Comstock Resources Q3 2023 Earnings Call Transcript

Quartr
Provided by Quartr
October 31, 2023

There are 15 speakers on the call.

Operator

Good day and thank you for standing by and welcome to the Q3 2023 Comstock Resources Inc. 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. Please be advised that today's conference is being recorded.

Operator

I would now like to introduce your host for today's call, Jay Allison, Chairman and CEO. Please go ahead.

Speaker 1

Good morning, everyone. In Frisco, Texas, this morning, it's 34 degrees. The Texas Rangers took the lead in the World Series and I saw natural gas prices were up about $0.20 this morning. So we're all smiles here. We started out the day the right way.

Speaker 1

The world of natural gas is something that is a big part of our business. Reported a profitable 3rd quarter with a realized gas price of only $2.41 With only 18% of our gas hedged, highlights our extremely low operating cost structure and our high margins. The 18 net operated wells returned to sales since our last update on our extensive HaynesvilleBossier acreage position continued To deliver solid results from our legacy area as well as the emerging Western Haynesville, The 2 Western Haynesville wells we recently turned to sales were top of the class wells as were the other 5 that we turned to sales starting with Our Western Haynesville well, the Circle M, which started production April of 2022. Make no mistake about it, we're extremely pleased With the results of all the Western Haynesville wells we have turned to sell so far. This year, we're focused on proving at the Western Haynesville and continuing to build our It's a brokerage position.

Speaker 1

During this time of weak natural gas prices, we're providing a dividend to our stakeholders, Holding our legacy production steady, while being accountable to our bank lending group, who just reaffirmed our $2,000,000,000 borrowing base, Improving up a much needed new gas for resource near the expanding LNG export facilities along the Texas And Louisiana Gulf Coast. A major step in development of our Western Haynesville play is finding the right partner For the midstream build out needed to support our Western Haynesville drilling program, we're excited to partner with Quantum Capital Solutions to that end. We want to publicly thank them for entering into this new adventure with us. If you go to the main slides, we welcome you to the Comstock Resources 3rd quarter 2023 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation.

Speaker 1

There you'll find a presentation entitled 3rd Quarter 2023 Results. I have Jay Allison, Chief Executive Officer of Comstock And with me is Roland Burns, our President and CFO Dan Harrison, our COO and Ron Mills, our VP of Finance and Investor Relations. If you go to Slide 2, please refer to Slide 2 in our presentations and note that our discussions today include forward looking statements Within the meaning of securities laws, while we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove To be correct. Now if you'll flip to Slide 3, what we'll do is we'll summarize the highlights of the 3rd quarter. The financial results were heavily impacted by the continued low natural gas prices we realized in the quarter.

Speaker 1

Oil and gas sales, including hedging, were $316,000,000 in the quarter. We generated cash flow from operations of 100 and $16,000,000 or $0.60 per share and adjusted EBITDAX was $209,000,000 Our adjusted net income was $0.04 for the quarter. We continue to have strong results from our drilling program. We drilled 13 or 10.2 net successful operated Haynesville and Bossier Shale horizontal wells in the quarter with an average lateral length of 11,644 feet. Since the last conference call, we've connected 21 or 18.1 net operated wells for sales With an average initial production rate of 29,000,000 cubic feet per day, we're having great success in our Western Haynesville's forward toward play.

Speaker 1

Our 6th and 7th wells were recently turned to sales with strong initial production rates, both of which were drilled In the Bossier Shale, we recently entered into a new venture with Quantum Capital Solutions to fund the midstream A build out to support our Western Haynesville drilling program, which I'll expand on the next slide. If everyone would turn to Slide 4, This visibly shows our Bethel plant, which is part of the Pinnacle gathering and treating system we acquired last year. Pinnacle combined with our processing we have in the area will allow us to grow our Western Haynesville production up to 500,000,000 cubic feet per day. Given how prolific these wells have been, we see running out of capacity in this area by 2025. We're excited to partner with Quantum Capital Solutions, an affiliate of Quantum Capital Group, to build out this system to handle future growth.

Speaker 1

To that effect, we have set up a mid spring partnership with QL to build out the system to increase the capacity 4 fold We'll contribute to Pinnacle Gethinking and Treating System to the partnership and QOL will contribute 100% of the capital required Up to $300,000,000 for the build out of the gathering and treating system. We'll operate the partnership, which will be called Pinnacle Gas Services, it will direct its activities. Quantum receives a preferred return in 80% of distributions Until the investment hurdle is achieved, then that reduces to 30%. I'll now turn it over to Roland to cover the Q3 financial results. Roland?

Speaker 2

All right. Thanks Jay. On slide 5, we covered the Q3 financial results. Our production in the 3rd quarter was 1.4 DCFe per day, which was 1% higher as compared to the Q3 of last year and 3% higher than the 2nd quarter. Low natural gas prices significantly impacted our oil and gas sales in the quarter, which came in at $316,000,000,000 which is 54% lower than The Q3 of 2022 EBITDAX was $209,000,000 and we generated $167,000,000 of cash flow during the quarter.

Speaker 2

We reported adjusted net income of $12,000,000 for the 3rd quarter as compared to only $1,000,000 in the Q2 of this year and then $326,000,000 in the Q3 of last year. Slide 6, we have our financial results for the 1st 9 months of this year. Production for the 1st 9 months averaged 1.4 Bcfe per day. That was 4% higher as compared to the same period in 2022. Oil and gas sales in the 1st 9 months of this year totaled $991,000,000 which is 42% lower than last year's Sales in the same period and EBITDAX was $685,000,000 and we generated $568,000,000 of cash flow for the 1st 3 quarters of this year.

Speaker 2

We reported adjusted net income of $105,000,000 for the 1st 3 quarters of this year As compared to $735,000,000 for the same period in 2022. On Slide 7, we detail our natural gas price realizations that we had in the 3rd quarter. The quarterly NYMEX settlement price in the 3rd quarter averaged $2.55 It was very close to the average spot price in the quarter, which averaged $2.58 Our realized gas price during the Q3 averaged $2.33 reflecting a $0.22 differential to the settlement price and a $0.23 differential to the reference price. The differential this quarter returned to more normal levels due to improvements in the Houston Ship Channel and Katy Hub prices following the Restart of the Freeport LNG facility. In the Q3, we were 18% hedged, which improved our realized gas price to $2.41 We've been using some of our excess transportation in the Haynesville to buy and resell third party gas.

