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.

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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.

I think what we tell you is that that is our goal, is to tell you that we don’t plan on spending as much money on acreage procurement as we have in the past. It tells you that probably half of our acreage that we own right now is Western Haynesville, the other half is a core, and it tells you that we’re not inventory starved. So we don’t have to do deals in the market, whether gas prices are high or low, in order to buy inventory. So then you come and you look at the cost and we look at deflation. I mean, Dan goes over some of the cost savings that we’ve had from the Frac company so far and some of the cost savings we’ve had in drilling and completing the wells. I think all we can do is tell you that we’ve looked at those numbers. We’ve looked at hedging.

We’ve hedged about 28% of our production in ’24 to 355 swap. I think that we need to be in the 50% range now. When will we get there? I don’t know, but I think you and the market need to know that it is a corporate goal that we have. And the reason we use kind of batting down the hedge as a theme is because if we need to delay some fracs, we see that in the next month or so, then I think we can do that. If we needed to lay down another rig, we’ll have the optionality to do that. So again, I think your goal is, how are you going to protect this thing? And that’s one reason I always say, if you look at the major shareholder, who owns 65% of this, if anybody’s trying to protect it, the Jones family is, and they’re well involved with what we do.

And then I think you have to look at any minimum volume commitments or farm transportation agreements that you have and say, are we impacted by reducing the rig count? And the answer is, we’re not. So you have to look at all those things too when you ask that question. But we’re going to continue to manage this just like we’ve managed it for a while. We as a group, we recognize pain. I mean, some groups haven’t recognized it because they haven’t experienced it, we do, so it’s a good thing. It’s an indicator, and whatever we need to do to ride this ship, that’s what we plan on doing. So, that’s a great question.

Charles Meade: Thank you for that elaboration. That was helpful, Jay.

Jay Allison: Yes, sir.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Fernando Zavala from Pickering Energy Partners. Your question, please.

Fernando Zavala: Hey, guys. Good morning. Kind of going back to your comments around evaluating dropping another rig, where would that rig come from? Would it come from the Western Haynesville or the core Haynesville?

Jay Allison: If we dropped another rig, it would be in the core, it would not be the Western Haynesville.

Fernando Zavala: Okay, got it. And then, can you talk a little bit about — this is my follow-up, the trajectory of production in 2024? It seems like the implied 2024 guidance is in line with first quarter, so just a little bit more color there.

Roland Burns: Yeah. From a — if you think about the time frame related to dropping a rig and starting to show up in terms of impacting production, Dan mentioned, we were dropping the first of those two rigs here this weekend and the second rig within the next two to three weeks I think he said, and so just like when you add a rig, when you drop a rig, there’s plus or minus a six or seven-month lag between the timing of changing your activity level and having it flow through to production. So that’s why — the first half of the year, production should remain relatively flat, and you start to see a little bit of a decline in the third quarter and a little bit larger decline in the fourth quarter as you start to feel the full brunt of running five rigs.

Fernando Zavala: Okay. That’s helpful. Thank you.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Jacob Roberts from TPH&Co. Your question, please.

Jacob Roberts: Good morning.

Roland Burns: Good morning.

Jay Allison: Good morning.

Daniel Harrison: Good morning.

Jacob Roberts: I think previously you’ve had some commentary about joint commitments and HPP provisions on the Western Haynesville, can you speak to the impact of running those two rigs for 2024 and any needed extensions or perhaps catch-up provisions to be needed in 2025 plus?

Daniel Harrison: No, we feel like that not running the three rigs like we originally anticipated this year that that’s not going to put us that far behind and we won’t really have to alter our future plans by taking this a little bit slower approach in 2024, but over a longer period of time, we have a lot of acres to — the term acreage that it has to be — we have to drill to hold. But given the actions we’re taking this year, we’re not really changing — having to know that we have to extend leases, et cetera, we still can keep all these kind of on track.

Jay Allison: In fact I think the slowdown is a positive in the Western Haynesville. We — as Dan said earlier, most of the wells we’ll be drilling now will be two wells per pad. We have been drilling one well per pad. I think it lets our land group now get ahead a little bit for ’25 and ’26 because we have added a lot of acreage within a small window. I think it lets us position our wells better in ’24 and ’25 to de-risk a lot greater swath of acreage with fewer wells. So it really has been — the slowdown has served our land group well. And as Roland said, and Dan will tell you, it has not impacted really the drilling. I do think we’ll add another rig in ’25 like we were going to do in ’24, but the results will speak for themselves.

And so far, the results have been really good. They’ve been stellar for the acreage that we have. And the area that we’ve de-risked, which is probably from the hill to our northern well, probably 23 or 24 miles, we’ve said that publicly. We’ve got a lot of acreage we’ve derisked there, so it looks good. And I think this environment is favorable for us to slow that down.

