Q3 2023 Comstock Resources Inc Earnings Call
Frisco, Texas, Oh hold on.
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 speaker's presentation there'll be a question and answer session to ask a question. During this session you will need to press star one on your telephone.
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Please be advised that today's conference is being recorded I would now like to introduce your host for today's call Jay Allison Chairman and CEO. Please go ahead.
Good morning, everyone.
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 20 since this morning, So were all smiles here.
We started out the day the right way.
The water natural gas is.
Something that is a big part of our business.
Reported.
Profitable third quarter with I realized gas price of only $2 41 since.
We're the only 18% of our gas hedged.
A lot are extremely low operating cost structure and our high margins.
The 18 net operated wells returned to sales since our last update on our extensive haynesville Bossier acreage position continued to deliver solid results from our legacy area as well as the emerging western Haynesville are the two western Haynesville wells, we recently turned to sales were quote.
Top of the class wells.
What are the other five that we turned to sales starting with our western Haynesville well the circle.
Which started production in April 2020 to make no mistake about it we're extremely pleased with the results of all the western Haynesville wells, we have turned to sales so far.
This year, we're focused on proving yet the western haynesville and continuing to build our extensive acreage position.
During this time of weak natural gas prices, we are providing a dividend to our stakeholders holding our legacy production steady while being accountable to our bank lending group are just reaffirmed our $2 billion borrowing base and proving up a much needed new gastro resource nearly expanding LNG export facilities.
Along the Texas, Louisiana Gulf Coast, a major step for the 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.
And we want to publicly thank them for entering into this new adventure with us.
If you go to the main slides, we welcome here's the Comstock resources third 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 Comstock resources Dotcom and downloading the quarterly results presentation, there you'll file.
A presentation titled third quarter 2023 results.
Hey, Allison Chief Executive Officer, Comstock, and with me is Roland Burns, our president and CFO, Dan Harrison, our CFO and Ron Mills, our VP of finance and Investor Relations.
Go to slide two phase refer to slide two in our presentations.
Note that our Skechers 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.
If you flip to slide three.
What we'll do is we'll summarize the highlights of the third quarter.
<unk> results were heavily impacted by the continued low natural gas prices, we realized in the quarter oil and gas sales, including hedging.
$316 million in the quarter.
We generated cash flow from operations of $116 million or <unk> 60 per share and adjusted EBITDAX was $209 million.
Our adjusted net income was four cents for the quarter. We continued to have strong results from our drilling program. We drilled 13 or 10, two net successful operated haynesville and Bossier shale horizontal wells in the quarter with an average lateral length.
A 11644 feet since the last conference call, we've connected 21 or $18. One net operated wells to sales with an average initial production rate of 29 million cubic feet per day.
We're having great success in our western Haynesville exploratory play our sixth and seventh wells were recently turned to sales with strong initial production rates both of which were drilled in the Bossier shale, where we recently entered into a new adventure with Quanta capital solutions for part of the midstream.
Build out to support our western Haynesville drilling program, which I'll expand on the next slide if everyone would turn to slide four.
Is visibly shows our Bethel plants, which was part of the pinnacle gathering and treating system, we acquired last year pinnacle.
Pinnacle combined with our processing, we have a new area will allow us to grow our western Haynesville production up to 500 million cubic feet per day.
Given how prolific these wells have been we see running out of capacity in this area about 2025, we're excited to partner with quantum capital solutions had affiliate of quantum capital group to build out this system to handle future growth.
To that effect.
We have set up a midstream partnership with Q2.
To build out the system to increase the capacity fourfold will contribute to pinnacle gathering and treating system to the partnership <unk> will contribute 100% of the capital required up to $300 million for the build out of the gathering and treating system will operate the partnership.
Which will be called Pinnacle gas services, it will directly activities corner receives a preferred return and 80% of distributions.
As the investment hurdle is achieved that reduces to 30% I will now turn it over to Roland to cover the third quarter financial results Rolling Alright. Thanks Jay.
On slide five we covered the third quarter financial results our production in the third quarter was one four Bcf per day, which is 1% higher as compared to the third quarter of last year and 3% higher than the second quarter.
Low natural gas prices significantly impacted our oil and gas sales in the quarter, which came in at $316 billion, which was 54% lower than the.
The third quarter of 2022, EBITDAX was $209 million and we generated $167 million of cash flow during the quarter.
We reported adjusted net income about $12 million for the third quarter.
As compared to only $1 billion in the second quarter of this year, and then $326 million in the third quarter of last year.
Slide six we have our financial results for the first nine months of this year.
Production for the first nine months average one four Bcf per day that was 4% higher as compared to the same period in 2022.
Gas sales in that.
First nine months of this year totaled $991 million, which is 42% lower than last year's sales in the same period.
And EBITDAX was $685 million and we generated $568 million of cash flow for the first three quarters of this year.
We reported adjusted net income of $105 million.
For the first three quarters of this year as compared to $735 million for the same period in 2002.
On slide seven we detail our natural gas price realizations that we had in the third quarter.
The correlated Nymex settlement price in the third quarter averaged $2.55. It was very close to the average spot price in the quarter, which averaged $2 58 sets.
Our realized gas price during the third quarter averaged $2 33 sets, reflecting that 'twenty two set differential to the settlement price and at 23 set differential to the reference price.
The differential this quarter returned to more normal levels due to improvements in the Houston ship channel and Katie have prices following the restart of the Freeport LNG facility.
In the third quarter, we were 18% hedged, which proved our realized gas price to $2 41 sites.
