Miles Jay Allison; Chairman of the Board of Directors & CEO; Comstock Resources, Inc.

Roland O. Burns; President, CFO, Secretary & Director; Comstock Resources, Inc.

Ronald Eugene Mills; VP of Finance & IR; Comstock Resources, Inc.

Bertrand William Donnes; Associate; Truist Securities, Inc., Research Division

Charles Arthur Meade; Analyst; Johnson Rice & Company, L.L.C., Research Division

Derrick Lee Whitfield; MD of E&P & Senior Analyst; Stifel, Nicolaus & Company, Incorporated, Research Division

Fernando Zavala; Analyst; Pickering Energy Partners

Jacob Phillip Roberts; Associate of Exploration and Production Research; Tudor, Pickering, Holt & Co. Securities, LLC, Research Division

John Phillips Little Johnston; Analyst; Capital One Securities, Inc., Research Division

Leo Paul Mariani; MD; ROTH MKM Partners, LLC, Research Division

Noel Augustus Parks; MD of CleanTech and E&P; Tuohy Brothers Investment Research, Inc.

Paul Michael Diamond; Research Analyst; Citigroup Inc., Research Division


Thank you for standing by, and welcome to the Comstock Resources Fourth Quarter 2023 Earnings Conference Call. (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.

Miles Jay Allison

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 today. Being a pure-play natural gas company in a sub $2 natural gas market that 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 2 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 midstream joint venture last year that allows us to build out 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 advantaged proximity to the Gulf Coast market. Number 8, lastly, our Western Haynesville (inaudible) on its Valentine’s Day allows us to materially grow our drilling inventory organically persist 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 U.S. 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 continue to create corporate value in a weak period for natural gas.

Now I’ll go over to the corporate group. 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 and downloading the quarterly results presentation. There, you will find a presentation entitled Fourth Quarter 2023 results.

I am 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 2 in our presentations and note that our discussions 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.

Fourth quarter 2023 highlights. On Slide 3, 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 have connected 22 or 16.5 net operated wells to sales with an average initial production rate of 24 million cubic feet per day at 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 8 well to sales. (inaudible) was completed in the Haynesville formation and is currently producing at 31 million cubic feet per day. Three additional wells, the Harrison (inaudible) are expected to come on production by the end of the first quarter.

I will now have Roland go over the fourth quarter and the annual financial results. Roland?

Roland O. Burns

Thanks, Jay. On Slide 4, 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.

Slide 5, 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.

Slide 6, 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 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 7, 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 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 8, 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, in turn 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 9, we cover our natural gas and oil reserves that were (inaudible) SEC prices. Our SEC proved 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 Bcfe of proved reserves to our year-end 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 0.5 Tcfe proved undeveloped reserves that aren’t included as they are not expected to be drilled within the 5-year required time period required by the SEC rules. We also have another almost Tcfe of (inaudible) reserves and 4.6 Tcfe of 3 feet or possible reserves for a total reserve base of around 10.9 Tcfe on kind of P3 basis, all determined at the low SEC pricing.

On Slide 10, we’ve used a NYMEX gas price of $3.50 per Mcf to determine the reserves to show you the impact of the low prices on the year-end reserves. Using this price, our proved 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 of proved undeveloped reserves that are outside the 5-year period. And then we would have 2.5 Tcfe of 2P of probable reserves 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 that a 350 NYMEX gas price, which, in our view, lined up closer to the long-term future 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 S. Harrison

Thank you, Roland. Over on Slide 12, this just 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 divided up into 4 buckets. Our short laterals run up to 5,000 feet. Our medium laterals run between 5,000 and 8,500 feet. We have our loan laterals between 8,500 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 in 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 linked 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 linked to our inventory now stands at 8,971 feet, and this is up slightly from 8949 at the end of the third quarter. Our inventory provides us with 25 years of future drilling locations.

