Q4 2022 Comstock Resources Inc Earnings Call
The conference will begin shortly to raise and lower Johan during Q&A, you can dial star one one.
[music].
Okay.
Thank you for standing by and welcome to Comstock resources fourth quarter 2022 earnings call. At this time all participants are in a listen only mode. After the speaker presentation, there will be a question and answer session.
To ask a question during the session you will need to press star one one on your telephone.
I would now like to hand, the call over to Jay Allison Chairman and CEO . Please go ahead.
Your tone you kicked it off right. So thank you.
Welcome to the Comstock resources fourth quarter, 2022 financial and operating results conference call.
You can view a slide presentation during or after this call by going to our website.
Www, Comstock Resources' dotcom and downloading the quarterly results presentation.
You'll find a presentation entitled fourth quarter 2022 results.
I'm, Jay Allison Chief Executive Officer contract with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Rod Mills, our VP of finance at.
In Investor Relations at <unk>.
If you would please refer to slide two in our presentations and note that our discussions today will include.
Forward looking statements within the meaning of securities laws, while we believe the expectations of such statements to be reasonable there can be no assurance that such expectations will prove to be correct now.
Good morning, everyone.
Are you all haven't done yet.
Did you say that smile I know you all out there.
P R.
The world of natural gas is ever changing.
And we do recognize that.
Comstock.
Realizing that natural gas prices have fallen over 70% since September of last year.
We made the call to drop two rigs at four.
Our 22% of our operated nine rigs.
Ensure we are positioned for a rebound in natural gas prices in the future now.
Most natural gas research analysts will tell you that they expect a substantial amount.
The additional 11 Bcf of peak gas needed by LNG ship are starting in 2025 and 2026 to come from the Haynesville luck.
Well guess, what Comstock is the pure player in that region now.
The question really is to be able to supply that natural gas when it is needed the most.
I believe Comstock will be one of those elite producers in that region.
Now we increased our Haynesville Bossier shale footprint by almost 100000 net acres in 2022.
Paying billions and billions of dollars.
Or an M&A transaction.
We avoided issuing millions and millions of shares of stock are incurring debt to acquire additional drilling inventory instead.
$550 per acre to grow our Haynesville Bossier shale footprint.
470000 net acres.
Which provides us with thousands of future drilling locations.
So how will we navigate the current natural gas market. That's the question.
Well last year, we fortified our balance sheet.
This year, we plan to protect our balance sheet by adjusting our drilling program to ensure that it is funded by operating cash flow.
The lowest cost structure, among our peers, giving us industry, leading high margins.
We have been very successful so far and delineating our western Haynesville play.
The results so far are both wells put us among the best wells ever drilled.
In the entire basin.
Our 2023 budget allows us to continue to prove up the western Haynesville with eight new wells being drilled now.
It will tip, our hat to the stellar 2022 results we had.
It would take our coats up and work toward achieving our 2023 goals.
Know that everybody listening and those that listen to this recording I know that you're all be cheering us on to success.
Why because the world needs of America's natural gas to solve its energy needs.
I will go back to the script slide three.
Our 2022 accomplishments.
On slide three we highlight our major 2022 accomplishments.
Differently strengthened our balance sheet by using the $673 million of free cash flow, we generated to want to retire.
$506 million of debt.
In November we entered into a new five year credit facility with <unk> Bank.
Which lowered our interest cost and increased our availability.
<unk>, our leverage ratio to one one times down from two four times in 2021.
And the 175 million in preferred stock.
The Covey Park acquisition was converted into common stock.
At the end of November .
This is a key point that conversion of the preferred by Jerry Jones is a statement demonstrating his confidence in the future of the company and his belief that ownership of Comstock equity has the greatest potential for future appreciation net.
We had another strong year of the drill bit in the Haynesville Bossier shales drilling 73, or <unk> 57 net wells.
Drill two very successful exploratory wells in our western Haynesville play.
The results so far of both wells put them among the best wells ever drilled in the Haynesville.
We increased the average lateral length of the wells were drilled by 14%.
Compared to 2021 to almost 10000 feet.
The wells, we put solid sales had an average IP rate of 26 million cubic feet per day.
And our drilling activity added one one tcf of proved reserve additions at.
At a low finding cost of <unk> 95 per Mcf.
Our SEC proved reserves grew 9% to $6 seven Tcf and we replaced.
216% of our 2022 production.
Our one P PV 10 value totaled fit.
Chain $5 billion.
Highlighting our attractive cost structure were achieved at 83% EBITDAX margin, which is one of the highest in the industry.
