Comstock Resources Q4 2023 Earnings Call Transcript

Quartr
Provided by Quartr
February 14, 2024

There are 14 speakers on the call.

Operator

Thank you

Speaker 1

for standing by, and welcome to the Comstock Resources 4th Quarter 2023 Earnings Conference Call. At this time, all participants are in a listen only mode. After the speakers' presentation, there will be a question and answer session. As a reminder, today's program is being recorded. And now I'd like to introduce your host for today's program, Jay Ellison, Chairman and CEO.

Speaker 1

Please go ahead, sir.

Speaker 2

All right, Jonathan. I love that broadcasting voice, kind of starts the day off right. Our corporate team 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-two dollars 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 10,000,000,000 cubic feet of natural gas per day to the LNG facilities Currently under construction in the next few years.

Speaker 2

Actions taken so far as we batten down the hatches to protect our balance sheet. Number 1, in January, we released a frac crew. Number 2, 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 3, we suspended our quarterly dividend until natural gas prices improve. Number 4, we continually our activity level as we plan to fund our drilling program within operating cash flow if possible.

Speaker 2

Number 5, we formed our midstream joint venture last year that allows us to build out the Western Angel Midstream assets to be funded by the Midstream Partnership and not burden our operating cash flow at Comstock. Number 6, we have positioned Comstock to have very few rigs needed to hold all of our corporate acres, including the 250 plus 1000 net acres in the Western Haynesville. Number 7, 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 box of chocolate on its Valentine's Day allows us to materially grow our drilling inventory organically First is through the M and 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 It's our counting on our U.

Speaker 2

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 script. Welcome to the Comstock Resources 4th Quarter 2023 Financial .com and downloading the quarterly results presentation.

Speaker 2

There you will find a presentation entitled 4th 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 2 in our presentations And note that our discussions today will include forward looking statements within the meaning of securities laws. While we believe 4th quarter 2023 highlights.

Speaker 2

On Slide 3, we summarize the highlights of the 4th quarter. The financial results continue to be heavily impacted by the continued weak natural gas prices. Oil and Gas sales, including hedging, were $354,000,000 in the quarter. We generated cash flow from operations of $207,000,000 or $0.75 per share and adjusted EBITDAX was $244,000,000 Our adjusted net income was $0.10 for the quarter. We continue to have very strong results from our drilling In the Q4, 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.

Speaker 2

Since the last conference call, We've connected 22 or 16.5 net operated wells to sales with an average initial production rate of 24,000,000 cubic foot 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 Angel exploratory play. We added 23,000 net acres to our expensive Western Haynesville acreage position in the 4th quarter alone, increasing our total acreage position in the play to over 250,000 net acres. We recently turned our 8th well to sales.

Speaker 2

The Nila well was completed in the Haynesville formation and is currently producing at 31,000,000 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 Q4 and the annual financial results. Roland?

Speaker 3

Thanks, Jay. On Slide 4, we cover our 4th quarter financial results. Our production in the Q4 of 1.5 Bcfe per day increased 6% for the Q4 of 2022 and grew 8% from the 3rd quarter. Low natural gas prices resulted in our oil and gas sales in the quarter coming in at $354,000,000 declining 37% from 20 22's Q4 despite the higher production level. EBITDAX for the quarter came in at $244,000,000 and we generated $207,000,000 of cash flow in the 4th quarter.

Speaker 3

We reported adjusted net income of $28,000,000 for the Q4 or $0.10 per share as compared to net income of $12,000,000 in the Q3 of 2023288,000,000 in the Q4 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 $1,300,000,000 and were 41% lower than our sales in 2022 due to the lower gas prices we realized. Our EBITDAX in 2023 was $928,000,000 and we generated $774,000,000 of cash flow for the year.

Speaker 3

We reported net income of $133,000,000 for 2023 as compared to net income of $1,000,000,000 in 20 22. Slide 6, we show our natural gas price realizations that we had in the quarter. During the Q4, 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 Q4 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 4th 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 buy and resell third party gas.

Speaker 3

We generated about $4,400,000 of profits in the 4th quarter That approved 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 4th quarter, 4% lower than the 3rd 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 3rd quarter rate at $0.23 Our production ad valorem taxes increased $0.03 from the 3rd quarter level.