On Slide 13, as a chart outlining our progress to date on our average lateral length drilled based on the wells that we 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 success of our long lateral drilling program. The individual links 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 (inaudible) sales had laterals exceeding 10,000 feet, including 7 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 sales in the Western Haynesville, and we do expect a total of 4 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 the 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 a 15,243-foot lateral. The Hamilton Verhalen B #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 7 wells producing in the Western Haynesville at the end of 2023, we recently placed our eighth well online. The Neyland #1 was drilled in the Haynesville, and today, 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 3 additional wells being turned to sales by the end of the first quarter. We currently have 2 rigs running on our Western Haynesville acreage, and we are currently planning to keep 2 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 (inaudible) 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 13 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 cost 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 7 rigs running. We are in the process of releasing one rig this weekend. End of the month, early next month, we’ll be releasing a second rig. We currently expect to run 5 rigs for the rest of 2024. On the completion side, we are currently running 2 frac crews. We do expect to maintain one to 2 frac crews running for the remainder of the year.

I’ll now hand the call back over to Jay.

Miles 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 in this exciting play. At the end of 2023, our Western Haynesville acreage position totaled over 250,000 net acres. Following the creation of our midstream 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 the Western Haynesville 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 3 completion crews, as Dan said, in 2 of our operated rigs on our legacy Haynesville footprint, bringing our total operated rig count to 5 rigs, of which 2 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 to provide some specific guidance for the rest of the year. Ron?

Ronald Eugene Mills

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. In the full year, D&C CapEx guidance is $750 million to $850 million. The lower spending versus last year related to the announced release of 2 drilling rigs in our press release last night in response to low gas prices. We’ve continued to see signs of (inaudible) pressures on service costs, including improvement in our completion cost 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 the range of $0.24 to $0.28 per Mcfe (inaudible) 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 Mcfe this year. In the first quarter, our cash G&A is expected to total of $7 million to $9 million and $30 million to $34 million for the full year. In addition, we’ll have noncash 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 (inaudible) 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 noncash 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.

I’ll now turn the call back over to the operator to answer questions from analysts who follow the company.


Our first question for today comes from the line of Derrick Whitfield from Stifel Financial.

Derrick Lee Whitfield

Let me first comment 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 produce capital if gas continues to deteriorate?

Roland O. Burns

Yes, 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 2 or 3 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 some deflationary actions kind of happening on that side. But the other levers that we can pull are 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 to each year and look to tighten up the ship wherever we can to kind of maximize the operating dollars that we have.

Derrick Lee Whitfield

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 breakeven to improve over time and if you’re expecting a meaningful difference in the breakeven between the Haynesville and Bossier intervals?

Daniel S. Harrison

This is Dan. I’d say we’re definitely gaining ground and going up the curve still faster on our Western Haynesville wells. We are — we’re drilling our first 2-well pad actually currently. We got to know (inaudible) second rig is going to its first 2-well pad next. That’s going to definitely help our efficiency there. We still have had some things that we’ve gained 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 in the Western Haynesville 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 2 frac crews, same vendor. We see some kind of some savings there, just really, really good solid performance. We brought in some 3 new rigs, new build rigs. So just 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 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 (inaudible) but yes, that’s where we’re at.


And our next question comes from the line of Charles Meade from Johnson Rice.

Charles Arthur 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 2 completion crews for the remainder of the year. Did I catch that right?

Daniel S. Harrison

That’s right. So if you look — if you just do the math, I mean, we’ve got 2, kind of 2 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. And then one running full-time and one with some gaps in between.

Charles Arthur Meade

Got it. And then my follow-up, Jay, I recognize that this is kind of a 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 $2 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 0 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 0, but why the right number for you guys is 1.7 or 1 to 2 for the next several months?

Miles 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 year 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 by well. And I think the other thing just as far as cost, I mean, usually in a conference call like this year going to release 2 rigs and it takes 2, 3, 4 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 (inaudible) was asked a question about the price of natural gas to save in 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 one 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 where the gas prices are high or low in order to buy inventory. So then you come and you look at the cost, 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 hedged about 28% of our production in ’24 to (inaudible). 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 battened down the hatches a theme 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 is 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 firm transportation agreements that you have and say, are we impacted by reducing the rig count and the answer is we are 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.