In addition, we achieved a 28% return on average capital employed.
A 62% return on average equity at.
At 2022, we added 98000 net acres that is perspective for the Haynesville and Bossier shales.
$54 $1 million or $550 per acre.
We reinstated our quarterly common stock dividend of $12.05 per quarter, and the fourth quarter and on the environmental front, we achieved independent certification for 100% of our operated natural gas production under the <unk> methane standard for responsibly sourced gas.
Now if you go over to slide towards the fourth quarter 2022 highlights on slide four we focus just on the fourth quarter highlights during the quarter, we generated free cash flow from operations of $129 million, a production increased 7% to one four points.
4 billion cubic feet of gas equivalent per day.
Our oil and gas sales were $558 million.
47% higher than the fourth quarter of 2021.
Our operating cash flow.
It was $434 million or $1 57 per diluted share.
<unk> EBITDAX increased to $478 million, our net income for the fourth quarter was.
$288 million or $1 five per share in the fourth quarter, we drilled 21 or 14 point net.
Operated Haynesville Bossier horizontal wells, which had an average lateral length of 9903 feet.
Since our last update we've COVID-19 or $13. One net operated wells to sales with an average initial production rate.
25 million cubic feet per day.
We also announced our second successful exploratory well in our western Haynesville play.
Which had an initial production rate of 42 million cubic feet per day.
We continue to further improve our balance sheet.
In the quarter with the additional retirement of.
Of $100 million of debt and the conversion of the preferred stock we.
We initiated our return on capital program with the re his favorite of our quarterly common dividend of <unk>.
$12.05 per share in December of 2022.
I will now turn it over to Roland to discuss the financial results Rolling.
Thanks, Jay and slide five we highlight the financial results.
For our recently completed fourth quarter.
Pro forma for the sale of our Bakken properties, which we completed in October of 2021, our production increased 9% in the quarter to one four bcf per day as compared to the fourth quarter of 'twenty, one our EBITDAX in the quarter grew by 70% to $478 million driven.
Really by the stronger natural gas price environment, and the production increase that we had.
We generated $434 million of cash flow during the quarter and 86% increase over 2021 fourth quarter and our cash flow per share during the quarter was $1 57 up 67 cents.
During the fourth quarter of 'twenty, one we reported adjusted net income of $288 million for the fourth quarter.
91% increase from the fourth quarter of 'twenty, one and our earnings per share came in at $1 five as compared to 37 <unk> in the fourth quarter of 'twenty one.
It generated $129 million.
Free cash flow from operations in the quarter at 22% higher than we did in the fourth quarter of 'twenty one.
And as Jay mentioned, we retired 100 million of debt in the quarter completely paid off our bank credit facility.
Which improved our leverage ratio for the year to one one times.
On slide six we highlight how much Comstock financial results have improved since 2019.
Production growth has averaged 21% over the last three years, our EBITDAX has gone from 614 billion to $1 $9 billion in an annual growth rate at 71% cash.
Cash flow has grown from $468 million to $1 $7 billion at an annual growth rate, averaging 89% over the last three years.
Our adjusted net income has grown from $122 million to obey and dollars at an annual growth rate of 245%.
And free cash flow from operations.
Grew to $673 million from really none that we generated in 2019 and our leverage ratio has improved.
From 3538 times in 2020 to one one times this year.
On a per share basis cash flow has increased from $2 50 to.
To $6 21.
And adjusted earnings has increased from 75 per share to $3 73 per share.
On slide seven we provide a breakdown of our natural gas price realization in the quarter.
On the slide we show that Nymex contract settlement price and the average Nymex spot price.
For each quarter. So during the fourth quarter, the correlate Nymex settlement price averaged $6 26 assets for Mcf and spot priced averaged $5 60.
During the quarter, we dominated 81% of our gas to be sold at <unk>.
Index price is tied to that contract settlement price and then we settled the remaining 19% of our gas in the daily spot market.
So the appropriate Nymex reference price for our sales in the fourth quarter would have been $6 13 sets.
We realized $5 57 stacks in the quarter, which which reflects a 56 differential from the Nymex <unk> benchmark.
This.
It was wider than normal.
The water regional differentials that we had and.
In the Haynesville and the much weaker Houston ship channel and Katie have prices.
That we incurred.
Really since last summer data their freeport shutdown.
About 7% of our gas is tied to those Gulf coast markets.
In the fourth quarter, we're off to a 47% hedged which reduced our realized gas price to $4 19 stats for the quarter.