Jacob Roberts: Thanks for that. My second question is around the leasing program that seems to have bled over from ’23 into 2024, and it’s pretty heavily focused in the first quarter of the year. Can you just provide any detail on what caused some of those conversations to fall into this year? Has the process become more competitive? And then maybe, if you can, a sense of the scale of the remaining transactions in the pipeline. Thank you.

Daniel Harrison: The process definitely has not become more competitive with the weak gas price environment. But — we’re leasing from lots of different parties. It’s a — there’s lots of reasons why you don’t actually close something you’re working on, so it’s not. I don’t think there’s any significant trend there. But we are kind of rounding up where we’ve captured a lot of the acreage in the areas that we think are the most prospective for the play. And so that’s really driving the program more than anything else, so just we’re finishing up.

Jacob Roberts: Great. Appreciate the time.

Jay Allison: We’ve stated that we average about $550 an acre, and in fact, at $1.61 gas, which is where we are right now, which I don’t think I’ve read it, we hadn’t been this low since spring of 2016, so eight years, I can promise you there’s no competition out there at $1.61 at all.

Operator: Thank you. One moment for our next question. And our next question comes to the line of Bertrand Donnes from Truist. Your question, please.

Bertrand Donnes: Hey, good morning, guys.

Jay Allison: Good morning.

Daniel Harrison: Good morning.

Roland Burns: Good morning.

Bertrand Donnes: This one might be a little bit weird, and I’m not saying it’s necessary, but if it did become necessary, is there any ability to negotiate with quantum on the minimum volumes? It seems like you guys have a mutual interest and even when they revert to 30%, there’s probably an interest in properly managing the asset instead of just kind of hitting a number that was inked at a different gas price, but it was purely out of curiosity.

Daniel Harrison: Well, that level is set so much far lower than our forecast and even our production level now. It’s just not even a question to give any thoughts to.

Bertrand Donnes: Sounds good, very succinct. And then, another one, just to keep them a little bit weird, is there — was there any consideration instead of technically suspending the dividend instead going to a kind of variable dividend? I just don’t know, management has a view on whether or not that has a place or no place or maybe it just doesn’t mesh with the corporate view.

Jay Allison: No, we didn’t consider that.

Bertrand Donnes: Sounds good. I appreciate the answers. Thanks.

Jay Allison: Great questions.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Phillips Johnston from Capital One Securities. Your question, please.

Phillips Johnston: Hey, guys. Thanks. My first question is on your 3.5 times max leverage ratio covenant. At current strip prices, our model shows that you might be close to reaching that later this year, would you also see that as a possible risk, and if so, how easy would that — how easy would it be to get a waiver from the banks?

Roland Burns: We don’t see that. So we don’t think that we come that close to that, Phillips. So I think we just continue to monitor our spending level and not use much more of the credit facility.

Phillips Johnston: Okay. Sounds good. And just to make sure our models are calibrated. As we think about the five rig program, what would you expect the net well count to look like for the year in terms of both wells drilled and wells turned to sales?

Jay Allison: Ron’s got that number.

Roland Burns: Yeah, it’s in the press release too. Please read it there, yeah. I don’t have that email. Hang on. Give me two seconds. So as it says in the press release, we plan to drill 46 gross and turn — and that’s about 36 net wells and turn to sales 44 gross, 38 net.

Phillips Johnston: Okay. Sorry about that I completely missed that. Thank you.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Leo Mariani from ROTH. Your question, please.

Leo Mariani: I just wanted to quickly follow-up on some of the prepared answers here that you guys had given here. Ron, you talked about prediction, kind of flattish in the first half of the year, a little bit of a third quarter decline, and then more of a fourth quarter decline, and of course, I’m sure it’s pretty obvious to you folks that that’s a bit inverse to what the futures curve is suggesting, where clearly prices are expected to be lower early in ’24 and then higher as you get towards those winter months in ’24. So you certainly expressed the belief that you want to be kind of flexible and sort of do what you can to kind of maximize the cash flow. So, is there some thought to pushing some of those turn-in lines out towards those later quarters and perhaps trying to shift the production a bit so it’s a little bit lower this summer and maybe higher next winter?

And is there any operational reasons maybe why you couldn’t do that maybe some of the Western Haynesville stuff has provisions or wells have to come online at a certain point in time, but any color you have there would be great.