And our next question comes from the line of Fernando Zavala from Pickering Energy Partners.

Fernando Zavala

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?

Miles Jay Allison

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

Fernando Zavala

And then can you talk a little bit about — as 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.

Ronald Eugene Mills

Yes. From — 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 2 rigs here this weekend and the second rig within the next 2 to 3 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 6- or 7-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 5 rigs.


And our next question comes from the line of Jacob Roberts from TPH & Company.

Jacob Phillip Roberts

I think previously you’ve had some commentary about drilling commitments and HBP provisions on the Western Haynesville. Can you speak to the impact of running those 2 rigs for 2024 and any needed extensions or perhaps cap provisions to be needed in 2025 plus?

Roland O. Burns

We feel like that not running the 3 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 ’24, but over a longer period of time, we have a lot of acres to the term acreage that has to be — we have to drill to hold. So — but there’s — but given the actions were taken this year, we’re not really changing — having to have — know that we have to extend leases, et cetera, we still can keep all these kind of on track.

Miles Jay Allison

In fact, I think the slowdown is a positive and that in the Western Haynesville, as Dan said earlier, most of the wells we’ll be drilling now will be 2 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 derisk 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 other 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 derisked, which is probably from the heel to our northern well, probably 3 or 4 miles. We’ve said that publicly. We’ve got a lot of acreage we derisked there. So it looks good. And I think this environment is favorable for us to slow that down.

Jacob Phillip Roberts

My second question is around the leasing program that seems to have bled over from 2023 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.

Roland O. Burns

The process definitely has not become more competitive with the weak gas price environment — it’s just — it’s we’re leasing from lots of different parties. It’s — 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, so just we’re finishing up.

Miles 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 read that we hadn’t been disclosed since Spring of 2016, so 8 years. I can promise you there’s no competition out there at $1.61 at all.


Our next question comes from the line of Bertrand Donnes from Truist.

Bertrand William 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.

Roland O. Burns

Well, that level has set so much far, far lower than our forecast and even our production level now. It’s just not even a question to give any thought to.

Bertrand William Donnes

Sounds good, very distinct. 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 if 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.

Our next question comes to the line of Phillips Johnston from Capital One Securities.

John Phillips Little Johnston

My first question is on your 3.5x 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 O. Burns

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

John Phillips Little Johnston

And just to make sure our models are calibrated. As we think about the 5-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.

Yes, it’s in the press release. (inaudible) read it there. Yes. Just I don’t have the detail (inaudible) 2 seconds. So as it says in the press release, we plan to drill 46 gross and that’s about 36 net wells and turn to sales 44 gross, 38 net.


And our next question comes from the line of Leo Mariani from ROTH.

Leo Paul 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 production 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, and that’s a bit inverse to what the futures curve is suggesting where clearly, prices are expected to be lower early in ’24 and the 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 flows.

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, maybe higher next winter? And are 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 O. Burns

Well, I think it’s difficult to understand the timing of shale production and the way that the wells are drilled, 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 is that something — I mean, you obviously can give consideration to it. And we can give consideration in the field if we have low spot prices that 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 plus it takes — it takes a lot of resources to — in preparation to bring these on and you don’t have all those available (inaudible) you can’t snap your fingers and get all the wells turned on one day.

And so it’s just really balancing all that and balancing with what you have, the facts you have at the time. So just because we present a plan and budget, that means 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 S. Harrison

Yes. And I’ll add specifically to the Western Haynesville, our 10 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 1 rig that just started the 2-well pad a couple of weeks ago, and our other rig is getting ready to move to a 2-well pad. And obviously, the Western Haynesville wells (inaudible) more days to drill. So with 2 well pads, they’ll be drilling all through the spring and summer and fall.