Speaker 3

And G and A came in at $0.02 per Mcfe, which was $0.03 lower than the 3rd quarter. Our EBITDAX margin after hedging came in at 68% in the 4th 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, spent a total of $1,300,000,000 on our development activities, including $1,200,000,000 on our Haynesville and Bossier Shale drilling program. Spending on other development activity including installing production tubing, offset frac protection and other workovers totaled $54,000,000 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.

Speaker 3

These wells had an overall average IP rate of 25,000,000 per day per well. On Slide 9, we cover our natural gas and oil reserves that were determined using the required SEC prices. Our SEC proved reserves decreased 26% in 2023 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 approved reserves to our year end reserves, which replaced 109% of our 2023 production.

Speaker 3

But we also had 1.8 Tcfe of negative provisions 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 TCFE approved 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 2P or probable reserves and 4.6 Tcfe of 3 fee 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 a NYMEX cash 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 proved reserves would have been similar to last year at 6.6 Tcfe.

Speaker 3

In addition, our overall reserves, we would have had an additional of another 2 Tcfe approved 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 at 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 $580,000,000 of borrowings under our credit facility, giving us a total of $2,700,000,000 in debt, including our outstanding senior notes. Our borrowing base for our bank credit facility is currently at $2,000,000,000 of which we have an elected commitment of $1,500,000,000 of that amount.

Speaker 3

So we ended the year with overall financial liquidity of just over $1,000,000,000 I'll now turn it over to Dan to kind of discuss our operations in more detail.

Speaker 4

Okay. Thank you, Roland. Overall, Slide 12, this shows where our current drilling inventory stands at the end of the year into the 4th quarter. Our inventory is split between our Haynesville and Bossier locations. We have it divided up into 4 buckets.

Speaker 4

Our short laterals run up to 5,000 feet. Our medium laterals run between 5,008,500 feet. We have our long laterals between 8,510,000 feet and then our extra long laterals extending out beyond 10,000 feet. Our total operated inventory currently stands at 1706 gross locations and 1303 net locations. This equates to a 76% average working interest across our operated inventory.

Speaker 4

Our non operated inventory has 1253 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, 4 38 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 6 30 locations have laterals greater than 10,000 feet and 63% of the gross operated inventory has laterals exceeding 8,500 feet.

Speaker 4

The average lateral length on our inventory now stands at 8,971 feet and this is up slightly from 8,949 at the end of the 3rd quarter. Our inventory provides us with 25 years of future drilling locations. On Slide 13, there's a chart outlining our progress to date on our average lateral length drilled based on the wells that we've turned to sales. During the Q4, we turned 17 wells to sales with an average length of 11,870 Foot And this is thanks to the continued success 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.

Speaker 4

During the Q4, 12 of the 17 wells we turned to 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 and 28 wells with laterals over 14,000 feet. During the Q4, we didn't turn any wells to sales on our new Haynesville acreage. To date, in 2024, we have turned 1 well to sales in the Western Haynesville. We do expect a total of 4 wells to be turned to sales by the end of the Q1.

Speaker 4

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 9,000,000 a day up to 42,000,000 a day with an average test rate of 24,000,000 cubic feet a day. The average lateral length was 11,966 feet with the individual laterals ranging from 5,000 736 feet up to a 15,243 foot lateral. The Hamilton Verhalen B2 well located in East Texas, which had a 9,000,000 a day IP rate suffered mechanical casing failure during completion, which resulted in this well producing from only half of the completed lateral.

Speaker 4

In addition to the first seven wells producing in the Western Haynesville at the end of 2023, We recently placed our 8th well online. The Neland No. 1 was drilled in the Haynesville and today it is currently producing 31,000,000 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 Q1.

Speaker 4

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 and C costs through the Q4 for our Mitch Mark 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 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 4th quarter, our D and C cost averaged $14.82 a foot on the 13th Benchmark long lateral wells And this reflects a 5% decrease compared to the 3rd quarter.

Speaker 4

Our 4th quarter drilling cost averaged $6.10 a foot, which is a 15% decrease compared to the 3rd quarter. The lower drilling cost reflects a slight downward trend on pricing we've experienced throughout 2023 and also our drilling costs in the Q3 was abnormally higher due to some drilling issues we had in that quarter. Our 4th quarter completion costs came in at $8.71 a foot, which is a 3% increase compared to the 3rd quarter. The increase in completion costs were primarily attributable to some slightly higher plug drill out cost in the Q4 due to the longer laterals. We currently have 7 rigs running and we are in the process of releasing 1 rig this weekend And end of the month, early next month, we'll be releasing a second rig.

