG facilities currently under construction in the next few years. Actions taken so far as we batten down the hatches to protect our balance sheet.

Number one, in January, we released a frac crew. Number two, several months ago, we gave notice to release two rigs and they will both be finished their work by the end of this month. Number three, we suspended our quarterly dividend until natural gas prices improve. Number four, we continually evaluate our activity level as we plan to fund our drilling program within operating cash flow if possible. Number five, we formed our mid-stream joint venture last year that allows us to build out of the Western Haynesville midstream assets to be funded by the midstream partnership and not burden our operating cash flow at Comstock. Number six, we’ve positioned Comstock to have very few rigs needed to hold all of our corporate acres including the 250,000 plus net acres in the Western Haynesville.

Number seven, we’re bullish on the long term outlook for natural gas and are growing our resource base in the advantage proximity to the Gulf Coast market. Number eight, lastly, our Western Haynesville “box of chocolate” on its Valentine’s Day, allows us to materially grow our drilling inventory organically versus through the M&A market. I can also assure you that our majority stockholder, the Jerry Jones family, is in 100% approval of all of our prior actions, as well as our recent moves to protect our balance sheet in this volatile natural gas market. They are in the cockpit with us helping fly this plane with a steady hand on the throttle, looking into the future where global natural gas markets are counting on our US gas to provide needed clean energy.

Our goal is to look back on this point in time in the future years and say, we handled it well and continued to create corporate value in a weak period for natural gas. Now I’ll go over to the corporate script. Welcome to the Comstock Resources Fourth Quarter 2023 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 entitled Fourth Quarter 2023 Results. I’m Jay Allison, Chief Executive Officer of Comstock. 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 in our presentations and note that our discussions today will include forward-looking statements within a meeting of securities laws. While we believe the expectations and such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Fourth quarter 2023 highlights. On slide three, we summarize the highlights of the fourth quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and gas sales, including hedging were $354 million in the quarter. We generated cash flow from operations of $207 million or $0.75 per share and adjusted EBITDAX was $244 million. Our adjusted net income was $0.10 for the quarter. We continue to have very strong results from our drilling program.

In the fourth quarter, we drilled 14 or 13.3 net successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 8,994 feet. Since the last conference call, we’ve connected 22 or 16.5 net operated wells to sales with an average initial production rate of 24 million cubic feet per day and an average lateral length of 11,966 feet. Our 2023 drilling program replaced 109% of our 2023 production with new proved reserves adds. We are continuing to make progress in our Western Haynesville exploratory play. We added 23,000 net acres to our expensive Western Haynesville acreage position in the fourth quarter alone, increasing our total acreage position in the play to over 250,000 net acres. We recently turned our eighth well to sales.

The Neyland well was completed in the Haynesville formation and is currently producing at 31 million cubic feet per day. Three additional wells, the Harrison, Glass and Farley Wells are expected to come on production by the end of the first quarter. I’ll now have Roland go over the fourth quarter and the annual financial results. Roland?

Roland Burns: Thanks, Jay. On slide four, we cover our fourth quarter financial results. Our production in the fourth quarter of 1.5 Bcfe per day increased 6% for the fourth quarter of 2022 and grew 8% from the third quarter. Low natural gas prices resulted in our oil and gas sales in the quarter coming in at $354 million, declining 37% from 2022’s fourth quarter despite the higher production level. EBITDAX for the quarter came in at $244 million and we generated $207 million of cash flow in the fourth quarter. We reported adjusted net income of $28 million for the fourth quarter or $0.10 per share, as compared to a net income of $12 million in the third quarter of 2023 and $288 million in the fourth quarter of 2022. On slide five, we show the financial results for the full year 2023.

Our production averaged 1.4 Bcfe per day, which was a 5% increase from the prior year. Oil and gas sales in 2023 totaled $1.3 billion and were 41% lower than our sales in 2022 due to the lower gas prices we realized. Our EBITDAX in 2023 was $928 million and we generated $774 million of cash flow for the year. We reported net income of $133 million for 2023 as compared to net income of $1 billion in 2022. On slide six, we show our natural gas price realizations that we had in the quarter. During the fourth quarter, the quarterly NYMEX settlement gas price averaged $2.88, which was $0.14 higher than the average Henry Hub spot price in the quarter of $2.74. Our realized gas price during the fourth quarter averaged $2.48, reflecting a $0.40 differential to the settlement price, and a $0.32 differential to our reference price.