We'll be using some of our excess transportation in the Haynesville to buy and resell third party gas, we generated about $2 $5 billion of profit from this activity, which improved our average gas price realization by another T cells.
On slide eight we detail our operating cost per Mcf produced in our EBITDAX margin our operating cost.
Averaged 85 cents per Mcf in the third quarter is 1% higher than our second quarter rate the increased unit costs relate to higher production taxes and higher adverse lower taxes.
Imposed in the state of Louisiana.
Our gathering costs were flat this quarter at 36 ads there at our other lifting costs were 3% lower than the second quarter right.
24 <unk>.
Our production and AD valorem taxes increased five <unk> this quarter compared to the second quarter level.
G&A came in at five per Mcf that was one set lower than the rate we had in the second quarter and our EBITDAX margin after hedging came in at 65.
65% in the third quarter as compared to 63% in the second quarter of this year.
On slide nine we recap our spending on drilling and other development activity for.
For the first nine months of this year.
So far we spent 958 million on our development activities, including $919 million on our operated Haynesville and Bossier shale drilling program.
Spending on other development activity has totaled $38 million so far this year.
In the first nine months of this year, we've drilled 52 wells or 40.
One three wells net to our interest.
In our operated drilling program and we've turned 57 or <unk> 43, net operated wells to sales.
The wells that we turned to sales had an average IP rate of 25 million cubic feet per day.
On slide 10, we recap our balance sheet at the end of the third quarter. We ended the quarter with $345 million of borrowings outstanding under our credit facility, giving us a total of $2 5 billion in total debt.
$2 billion borrowing base was recently reaffirmed by our Bank group this Matt.
And we ended the third quarter with financial liquidity of almost $1 $2 billion I'll now turn it over to Dan.
The operations in more detail okay.
So slide 11 is a breakdown of our current drilling inventory at the end of the third quarter.
The drilling inventory split between the Haynesville and the Bossier and is divided into four categories with our short laterals that are up to 5000 feet. We got our medium laterals that run between five and 8000 feet are long laterals at 8% to 11000 feet and our extra long laterals.
And 11000.
The total operated inventory currently stands at 1760 gross locations and 1338 net locations.
This equates to a 76% average working interest across the operated inventory.
Our non operated inventory has gone thousand 265 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 have 307 short laterals 286 medium laterals.
712 long laterals at 455 extra long laterals.
Our gross operated inventory has split 52% in the Haynesville and 48% in the Bossier.
26% of the gross operated inventory.
For the 455 locations have the lateral lengths greater than 11000 feet.
66, or two thirds of the gross operated inventory has laterals exceeding 8000 feet.
The average lateral length in the inventory stands now stands at 8949 feet, which is up slightly from 8947 feet at the end of the second quarter.
The inventory provides us with 25 years of future drilling locations.
On Slide 12 is the chart, which outlines our progress to date on our average lateral length drilled based on the wells that we've turned to sales.
During the third quarter, we turned 21 wells to sales with an average lateral length of 10460 feet. Thanks to the continued success of our long lateral drilling program there.
The individual lengths range from 6789 feet up to 15003.
333 feet and a record longest lateral still stands at 15726.
During the third quarter six of the 21 wells, we turned to sales head laterals that exceeded 11000 feet and five of these exceeded 14000 feet.
To date, we drilled a total of 64 wells with laterals over 11000 feet.
33 wells with laterals over 14000 feet.
During the third quarter. We also had two additional wells that turned to sales on our new Western Haynesville acreage.
The KZ EMS number one and the linear number one wells were both completed in the Bossier shale.
These wells represent the sixth and seventh new vintage wells and are 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 11000 feet and eight of the wells longer than 14000 feet.
We expect by year end 2023, our average lateral length will be approximately 11000 feet.
Slide 13 outlines our new well activity.
We've turned to sales and tested 21, new wells since the time of the last call.
The individual IP rates range from 18 million a day up to 39 million a day.
We had an average tax rate.
9 million cubic feet a day.
The average lateral length was 10460 feet with individual laterals from $67 89 up.
15333 feet.
Included in the quarter again are the sixth and seventh in the Venezuela, and our western Haynesville acreage.
The case of MFS, which was completed in the Bossier had a lateral length of 10000 in 2008, and we're starting to sales in August.
We've tested the well with an IP rate of 34 million cubic feet a day.
The linear number one well, which was also completed in the Bossier.
With a 9577 foot lateral.
This well was turned to sales in September we tested this well with an IP rate of 35 million cubic feet a day.
Sure.
In addition to the higher 700, producing wells, we have one well that is currently waiting on completion.
We do expect to turn that well to sales in January.
We currently have two rigs actively running on our western Haynesville acreage that are drilling our ninth and 10th wells.
Slide 14 summarizes our D&C cost.
Through the third quarter for our bits Mark long lateral wells that are located on our legacy.
<unk> East, Texas, and North Louisiana acreage.
This covers the wells, having lateral to greater than 8500 feet long.
During the quarter, we turned 19 wells to sales that were on our core East, Texas, North Louisiana acreage in 13 of the 19 wells, where our benchmark long lateral wells.
In the third quarter of D&C cost averaged $1561 a foot only 13 benchmark wells, which reflects a 1% increase compared to the second quarter.
Our third quarter drilling cost averaged $719 fit which is a 10% increase compared to the second quarter.
Partially due to the lower average lateral length in the quarter and some drilling issues encountered in the quarter.