Roland Burns: Well, I think it’s difficult to under shale if you don’t understand the timing of shale production and the way that the wells are drilled and all that to try to be super precise and bring production on within what the futures curve says it could be now, which it could be different when you get there. I mean, it’s not — I mean, you obviously can give consideration to it, and we can give consideration in the field if we have low spot prices that do we not turn a well on that day definitely. So you can manage these kind of around that, but I don’t know that you can think that you can direct it a real precise level because you could — your assumptions could be wrong and too, plus it takes like — it takes a lot of resources in preparation to bring these on and you don’t have all those available.

You can’t snap your fingers and get all the wells turned on in one day. So it’s just really balancing all that and balancing it with what you have, the fracs that you have at the time. So just because we present a plan and budget doesn’t mean it’s going to happen exactly that way. So we’ll adjust as we go through the year to what’s going on in the markets and what’s available in the spot market or the index market, et cetera.

Daniel Harrison: Yeah, and I’ll add specifically to the Western Haynesville, our two frac crews are actually fracking wells there now in the Western Haynesville, so there’s really only one other well right behind those, and we don’t have anything else coming on in the Western Haynesville till the end of the year, because, like I mentioned earlier, we got both — we got one rig that just started a two well pad a couple of weeks ago. And our other rig is getting ready to move to a two well pad, and obviously, the Western Haynesville will take more days to drill. So with two well pads, they’ll be drilling all through the spring and summer and fall.

Leo Mariani: Got it. Okay, that’s helpful color, guys. And I know you can’t snap your fingers like you said, Roland, but it sounds like maybe there is some flexibility to kind of manage this a little bit on your end, and I’m sure you’re going to be watching it very closely as the year progresses here. Okay. Maybe just a follow-up on the Western Haynesville. You obviously had your reserve report out, can you give any color around like, what some of these Western Haynesville wells were getting booked at? Maybe like, in terms of reserves per thousand feet or however you guys want to present it here.

Daniel Harrison: Generally, we don’t have a lot of bookings because we’re not trying to get beyond a direct offset as far as booking anything in the Western Haynesville. It’s still early, and we only had the seven producing wells in total in the play. So there’s a limited number of locations in the reserve report. But I would say, overall, the average is — the average kind of reserve bookings are in that 3.5 bcf per thousand feet of completed lateral. Only really one well has a pretty significant track record of performance, which is the first one, the Circle M, and it was upwardly revised with — it’s kind of outperformed that. The rest of the wells don’t have near the number of months to production. So kind of left them where they are, but the reserves are trending nicely in the play for the first wells that we’ve drilled.

Leo Mariani: Okay. That’s great color and certainly appreciate that. And just lastly for me here, just — obviously, I don’t think gas has turned out like anyone expected in 2024 here. It sounds like the plan is to really not kind of add debt from what I’m hearing from you here, Roland, and I guess just to the extent that for whatever reason, let’s say next winter is warm and it’s kind of a weaker start to the year, hopefully, that’s not the case, but if that is, are you still in a position where you don’t want to add debt or do you have to have maybe a little bit more activity next year because of holding some of the Western Haynesville? And were there any consideration of maybe putting in some, I’ll call it, near term funding to kind of get you over the gap here until markets improve later in ’25 and ’26?

Jay Allison: I think we position ourselves right now so that the things that we don’t allow us to protect our balance sheet. I mean, if you just segregate it and you look at the Western Haynesville, like Dan said, these wells will be slower to reach production, so even though we didn’t add a third rig, I mean, as Ronald mentioned, we’re not going to have any issues with our mid-stream quantities. So I don’t see an issue there. And then I think, as far as any obligations, we have to drill the complete wells, we don’t have any obligations there. And we — as we said, we were very, very proactive even in December, much less January, February, to cut some cost. So I think we’re just monitored like that. So, if we need to lay down another rig, if we need to defer completions, all of those things, those are all in the hopper that we’ll look at to do, so — even in a very tough market, I think we’ve got a lot of switches to pull to protect where we are.

And the bottom line is, we’re just so rich in inventory that we just have to protect what we already own, period. We don’t have to breach the 10th commandment and covet everybody else’s inventory. We just have to continue to perform in the Western Haynesville. Like Roland said, I mean, the EURs look solid. Dan said the costs are coming down. It’s still early innings, but we’ve captured a lot of acreage and we’ll just see what the story book tells us in the future.

Leo Mariani: Okay. Appreciate the color.

Jay Allison: Yes, sir.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Your question, please.

Noel Parks: Hey, good morning.

Jay Allison: Hello, Noel.

Noel Parks: I just wanted to touch again on the Western Haynesville. I was wondering, can you talk a little bit about what kind of science you’re doing on the latest Western Haynesville Wells sort of like, what are you most interested in learning about next, as far as just your drilling practices for instances?