The differentials were a little wider in the quarter starting in October, which normally occurs as we reach the end of storage injection period. In the fourth quarter, we were 16% hedged and that improved our realized gas price for the quarter to $2.51. We’ve also been using some of our excess transportation in the Haynesville to buy and resell third-party gas. We generated about $4.4 million of profits in the fourth quarter and that improved our gas price realization by another $0.03 in the quarter. On slide seven, we detail the operating cost per Mcfe and our EBITDAX margin. Our operating cost per Mcfe averaged $0.81 in the fourth quarter, 4% lower than the third quarter. Lower gathering costs were offset though by higher production and ad valorem taxes.

Our gathering costs were down $0.03 to $0.33 during the quarter and our lifting costs were also $0.01 lower than the third quarter rate at $0.23. Our production ad valorem taxes increased $0.03 in the third — from the third quarter level and G&A came in at $0.02 per Mcfe, which was $0.03 lower than the third quarter. Our EBITDAX margin after hedging came in at 68% in the fourth quarter, up from the 65% level we had in the previous quarter. On slide eight, we recap our spending on drilling and other development activity. In 2023, we spent a total of $1.3 billion on our development activities, including $1.2 billion on our Haynesville and Bossier shale drilling program. Spending on other development activity including installing production tubing, offset frac protection and other workovers totaled $54 million.

In 2023, we drilled 67 wells or 55.5 wells net to our interest and turned 74 or 55.7 net operated wells to sales. These wells had an overall average IP rate of 25 million cubic feet per day per well. On slide nine, we cover our natural gas and oil reserves that were determined using the required SEC prices. Our SEC-approved reserves decreased 26% in 2023 to 4.9 Tcfe due to the low gas price used in the determination. The required SEC gas price decreased 60% for 2023 to $2.39 per Mcf, down from the $6.03 that was used in 2022. Our 2023 drilling activity added 571 Tcfe-approved reserves to our year in reserves which replaced 109% of our 2023 production. But we also had 1.8 Tcfe of negative revisions due to the lower proved undeveloped reserves caused by our reduction in drilling activity and the low natural gas price that was used to determine which undrilled locations we would drill In addition to the total 4.9 Tcfe of SEC proved reserves that we had at the end of the year, we have another half a Tcfe approved undeveloped reserves that aren’t included as they are not expected to be drilled within the five-year required — time period required by the SEC rules.

We also have another almost Tcfe of 2P or probable reserves and 4.6 Tcfe of 3P or possible reserves for a total reserve base of around 10.9 Tcfe on a P3 basis, all determined at the low SEC pricing. On slide 10, we’ve used NYMEX gas price of $3.50 per Mcf to determine the reserves to show the impact of the low prices on the year end reserves. Using this price, our approved reserves would have been similar to last year at 6.6 Tcfe. In addition, our overall reserves we would have had an additional of another 2 Tcfe approved undeveloped reserves that are outside the five-year period, and then we would have 2.5 Tcfe of 2P or probable reserves and another 8.7 Tcfe of 3P or possible reserves for a total overall reserve base of 19.8 Tcfe on a P3 basis, all determined at a $3.50 NYMEX gas price, which in our view lined up closer to the long term futures prices for natural gas.

On slide 11, we recap our balance sheet at the end of 2023. We did end the quarter with $580 million of borrowings under our credit facility, giving us a total of $2.7 billion in debt, including our outstanding senior notes. Our borrowing base for our bank credit facility is currently at $2 billion, of which we have an elected commitment of $1.5 billion of that amount. So we ended the year with overall financial liquidity of just over $1 billion. I’ll now turn it over to Dan to kind of discuss our operations in more detail.