Speaker 2

We generated about $2,500,000 of profits On Slide 8, we detail our operating cost per Mcfe produced and our EBITDAX margin. Our operating cost averaged $0.85 per Mcfe in the 3rd quarter, it's 1% higher than our 2nd quarter rate. The increased unit costs relate to higher production taxes and higher ad valorem taxes imposed in the State of Louisiana. Our gathering costs were flat this quarter at $0.36 and our other lifting costs were 3% lower than the 2nd quarter Our production and ad valorem taxes increased $0.05 this quarter compared to the 2nd quarter level. G and A came in at $0.05 per Mcfe.

Speaker 2

That was 0 point 0 $1 lower than the rate we had in the 2nd quarter. And our EBITDAX margin after hedging came in at $0.65 65% in the 3rd quarter as compared to 63% In the Q2 of this year. On slide 9, we recap our spending on drilling and other development activity For the 1st 9 months of this year, so far we spent $958,000,000 on our development activities including 919,000,000 on our operated Haynesville and Bossier shale drilling program. Spending on other development activity has totaled $38,000,000 so far this year. In the 1st 9 months of this year, we've drilled 52 wells or 41.3 wells net to our interest in our operated drilling program and we've turned 57 or 43 net operated wells to sales.

Speaker 2

The wells that returned to sales had an average IP rate of 25,000,000 cubic feet per day. On slide 10, we recap our balance sheet at the end of the Q3. We ended the quarter with $345,000,000 of borrowings Outstanding that our credit facility given us a total of $2,500,000,000 in total debt. Our $2,000,000,000 borrowing base was recently reaffirmed by And we ended the Q3 with financial liquidity of almost $1,200,000,000 I'll now turn it over to Dan to Discuss the operations in more detail.

Speaker 3

Okay. Thank you, Roland. So Slide 11 is a breakdown of our current drilling inventory At the end of the Q3, the drilling inventory split between the Haynesville and the Bossier and is divided into 4 categories With our short laterals that are up to 5,000 feet, we got our medium laterals that run between 5,000 feet and 8,000 feet, our long laterals At 8,000 to 11,000 feet in our extra long laterals beyond 11,000. The total operated inventory Currently stands at 1760 gross locations and 13 38 net locations. This equates to a 76% average working interest across the operated inventory.

Speaker 3

Our non operated inventory has 12 65 gross locations and 153 net locations, which represents a 12% average working interest across the non op inventory. Breaking down our gross operated inventory, we 307 short laterals, 286 medium laterals, 7 12 long laterals and 455 Extra long laterals. The gross operated inventory is split 52% in the Haynesville and 48% in the Bossier. 26% of the gross operated inventory for the 4 55 locations have the lateral lengths greater than 11,000 feet, 66 or 2 thirds of the gross operated inventory has laterals exceeding 8,000 feet. The average lateral length in the inventory stands at now stands at 8,949 feet, which is up slightly from 8,947 feet at the end of the second The inventory provides us with 25 years of future drilling locations.

Speaker 3

On Slide 12 is the chart which outlines our progress to date on our average lateral lengths drilled based on the wells that we have turned to sales. During the Q3, we returned 21 wells to sales with an average lateral length of 10,460 feet, thanks to the continued success of our long lateral drilling program. The individual links range from 6,789 feet up to 15,000 333 feet and our record longest lateral still stands at 15,726. During the Q3, 6 of the 21 wells returned to sales had laterals that exceeded 11,000 feet and 5 of these exceeded 14,000 feet. To date, we've drilled a total of 64 wells with laterals Over 11,000 feet and 33 wells with laterals over 14,000 feet.

Speaker 3

During the Q3, we also had 2 additional wells that turned Sales on our new Western Haynesville acreage. The KZMS 1 and the Lanier 1 wells were both completed in the Bossier Shale. These wells represent the 6th and 7th new vintage wells now producing in the Western Haynesville. Based on our current schedule, we plan to turn another 17 wells to sales by year end. 13 of these will be longer than 11,000 feet and 8 of the wells Longer than 14,000 feet.

Speaker 3

We expect by year end 2023, our average lateral length will be approximately 11,000 feet. Slide 13 outlines our new well activity. We've turned to sales and tested 21 new wells It's the time of the last call. The individual IP rates range from 18,000,000 a day up to 39,000,000 a day We had an average test rate of 29,000,000 cubic feet a day. The average lateral length was 10,460 feet With individual laterals from 6,789 up to 15,333 feet.

Speaker 3

Included in the quarter again are the 6th and 7th new vintage wells in our Western Haynesville acreage. The KZMS, Which was completed in the Bossier had a lateral length of 10,028 feet and was turned to sales in August. We tested the well with an IP rate of 34,000,000 cubic feet a day. The Lanier number 1 well, which was also completed in the Bossier, It was completed with a 9,577 foot lateral and this well was turned to sales in September. We tested this well with an IP rate of 35,000,000 cubic feet a day.

Speaker 3

In addition to the First 7 producing wells, we have one well that is currently waiting on completion and we do expect to turn that well to sales in January. We currently have 2 rigs actively running on our Western Haynesville acreage that are drilling our 9th and 10th wells. Slide 14 summarizes our D and C costs through the Q3 for our benchmark Long lateral wells that are located on our legacy core East Texas and North Louisiana acreage discovers the wells having laterals greater than 8,500 feet long. During the quarter, we turned 19 wells to sales that were on our core East Texas, North Louisiana acreage And 13 of the 19 wells were our benchmark long lateral wells. In the Q3, our D and C cost averaged $15.61 a foot on these 13 benchmark wells, which reflects a 1% increase compared to the 2nd quarter.

Speaker 3

Our 3rd quarter drilling cost averaged $7.19 a foot, which is a 10% increase compared to the 2nd quarter, partially due to the lower average lateral length in the quarter and some drilling issues encountered in the quarter. Our Q3 completion costs came in at $8.42 a foot. This is a 5% decrease compared to the 2nd quarter. The decrease in completion costs mirrors the slight decline in service costs we have experienced since earlier in the year, which is associated with the lower Activity levels. And to wrap up our forecasted activity levels, we're currently running 7 rigs.