We have been using some of our excess transportation that we have available to us at the Haynesville to buy and resell third party gas this generated about $22 million of profits in the quarter and this improved our average price realization by 17 SaaS make it up for some of that water differential.
On slide eight we detail our operating cost per Mcf.
In our EBITDAX margin, our operating cost per Mcf averaged 76 in the fourth quarter <unk> <unk> lower than the third quarter rate.
Mostly by lower production taxes production taxes decreased 7%, primarily due to the lower gas prices that we had during the quarter.
Our gathering cost also decreased by 3% during the quarter, but our lifting costs increased by text ads.
G&A costs came in at eight <unk>.
<unk> <unk>, representing a <unk> <unk> increase over the third quarter, but about the same rate that we had in the fourth quarter of 'twenty one.
We generated an EBITDAX margin after hedging at 82% in the fourth quarter.
That's down from the 85% margin we had in the third quarter, where we had the very high gas prices.
On slide nine we recap our spending on our drilling activities in our other development activity for all of 2022.
Last year, we spent $1 billion on development activities, including $919 million that we spent on our operated Haynesville and Bossier shale drilling program.
We spent another 47 day at our non operated wells 45 day of that was in the Haynesville 2 billion within the Eagle Ford.
And we spent $66 million.
Other development activity, including infrastructure.
Selling production tubing, offset frac protection and other workovers.
In 2022, we drilled 73 or <unk> 57, net operated horizontal haynesville wells and we turned 66 or 53 six net operated wells to sales.
These wells had an average IP rate of 26 million cubic feet per day.
We also had an additional one eight net non operated wells turned to sales.
On slide 10, we show our oil and gas reserves.
We grew our SEC proved reserves, 9% in 2022 to $6 seven Tcf.
And replaced 216% of R 22 production.
Our drilling activity.
In 2022 added one one tcf, which make up really substantially all of the reserve growth that we had in 'twenty two.
Our finding cost for 2022 came in at 95 per Mcf.
The present value at a 10% discount rate of our proved reserves was $15 $5 billion based on the average first of the month prices that we had in 2022.
In addition to that $6 seven Tcf SEC proved reserves, we have an additional $2 seven tcf of proved undeveloped reserves, which we don't include in our SEC reported reserves as they are currently not expected to be drilled within the five year period required by SEC rules.
We also have another three five tcf of tupi or probable reserves.
Nine nine tcf of Threep or possible reserves for total overall reserves of $22 eight tcf on.
On a P three basis.
Slide 11, recaps, our balance sheet at the end of last year.
We fully repaid our revolving credit facility in the fourth quarter and ended the year with $2 2 billion in long term debt.
Our leverage ratio was one one times at the end of the year.
And in November we entered into a new revolving bank credit facility with a $2 billion borrowing base.
With $1 $5 billion of elected commitments from 17 banks.
The maturity of the revolving credit facility was extended three years to 2027.
So we ended <unk>.
22, with financial liquidity of more than $1 5 billion.
I'll now turn it over to Dan to discuss our operations in more detail.
Okay. Thanks Rolla.
If you look over on slide 12. This is just a good overview of our current acreage footprint in the traditional haynesville and Bossier shales.
We are the leading operator, our acreage position now total 618000 gross acres and 470000 net acres across Louisiana, and Texas, and the Haynesville and Bossier shales, which is also which also includes our acreage located in the western Haynesville.
Slide 13 details our 2022 year end drilling inventory.
The drilling inventory laboratory in Haynesville, and Bossier and it's divided into four categories are short laterals are up to 5000 foot or.
Our medium laterals are at 5000 8000 foot long are long laterals are at 8000 to 11000 feet long.
And then we have our what we call our extra long laterals for our wells greater than 11000 feet.
Our total operated inventory currently stands at 1826 gross locations.
In 1387, net locations, which gives us a 76% average working interest across the operated inventory.
On a non operated inventory we have 1336 gross locations in 185 net locations.
Which represents a 14% average working interest across the non operated inventory.
Based on the success of our new extra long lateral wells, we've modified our drilling inventory to take advantage of our acreage position and where possible we've extended our feature laterals.
Al further into the 10000 to 15000 foot range.
And in 2022, our average operated lateral length averaged almost 10000 feet.
Longer than 2021 coming in at coming in at 10008 2021 were at 8800 feet.
And our extra long lateral bucket, we capture all our wells that now extend beyond 11000 feet long.
In this bucket. We currently have 455 gross operated locations and 334 net operated locations.
The recap our total gross operated inventory, we have 335 short laterals.
287 medium laterals 749 long laterals and 455.
Extra long laterals.