Daniel Harrison: Okay. Thank you, Roland. Over on slide 12, this shows where our current drilling inventory stands at the end of the year into the fourth quarter. Our inventory is split between our Haynesville and Bossier locations. We have it divided up into four buckets. Our short laterals run upto 5,000 feet. Our medium laterals run between 5,000 feet and 8,500 feet. We have our long laterals between 8,500 feet and 10,000 feet. And then our extra-long laterals extending out beyond 10,000 feet. Our total operated inventory currently stands at 1,706 gross locations and 1,303 net locations. This equates to a 76% average working interest across our operated inventory. Our non-operated inventory has 1,253 gross locations and 160 net locations.

This represents a 13% average working interest across the non-operated inventory. If you break down our gross operated inventory, we have 291 short laterals, 347 medium length laterals, 438 long laterals, and 630 extra-long laterals. The gross operated inventory is split 51% in the Haynesville and 49% in the Bossier. 37% of our gross operated inventory or 630 locations have laterals greater than 10,000 feet and 63% of the gross operated inventory has laterals exceeding 8,500 feet. The average lateral length in our inventory now stands at 8,971 feet and this is up slightly from 8,949 at the end of the third quarter. Our inventory provides us with 25 years of future drilling locations. On slide 13, is a chart outlining our progress to date on our average lateral length and drilled based on the wells that we’ve turned to sales.

During the fourth quarter, we turned 17 wells to sales with an average length of 11,870 feet and this is thanks to the continued sales of our long lateral drilling program. The individual lengths range from 5,736 feet up to 15,243 feet, while our record longest lateral still stands at 15,726 feet. During the fourth quarter, 12 of the 17 wells we turned to sales had laterals exceeding 10,000 feet, including seven of those wells longer than 14,000 feet. To date, we have drilled a total of 80 wells with laterals over 10,000 feet long and 28 wells with laterals over 14,000 feet. During the fourth quarter, we didn’t turn any wells to sales on our new Western Haynesville acreage. To date, in 2024, we have turned one well to sales in the Western Haynesville and we do expect a total of four wells to be turned to sales by the end of the first quarter.

In 2023, we turned a total of 74 wells to sales with an average lateral length of 10,820 feet and this is up 8% from our 2022 average lateral length of 9,989 feet. Slide 14 outlines our new well activity. We have turned to sales and tested 22 new wells since the time of our last call. The individual IP rates range from 9 million a day up to 42 million a day with an average test rate of 24 million cubic feet a day. The average lateral length was 11,966 feet with the individual laterals ranging from 5,736 feet up to 15,243 foot lateral. The Hamilton Verhalen B number 2 well located in East Texas, which had a 9 million a day IP rate, suffered mechanical casing failure during completion, which resulted in this well producing from only half of the completed lateral.

In addition to the first seven wells producing in the Western Haynesville at the end of 2023, we recently placed our eighth well online. The Neyland number 1 was drilled in the Haynesville and to date, it’s currently producing 31 million cubic feet a day. This well is still in the process of being tested and cleaning up. We do anticipate three additional wells being turned to sales by the end of the first quarter. We currently have two rigs running on our Western Haynesville acreage and we are currently planning to keep two rigs running in the Western Haynesville for the remainder of the year. On slide 15, this summarizes our D&C costs through the fourth quarter for our benchmark long lateral wells that are located on our legacy core East Texas and North Louisiana acreage.

This covers all our wells having laterals greater than 8,500 feet long. During the quarter, we turned 17 wells to sales that were on our core East Texas and North Louisiana acreage, 13 of the 17 wells were our benchmark long lateral wells. In the fourth quarter, our D&C cost averaged $1,482 a foot on the 13th benchmark long lateral wells and this reflects a 5% decrease compared to the third quarter. Our fourth quarter drilling cost averaged $610 a foot, which is a 15% decrease compared to the third quarter. The lower drilling cost reflects a slight downward trend on pricing we’ve experienced throughout 2023 and also our drilling costs in the third quarter was abnormally higher due to some drilling issues we had in that quarter. Our fourth quarter completion cost came in at $871 a foot, which is a 3% increase compared to the third quarter.