Speaker 3

We do expect to keep the same rig activity going into next year and we are also running our 3 frac crews and we expect to keep these 3 frac crews Also working into next year. I'll now turn the call back over to Jay.

Speaker 1

Okay. Thank you, Dan. Thank you, Roland. If everyone would turn to Slide 15. I will direct you to Slide 15, where we summarize our outlook for the rest of 2023.

Speaker 1

We remain very focused on improving up our Western Haynesville play and continuing to add to our extensive acreage position in this prolific play. 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. Our new Western Haynesville Midstream partnership will reduce 2024 capital expenditures that would otherwise be required to support the growth in production that we expect. Our industry leading lowest cost structure is an asset in the current low natural gas price environment as our cost structure is substantially lower Then the other public natural gas producers, we plan to retain the quarterly dividend of $0.125 per common share. And lastly, we'll continue to maintain our Very strong financial liquidity, which totaled almost $1,200,000,000 at the end of the quarter.

Speaker 1

I'll now have Ron to provide some specific guidance for the rest of the year. Ron?

Speaker 4

Thanks, Jay. On Slide 16, we provide The financial guidance for the Q4 of 2023.

Speaker 1

4th quarter D

Speaker 4

and C CapEx guidance is $240,000,000 to $280,000,000 We've seen some signs of deflationary pressures on service costs relative to earlier this year. We believe most of those improvements will be seen in 2024. In terms of infrastructure and other spending, we continue to budget $15,000,000 to $25,000,000 of spending during the Q4. On our combined basis, our D and C and infrastructure and other CapEx should remain within our past annual guidance of $1,020,000,000 to $1,280,000,000 In addition to what we spend on our drilling program Noted above, we now anticipate spending $30,000,000 to $40,000,000 in the 4th quarter for additional leasing activity. Our LOE costs are expected to average $0.24 to $0.28 per Mcfe in the 4th quarter, while our Gathering and transportation costs are expected to be $0.32 to $0.36 per Mcfe in the Q4.

Speaker 4

Production and adnorm taxes are expected to average $0.15 to $0.20 per unit in the 4th quarter, which is higher due to higher ad valorem taxes in Louisiana to go along with the higher production tax rate that Louisiana put into effect at the beginning of Q3. DD and A rate is expected to remain in the $1.05 to 1.15 Per Mcfe range, while our cash G and A is expected to remain in the $7,000,000 to $9,000,000 range for the quarter with an additional plus roughly $2,000,000 of non cash G and A. Due to the increase in SOFR rates, our cash Interest expense is now expected to total $42,000,000 to $46,000,000 in the 4th quarter, while our non cash interest will remain roughly $2,000,000 per quarter. On taxes, the effective tax rate is still expected to be in the 22% to 25% range and we still expect to defer 95% to 100% of our reported taxes this year. Now I'll turn the call back over to the operator to answer questions.

Operator

And our first question comes from Derrick Whitfield from Stifel. Your line is now open.

Speaker 5

Thanks. Good morning all and congrats on your partnership. Thank you. Regarding the Quantum partnership, I wanted to confirm a Comment you made in your prepared remarks. If my numbers are correct, a fourfold increase suggests you're solving for 2 Bcf per day of capacity In the Western Haynesville, if that's correct, could you comment on how you're thinking about mainline egress as well?

Speaker 1

Well, I think when we looked at our footprint in the Western Haynes, we look at our inventory and we looked at The wells that we'll be drilling between now and maybe 2028 and we look around the corner to see what type of production we may have Between now and then and a lot of that depends upon what the market needs. We think in the latter part of 'twenty four, You're going to need another 4.5 to 5 Bs and every year after that you're going to probably need another B a day and that's just for LNG, exportable gas, Pete, yes. So when we looked around in Quantum, which is I mean, that is a blue ribbon financing source when we started I was visiting with them months ago and they started looking at our footprint and the well performance. We looked at what do we need to do for Structure to build this out. We also looked at in the Q2 of 2022 when we had bought the Pinnacle Facility, the Bethel in that 145 mile pipeline, what is our starting block as far as this midstream company?

Speaker 1

So we evaluated all that. We looked at the rig count, which again we will add. Our goal is to add a rig In the Haynesville in the Western Haynesville next year, we go from 2 rigs to 3 and then we would add another rig in 2025 and we think that would VP, our entire footprint. So if you look at that and you look at the model for 5 years and you look at the need for gas, We modeled it out that by 2028, we would have the capacity With the takeaway both for transportation and the gathering for the financing from Quantum to have at least 2 Bs a day If we would have available to serve America and the global, that's where we come up with this fourfold number And it's based upon us having about $500,000,000 a day by kind of mid-twenty 25 and then growing on that With investments that we would make between now and then and into the future years to 2028. That is how we backed into this, which I I think that's a really good question because Quantum, which is known for funding midstream And the Western in the Haynesville and now in the Western Haynesville, I mean, I think they looked at everything kind of like our banks did And Sid, we're really pleased with what you've done and we like where you're going and we would like to partner with you.

Speaker 1

And so we were that's why We publicly thank them for entering through this new venture with us because they give a good check mark to the rest of the world That they do approve with what we've been doing and where we're going. Remember, our first Western Angel well was only drilled 2 years ago, we started drilling those 2 years ago and we started leasing the acreage 3 years ago. But we really are building a company. And when you build that company, you have to look what's going to happen in 'twenty seven, 'twenty eight and all that is dependent upon The feedstock that's needed for LNG, that's where we had the announcement today and that's where that 2 Bs come from. You did your math on that.

Speaker 5

Appreciate it Jay and thanks for all the color too. In the past, you guys have talked about the Western Haynesville And the asset seeing similar returns to the legacy Haynesville at kind of current operating conditions. With the understanding that you're still in the early stages of your learning curve in the Western Haynesville, could you speak to what you're seeing in operational efficiency gains And the degree cost could improve over time?

Speaker 3

Yes. This is Dan. So we have seen we've made great strides And our cost structure in the Western Haynesville, like you mentioned, it is early. We're on the steep part of the learning curve still. We've probably cut off, I'd say around 20 days on our drill times from when we drilled the first Circling well is kind of where we're at today.