Speaker 4

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 1 to 2 frac crews running for the remainder of the year. I'll now hand the call back over to Jake.

Speaker 2

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 Angel acreage position totaled over 250,000 net acres.

Speaker 2

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 mid partnership and will not be a burden on our operating cash flow. We believe that we are building a great asset and the Western Angel 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 1 of our 3 completion crews, as Dan said, and 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.

Speaker 2

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 $1,000,000,000 at the end of the Q4. I'll now have Ron provide some specific guidance for the rest of the year. Ron?

Speaker 5

Thanks, Jay. On Slide 17, we provide the updated financial guidance for the Q1 of this year and the full year. 1st quarter D and C CapEx guidance is $225,000,000 to $275,000,000 In the full year, D and C CapEx guidance is 7 $850,000,000 The lower spending versus last year is 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 some deflationary pressures on service costs, improvement in our completion cost per stage. We anticipate spending an additional $30,000,000 to $40,000,000 on lease acquisitions in the Q1 $40,000,000 to $50,000,000 over the course of the year.

Speaker 5

Capital expenditures related Pinnacle Cash Services will be funded by our midstream partner and are expected to total $30,000,000 to $40,000,000 in the Q1 and $125,000,000 to $150,000,000 for For both the Q1 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 and A rate is expected to average $1.30 to $1.40 per Mcfe this year. In the Q1, our cash G and A is expected to total $7,000,000 to $9,000,000 $30,000,000 to $34,000,000 for the full year. In addition, we'll have non cash G and A in the Q1 of $2,700,000 to $3,000,000 and $10,000,000 to $12,000,000 for the full year.

Speaker 5

With the increase in SOFR rates and our current debt levels, Cash interest expense is now expected to total $43,000,000 to $47,000,000 in the Q1 and $195,000,000 to $205,000,000 for the year, while non cash interest will remain approximately $2,000,000 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.

Speaker 1

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.

Speaker 6

Good morning, all, and thanks for your time.

Speaker 2

Yes, sir.

Speaker 6

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? Yes,

Speaker 3

Derek. 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 other 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 are continue to look at dropping another rig.

Speaker 3

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 Each year and look to tighten up the ship wherever we can to kind of maximize the operating dollars that we have.

Speaker 6

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 to 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?

Speaker 4

So Barry, this is Dan. I'd We're definitely gaining ground and going up the curve still faster on our Western Haynesville wells. We are we're drilling our first two well pad actually currently. We got to know what the second rig is going to, its 1st, 2 well pad next. That's going to definitely help our efficiency there.

Speaker 4

We still have had some things that we've Gayed 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 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 efficiency, 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.

Speaker 4

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 were probably down 10% or so this year since the beginning of last year. And obviously, times, we I think everybody gets pretty streamlined and pretty efficient and the cost come down. But Obviously, we'd like to see maybe prices be a lot higher and be battling some of those things.

Speaker 4

But yes, that's where we're at.

Speaker 6

Very helpful. Thanks for your time.

Speaker 1

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.

Speaker 7

Good morning, Jay, to you and your whole team there, Comstock.

Speaker 2

Good morning.

Speaker 7

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 12 completion crews For the remainder of the year, did I catch that right?

Speaker 4

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.

Speaker 7

Got it.

Speaker 4

Got it. So one running full time and one with some gaps in between.

Speaker 7

Got it. And then my follow-up, Jay, and I recognize that this is kind of a maybe the 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 above We don't get up $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 So kind of bridge the view for it looks like the right number is 0, but why the right number for you guys is 1.7 or 1 to 2 for the next several months?

Speaker 2

Well, I think that's a really good question. Number 1, 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. 2nd of all, maybe you have contracted to have that frac crew and you have to use them. We don't have any contracts.

Speaker 2

It's a well by 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 2 rigs and it takes 2, 3, 4 months to release those rigs and 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, 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.

Speaker 2

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 where the gas prices are high or low in order to buy inventory. So then you come and you look At the cost, when 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.