Our total gross operated inventory are split 53% in the Haynesville and 47% in the Bossier.
By extending our laterals. We have also increased the average lateral length in our inventory from 8520 <unk>.
Up to 8870 feet or a 4% increase.
In addition to the uplift in our economics, the longer laterals will help to reduce our surface footprint on future activity and further reduced our greenhouse gas at methane intensity levels.
So to summarize where we're at today, our current inventory provides us with over 25 years of future drilling locations.
It's just based on our planned 2023 activity level.
On slide 14 is an update to our average lateral length, we drilled since 2017.
2022, our average lateral increase up to 9989 feet.
Based on the 66 wells that we turned to sales during the calendar year.
That is a 14% longer than the previous year's average lateral length of 8800 feet.
In 2020 to 16 of our 66 total wells turned to sales were extra long lateral wells greater than 11000 foot late.
Included in the 16 extra long lateral wells turned to sales were six wells that we completed with laterals longer than 15000 feet.
During the fourth quarter, we turned to sales a record longest lateral well to date with a completed lateral 15726 feet and this well was drilled on our east Texas acreage.
In 2023, and we anticipate turning 69 gross wells to sales with an average lateral greater than 11000 feet and we anticipate 31 of these in 2023 to be longer than 11000 feet.
And 12 to be 15000 foot laterals.
Slide 15 is a summary of our new well activity for the fourth quarter.
We've turned 19, new wells to sales since our last earnings call.
Strong well performance this quarter with the individual lockheed's, ranging from 2014 up to 42 million cubic feet a day.
With an average test rate of 25 million cubic feet a day.
The wells were drilled with lateral lengths that range from 6769 feet up to 15726 feet.
The average lateral length came in at 10186 feet.
Included in the fourth quarter Wells was our second well completed in our western Haynesville area.
The KZ Black number one H well was completed in the Bossier with a 7912 foot long lateral.
And it will start to sales in November .
The well was tested with an IP rate of 42 million a day.
After we got the Casey well test at our total field production exceeded the existing Schrader training capacity in the field and the wireless worker tail to slightly below our trading capacity.
Prior to being curtailed our first well completed in the field our circle M oil.
It was producing at a flat rate of 30 million a day since we turned into sales back in April of last year.
With the exception of being shut in for the month of October while the KZ Blackwell was being completed.
The existing Schrader is currently being expanded we expect to have additional treating capacity available.
Basically by the beginning of the second quarter.
We're currently completing the third well on our western Haynesville acreage versus the Campbell be number two as well.
This well was drilled in the Bossier formation with a 12700 foot long lateral.
We anticipate starting to swell to sales by the end of next month.
We also have two rigs currently running on the western Haynesville acreage that are drilling our fourth and fifth well.
On Slide 16, Slide 16 is a recap of all our.
Full year 2022 activity.
For the full year, we turned a total of 66 wells to sales.
The wells in this group were drilled with lateral lengths range from 4428 feet up to 15726 eight and.
And the average lateral for the year was.
<unk> thousand 989 feet.
The IP rates for the year range from $12 million up to 42 million cubic feet a day with the average IP at $26 million a day.
We're currently running nine rigs in the play we got three full time Frac crews over the next two to three months, we do have a plan in place to drop a rig count down to seven rigs and continue running a seven rig program through the end of the year.
On the completion side for 10 months now we've been working our first natural gas powered Frac fleet, along with our two conventional diesel fleets.
We've been really pleased with the performance so the natural gas powered Frac fleet.
This past summer, we executed a contract for a second natural gas powered Frac fleet.
And we are expecting the arrival of that fleet later in the second quarter.
Yes.
At that time, we are planning to run four frac fleets for just the short time through the summer.
Which point, we plan to drop back to three Frac fleets for the remainder of the year and also into next year.
Once that change has made down to three frac fleets that will leave us operating two natural gas fleet in just one conventional diesel fleet.
Operating the two natural gas powered frac fleets will allow us to capture additional cost savings on our completions largely through the elimination of buying expensive diesel.
And as well <unk>.
<unk>, reducing our greenhouse gas emissions.
Slide 17 shows our D&C cost trend through the fourth quarter and our full year 2022.
Performance for our benchmark long lateral wells. This is all of our wells that are longer than 8000 feet.
Of the 13 wells, we turned to sales during the fourth quarter 11 of these fell into the category of our bench Mark long lateral wells.
Our fourth quarter D&C D&C cost average $1425 a foot. This is just a 1% increase compared to the third quarter.