Speaker 3

We do have some things in the pipeline, a line of sight to get the cost down Further, that will be coming up in the future. So we feel pretty confident about that. And then on the completion side, I think That probably doesn't have as big a potential for cost savings because it's pretty much the same thing we do day in and day out. It's a little bit higher Our cost to frac these wells down here, so really the efficiency gains on the completion side would be would come from doing multi well pads And just typical operational improvements.

Speaker 1

I would comment on looking at Dan and the group, Things that were once really complex when we drill the Circle M, some of those things become a little simpler. If you drilled your 7th well and turn it to sales, now you're drilling your 8th, 9th and 10th well, and now we started focusing on the Haynesville, not so much the Bossier. So I do see that. And some of the hand wringing that would require us to drill the first So certainly I'm well. I don't think we have as much of that.

Speaker 1

We do have it going forward. But I do think that that shows you where Quantum comes in and has seen the well results and performance and what the future looks like as far as our inventory. And that kind of answers your question. We think the cost can come down. We think our focus is on lasting worth, Not near term kind of wealth, it's more of a lasting long term goal as we quote continuing to build this company.

Speaker 1

We are building the company.

Speaker 5

Very helpful. Thanks for your time.

Operator

And thank you. And one moment for our next question. And our next question comes from Charles Meade from Johnson Rice.

Speaker 6

Good morning, Jay, to you Roland, Dan, Ron and the whole crew there.

Speaker 4

Good morning.

Speaker 1

Carl, it's always good to hear from you. You should be here with us The 34 degree weather, you'd be happier.

Speaker 6

I would be happier. We were in the 50s down here this morning. I liked it. But anyway, Jay, I want to ask a real question about your business decisions here. $300,000,000 from of outside capital, that's great that you've got a high quality partner like Quantum willing to put that kind of Money into a JV.

Speaker 6

I'm curious about what you can share about the way they looked at this and I'm imagining that For them to put that much money to work, they have to have some kind of maybe it's not a firm commitment, but some kind of commitment to the amount of volumes that you're going to put through this This system and maybe that's a minimum volume commitment, maybe it's something else. And also, can you talk about the rate That you're going to be paying per Mcf is usually the way that's denominated. But just in general, how are you as the producer going to pay That Midstream entity Pinnacle Gas.

Speaker 2

Yes, Charles, that's a good question. And I think that we're We're going to continue to charge the same rate that we've been charging since the first wells went on to the system that we acquired last year. Yes. And we charge for all processing and transportation about $0.54 Per Mcf, so there's really no change in the rate. It's the same rate that we historically have had.

Speaker 2

And yes, we have a very Yes. Small MVC, that's back to our own subsidiary here. That is far less than half of what we project the production to be. So that kind of just kind of supports The new midstream entity.

Speaker 6

Got it. So that's if I understood you right Roland, so As far as midstream rates, it's just consistent with what you guys are already paying and that there was some volume commitment, but it's less than half of what you're projecting From this asset? That's correct. Okay, got it. Yes.

Speaker 1

You know risk adjustment too with the existing production that we have Charles. So I think we start out with a big risk adjustment day 1.

Speaker 6

Got it. And then I guess we can do the work ourselves, Between those two numbers, we should be able to figure out when that ownership reverts or rather where they go from, Whatever 80 to 30, but we'll do that work offline. Second question, I want to ask again about the Western Haynesville, obviously you guys are This is a big effort for you guys. When I look at your rub results, you guys are clearly, you guys can put up These IPs in the mid to high 30s or even I think you've had 1 or 2 over 40. So I think that aspect has been derisked.

Speaker 6

But There's other important data points, which are the D and C costs. I wonder if you could share what your Maybe not where you are now, but what your target D and C cost is on these wells? And then perhaps what the pressure drawdown is like over time, If you want to share any of that.

Speaker 1

Well, I'll start out and then I'll leave it to Dan. I think number 1, We're not rigging the system with a high IP rate that's cut in half. The second that you don't need an IP rate, I mean these IP rates are real rates that we're flowing these wells at. I think that's number 1, which that's unusual. Number 2, I think the EURs, as we said in the wells that we're drilling, I mean, they may be double what the EUR is in a typical legacy well.

Speaker 1

So those are big game changers. Number 3, I think the cost of any exploration play or exploitation play For the first seven wells, it's going to be a little higher than normal. We always said, Charles, you take the first seven wells And the HaynesvilleBossier in the legacy footprint back in 2,008 and you need a big barf bag because they look terrible. I think these 7 wells will make you smile. Dan already said that he's cut the drilling days down by at least 20 days And the costs have come down on these wells and we think we stated in our last conference call that we think that the Western Angel wells As is where he is today, are fairly competitive, if not equal to, the legacy wells that we're drilling.

Speaker 1

I think the thing that you don't know and we won't know for a while is what the type curve really looks like when these wells really start falling over And if these bottle hole pressures will maintain where they are today. That's why we say these wells are top of class Because out of the 1,000 wells we've drilled in the core and the Western Haynesville, These are some of the best wells we've ever touched. So Dan, do you want to comment anymore?

Speaker 3

Totally correct there. So I'll just kind of comment a little bit on the D Seital, so we have this is a totally kind of a different casing design down here than what we have up in the core. It just Takes a lot more days to drill the vertical part of the hole and basically the laterals get a lot more heat. We've made a lot of headway. The first 7 wells we have produced and we targeted the Bossier, not entirely due to temperature, but partially due to temperature.

Speaker 3

We've gotten a lot better at drilling at the higher temps. We've got of the next, I think we've got 10 wells targeted to turn to sales next year. 8 of those are going to be in the Haynesville, 2 will be in the Bossier. So we are going to turn our focus to that. But We still got some things that we've got targeted to put to work out here in the field.

Speaker 3

It's going to get the cost down, We feel considerable amount. And then the one thing I want to emphasize is we're drilling single wells here. So when you look The cost up in the core, everything up there is a multi well pad, either 2 or 3 well pads. So you're getting 6%, 7%, 8% less cost just via multi well pad versus these down here are single wells. So That alone is driving our cost up a little bit.

Speaker 3

But Jay is totally right. I mean, you're looking at EURs Definitely potentially double what we have up in the core. And then the cost is going to we're going to make a lot of improvements on that going forward in the future.