Speaker 2

We've looked at hedging. We've hedged about 28% of our production in 2024 to 355 swap. I think that we need to be in the 50% range. Now when will we get there? I don't know.

Speaker 2

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 batten down the hatch 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 need 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 65% of this, if anybody is trying to protect it, the Jones family is and they're well involved with what we do.

Speaker 2

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.

Speaker 2

I mean, some groups haven't recognized it because they haven't experienced it. We do. 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.

Speaker 2

So that's a great question.

Speaker 7

Thank you for that elaboration. That was helpful, Jay.

Speaker 2

Yes, sir.

Speaker 1

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.

Speaker 8

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

Speaker 2

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

Speaker 8

Okay, got it. And then can you talk a little bit about the as my follow-up, the trajectory of production In 2024, it seems like the implied 2024 guidance is in line with Q1, so just a little bit more color there.

Speaker 5

Yes. From a if you think about the timeframe 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 3rd quarter and a little bit larger decline in the Q4, as you start to feel the full brunt of running 5 rigs.

Speaker 8

Okay, that's helpful. Thank you.

Speaker 1

Thank you. One moment for our next question. And our next question comes from the line of Jacob Roberts from TPH and Company. Your question please.

Speaker 9

Good morning.

Operator

Good morning. Good morning.

Speaker 9

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 20 24 and any needed extensions or perhaps catch up provisions to be needed in or perhaps CAPTCHA provisions to be needed in 2025 plus?

Speaker 3

No. 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 2024, Yes. 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 we're taking this year, we're not really changing Having to have know that we have to extend leases, etcetera, we still can keep all these kind of on track.

Speaker 2

In fact, I think The slowdown is a positive in that in the Western Haynesville, we as Dan said earlier, Most of the wells we'll be drilling now will be 2 wells per pad. We have been drilling 1 well per pad. I think it lets our land group Now get ahead a little bit for 2025 and 2026 because we have added a lot of acreage within a small window. I think it lets us position our wells better in 2024 and 2025 to derisk a lot greater swath of acreage with fewer wells. So it Really has been the slowdown has served our land group well.

Speaker 2

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 2025 like we were going to do in 2024. 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 that the area that we derisk, which is probably from the Hill to our northern well, probably 20 3 or 4 miles. We've said that publicly, we've got a lot of acreage we derisk there.

Speaker 2

So It looks good. And I think this environment is favorable for us to slow that down.

Speaker 9

Thanks for that. My second question is around the leasing program that seems to have bled over from 2030 into 2024 And it's pretty heavily focused in

Speaker 3

the Q1 of the year. Can you

Speaker 9

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.

Speaker 3

The process definitely has not become more competitive with the weak gas price environment. It's just a We're leasing from a lots of different parties. It's a there's a lot of lots of reasons why you don't 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.

Speaker 3

And so that's really driving the program With anything else, it's just we're finishing up.

Speaker 9

Great. Appreciate the time.

Speaker 2

Well, we've stated that we average about $5.50 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 8 years. I can I promise you there's no competition out there at $1.61 at all?

Speaker 1

Thank you. One moment for our next question. And our next question comes from the line of Burton Dong from Truist. Your question please.

Speaker 10

Hey, good morning guys.

Operator

Good morning. Good morning.

Speaker 10

Good morning. This one might be a little bit weird and I'm not saying it's 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

Speaker 3

Well, that level is 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 thoughts to.

Speaker 10

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.

Speaker 2

No, we didn't consider that.

Speaker 10

Sounds good. I appreciate the answers. Thanks.

Speaker 2

Great questions.

Speaker 1

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

Speaker 11

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 Thanks.

Speaker 3

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

Speaker 11

Okay, sounds good. 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?

Speaker 2

Ron's got that number.

Speaker 3

Yes, it's in the press release.

Speaker 2

Yes, it's in the press release.

Speaker 3

You want to read it there, yes.

Operator

So as it says in

Speaker 5

the press release, we plan to drill 46 gross And that's about 36 net wells and turn to sales 44 gross, 38 net.

Speaker 11

Okay. Sorry about that. I completely missed that, I'm taking.

Speaker 3

Thank you.

Speaker 1

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

Operator

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 in the first half of the year, a little bit of a 3rd quarter decline and then more of a 4th 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 2024 and then higher as you get those winter months in 2024. 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, maybe higher Next winter, is there any operational reasons maybe why you couldn't do that?