Daniel Harrison: Well, so we’ve — I think we’ve stated before, probably the biggest difference between the Western Haynesville and our core is the temperature in the depth. I mean, obviously, they’re a little bit deeper. And if you just look at the TVDs of the wells, and of course, with that comes temperature, and we’ve just really done a really good job at managing the temperature. And when I say that managing, getting our bottom hole assemblies to perform and stay on bottom longer, faster ROPs, less trips in and out of the hole to get the lateral drill. So we’ve made a lot of gains there. And then just up top, you got, obviously, a longer vertical section to drill. We’ve made some modifications to our casing design. We’ve seen our penetration rates pick up top also.

So you just kind of go attack, you got to attack everything, and we don’t have all of those things just totally kind of maxed out like we do in the core. I mean, the core, we just kind of make some tweaks a little bit here and there, and you pick up a day or two, but we’re picking up bigger chunks down here in the Western Haynesville, just flickering the sling out.

Noel Parks: And are you at a point where productivity of the rock is pretty much not a surprise anymore or are you still learning things there?

Daniel Harrison: I’d say, the rocks turned out — I mean, we know — everybody knows that the gas is there. There were two old wells drilled back in 2010 and 2011 that we got died on. They had all kinds of problems, had very inferior completions put on them, but still with that, they still had a decent amount of gas, so we knew the gas was there. It’s really a matter of economics. And the wells, they do treat at higher pressures when they frac, but they also frac very consistently. The pressures don’t just go up and down and go all over the place. That would obviously make it a lot more difficult. So they frac very consistently, which makes it easier to frac them at the high pressures. So we’ve had pretty good costs there, not cost fluctuation, I mean, consistent on the cost, also on the completion side.

We also have — a few years ago, we started drilling out these long laterals with snubbing units using a stick pipe. You can basically handle higher pressured wells with that than with coiled tubing. And so we’ve had great success in that regard also, that helped us out with these wells. So really I mean the completion side, everything is just clicking along really good. We’ll get some cost savings from our vendor there. And then really, on the drilling side, it’s just the gains we’re seeing, just basically shaving days off these wells.

Noel Parks: Great. Thanks a lot.

Jay Allison: Yes, sir. Good question.

Operator: Thank you. One moment for our next question. And our next question comes from the line of Paul Diamond from Citi. Your question, please.

Paul Diamond: Thank you. Good morning. Thanks for taking the call. Just a quick want to touch base on some of the D&C costs in slide 15. Just wanted to get an idea of you guys view on how much of that shift down and drilling is — was deflationary or how much should we think about that as sticky and kind of inverse for completions? How much should we expect that to be sticky going forward?

Roland Burns: I think — so going forward this year I think we’re still, obviously with the activity, we’re going to still see the deflation occurring. I mean, we still are seeing maybe another 10% cost into this year versus last year. Say more on the completion side, there is a little bit more predictable, I would say. Just need to get — it just going to basically be lower prices from everybody. The drilling side, because the Western Haynesville is going to be a big component of our program this year, it’s also going to be on the drilling side just increased performance, less days to TD for the cost savings along with just vendor pricing coming down.

Paul Diamond: Understood. And just kind of circle back on that towards the Western Haynesville, the — as far as like drilling days and operational improvements, are we towards — you guys view, are we towards the end of those — of that improvement trend or is this kind of just a beginning?

Daniel Harrison: No, well, we’ve made some pretty good improvements, but we still got a lot of them in the pipeline coming. I mean, we’re in the middle of some of those right now and we definitely see a lot more days getting cut off these wells from even where we’re at today. As far as trying to say in the middle, I’d say maybe that’s probably, maybe somewhere in there in the middle. I mean, we’ve probably shaved off 20 days off these things since the first couple of wells we drilled and we still see that kind of potential going forward.

Paul Diamond: Got it. So another potential 20 days decline in drilling time?

Daniel Harrison: Yes, sir.

Paul Diamond: Good. Thanks for your time.

Operator: Thank you. This does conclude the question-and-answer session of today’s program. I’d like to hand the program back to Jay Allison for any further remarks.

Jay Allison: First of all, I’d like to thank all of you for your questions. They make us better managers. Hopefully, we had shown you that we’ve started and I think we’ve been very proactive to batten down the hatch to protect our balance sheet. We were very proactive on our operations arena to release the frac crew and two rigs. The underlying denominator of everything is stellar drilling performance and stellar inventory in our core area, and in that area we operate. And you look at the Western Haynesville, I mean, almost half our footprint corporately is in the Western Haynesville. Those wells look very promising. So, again, we know that it’s a stressful time, but we do want to assure you that we’re going to continue to manage this company with a steady hand. And we want to wish you all a Happy Valentine’s Day. So thank you for your time.

Operator: Thank you, ladies and gentlemen, for your participation in today’s conference. This does conclude the program. You may now disconnect. Good day.