Our third quarter completion costs came in at $842 a foot. This is a 5% decrease compared to the second quarter.
The decrease in completion cost mirrors, the slight decline in service costs, we have.
Experienced earlier in the year, which is associated with the lower activity levels.
And to wrap up our forecasted activity levels. We are currently running seven rigs.
We do expect to keep the same rig activity going into next year.
And we're also running our three frac crews and we expect to keep these three frac crews also working into next year.
I'll now turn the call back over to Jack. Thank you Dan. Thank you Roland if everyone would turn to slide 15.
We direct you to slide 15.
Summarized our outlook for the rest of 2023.
We remain very focused on proving 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 a western haynesville that we'll 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 2020 for capital expenditures that would otherwise be required to support the growth in production that we expect our industry, leading our lowest cost structure is an asset in the current low natural gas price environment is our cost structure is substantially lower than the other public natural.
Gas producers.
Plan to retain the quarterly dividend of $12.05 per common share and lastly, we will continue to maintain our very strong financial liquidity, which totaled almost $1 2 billion at the end of the quarter I will now have Rhonda provide some specific guidance for the rest of the year Ron.
Thanks Jay.
Slide 16, we provide.
Financial guidance for the fourth quarter 2023.
The fourth quarter, D&C, Capex guidance is $240 million to $280 million.
<unk> 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 how they are spending we continue to budget at $15 million to $25 million of spending during the fourth quarter.
On a combined basis.
Our D&C and infrastructure and other Capex should remain within our past annual guidance of 102 to 1.28 billion.
In addition to what we spend on our drilling program noted above we now anticipate spending $30 million to $40 million in the fourth quarter for additional leasing activity.
Our low costs are expected to average 24 to 28.
Per mcf in the fourth quarter, while our gathering and transportation costs are expected to be 32 to 36 per mcf in the fourth quarter.
Production and AD valorem taxes are expected to average 16% to 20.
<unk> unit in the fourth 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 the third quarter.
DD&A rate is expected to remain in the $1 five $1 15.
Mcf range.
While our cash G&A is expected.
<unk> remain in the $7 million to $9 million range for the quarter.
With an additional roughly.
Roughly $2 million of noncash G&A.
Due to the increase in separates our cash interest expense is now expected to total $42 million to $46 million in the fourth quarter, while our noncash interest will remain roughly $2 million per quarter.
On taxes, the effective tax rate is still expected to be in the 22% to 25% range and we still expected to occur.
95% to 100% of our reported taxes this year.
Now I'll turn the call back over to the operator to answer questions.
And thank you as a reminder to ask a question. Please press star one one on your telephone and wait for your name to be announced to withdraw. Your question. Please press star one again, please standby, while we compile the Q&A roster.
And we do ask that you limit yourself to one question one follow up again Thats, one question and one follow up.
Our first question.
And our first question comes from Derrick Whitfield from Stifel. Your line is now open.
Thanks, Good morning, all and congrats on your partnership.
Thank you.
Regarding the quantum partnership but wanted to confirm a comment you made in your prepared remarks, if my numbers are correct.
Fourfold and suggest you're solving for T Bcf per day of capacity and the Western Haynesville. If that's correct could you comment on how youre thinking about mainline egress as well.
And I think when we looked at our footprint in the Western Asia, when we look at our inventory.
And we looked at the.
The wells will 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 have we think in the latter part of 'twenty four youre going to need another four 5% to five days and every year after that youre going to probably need another b a day and Thats just for LNG exportable gas as peak gas.
So when we when we looked around and quantum which is I mean that is a blue ribbon financing source. When we started this thing with them months ago.
And they started looking at our footprint and our well performance.
We looked at what do we need to do.
To build this out we also looked at in the second quarter of 2022, when we hit both the pinnacle facility that vessel in that 145 mile pipeline.
What is our starting block as far as midstream company.
So we evaluated all of that we looked at the rig count.
Again, we will add our goal is to add a rig.
In the Haynesville and the Western Haynesville next year should we go from two rigs to three.
And then we would add another rig in 2025, and we think that with HCP.
Entire footprint. So if you look at that and you look at the model for five years.
Look at the need for gas.
We modeled it out that.
By 2028, we would we would have.
We have the capacity.
With the takeaway both for transportation and the gathering for the financing from quantum to have at least two BS a day that we would have available to serve America Andrew.
That's where we come up with this fourfold number.
Based upon us having about 500 million a day.
But by kind of mid 2025 and in growing on that with investments that we would make between now and then and into the future years through 2028.
That is how we backed into this which I think that's a really good question because.
Quantum which is known for funding midstream and.
And the western in the Haynesville and now in the Western Haynesville.
<unk> looked at everything kind of like our banks did.
Instead, we're really pleased with what you've done.
And we like where you're going.
And we would like to partner with year and so that's why we.
We publicly thank Tim are entering to this new venture with us because.
They give a good checkpoint to the rest of the world.
They will approve with what we've been doing and where we're going to remember our first western Haynesville well was only drilled.
Two years ago, we started drilling two years ago.
And we started leasing the acreage three years ago.
But we really are building a company when you build a company you have to look what's going to happen in 2728, and all of that is dependent upon.
The feedstock that stated for LNG, that's where we had the announcement today and Thats, where <unk> come from you did you did your math on that.
Appreciate it thanks for all the color to in the past you guys have talked about the western Haynesville and the asset seen similar returns to the legacy Haynesville at kind of current operating conditions.
With the understanding that Youre still in the early stages of your learning curve and Western Haynesville could you speak to what youre seeing in operational efficiency gains and the degree costs could improve over time.