The increase in completion costs were primarily attributable to some slightly higher plug drill-out cost in the fourth quarter due to the longer laterals. We currently have seven rigs running. We are in the process of releasing one rig this weekend and end of the month, early next month, we’ll be releasing a second rig. We currently expect to run five rigs for the rest of 2024. On the completion side, we are currently running two frac crews. We do expect to maintain one to two frac crews running for the remainder of the year. I’ll now hand the call back over to Jay.

Jay Allison: Thank you, Dan. Thank you, Roland. If you’ll turn to slide 16, we’ll summarize our outlook for 2024. We remain very focused on proving up our Western Haynesville play and continuing to add to our extensive acreage position and its exciting play. At the end of 2023, our Western Haynesville acreage position totaled over 250,000 net acres. Following the creation of our mid-spring joint venture late last year, the capital costs associated with the build-out of the midstream assets in Western Haynesville will be funded by the midstream partnership and will not be a burden on our operating cash flow. We believe that we are building a great asset in Western Hansville 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.

We are actively managing our drilling activity level to prudently respond to the current low gas price environment. We have already released one of our three completion crews, as Dan said, and two of our operated rigs on our legacy Haynesville footprint, bringing our total operated rig count to five rigs, of which two are drilling in the Western Haynesville. We are focused on preserving our balance sheet in this gas price environment. We’ll continue to evaluate our activity level as we plan to fund our drilling program within operating cash flow. We are going to suspend our quarterly dividend until natural gas prices improve. Our industry-leading lowest cost structure is an asset in the current natural gas price environment as our cost structure is substantially lower than the other public natural gas producers.

And lastly, we’ll continue to maintain our very strong financial liquidity, which totaled around $1 billion at the end of the fourth quarter. I’ll now have Ron provide some specific guidance for the rest of the year. Ron?

Roland Burns: Thanks, Jay. On slide 17, we provide the updated financial guidance for the first quarter of this year and the full year. First quarter D&C CapEx guidance is $225 million to $275 million and the full year D&C CapEx guidance is $750 million to $850 million. The lower spending versus last year is related to the announced release of two drilling rigs in our press release last night in response to low gas prices. We’ve continued to see signs of some deflationary pressures on service costs, including an improvement in our completion costs per stage. We anticipate spending an additional $30 million to $40 million on lease acquisitions in the first quarter and $40 million to $50 million over the course of the year. Capital expenditures related to Pinnacle Gas Services will be funded by our midstream partner and are expected to total $30 million to $40 million in the first quarter and $125 million to $150 million for the full year.

For both the first quarter and the full year, our LOE is expected to be in a range of $0.24 to $0.28 per Mcfe. GTC are expected to be $0.32 to $0.36 per Mcfe and production and ad valorem taxes are expected to average $0.16 to $0.20 per Mcfe. DD&A rate is expected to average $1.30 to $1.40 per Mcf this year. In the first quarter, our cash G&A is expected to total $7 million to $9 million and $30 million to $34 million for the full year. In addition, we’ll have non-cash G&A in the first quarter of $2.7 million to $3 million and $10 million to $12 million for the full year. With the increase in SOFR rates in our current debt levels, cash interest expense is now expected to total $43 million to $47 million in the first quarter and $195 million to $205 million for the year, while non-cash interest will remain approximately $2 million per quarter.

Effective tax rate will remain in the 22% to 25% range and we continue to expect to defer 95% to 100% of our reported taxes this year. We’ll now turn the call back over to the operator to answer questions from analysts who follow the company.

See also 15 States with the Best Healthcare in the US and Top 20 Biggest Mortgage Companies in the US.

Q&A Session

Operator: Certainly. One moment for our first question. And our first question for today comes from the line of Derrick Whitfield from Stifel Financial. Your question, please.

Derrick Whitfield: Good morning, all, and thanks for your time.

Jay Allison: Yes, sir.

Derrick Whitfield: Let me first commend you on a strong year end and your decision to reduce capital outflows in the current depressed gas price environment. With respect to your 2024 outlook, could you speak to the average gas price that underpins your spending within cash flow view? Any additional steps you’d likely take to further reduce capital if gas continues to deteriorate?