Our D&C costs for the full 2022 year averaged $1329 a foot and this represents a 28% year to year increase.
Our fourth quarter drilling cost was $583 a foot. This is a 3% decrease compared to the third quarter.
And our 2022 full year drilling cost averaged $523, a foot, which is a 32% increase.
Prior to our average 2021 drilling costs.
On the completion side, our costs for the fourth quarter came in at $843 eight.
This represents a 4% increase compared to the third quarter.
And for our 2022 full year, our completion cost payment at 800 $806 a foot.
Which marks a 25% increase compared to our average 2021 and full year completion costs.
These cost increases are a reflection of the swift inflationary pressures, we and the rest of the industry faced.
<unk> faced in 2020.
While we face the same inflationary pressures in both our drilling and completion operations. Our completion costs were somewhat buffered it through the deployment of our first natural gas Frac fleet back in April of last year.
And as mentioned on the previous slide we expect to capture more of these cost savings in 2023 and beyond.
Through the deployment of our second natural gas powered Frac fleet, which is going to show up in the second quarter.
As seen in the numbers.
We did experience a flattening of both our service costs and pipe costs during the fourth quarter.
And with the recent sharp drop in gas prices. We are cautiously optimistic that we will see service costs began to decline slightly throughout the rest of the year along with a reduction in the rig activity.
I'll now turn it back over to Jay to summarize the outlook for 2023.
Okay, Ralph and Dan. Thank you for the report and now we will jump into 2023 outlook.
I would direct you to slide 18, where we summarize our outlook.
Our 2023.
We will continue to de risk and delineate our western Haynesville play with a two rig program in 2023.
And we are managing our drilling activity levels to prudently respond to the lower gas prices environment. We've had so far this year.
In the process releasing two of our operated rigs on our legacy haynesville footprint to pull down our activity in response to lower natural gas prices.
We remain very focused on maintaining the strong balance sheet, we created last year.
As a result, we will continue to evaluate our activity and plan to fund our drilling program with operating cash flow are.
Our industry, leading low cost structure provides acceptable drilling returns even at current natural gas prices as our cost structure is substantially lower than the other public natural gas producers, we 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 more than one 5 billion at the end of 2022.
I'll now turn it over to Rob to provide some specific guidance for the rest of the year Ron Thanks, Jim on Slide 19, we provide our financial guidance for 2023.
First quarter production guidance is one 375 to $1 43, five Bcf per day and the full year guidance is $1 45 to one five Bcf per day.
During the first quarter, we do plan to turn to sales between 9% to 12 net wells.
On our first quarter development Capex guidance, we have said it at 275 million to $325 million and our full year development Capex guidance is 105.
To 1.15 billion.
Our 2023 wells will have an average lateral length being approximately 10% longer than 2022, which is helping to offset some of the cost inflation.
In addition to what we spend on our drilling program, we could spend up to $25 million to $35 million on additional bolt on acquisitions for new leasing.
Our lease operating costs are expected to average 20% to 24 in both the first quarter and the full year.
Our GTC costs are expected to be between 28 and 32 in both first quarter and the full year.
Production and AD valorem taxes are expected to average between 16 and 20.
In both the first quarter and for the full year.
This year, the DD&A rate expected to remain in the 95 to $1 five.
Per Mcf range.
And our cash G&A is expected to total $7 million to $9 million in the first quarter and 30% to $34 million for the full year.
Noncash G&A is expected to be about $2 million per quarter.
Cash interest expense. This year is expected to total $34 million to $36 million in the first quarter and $138 million to $140 million for the full year.
Effective tax rate is expected to remain 22% to 25% and we expect to defer 75% to 80% of our taxes.
I will now turn the call back over to the operator to answer questions from analysts who cover the company.
Please proceed.
As a reminder to ask a question you will need to press star one on your telephone again Thats Star one on your telephone to ask a question.
Our first question.
Comes from the line of.
Derrick Whitfield of Stifel. Your line is open Derrick.
Thanks, and good morning all.
Good morning, I Love. This nothing says I'll lead you more than dropping gas rigs.
In announcing better than expected full year 'twenty three guidance.
It was a moment of elevated thank you and I must say.
When I say Valentine.
Yeah.
I think it's safe to say that the operational plan and update our certainly welcome news.
With my first question I wanted to focus on the trajectory of your production profile for the year, while certainly sparing you guys that 2024 outlook question. Given that you are now just dropping rigs I wanted to ask if you could perhaps elaborate on the facility constraints that are impacting your Q1 production and.
If you could comment on your ability to hold production flat with seven rigs once the dock cycle through.