Speaker 1

I think Charles, the really answer is if our borrowing base is reaffirmed for that 2,000,000,000 So the 17 or so banks that support us, I mean, they've looked at that. I think Quantum has looked at it. I think where we are right now with where we're going, We see a lot of clarity and some of that confusion that we had 2 years ago when we first drilled the Circle M. Some of that is easing off. And as we drill the wells, they will tell us what the EUR is and then you'll see what the real cost To drill and complete these wells are, once we've had a good enough sample set, and that'll be months down the road, but we'll still report to you the results On a quarterly basis, which have been really good.

Speaker 6

Jay and Dan, thank you for that in detail. Appreciate it.

Speaker 1

Thank you. Great questions.

Operator

And thank you. And one moment for our next question. And our next question comes from Jacob Roberts from TBH and Company. Your line is now open.

Speaker 7

Good morning and happy Halloween.

Speaker 1

That's right. Offer call on Halloween.

Speaker 7

That's right. On the Quantum partnership, I'm curious if you could provide your view on what the cadence of spend would have been If Comstock were entirely responsible and then just on that comment on Slide 15 that this will reduce capital outlays, Are you able to comment on how we should be thinking about 2024 CapEx relative to 2023? Is this going to be offset somewhere else and kind of maintain the same level or Should we be expecting kind of a lower number?

Speaker 2

Well, we started out with more rigs, Talking about the CapEx, beginning this year then we're going to be starting out next year at. So we would and we think overall Service cost in drilling rates are down a little bit. So, there's a lot of signs that point to lower capital and We've made investments in the midstream before this partnership and now the partnership will kind of take over that responsibility. The build out of the Western Haynesville Midstream is going to be phased in. We're not going to build it all On day 1, they handle a huge volume.

Speaker 2

It's going to be layered in over a 5 year period based on the well results that we achieved. We have quite a bit of capacity now because we acquired a base system and we made upgrades to that this year. And so we have a great kind of great starting toolkit here. And then what we'll do is we'll start to add additional Treating capacity, additional gathering lines as we need them as we build this out. So I think Next year, the spending for this venture is probably between $100,000,000 $200,000,000 So that would have been part of our base CapEx and so now we'll kind of be funded from this other source.

Speaker 7

Great. Appreciate it. And looking I know this is a really long term question, But Jay, you mentioned the 4 rigs on the Western Haynesville in 2025 and then this plan to step up to 2 Bs a day in 2028. Can you talk a little bit about the rig count you think you might need to get to that level by 2028?

Speaker 1

Well, as we There's really 2 questions. One really 3 questions. 1, how many rigs we get to have that we think to hold Our big footprint in the Western Haynesville, we think we probably have to have a 4th rig by 2025. So that It's not 10 or 12 rigs, it's 4 rigs. I mean that's the beauty of the play how we leased this starting over 3 years ago, how we leased it Because we needed to look at the rig count.

Speaker 1

We think depending upon the laterals and unitization, we probably need 4 rigs at some point in time To hold all that acreage, that's all of the acreage. So as the wells have performed, we went from 1 rig to 2nd rig and now the wells, as Dan has said and Roland has shown in the financial results, it calls for a 3rd rig. Remember, we had 3 new cactus rigs built. 1, we've started using several months ago, we'll get another one in November and get another one I think in February. And those are built really to drill these wells in the Western Haynesville.

Speaker 1

So that's one question. 2nd question is, If you take a model and you have a JV with midstream with They want to see what we look like down the road. So we model that out through 2028 and that's where You end up with that 2 Bs a day. As we get there though, if you look at the core, we've got We've gone from 9 to 8 to 7 to 6 to 5 rigs in the core. And now we have 52.

Speaker 1

So next year, we should have 4 in the legacy or the core and 3 in the Western Haynesville. That's still that 7 rig count That we talked about and that Dan mentioned earlier in his presentation. So we don't see adding any Gross numbers of rigs, we keep our 7 rigs. We just deploy them in different areas for 2024. And then we see what happens And 2024 with the results of the Western Gainesville and commodity prices.

Speaker 1

So that's where we go in guidance. It's the same rig count.

Speaker 7

Okay. Thank you. Appreciate the time.

Operator

And thank you. And our next question comes from Bertram Doss from Truist. Your line is now open.

Speaker 8

Hey, good morning. And Jay, I just want to start off and say thanks for not putting out your press release on Halloween night for us with young children.

Speaker 1

You get some of that caramel corn.

Speaker 8

Exactly, exactly. And then the first question just On the agreement, were there talks to go beyond $300,000,000 to start or was that just kind of a happy medium for both parties to get a little more data and then expand it. And maybe where I'm going with that is there any interest in eventually allowing 3rd party gas into the

Speaker 2

Yes. I think it was kind of designed to be what we needed. It's got lots of flexibility. So it's not Yes. We're not building out any particular volume.

Speaker 2

We're just going to continue To build out our the system has the well results tell us what we need. So let's not act like we're going to spend the whole amount on day 1. So we're and then I think it's got lots of flexibility to expand or stay at a smaller level. So we don't That's the why we really like this partnership. Comstock will operate it, make all the decisions.

Speaker 2

We've hired a very experienced the midstream group that's going to run this project and build this out. And then Quantum will be our kind of our financial partner. So, it's got lots of flexibility as far as Yes. How much we spend? And we're going to spend based on what the wells tell us we need.

Speaker 2

And so that's we've got a nice base system like I said earlier that Gives us a lot of flexibility and we didn't have to spend a lot of capital. We made Just a phenomenal acquisition last year of buying this system from legacy reserve, and just getting it Refurbishing it back to the state that it was. And so I think that's how we see it. And obviously, if it needs if the We need a lot more capacity. I think we have the flexibility to expand the relationship We're also contracted if we don't need to use all those funds.

Speaker 2

So that's why we really like this overall partnership.

Speaker 8

And then potential Yes,

Speaker 1

I think it provides what we need for the short term, but we keep an eye out on the obvious long term for natural gas. So it gives us flexibility for the longer term too. That's what a Tier 1 partner does for you.

Speaker 2

Yes. And on 3rd party volumes there, we owned all the There's not a lot of other third party volumes available out there.

Speaker 1

Well, that's why the value of the Pinnacle That was created. It's the volumes that we have, which you didn't have those volumes and we bought that in 2022.