Yes. This is Dan so we have seen we made great strides.
And our cost structure in the western Haynesville like.
Like you mentioned it is early we're on the steep part of the learning curve still we've probably cut off let's say around 20 days on our drill times from when we drill.
<unk> drilled the first circle and wealth kind of where we're at today we.
We do have some things in the pipeline on a line of sight to get the cost down.
Further it will become in the future. So we're feel.
Feel pretty confident about that and then.
On the completion side I think thats.
That's probably doesn't have as big.
A potential for cost savings because it's pretty much the same thing with a day in day out that's a little bit higher horsepower cost to Frac. These wells down here, so really the efficiency gains on the completion side would meet would come from doing multi well pads.
And.
Just just.
Typical operational improvements.
I would comment on looking at Dan and the group thinks that.
Once really complex and we drove a sharp land some of those things become a little simpler if you drilled your seventh well internally to sales now you're drilling your eighth and ninth and 10th well now.
We started focusing on the haynesville not so much the bossier.
So I do I do see that and.
Some of the hand, wringing their debt, which required us to drill the first circle and well I don't think we have as much of that we do have it going forward, but.
But I do think that that shows you where quanta comes in and has seen the well results and performance and.
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 one last thing worth not near term kind of well, it's more of a lasting long term goal.
As we can.
<unk> to build this company.
We're building the company.
Okay.
Okay very helpful. Thanks for your time.
And thank you.
And one moment our next question.
And our next question comes from Charles Meade from Johnson Rice. Your line is now open.
Okay.
Good morning, Jay could you Roland.
Ron in the whole crew there.
Good morning.
That's always good.
Okay.
Yeah.
Being here with us that the third quarter, great one other you'd be happier.
I would be happier, where we were in the 50 is down here. This morning.
Yes.
I liked it but anyway, Jay I wanted to ask a real question about your you said in your business decisions here.
$300 million from outside capital.
Great that you are that you've got a high quality partner like quantum are willing to put that kind of money into a JV.
Im curious about what 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 a.
Kevin.
Maybe it's not firm commitment with some kind of commitment to the to the amount of volumes that you're going to put through this through system and maybe that's a minimum minimum volume commitment maybe it's maybe something else and also could you talk about the rate that youre going to be paying per Mcf is usually where that's denominated but but just in general.
How are you as the producers are going to pay that.
Midstream entity Pinnacle gas.
Yes, Charles that's a good question.
Sure.
<unk>.
We're going.
<unk> got to continue to charge the same rate that we've been charging since the first wells went onto the system that we acquired last year.
Yes.
We charged for processing and transportation about 54 cents.
<unk> per Mcf. So that's really no change in the rate is the same rate that we historically have had.
And yes, we have a we have a very yes.
Yes.
Small NBC yet.
That's back to our own subsidiary here Thats at <unk>.
That is far less than half of what we projected production to be so that kind of just kind of supports that.
<unk> midstream entity.
Got it so that's if I understood you right rolling so.
As far as midstream rates, it's just consistent with what you guys are already paying and that there were some volume commitment, but it's less than half of what you are projecting from from this asset.
That's correct, Okay got it.
Non risk adjusted with existing production that we have Charles.
We start out with a big risk adjustment day one.
Got it and then I guess, we can do the work ourselves, but between those two numbers, we should be able to figure out when that.
Ownership reverts.
Rather.
Where they go from whatever 80% to 30, but we will do that work offline second.
Second question I wanted to ask again about the the western Haynesville.
Obviously, you guys are.
This is a big.
A big effort for you guys.
When I look at your well results you guys are clearly you guys can put up these these ips in the mid to high Thirty's or anything I think <unk> had watershed where over 40, so I think that aspect of safety risk, but but.
There is other important data points, which are the <unk>.
D&C costs I Wonder if you could share what you are maybe not where you are now, but what's your target D&C costs on these wells and then perhaps what the.
But the pressure drawdown is like over time, if you're willing to share any of that.
Hello.
Start out and then.
If it to Dan I think number one.
We are not rigging the system with the IP rate, it's cut in half.
The second that you don't need an IP rate these IP rates or real rates. We're flowing these wells at I think that's number one which that that's unusual number two.
The EUR is 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.
So those are big game changers number three I think the cost of any exploration player exportation play.
For the first seven wells is going to be a little a little higher than normal. We always said Charles you take the first seven wells.
In the Haynesville Bossier in the legacy footprint back in 2008, and you need a big BARF bag, because they look terrible.
I think these seven wells will make smile.
Dan already said that he has cut the drilling days down by at least 20 days and the cost have come down on these wells and we I think we stated in our last conference call that we think that the western Haynesville wells as is where he is today.
Are fairly competitive if not equal to the legacy wells that we're drilling.
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 this bottom hole pressures will maintain.
Where they are today, that's why we say these wells are top of class.
It goes out of the wells we've drilled in.
And in the core and the Western Haynesville.
These are some of the best wells, we've ever touch so.
Yes.
Totally correct there so I'll just kind of comment a little bit on the D&C call. So we have.
This is a totally kind of a different casing design down here than what we have up in the core.
It takes a lot more days to drill the vertical part of the whole and basically the lateral scale a lot more heat we've made a lot of headway.
Seven wells, we have producing and we targeted the Bossier.
Not entirely due to temperature, but partially due to temperature, we've gotten a lot better at drilling.
Drilling at the higher temps, we've got.