Yes, so one Derrick I wanted to comment on your title I think that just shows you that the whole world out there is wanting companies like Comstock to drop rigs.
And I think that was attention valve that we wanted to be the first to say, we're going to do that.
On takeaway, we've taken our core areas, probably 95% utilized in other words theres not a lot of takeaway.
We've worked with.
Newell, who is our new VP of marketing to provide takeaway for the wells that we will be drilling in 2023.
And through 2024, but I think our greater takeaway.
And Dan can address this in a moment as our western Haynesville.
We had commented that we had a plant issue with the two wells that we brought online.
The plant didn't expect that top volumes.
So our goal is to get that functioning properly.
The expected production that we think we will have and then really by the end of 2023, whatever that takeaway that we think we might need.
We'd like to have double that amount in case, we needed in the future to prepare ourselves for 2025 2026 takeaway, but really these are shippers will need more of this gas.
Dan you want to comment on the the plant facility in a takeaway issue, yes. So.
Western Haynesville Derrick.
Jay mentioned they weren't expecting these kind of volumes, we had forecasted potentially having these volumes, but obviously.
There was maybe a little bit about that.
We like to see a little bit of gas go up before they where they spend a lot of the money.
Investing a lot of money to upgrade their facilities.
But they did they had been working on it.
While we had the circle and well on since April of last year, we were fine.
When we put the casing and when obviously, we exceeded that capacity not by a whole lot but.
We had the facility kind of maxed out in December they were having a lot of up and downtime. So we basically curtailed the wells back just a little bit more just to make sure. We can keep the plant running.
Full time, which they have but.
The plant is actually down today doing some of the upgrade work and they're going to have.
Basically all of the additional capacity that's been planned will be basically up in owned by April .
We got some of the capacity is being basically added right now.
So we should be for everything that we've got forecasted all our production for the rest of this year, we're going to be in good shape. After these upgrades are completed.
And Derek we are drilling some of these wells will be drilling along that political pipeline, which we will.
Both of that plant.
145 mile pipeline. So some of the wells will be drilling in our western Haynesville will connect to our own pipeline.
And I think right now we think the capacity of that is about 300 million a day.
We had three other sources for takeaway that may double that amount thats what were working toward but I don't think we will need that much we're working toward that and Thats. Another reason Derrick production is a little softer in the first quarter versus second third and fourth quarter.
It's the fits together and plant.
Terrific and then.
Hi, Jay is it safe to assume as we kind of look at these docs flowing through and as we're modeling out the forecast with seven rigs I mean, it looks to US that you guys can at least hold production flat with seven rigs five being in the legacy to be in the western Haynesville.
Well you know we've.
We are one of the few that hadn't had really any well degradation in.
In fact, if you look all of our wells our wells are performing nearly 20% better.
Versus the 2020 and 21 production.
So if you look at that and you model. It forward and if you look at the amount of pretty stable production, we're getting from western Haynesville well.
We think we can have a 6% production growth within cash flow.
And give the dividend and have material reserve growth at the same time add material inventory.
Without <unk>.
That happened to go to the M&A market.
Yes, and maybe just as my follow up I wanted to lean into your last point, there and congratulate you guys on what appears to be one of the better organic leasing programs across the industry in recent years.
Regarding the western Haynesville now that you're three ish wells into your delineation program. What can you tell us about how the wells are performing against your pre drill expectations and the progress you are making from a D&C learning curve perspective.
So there I got to say I mean as far as our expected expectations were they basically have exceeded our expectations to date now.
We haven't had the KC blackout for very long the sarcolemma, we've got.
Basically it's still a 30 million a day well.
It was.
That is a pancake up through.
December which time, we started having some of the plant capacity issues and we had to basically pull everything back a little bit.
It's been it's been pulled back through today to when the plant is.
They're doing the upgrades on the plant, but we totally expect that well to be basically back up to when the plants back up and running and we will we will have it back up to that 30 million a day rate flat. So.
That well has obviously been.
Really good it has exceeded our expectations the KZ Blackwell off we guided I paid.
Looks just as good but obviously with the plant.
The plant.
If you use the full capacity that we haven't been able to flow that well at a full capacity for a length of time. So we'll have to we'll have to get the plant upgrades are done and get everything back honestly, how that one looks.
The third well is coming on and soon as the upgrades were done were going to have this campbell well coming on to actually plan to come out about mid March if everything goes well on the completion.
We're currently fracking it now so.
And then we really don't have anything else coming on there until July which Tom We've got two wells coming on us will have a big jump there.
And then.