Speaker 8

That's great guys. And then just a follow-up is on the acreage acquisition dollars, I think last quarter the update was, hey, maybe we've got we're towards the end of the program, maybe 90% or somewhere around there and then 4Q looks like a small step up. Was that just something you saw unattractive package maybe earlier in October or is there maybe a rethinking there?

Speaker 1

Well, I think as we go back over 3 years ago and we have a footprint and we expand it And then we get what we call Tier 1, Tier 1, Tier 3 Acres, however we classify. I would tell you that even with the expansion that we have, which is nominal and it goes over into kind of Not core acreage at all, that 90% of all the acreage that we set out to get as of 3 years ago or 2 years ago or 1 years ago, 1 year ago, we have that. In other words, anything that we get from this point on would just be it will just be an additive. It Will not be the core of the core at all. It'll just be rounding out where we would like to add some more acreage if we can get it.

Speaker 1

But no, at the end of this year, I think there's a big land grab that we've had for 3 years, that is open with. And the mineral owners that we would like to lease from, majority of those we've already communicated with and we'll see if we can finalize those leases or not. That's where we are. I think that seasonal land grab is coming to an end.

Speaker 8

Great. Thanks for taking my questions.

Operator

And our next question comes from Phillips Johnston from Capital One Securities. Your line is now open.

Speaker 9

Hey guys, thanks. My question was on 3rd party volumes as well, but it does sound like this ramp sort of the 500 and then ultimately up to 2Bs a day by 28 is mostly if not all Comstock volumes. I guess maybe if you could help us with the starting point. I know your current production isn't That's significant because it's relatively early, but and it's not broken out. But are you able to say Approximately what your gross volumes are in the play today?

Speaker 1

No. Philip, I think If you ask me if I'm going to do a big M and A and double massage my company, then I'll do a big M and A. And I don't know what the M and A would be. If I'm out there derisking the Western Haynesville and you know we're going to add a 3rd rig next year, we have to see how these wells hold up. We have to see how the new wells perform.

Speaker 1

So that is where we try to keep it simple. We try to show you that if these volumes do grow Between now and 2028, we think we have the top geology that let us have about 2 Bs a day. But we throw that out there just because that is in the model that we have with Quantum. That is not something anyone To be focused on between now and then. That's a long way down the road.

Speaker 9

Sure. Yes. Okay. And then maybe a question for Roland. In In the first half of the year, you guys were helped by some fairly sizable working capital, cash inflows and some of that of course reversed here in Q3.

Speaker 9

Just Wondering what that might look like in Q4 and if we assume you continue to run 7 rigs throughout next year. Would you expect working capital will either be a material source or use of cash next year?

Speaker 2

Well, there's 2 elements of the working capital change and one of them is spending levels and I think the spending levels Yes, have come down from where they were earlier in the year. So you see that it lags. It's like a 2 month, I mean 2 months really lag Between cash numbers and so I think you've seen that impact of spending. So I would think that working capital will stay from Spending will be kind of won't be a source or use kind of going forward because we're now kind of at the 7 rig level Yes, for a while. And then but secondly, the other element that is our gas prices.

Speaker 2

So if gas prices are higher now And we're still receiving gas from 2 months ago that's lower priced. I mean, obviously, it will be a Well, that lag will be part of the working capital change. So obviously, we're hoping that gas prices keep going up and you'll continue to see Yes, a little bit of a negative effect of working capital adjustment as you continue to see higher gas prices from the quarter before. And that's what you're seeing. The lowest gas price we had for the year were in the Q2.

Speaker 2

Q3, they were a little bit better. In Q4, they're a lot better. So hopefully next year, they continue to be better.

Speaker 1

And I think that we'll go To the hedging position, we did add $100,000,000 a day of hedges, which were swaps at $355,000,000 I think Ron is a good number. So we did that in the last probably 3 or 4 weeks. We're I think 22% hedged for 2024. If you look at the perfect world of Comstock, I think we'd like to be in the 40% plus. So everyone listening to know that we're still looking to do that.

Speaker 1

We think we should add those extra edges Just to mitigate some risk as we go through 2024, we think the demand for the gas will really appear at the latter part of 'twenty four And then 25 on, you should see it pretty consistent. So that is our goal, Philip.

Speaker 9

Okay, great. That sounds good guys. Thanks.

Operator

And thank you. And one moment for our next question. And our next question comes from Leo Mariani from ROTH MKM. Your line is now open.

Speaker 4

Hey guys. Could you talk

Speaker 10

a little bit to kind of what you're seeing in terms of leading edge Service costs and kind of the traditional kind of Eastern core Haynesville, I think you alluded earlier that maybe those have come in some. Could you give us kind of I mean, just looking at your Q3 D and C, it was up 1% like you said. So what do you kind of see in the service cost doing in the leading edge? And when do you think that starts to show up and the financials.

Speaker 3

So Leo, this is Dan. We have seen the service costs come down. They've been easing down since Probably, I mean, earlier this year, but we I'd say we've seen the biggest decrease just on the rig rates have come And of course, they're the ones that went up higher than anything else when they went the other direction. But we've seen the rig rates are probably down 10% since back Earlier part of this year, I think on the completion side, probably not quite as much. I mean, that's driven really just by our frac cost.

Speaker 3

That's probably more like a 5%, 6%, 7% decrease since earlier in the year. I think we'll see that continue to trend Into this Q4 and into next year, we'll just kind of have to wait and see really what these gas prices, how they materialize next year. And with the activity in the Permian also, which affects us if how much they continue to slide or maybe level out or Maybe even potentially pick up just a year next year.

Speaker 2

The one comment I may add is, Leo, when you're looking at that Cost per completed well that there's a big time difference. Drilling costs are the oldest cost in there. And so there because these wells were drilled Probably back a couple of quarters ago or at least a quarter ago, completion costs are more in the quarter, But even all of them lag because we can't report this until the well is completed. So there's a disconnect between the drilling costs, which are older numbers Yes, that get reported this quarter. So you'll see the drilling cost comes down last.

Speaker 2

So I think what we would expect to see as you get to kind of If you go out and look in the future to what this chart may look like, we should see drilling costs continue to come down because we'll get we'll start reporting more recent costs With wells that we complete, probably more Q1, I think that's when we really see, I think, that the current costs we're seeing now Show up in the this particular scorecard.