Next I think we've got 10 wells targeted to turned to sales next year.
Eight of those are going to be in the haynesville and the Bossier. So.
We are going to turn our focus to that but we will.
We still got some things that we've got targeted too.
Put to work out here in the field is 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 at the cost up in the core everything up there is a multi well pad or.
Two to three well pads.
Getting.
Seven 8%.
The last cost just just.
Multi well pad versus lease down here are single single wells. So that alone is driving our cost up a little bit.
Jay is totally right I mean, youre looking at EUR is definitely potentially double what we have up in the core.
And then the cost <unk>.
We're going to make we're going to make a lot of improvements on that going forward in the future I think Charles there really answer is if our borrowing base was reaffirmed for the 2 billion. So the 17 or so banks that support us I mean, <unk> I think quantum is looked at it I think where we are right now with where we're going.
We see a lot of clarity in some of the confusion that we had two years ago. When we first drilled the sharply on some of that is.
His easing off.
And as we drill the wells they will tell us.
What the EUR is in and Youll 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 will still report the results on a quarterly basis, which have been which have been really good.
Jay and Dan. Thank you for the added detail I appreciate it.
Thank you great questions.
And thank you.
And one moment our next question.
Okay.
And our next question comes from Jacob Roberts from TBA <unk> Company. Your line is now open.
Good morning, and happy Halloween.
Oh, that's right.
Conference call on Halloween.
Alright.
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.
Clearly 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 2020 for capex relative to 2023, and that's going to be offset somewhere else and kind of maintain the same level or should we be expecting kind of a lower number.
Well, we started out with more rigs.
About the Capex at the end.
This year, then we're going to be starting that next year at so we would and we think overall.
Service cost and drilling rates, our download ads, so theres a lot of signs that point to lower capital and then.
We've made investments.
And the midstream before this partnership and know the partnership will kind of take over that responsibility.
And the build out of that.
Of the Western Haynesville midstream is going to be phased in and we're not going to build it all on day, one to handle the huge volume its going to be layered in over.
Five year period based on that well results that we achieved we have quite a bit of capacity now because we acquired.
Based system and we've 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 gas.
Gathering lines as we need them as we build this out so.
Yeah.
Next year for you.
<unk> spending for this venture yes, probably.
Between 100 and $200 million.
So.
That would've been part of our base Capex and so now we will kind of be funded from this other source.
Great I appreciate it.
And looking I know this is a really long term question.
Well as we go.
Two questions one.
Early quick questions one how many rigs do we get to have where we think to hold our big footprint in the western Haynesville. When we think we probably have to have a fourth rig by 2020, so that it's not 10 or 12 rigs with four rigs I mean, that's the beauty of the play how we leased this starting over three years ago.
At least it because we needed to look at the rig count we think.
Leaning upon the laterals unionization.
The need for rig some point in time to hold all that acreage. That's all of the acreage so as as the wells have performed we went from one rig the second rig and now the wells as Dan has said in rolling as shown in our financial results.
It calls for a third rig and remember we had three new cactus rigs built.
One of <unk>.
Sorted using several months ago, we will get another one in November and get another one and I think in February and those are built really to drill these wells in the western Haynesville. So.
That's one question second question is if you if you take a model.
You have a JV with midstream worth of quantum they wanted to see what we looked like.
Down the road.
So we model that out through 2028, and that's where you.
You end up with that to visa 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 six to five rigs in the core.
And now we have five two so next year, we should have for the legacy or the core and three in the Western Haynesville, that's still a seven rig count that we've talked about and as Dan mentioned earlier in his presentation. So we don't see adding any quote gross numbers of rigs.
Keep we keep our seven rigs were just deploy them in different areas for 2024, and then we see what happens.
In 2024 with the results of the west from the Haynesville and commodity prices.
So that's where we go in Europe and guidance, it's the same rig count.
Okay. Thank you I appreciate the time.
Okay.
Thank you.
And one moment our next question.
And our next question comes from Bertram Douglas from Jefferies. Your.
Your line is now open.
Hey, good morning, and I, just wanted to start off and say thanks for not putting out your press release on on Hollywood Halloween night for Us with young children.
Yes, so Matt caramel.
Exactly exactly and then the first question Jeff.
On the agreement.
Were there talks to go beyond 300 million 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 and maybe where I'm going with that is there any interest in eventually, allowing third party gas into the system.
Yes, I think it was kind of designed to be what we need it it's got lots of flexibility. So.
Yes, we're not building any to any particular volume, we're just going to continue to.
To build out our the system as the well results tell us what we need so that's that.
That act like we're going to spend it all about on day one so we're.
And then I think it's got lots of flexibility to expand or stay at a smaller level. So.
That's why we really like this partnership Comstock will operate it make all the decisions.
We hired a very experienced the midstream group.
It's going to run this project and build this out.
And then quantum will be our kind of our financial partner.
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 and so that's that 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.
Just getting it refurbish and add back to that state than it was in.
So I think thats, how we see it and obviously if it needs if that we need a lot more capacity.
I think we have the flexibility to expand their relationship or or are also contracted if we don't need to use all of those funds.
That's why we really like this our overall partnership.
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, that's what a tier one partner does for you.
Third party volumes there we owned all the acreage mostly in this play out there's not a lot of other.
Third party volumes.
Yeah available out there.
That's great guys and then just.
Follow up is on the acreage acquisition dollars.
I think last quarter or the update was hey, maybe we've got we're towards the end of the program, maybe 90% or somewhere around there and then <unk> looks like a small step up was that just something you saw on attractive.