Then early 'twenty four as Joe mentioned, we got out of the wells, we're drilling them, but they will go into our pinnacle gathering system and not this existing treating facility we're going in now.
Yeah, Derik and I think the big question is could you really.
Drill at this depth lateral length of 6000 feet 8000 feet much less 12700 feet, which is what we did on the Campbell in other words could you really do that and I know in 2008, and nine and the core of the Haynesville. It took a consortium of companies years to figure out how to drill long.
Laterals and we're really we're one company enter trying to de risk. This.
And I think the operations group.
As a tier one group have done a really good job with that.
That's very helpful. Thanks for your time.
As Sarah Thank you.
Okay.
Thank you.
Our next question comes from the line.
Charles Meade.
Johnson Rice your line is open Charles.
Okay.
Good morning, Jay Roland and the rest of the Comstock team there.
Good morning Charles.
Jay I wanted to I wanted to pick up on.
Pick up on the thread that you.
Comment you made in your prepared remarks about.
About drilling within cash flow.
Ed.
I just wanted to get you to elaborate your your thought process there and about how you can you know.
How you can navigate the company.
In that in that way because.
As I look at it the strip has moved so far so fast and that no company could.
Can maneuver on a quarterly granularity it seems like you can't you can't.
You Couldnt decelerate <unk> enough to drill within QQ cash flow. So how is it that youre looking at Eric.
Are you aiming to be within within cash flow, a couple or few quarters out and is that kind of a market that you tried to hit or if you could just elaborate on.
How you how you think about that target and what you can do to to hit it.
Yes, that's a great question, Charles and yes.
There is a dynamic environment and I think you saw some of that change.
Changes to our drilling program was debt to try that.
Steve that.
Commodity prices could go a lot of different directions for the rest of this year.
So that's a big unknown and I think that.
On the other side.
Service cost in our Australia, we've kind of.
At <unk>.
Budgeted for kind of that very high service cost environment that we had last year with with a lot of inflation. So we hope to see some D inflation of some of that is cost, especially in the second half of this year.
I think the win.
One additional kind of source of cash thats.
Not that its easy to model is the fact that we.
We will have.
Some are even up about a couple of hundred million dollars of working capital that you know that.
Well that was really earned in.
Our great 'twenty two year that gets it received this year.
Yes, the way we had to settle hedges early.
Et cetera from last year, and just that the timing of gas receipts there'll be quite a bit of extra if youre just looking at the model you don't pick that up but yes, I think thats a little bit of a cushion there to that that we see as we look ahead.
After this year, but it's it will be something that we'll continue to monitor.
We have tremendous liquidity and financial resources, So I think that's that.
It's just our goal is to say our overall goal is not to overspend cash flow and we'll continue to try to.
Change our program as the year progresses to do that yes, I think thats the messaging I mean, if you go back even.
Probably on the not to this month natural gas had dropped 46% this year.
And as to your point, it's all over the board, we do think that the Henry hub Selloff is now overdone.
We've accepted distance seasonally warm weather.
But we do think a big event change during 2023 is the restarted the Freeport LNG.
Looked at gas storage and you have all these numbers I mean storage today is about 11% above one year about 5% above five year, but.
If you were to add back that two bcf of lost.
Demand related to Freeport, those numbers shows or changed dramatically would be 11, 5% below one year would be 16% below the five year. So we look at that too and then we look at all of this flexibility. We have we tell you we have a 6% production growth in 2023 and.
And most of these companies have less than that so we could flex down and have less production is still probably had more production than the peers and then I think it always shows up and you always point this out.
We are a low cost producer period, and we've been very I think we have managed our money properly.
In the past and we will exactly do the exact same thing we're going to manage our money just like we did in the past forget to manage it be that responsible in the future.
So our goal is net net net forget quarter by quarter by quarter, If you get through 2023, and it's a soft year.
Our goal is to not have borrowed net at the end of the end of next year, a penny from our from our credit facility.
So you can't look at on a 90 day basis to drive you Crazy.
But thats our goal.
Right right.
It is thank you for that elaboration because it's Hugh.
It's you can't affected on a 90 day basis, and so that was that was a helpful. Exposition on the way you guys are approaching it.
My second question or the Western Haynesville, so it seems to me.
I always like maps, but I understand you guys don't want to put the put the maps and now because.
You say for competitive reasons I.
I look at that you guys.
Erik pointed out great job that you guys picked up this almost 100000 acres.
But it looks to me like you guys. If I look at that you don't want to show map, but youre also guiding to I think about $30 million of lease acquisition.