Roland Burns: Yeah, Derrick, I mean — of course, that’s a moving target where gas prices are, and I think that probably where the gas price was in the market, maybe about two or three weeks ago was probably exactly kind of where that’s in balance. So it’s going to be a kind of a volatile deal. But I think the things that we’ll continue to monitor are, what are our service costs. They are trending down a little bit as far as the — some deflationary actions kind of happening on that side. But the other levers that we can pull or continue to look at dropping another rig, that’s the most effective way to reduce capital expenditures. That has the most impact on creating net operating cash flow. And so that’s what we’ll continue to monitor the activity like we do each year and look to tighten up the ship wherever we can to kind of maximize the operating dollars that we have.

Derrick Whitfield: Terrific. And as my follow-up, I wanted to shift over to the Western Haynesville, with the understanding that it’s a long-game resource, could you speak to the gains you’re experiencing in operational efficiency, the degree you’re expecting your breakevens to improve over time, and if you’re expecting a meaningful difference in the breakevens between the Haynesville and Bossier intervals?

Daniel Harrison: So, Derrick, this is Dan. I’d say, we’re definitely gaining ground and going up the curve still faster on our Western Haynesville wells. We’re — we’ve — we’re drilling our first two well pad actually currently. We got — the second rig is going to its first two well pad next. That’s going to definitely help our efficiency there. We still have had some things that we’ve gained-on on the drilling front that’s still increasing our drill times. So, we — and we still see a little bit more running room there to get faster. So I think, we definitely are seeing an increase there on the Western Hainsville wells and we’re seeing those costs come down in the core area, probably as far as the moving the needle on efficiencies, probably not as much.

I mean, we’ve been there for a long time and got everything pretty streamlined, but down to the two frac crews, same vendor, we see some kind of some savings there, just really good solid performance. We brought in some three new rigs, new build rigs. So I think we’re going to have some better performance there just kind of overall. So, I think we will, and of course, we’re seeing the cost savings come down with the activity levels. We’re probably down 10% or so this year since the beginning of last year. And obviously difficult times, we — I think everybody gets pretty streamlined and pretty efficient and the costs come down, but obviously, we’d like to see maybe prices be a lot higher and be battling some of those things, but yes, that’s where we’re at.

Derrick Whitfield: Very helpful. Thanks for your time.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Charles Meade from Johnson Rice. Your question, please.

Charles Meade: Good morning, Jay, to you and your whole team there at Comstock.

Jay Allison: Good morning.

Charles Meade: Dan, I’m going to start with just a really quick clarifying question with you. I think I heard you say in your prepared comments that you’re planning on running between one and two completion crews for the remainder of the year, did I catch that right?

Daniel Harrison: That’s right. So if you look — if you just do the math, I mean, we’ve got two — kind of two dedicated fleets to us, but if you do the math with the number of wells we’re going to turn to sales, it comes out to like 1.7 frac crews, is what we’ll need this year.

Charles Meade: Got it. And then —

Daniel Harrison: One running full-time and one with some gaps in between.

Charles Meade: Got it. And then my follow-up, Jay, I recognize that this is kind of maybe a simplistic way to start this, but I recognize you guys look at a lot more data and have a lot more considerations than somebody sitting in my chair does, so — but in my chair, I look at the futures curve here, and we don’t get up two bucks until July, and so from my seat, it looks to me like the right number of completion crews to be running right now for at least the next several months is zero. And I recognize that’s not a realistic case, but can you bridge the pieces — to kind of bridge the view — it looks like the right number is zero, but why the right number for you guys is 1.7 or one to two for the next several months?

Jay Allison: Well, I think that’s a really good question. Number one, I think if you look at how proactive we’ve been, typically on a conference call like this, you’re going to release a frac crew, we’ve already done that. Second of all, maybe you have contracted to have that frac crew and you have to use them. We don’t have any contracts. It’s a well above well. I think the other thing, just as far as cost, I mean, usually in a conference call like this, you’re going to release two rigs, and it takes two or three, four months to release those rigs, and we were proactive back in December to give notice, and as Dan has said, we’ll have both of those released by the beginning of March is our goal. So then, Roland was asked a question about the price of natural gas to stay within operating cash flow, which is kind of your question.