Package, maybe an earlier in October or is there maybe a rethinking.
Well I think.
We go back over three years ago, when we have a footprint can we expand it and then we get what we call tier 123 acres every week.
We plan to file.
I would tell you that even with the expansion that we have which is nominal and it goes over into and to kind of.
Ah.
Not core acreage at all.
90% of all the acreage that we set out to get.
Three years ago, or two years ago, one year ago, one year ago.
We have that in other words anything that we get from this point on would just be you will just be an additive it will not be the core of the core at all.
Just be rounding out where we would like to add some more acreage if we can get it but.
But no at the end of this year I think.
Big land grab that we've had for three years.
That's where we are I.
I think that season of land grab is coming to an end.
Great. Thanks for taking my question.
Okay.
And thank you.
And one moment our next question.
And our next question comes from Phillips Johnston from capital One Securities. Your line is now open.
Hey, guys. Thanks, Mike.
My question was on third party volumes as well, but it does sound like this ramp.
500, and then ultimately up to to be the day by <unk>.
2008, it is mostly if not all comstock volumes.
I guess, maybe if you could help us with the starting point I know you are.
Current production is.
<unk>.
That's significant.
Because.
Relatively early but.
Now Philip I think if you. If you asked me if I am going to do a big M&A and doubled the size of our company Theyre not the big M&A.
Don't know what the M&A would be if I'm out there de risking the western Haynesville and you know we're going to add.
Third rig next year, we have to see how these wells hold up we have to see how the new wells perform so that is where we try to keep it simple we tried to show you that if these volumes do grow between now and 2028, we think we will.
We have the top geology that let us have about two 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 should be focused on between now and then that is that's a long way down the road.
Sure Yep.
Okay, and then maybe a question for Roland.
The first half of the year you guys were helped by some fairly sizable working capital cash inflows and some of that of course reverse here in Q3.
Wondering what what that might look like in Q4, and if we if we assume you continue to run.
Seven rigs throughout next year would you expect.
Working capital will either be a.
Material source or use of cash next year.
Well, there's two elements of our working capital change and.
One of them is spending levels and I think the spending levels.
Have come down from where they were earlier in the year. So you see that it lags the.
We're talking two months two months really lag between cash numbers.
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 as <unk> kind of going forward, because we are now kind of at the seven rig level for a while.
But secondly, the other element that is all gas prices. So if gas prices are higher now and we are still receiving gas from two months ago, that's lower priced domain.
Obviously there'll be a yes.
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 is.
As you continue to see higher gas prices from.
From the quarter before and Thats, what Youre seeing.
The lowest gas price you had for the year were in the second quarter third quarter, they were a little bit better in fourth quarter there.
Yes.
A lot better so hopefully next year that continue to be better.
We will go into the hedging position, we did add 100 million a day of hedges.
Which were swaps at 355, I think Ron is a good number so we did that in the lab.
<unk>, probably triple weeks.
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.
So so everyone listening to know that we are still looking to do that we think we should add those extra hedge.
Hedges.
Just to mitigate some risk as we go through 2024, we think the demand for the gas for really appear that latter part of 'twenty four and then 25, one you should see it pretty consistent.
So that is our goal.
Okay, great Okay, guys. Thanks.
And thank you.
And one moment our next question.
And our next question comes from Leo Mariani from Roth MK Ann Your line is now open.
Hey, guys could you talk a little bit to kind of what youre seeing in terms of leading edge service cost and kind of the traditional.
Kind of the eastern core Haynesville I think you alluded to earlier that maybe it doesn't come in some could you give us kind of a sense I mean, just looking at your third quarter D&C was up 1% like you said so what are you kind of seeing the service costs doing in leading edge and when do you think that starts to show up on the financials.
So Leo is a day and we have seen the service costs come down they have been easing down.
Probably I mean earlier this year, but we.
I'd say, we've seen the biggest decrease just on the rig rates have come down.
And of course, they are the ones that went up higher than anything else when they went the other direction, but.
The rig 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, thats driven really just by our frac cost.
Probably more like a 567% decrease.
Since earlier in the year I think we will see that continue to trend down.
Into this fourth quarter and into next year.
We will just kind of have to wait and see really what these gas prices how they materialize next year.
Sure.
With the activity in the Permian also which affects us.
How much they continued to slide or maybe level out or maybe even potentially pick up just to hear next year. So the one comment I may add is laid.
When youre looking at that debt.
Cost per completed well that there is a big time difference, yes drilling cost are the oldest cost in there instead of there because these wells were drilled probably back a couple of quarters ago or at least a quarter ago completion cost or more.
Yes, more in the quarter.
But even all of them lag because we can't report this until the wells completed so there's a disconnect between the drilling cost which are older numbers that get reported this quarter. So youll see the drilling cost comes to add last so I think that we would expect to see as you get to kind of.
And look in the future to what this chart may look like we should see drilling costs continued to come down because we'll get we'll start reporting more recent costs with wells that we can play probably more first quarter I think that's when that's when we really see I think.
That the current costs, we're seeing now show up in.
This particular scorecard, yes, and Thats a really good point I mean, if you look at if we report my wells when they turned to sale. So just.
Grateful wells that turned to sales on three key a lot of that drilling costs was done back in Q1 as far as when we were actually drilling the wells. So sorry, the savings are here yet in that number Thats correct, yes.
Okay. That's helpful guys and then maybe just.