Leo Paul Mariani

That’s helpful color, guys. And I know you can’t snap your fingers like you said, but it sounds like maybe there is some flexibility to kind of manage this a little bit on you all’s end. And I’m sure you’re going to be watching it very closely as the year progresses here.

Maybe just a follow-up on the Western Haynesville. You obviously had your reserve report out. Can you give me any color around like what some of these Western Haynesville wells were getting booked at maybe like in terms of reserves per 1,000 feet or however you guys want to present it here?

Roland O. Burns

And 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 7 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 kind of reserve bookings are in that 3.5 Bcf per 1,000 feet of completed lateral.

Only really one well has a pretty significant track record of performance, which is the first one, the (inaudible) 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 under production. So kind of left them where they are, but the other reserves are trending nicely in the play for the first wells that we’ve drilled.

Leo Paul Mariani

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 one I’m hearing (inaudible) 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 it is, I mean, 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 will there be any consideration to 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.

Miles Jay Allison

I think we’ve positioned ourselves right now so that the things that we’ve done allow us to protect our balance sheet. I mean if you could just segregate it and you look at the Western Haynesville, like Dan said, we — these wells will be slower to reach production. So even though we didn’t add a third rig, I mean, (inaudible) mentioned, we’re not going to have issues with our midstream quantities. So I don’t see any 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 in January, February, to cut some costs. So I think we just monitored like that.

There’s — 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. We don’t have to reach the (inaudible) 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 storybook tells us in the future.


Our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research.

Noel Augustus Parks

I just wanted to touch again on the Western Haynesville. So I just wondered, 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 instance?

Daniel S. Harrison

Well, I mean, we — so we’ve — I think we’ve stated before, probably the biggest difference between the Western Haynesville and our core is the temperature and the depth. I mean obviously, they’re a little bit deeper. 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, manage it, getting our (inaudible) to perform and stay on bottom longer, faster ROPs, less trips in and out of the hole to get the lateral drilled. So we’ve made a lot of gains there. And then just up top, we’ve got obviously a longer vertical section to drill. We made some modifications to our casing design.

We’ve seen our penetration rates pick up, up top also. So you just kind of — 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 in the core, we just kind of make some tweaks a little bit here and there and you pick up a day or 2, but we’re picking up bigger chunks down here in the Western Haynesville just figuring this thing out.

Noel Augustus 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 S. Harrison

I’d say we’re — the rocks turned out. I mean we knew everybody knows that the gas is there. There were 2 old wells drilled back in like 2010 and 2011 that we got data on. They had all kinds of problems, the very inferior completions put on them. But still with that, 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 our 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 been — we’ve had pretty good cost 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 the stick pipe. You can basically handle higher pressure 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.


Our next question comes from the line of Paul Diamond from Citi.

Paul Michael Diamond

Just a quick, I want to touch base on some of the D&C costs on Slide 15. Just wanted to get an idea of your view on how much of that (inaudible) drilling is 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?

Daniel S. Harrison

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 the last year. I would say more on the completion side, it’s a little bit more predictable, I would say, just need to get — this is going to basically be lower process 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 (inaudible) for the cost savings along with just the vendor pricing coming down.

Paul Michael Diamond

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

Daniel S. Harrison

Well, we’ve made some pretty good improvements, but we still got a lot of them in the pipeline (inaudible) 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. So I mean, (inaudible) as far as try to say in the middle, I’d say maybe that’s probably maybe somewhere 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 Michael Diamond

Got it. So another potential 20 days decline in the drilling time?

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.

Miles Jay Allison

First of all, I’d like to thank all of you for your questions. They make us better managers. Hopefully, we have 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 the 2 rigs, the underlying denominator of everything is stellar drilling performance and stellar inventory in our core area and that area we operate. And you look at the Western Haynesville, I mean, almost half of our footprint corporately is in 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 today. So thank you for your time.


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

By admin

Leave a Reply

Your email address will not be published. Required fields are marked *