Operator

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.

Speaker 3

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 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 something I mean, you obviously can give consideration to it and we can give consideration in the field if we have 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 2 plus it takes like It takes a lot of resources to in preparation to bring these on and you don't have all those available at the You can't stack your fingers and get all the wells turned on in 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 mean it's going to happen exactly that way.

Speaker 3

So, we'll adjust as we go through the year to what's going on in the markets And what's available on the spot market or the index market, etcetera?

Speaker 4

Yes. And I'll add specifically to the Western Haynesville. Our 2 frac crews are actually fracking wells there now in the Western Haynesville. So there's really only one other well 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 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 is taking more days to drill.

Speaker 4

So with 2 well pads, they'll be drilling all through the spring and summer and fall.

Operator

Got it. Okay. That's helpful color guys. 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 you all's end and I'm sure you're going to be watching it very closely as the year progresses here. So Okay.

Operator

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 1,000 feet or however you guys want to present it here?

Speaker 3

Yes. And generally, we don't have a lot of bookings because we're not trying to get beyond 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 is the average kind of reserve bookings are in 3.5 Bcf per 1,000 feet of completed lateral.

Speaker 3

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 this, 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.

Operator

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, 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 next year because of holding some of the Western Haynesville and whether there be any consideration of maybe putting in some, I'll call it near term funding to kind of you over the gap here until markets improve later in 2025 and 2016?

Speaker 2

I think we have positioned ourselves right now So that the things that we've done allow us to protect our balance sheet. I mean, if you just Segregated, 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 3rd rig, I mean, as Raul mentioned, we're not going to have any issues with our midstream 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.

Speaker 2

And we as we said, we were very, very proactive even in December, much less January, February to cut some cost. Much less January, February to cut some costs. So I think we're 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.

Speaker 2

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.

Speaker 2

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.

Speaker 6

Okay. Appreciate the color.

Speaker 1

And our next question comes from the line of Noel Parks from Tuohy Brothers Investment Research. Your question please.

Operator

Hey, good morning. Good morning, Noel.

Speaker 12

I just wanted to touch again on the Western Haynesville.

Operator

I just wondered, can you talk

Speaker 12

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?

Speaker 4

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 in 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 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 on the we've got Obviously, a longer vertical section to drill.

Speaker 4

We've made some modifications to our casing design. We've seen that Our penetration rates pick up, up top also. So you just kind of 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 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.

Operator

And are you at a point where

Speaker 12

productivity of the rock It's pretty much not a surprise anymore? Are you still learning things there?

Speaker 4

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 2011 that we got data 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.

Speaker 4

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 been we've had pretty good costs there, not cost fluctuation, I mean, consistent on the cost also on the completion side.

Speaker 4

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 pressured wells with that than with coiled tubing. And so we've had great in that regard also that helped us out with these wells. So really, I mean, the completion side, everything is clicking along really good. We'll get some cost savings from our vendor there.

Speaker 4

And then really on the drilling side, it's just the gains we're seeing, just basically shaving days off these wells.

Operator

Great. Thanks a lot.

Speaker 2

Yes, sir. Good question.

Speaker 1

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

Speaker 13

Thank you. Good morning. Thanks for taking the call. Just a quick, I want to touch base on some of the D and C costs on Slide team, just wanted to get an idea of your guys' view on how much of that shipped in shipped out in drilling is deflationary or how much should we think about that and kind of inverse for completions, how much should we expect that to be sticky going forward?

Speaker 4

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% Calls into this year versus last year, save more on The completion side is a little bit more predictable, I would say. Just need to get This is 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.

Speaker 13

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

Speaker 4

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. So I mean, As far as trying to say in the middle, I'd say maybe that's probably 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.

Speaker 13

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

Speaker 4

Yes, sir.

Speaker 13

Thanks for your time.

Speaker 1

Thank you. This does conclude the question and answer session of I'd like to hand the program back to Jay Ellison for any further remarks.

Speaker 2

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.

Speaker 2

In that area we operate and you look at the Western Angel, I mean, almost half our footprint corporately is in the Western Angel. Those wells look very promising. So, we again, we know that this is 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. Thank you for your time.

Speaker 1

Thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program.

Powered by Quartr
Earnings Conference Call
Comstock Resources Q4 2023
00:00 / 00:00