A follow up a little bit on just the kind of financing side. Obviously, you guys were able to mitigate some some future capex with this deal it's great to see certainly noticed that the revolver that popped up.
This quarter.
We'll see what gas prices do going forward, but.
I guess to the extent that that revolver debt would climb a little more would you guys kind of look to term that out or you kind of thinking about sort of maximum liquidity.
As you kind of think about future funding needs and yes.
Could we see some term out at some point in the near future.
I would doubt it Leo I mean, we see repaying that as gas prices get.
Get back up over a little bit over $3, I mean, I think that kind of puts us back in a good balance there.
The second and third quarter had these very low gas prices.
You had to lean into the revolver, a little bit, but we see that trend reversing.
Okay.
Okay. Thanks, guys.
And thank you Leon.
And one moment our next question.
And our next question comes from Paul Diamond from Citi. Your line is now open.
Thank you good morning, Thanks for taking my call.
Can I just get a bit of.
More detail on the breakdown.
<unk> development plans for Haynesville versus closure I know you talked about it into next year is that roughly when you guys think it fits long term or is that something that's still kind of in flux the development play.
Yes. So are you is that related to the western haynesville or just overall.
Western Haynesville.
Yes. So we we've got seven wells that are currently producing miles. We stated all of those are producing from the merger with the exception for one we've got one haynesville producer in that much and then no next year, we don't have any more wells turn into sales. This year that makes some alternative sales in January so.
For full year next year, we'll have 10 wells that are scheduled to turn to sales and eight eight of those will be the haynesville. It just that's what we had said earlier correct to ingest too in the Bossier.
And is that something we should expect to continue going forward or is that still kind of being felt out is.
On how the wells perform.
I mean, obviously, how the wells perform will play a role in that I think youll see a mix. We when we first entered the play we knew obviously that.
This is a hot bottom wholesale play.
Play.
Specifically targeted the Bowser early on just to kind of.
Increase our chances of success.
We've leaned in Erith since that time, we've got a lot better at dealing with the temperature. So we've leaned in more on drill in the Haynesville.
Thank you.
Still early but I think youll see the haynesville will be a better mix going to be a better performer than the bossier dislike up in the core we like the Moser of these Moser wells look fantastic, but just like out there we expect the haynesville to be a better performer and so.
If you can get your.
Your cost basically the same.
The Haynesville wells are going to be the better better performing wells.
Understood.
One quick follow up.
The lateral lengths in the western Haynesville are kind of sitting around 10000 feet, but I know there's been efforts to kind of extend that in the core.
Over in Western Haynesville, given the higher pressure.
Whereas you're kind of back of the envelope, where do you guys said you can get to as far as lateral length for the next 18 months.
Well, so we've already drilled one out to 1700 <unk> you remember that was the third well we drilled in the play that was the Bossier well.
So if you look at the first seven or an <unk>.
The average lateral length right now looks is about 9400 feet.
And if you look at the wells that we've got planned to turn to turn to sales next year that group of 10.
We're going to probably be at 10 10 to 10500 foot 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 you get 234 years down the road with the technology improvements so.
<unk> totally rule it out but I think.
10000 foot Mark is pretty much going to be our target.
Understood. Thanks for the clarity that's all for me.
And thank you.
Okay.
Okay.
One moment our next question.
And our next question comes from Noel Parks until the brothers investment Research. Your line is now open.
Okay.
Hi, good morning.
Good morning.
So we wanted to ask a bit about one of the big factors that changed in this cycle and that's the interest rate environment. So I was curious.
About negotiation process, you went through with Wisconsin.
Just curious.
As they were looking at their returns and Youre looking out fairly long term.
What would you do for scenarios with interest rates.
Okay.
And if we have greater volatility in gas prices as a result of LNG coming into the mix.
Yeah.
Wondering if you've given any thought tag.
Just how that might affect your returns or are you planning on.
Your own leverage longer term.
But yes, it's a good comment on that yes, the interest rate environment and interest rates are up a lot that's showing up in both long term rates and then obviously the floating rate <unk> been up a lot this year.
And the cost of debt.
Across the board, where we're very fortunate to have so much of our interest rate fixed at very attractive rates.
And then yes, we have yes.
Yes.
And then the midstream we have a low rate that's also kind of effects. So.
We don't think that companies that complex too exposed to.
The higher interest rates as we kind of look forward.
Over the next.
Three to four years.
And hopefully we will get to an environment sometime after that period, where rates kind of come back down.
Right great. Thanks.
One thing I wanted to run by you.
<unk>.
Sorry.
I might note here.
Hi.
Yes.
Yes.
One thing we're hearing about.
There are parts of the country and it sort of depends a lot on just.
Individual.
So the grid operators in regulation in different parts of the country, but.
Aside from LNG I, just wondering if you were.
Getting many inquiries.
About.
Gas contracts within industrial users.
Maybe with an eye to.
Some of the micro grid technology, we've seen it.
Small, but but getting sure just as people get get more worried about either.
Expand their access to the greater reliability of the grid. So I was wondering if you.
You're hearing anything getting.
Getting our feelers out for.
Customers that might be looking to do something like that.
That's a great question no we've had a big initiative that we really we put in place.
Team there.
And they're really reach out to more industrial users.
Yes.
Luckily can access kind of the <unk>.
Growing area.
The Gulf Coast, Louisiana Gulf Coast, where there's a lot of new construction for <unk>.
<unk> demand that's not LNG related in addition to the LNG users and they are all.
See the big demand pull coming in the area and so we're we're gas supply was relatively easy to get its now being contracted out by the by the large LNG users. So we're seeing a lot of interest from long term supply contracts to those type of users and.