Speaker 3

Yes. And that's a really good point. I mean, if you look at if you we report my wells when they turn to sales. So The scrape of wells that turned to sales in 3Q, a lot of that drilling cost was done back in Q1 as far as when we're actually drilling the wells. So Probably

Speaker 2

the savings aren't here yet in that number.

Speaker 3

That's correct. Yes.

Speaker 9

Okay. That's helpful guys.

Speaker 10

And then maybe just to Follow-up a little bit on just the kind of financing side. Obviously, you guys were able to mitigate some future CapEx with this deal. It's great to see. So we noticed that the revolver debt popped up a fair bit this quarter. I guess we'll see what gas prices do going forward.

Speaker 10

But I guess to the extent that that revolver debt were to climb a little more, would you guys kind of look to term that out? Are you kind of thinking about sort of maximum liquidity As you kind of think about future funding needs and could we see some term out at some point in the near future?

Speaker 2

I would doubt it, Leo. I mean, we see repaying that as gas prices get back up over Yes, a little bit over $3 I mean, I think that kind of puts us back in a good balance. The second and third quarter had these very low gas prices That you had to lean into the revolver a little bit, but we see that trend reversing.

Speaker 11

Okay. Thanks guys.

Speaker 1

Thank you, Liam.

Operator

And one moment for our next question. And our next question comes from Paul Diamond from Citi. Your line is now open.

Speaker 12

Thank you. Good morning all. Thanks for taking my call. Could I just get a bit of a bit more detail on the breakdown of your Development plans for Haynesville versus Bossier. I know you talked about 8% and 2% next year.

Speaker 12

Is that roughly where you guys think it It's long term or is that something that's still kind of influx with development in the play?

Speaker 3

Yes. So are you is that in relation to the Western Haynesville or just overall? Western Hansel. Yes. So we've got 7 wells that are currently producing now as we stated.

Speaker 3

All of those are producing from the Bossier with the exception for 1. We got one Haynesville producer in that bunch. And then next year, we don't have any more wells turn into sales this year. The next one will turn to sales in January. So Full year next year, we'll have 10 wells that are scheduled to turn the wells and 8 of those will be the Haynesville, which is that's what we had said earlier, correct, To ingest 2 and the Bossier.

Speaker 12

And is that something we should expect to continue going forward or is that still kind of being felt out as the On how the wells perform?

Speaker 3

I mean, obviously, how the wells perform will play a role in that. I think you'll see a mix. When we first kind of entered the play, we knew obviously that this is a high bottom hole temp play. We Specifically targeted the Bossier early on just to kind of increase our chances of success. And We've leaned in since that time.

Speaker 3

We've got a lot better at dealing with the temperature, so we've leaned in more on drilling the Haynesville. I think it's still early, but I think you'll see the Haynesville will be a better it's going to be a better performer than the Bossier just like up in the core. We like the Bossier. These Bossier wells look fantastic, but just like up there, we expect the Haynesville to be a little better performer. And If you can get your cost basically the same, the Haynesville wells are going to be the better performing wells.

Speaker 12

Understood. Just one quick follow-up. Is the lateral lengths in the Western Haynesville are kind of sitting around 10,000 feet, but I know there's been efforts To kind of extend that in the core, over in Western Haynesville, given the higher pressure, how about I guess, where is your kind of back end of the envelope, where do you guys think you can get to as far as At the length of next 18 months?

Speaker 3

Well, so we've already drilled 1 out to 12,700 feet. Remember that was the 3rd well we drilled In the play, that was the Bossier well. So if you look at the first seven, our average lateral length right now Look, it's about 9,400 feet. And if you look at the wells that we've got planned to turn the sales next year, that group of 10, We're going to probably be at 10,000 to 10,500 feet average lateral length on those wells. So I don't really see us getting a whole lot longer Out here just due to the temperature, but you never know where you can end up sometimes.

Speaker 3

You get 2 or 3, 4 years down the road with the technology improvements. So I wouldn't totally rule it out, but I think that 10,000 foot mark is pretty much going to be our target.

Speaker 12

Understood. Thanks for the clarity. That's all for me.

Speaker 7

Thank you. Okay.

Operator

One moment for our next question. And our next question comes from Noelle Parr from Tuohy Brothers Investment Research. Your line is now open.

Speaker 11

Hi, good morning.

Speaker 1

Good morning.

Speaker 11

So we wanted to ask a bit about One of the big factors that's changed in this cycle and that's the interest rate environment. So I was curious thinking about Negotiation process you went through with Quantum, just curious As they were looking at their returns and you're looking out fairly long term, What did you do for scenarios of interest rates? And if we have greater volatility In gas prices as a result of LNG coming into the mix, we wonder if you've given any thought Just how that might affect your returns or your planning or even your own leverage longer term?

Speaker 2

Well, that's a good comment on that interest rate environment. The interest rates are Yes, we're up a lot. Yes, that's showing up in both long term rates and then obviously the floating rates have been up a lot this year, Raising the cost of debt across the board. We're very fortunate to have so much of our interest rates fixed at a very attractive rate. And then in our we have in the new midstream, we have a low rate that's also kind of fixed.

Speaker 2

We don't think the company's the Comstock is too exposed to the higher interest rates as we kind of look forward At least over the next 3 to 4 years, and hopefully we'll get to an environment sometime after that period where rates Kind of calm back down.

Speaker 11

Right. Great. Thanks. And One thing I wanted to remind you, sorry, just catching up on my One thing we're hearing about In other parts of the country and it sort of depends a lot on just individual So the grid operators and regulation in different parts of the country. But aside from LNG, I just wondered if you were getting many inquiries About gas contracts within industrial users, maybe with an eye to Some of the microgrid technology we've seen, it's still small, but getting share just as people get more worried about either Being able to expand their access to the grid or reliability of the grid.

Speaker 11

So I just wondered if you were hearing anything, getting any feelers out for Customers that might be looking to do something like that?

Speaker 2

That's a great question, Noel. We've had a big initiative that we really We put in place a new team there and to really reach out to more industrial users. We luckily can access kind of the growing area along the Gulf Coast, especially Louisiana Gulf Coast where there's a lot of new Construction for industrial demand that's not LNG related in addition to the LNG users. And Yes. They are all they all see the big demand pull coming in the area.