They offer maybe even stronger pricing for us and probably more more very reliable customers. They have they can really predict what their demand is.
And I think as we go forward.
Youll see more and more of our sales are directly tied to either LNG shippers or industrial users, we would like to have.
Our portfolio of all of those users.
As we go forward that we can directly connect to either from our new growing western Haynesville play or are our base play.
In Louisiana, where where that yes, the anchor shipper on Acadian and we can get a lot of gas down to that market.
All right and just.
Im sure Nothing's really final or signed until it's until it's done but.
When you have those discussions are due that outreach.
What sort of terms are people thinking about five years, 20 years or or or just something more market tight.
It wouldn't be long contracted at all.
I think the interest is it three to 10 years as far as supply contracts. I mean, three is very very calm and longer term contracts. Obviously, because I think people are worried about the short term contracts and just all of a sudden the market.
Everybody pulling on gas at the same time, so yes, we are seeing.
Interest in longer term contracts from the end users. The key is us acquiring the transportation or getting being able to directly connect to these parties and that's something we've been working on a lot of continue to work on it.
Especially as we have kind of a.
Like canvas for our for our new gas in the Western Haynesville, where it's not committed.
Two a lot of other long term contracts.
Okay.
Great. Thanks, a lot.
And thank you.
And one moment our next question.
And our next question comes from Fernando Zavala Pickering Energy Partners. Your line is now open.
Hey, guys. Good morning, just a quick one from me.
With a plan to move to one rig.
Tier 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 the declines a little bit with a four rig program.
I think it's a good chance that it would be hard to hold it flat.
Just four rigs.
We are going to be looking at heart, maybe hot we can high grade some of that to the best prolific part.
So look at where we have the best markets in the past and transport.
To utilize that but.
As to the Western Haynesville starts to build a nice production base and then it has a much lower.
Yes that productions, yes, even though.
Like Dan said, we're kind of happy though she now thats almost like what we produce for a long period of time.
That production becomes.
Very stable part of the base, so with lower declines so I think longer term I think that yes. We will have we can lower our corporate decline rate as the western Haynesville takes over a more meaningful part of that production base.
In short term, we will have to kind of see how to balance the two.
Alright. Thanks.
And thank you.
Yes.
And one moment our next question.
And our next question comes from Gregg Brody from Bank of America. Your line is now open.
Hey, guys. Thanks for fitting me in.
Yes, Sir.
You mentioned.
300 million of capital coming from.
About 100 to Tim when you said it will be spent next year does there to get to the two Bcf per day is there a need to raise more capital.
And.
Or is the 300 enough are there Mr plans to raise the revolver down does that facility. Maybe you can kind of fill in there. It seems like you might need more than $300 million, but maybe I'm wrong about that.
Well I think that yes.
Dave.
The entity will become self financing as it is after it gets kind of 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 yes, a lot of it is.
We do see that that is that is adequate based on kind of how we're seeing it build out but yes, theres a lot of the future still to be written on that so we got lots of flexibility.
Yes that.
That will be that is set up an unrestricted subsidiary so that would kind of have its own potential financing base. So in the future. If it makes sense ticket it can have its own.
Could have its own credit facility, but that's not anticipated.
To do right out of the box here.
Did you ask.
Instead, it's unrestricted Comstock doesn't have is not guaranteed any of that.
That's correct, yes, <unk> Comstock does not guarantee and.
Yes.
That's in that subsidiary right in that commitment.
Commitment company for quantum will be kind of equity dollars coming in and so.
They run at it.
Very very kind of unlevered basis is kind of the.
The immediate plans here at any of its own its own cash flow.
Will help also be reinvested into the build out.
Yes that makes sense and then last question for you just the 300 300 million of capital.
Is there is it all available to you at your discretion or is there is there some approval process to get access to certain groups that certain tranches of it.
That part.
That part is available and then it actually.
Yes, actually it can expand with additional approval.
Up to $500 million.
The 300 additional committed part of the of the investment and it's based on obviously with the budgets that debt that's approved out there.
Et cetera.
That's really helpful. Thank you guys.
Thank you.
And thank you.
I'm showing no further questions I would now like to turn the call back over to Jay Allison for closing remarks.
Perfect again, I want to thank everyone for spending time.
Probably your most valuable assets. So thank you for spending the time with us.
As I was listening to the Q&A in our presentation.
Even with weak natural gas prices, we reported solid results.
For the Western Haynesville shale drilling program 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 our pricing all of our western Haynesville wells.
And we want to turn that play from exportation to developmental drilling.
And we want to adjust.
The risk by adding some hedges for 2024 if that opportunity.
Rises.
I was reading all of the analyst reports on a one of them was titled finding a dance partner for the Western Haynesville I would expand upon that on the dance floor I think on the dance floor for Comstock right now.
We have the Jones family.
I think we have all the equity stakeholders with the Jones family we.
We have our bank sponsors we have our bond holders and now we have quantum.
So the question is what kind of <unk>.
Is that it takes to step is jitterbug cottonade, Joe well, we hope it is over the years to come as it all deal waltz across Texas.
That's our goal.
We might not be perfectly with our feet every day.
But that is our goal and.
No.
We were pleased that people around the globe.
Consumers in America Sydney. This gas that's our goal. Thank you for that headline and thank you for your <unk>.
Participation today.
This concludes today's conference call. Thank you for participating you may now disconnect.
Okay.
Okay.
[music].