Speaker 2

And so where gas supply was relatively easy to get, it's now being Tracked it up by the large LNG users. So we're seeing a lot of interest from long term supply contracts to Those type users and they offer maybe even stronger pricing for us and probably more very reliable customers. They have a They could really predict what their demand is. And I think as we go forward, you'll see more and more of our sales Are directly tied to either LNG shippers or industrial users. We would like to have a portfolio of all those users As we go forward that we can directly connect to either from our new growing Western Haynesville play or Our base play in Louisiana where we're the anchor shipper on Acadian and we can get a lot of gas down to that market.

Speaker 11

And just, I'm sure nothing is really final or signed until it's done. But When you have those discussions or do that outreach, what sort of terms are people thinking about 5 years, 20 years or just something more market tied where there wouldn't be long contracts at all?

Speaker 2

I think the interest is 3 to 10 years as far as supply contracts. I I mean 3 is very, very common. Longer term contracts obviously because they're like people are worried about the short term contracts and just all of a sudden the market Being everybody pulling on gas at the same time. So yes, we're seeing interest in longer term contracts From the end users, the key is us acquiring the transportation or getting be able to directly connect to these parties. And that's something we've been working on a lot and continue to work on, especially as we have kind of A blank canvas for our new gas in the Western Haynesville where it's not committed to a lot of other long term contracts.

Speaker 11

Great. Thanks a lot.

Operator

And thank you. And our next question comes from Fernando Zavala, Pickering Energy Partners. Your line is now open.

Speaker 13

Hey guys, good morning. Just a quick one from me. With the plan to move to one rig To move one rig from your legacy Haynesville into the Western Haynesville next year, do you think your legacy Haynesville production can be held flat with that rig cadence? Or do you think it declines

Speaker 11

a little bit with a 4 rig program?

Speaker 2

I think it's a good chance that it'd be hard to hold it flat with Just 4 rigs. We are going to be looking at maybe we can high grade some of that to the most prolific part. We'll also look at where we have the best markets and the best transport to utilize that. But I think the as the Western Haynesville starts to build a nice production base and then it has a much lower Yes. That production, even though like Dan said, when we kind of IP those, that's almost like what we produce them at for a long period of That production becomes a very stable part of the base, so with lower So I think longer term, I think that we'll have we can lower our corporate decline rate as the Western Haynesville takes over a more meaningful part of that production base.

Speaker 2

In short term, we'll have to kind of see how to balance the 2.

Speaker 11

Makes sense. All right. Thanks.

Operator

And our next question comes from Gregg Brody from Bank of America. Your line is now open.

Speaker 14

Hey guys and thanks for fitting me in.

Speaker 1

Yes, sir.

Speaker 14

So You mentioned $300,000,000 of capital coming from Quantum, about $100,000,000 to $2,000,000 you said will be spent next year. Is there To get to the 2 Bcf per day, is there a need to raise more capital? And was the 300 enough? Or Is there plans to raise a revolver down to that facility? Maybe you can kind of fill in there.

Speaker 14

It seems like you might need more than $300,000,000 but Maybe I'm wrong about that.

Speaker 2

Well, I think the entity will become self financing After it gets cut, we think that that's the amount of equity capital that has to come in. We don't really plan to put much leverage on those assets at this time. So a lot of it is that we do see that that is adequate based on kind of how we're seeing it Build up, but yes, there's a lot of the future still to be written on that. So we've got lots of flexibility. That will be that is set up in an unrestricted subsidiary.

Speaker 2

So that will kind of have its own potential financing base. So in the future, That makes sense. It could have its own credit facility, but that's not anticipated To do right out of the box here.

Speaker 14

Did you have is you said it's unrestricted. Comstock doesn't have has not guaranteed any of that.

Speaker 2

That's right. Comstock does not guarantee anything that's in that subsidiary, right. And The commitment coming from Quantum will be kind of equity dollars coming in. And so we tend to run it at a Very kind of an unlevered basis is kind of the immediate plans here. And then, yes, its own cash It will help also be reinvested into the build out.

Speaker 14

Yes, that makes sense. And then last question for you. Just The $300,000,000 of capital, is there is it all available to you at your discretion or is there some approval process to get access to certain tranches of it?

Speaker 2

That part is available and then it actually Actually, we can expand with additional approval up to 500,000,000 But the $300,000,000 is initial committed part of the investment. And it's based on obviously the budgets that's approved out there and Etcetera.

Speaker 14

That's very helpful. Thank you, guys.

Speaker 1

Thank you.

Operator

Thank you. And I'm showing no further questions. I would now like to turn the call back over to Jay Allison for closing remarks.

Speaker 1

Perfect. Again, I want to thank everyone for spending time. That's probably your most valuable asset. So thank you for spending the time with us. As I was listening to the Q and A in our presentation, even with weak natural gas prices, we've reported solid results For the Western Haynesville Shale Drilling Program.

Speaker 1

And just to clarify, our goal is we want to keep the dividend, We want to manage the balance sheet. We want to be a great partner to Quantum as we build the midstream in the Western Haynesville. We want to maintain an eye on appraising all of our Western Haynesville wells and we want to turn that play from exploitation to developmental drilling. And we want to adjust the risk by adding some hedges for 2024 if that opportunity arises. As I was reading all the analyst reports, I know one of them was titled Finding a Dance Partner for the Western Haynesville.

Speaker 1

Well, I would expand upon that On the dance floor, I think on the dance floor for Comstock right now, we have the Jones family. We have all the equity Stakeholders with the Jones family. We have our bank sponsors. We have our bond holders and now we have Quantum. So the question is what kind of dance is it?

Speaker 1

Is it a Texas 2 step? Is it a Jitterbug? Is it a Cotton Eyed Joe? Well, we hope it is Over the years to come is that all deal waltz across Texas. That's our goal.

Speaker 1

We may not be perfect with our feet every day, but that is our goal and We'll please the people around the globe and the consumers in America that need this gas. That's our goal. Thank you for that headline and thank you for your participation today.

Operator

This concludes today's conference call. Thank you for participating. You may now disconnect.

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Earnings Conference Call
Comstock Resources Q3 2023
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