No I'm, sorry, more closer to 100, so so that suggest to me you're you're not you're not done building that position, but you're probably more than half done building that position is that up.
Is that a fair way to characterize it or how would you characterize it.
I think that we kind of we talked about it's been roughly the $30 billion is the right number for for lease acquisition in 'twenty three I think youre looking at the infrastructure right with you right, Yes, <unk>, yes.
Investments that we are probably going to make which are.
Separate from that so I think that we do feel like we will substantially complete cap.
Capturing we think the best part of this play it out this year.
I would say that we're more than half done there.
Charles I would I would comment on this.
We've disclosed the detail that.
In the case in Qs It we have to because we're a public company.
Then we don't disclose the things that we don't have to disclose as public company, because we're still in that area.
And then we would disclose the amount of money because you need to know that we think we're going to spend kind of closing out the checkered flag on our acreage.
We want to we want to make sure that when you're on the team and you own the stock like the Johns is converting that $175 million preferred into equity because thats, where the torque is it's the equity ownership. We want you to know his perspective stakeholder in an analyst.
But we do have a checkered flag, we kind of know where our parameter is we do have a budget for that spending, but we always we always do what it tells us to do and that is.
How's the drilling going how the lateral lengths going do we have any takeaway there and we monitor that and then I think to kind of daycare crescendo is.
When will all of this kind of really materialize and be extremely valuable.
It's been at $2025 2026 timeframe, which is what.
That's when most of these companies need this natural gas and if you needed as a shipper.
Not many companies that can provide you a decade upon decades of inventory and drilling.
And that is our vision.
Can't fully explain it to you right now were still kind of marking it up.
The sheet of paper, but we want to we want to make sure you're not left behind as we move in that direction.
Thank you Jeremy.
Thanks Charles.
Thank you.
Our next question comes from the line of.
In Ma.
Choudhary of Goldman Sachs. Your line is open.
Hi, good morning, and thank you for to Lauren's question.
Really appreciate all the color on your vision and how you are shaping as activity levels. Both in the near term, but also setting the company up from a long term perspective.
I wanted to kind of focus a little bit more on the near term.
It sounds like your completions and production growth. This year is going to be more back half weighted consistent with higher gas prices that we see in the future Gulf Good day.
You made a comment about tight oilfield service market today.
I was wondering what kind of flexibility do you have with your rig and pressure pumping counterparties.
To add or drop activity F gas, but I say surprises to the upside or on total put it outside.
Yes.
<unk>.
We're in really good shape there.
We've got a few rigs on some just really kind of medium short term contracts. The majority of them are basically well to well contracts. So.
One reason, we were able to basically kind of implement our plan to dropdown to these seven rigs pretty quickly I mean, you can't we cannot really do it any quicker than we did because obviously they are drilling on multi well pads and now maybe just even just don't one multi well pad you're there for two months so.
So we're in great shape, there, we do have the ability to drop additional rigs quickly if we need to and we also very confident that we can add rigs pretty quickly in the back half of the year.
We had a surprise to the upside and that's the path we wanted to date.
Same thing on the Frac crews.
We've got the one natural gas fleet. This on a long term contract.
Other than that.
Diesel fully our conventional fleets or just.
Short term contracts that we could that we could.
Things turn south we could obviously dropped those pretty quick and we've got we.
We can kind of we've got obviously plans to go to the floor.
Frac fleet that I mentioned earlier, when we pick up this new second gas fleet.
So we.
We've got the option to we could drop one and basically just stay at three when the new fleet gets here or we can go to four which is what we have planned.
Basically kind of.
Some of our ducks down a little bit before we dropped back to three at the end of the summer.
And then obviously, we could go to <unk>, we could just dropped down to the two gasoline. So really in summary, we've got we've got really great flexibility to go up or down rigs and frac crews.
That is really helpful.
And I guess, just a follow up.
This activity levels point.
As you talk to some of your non operated partners in the Haynesville.
Any color you can provide in terms of what they are thinking about from a activity perspective.
Accounts, so far has been fairly resilient, if we look at some of the Nic data.
Well there.
Definitely dropping rigs we have talked to a few of them not all of them, but everybody. We have talked to is basically planning to drop rigs.
<unk> seen a.
A few rigs drop here just in the last two to three two to three weeks so I.
I think thats how.
How many ultimately they dropped remains to be seen but.
Definitely everybody that we have talked to is dropping rigs has dropped rigs.
That's really great color. Thank you so much guys.
You bet. Thank you.
Thank you.
Our next question comes from the line of Bertrand <unk> of <unk>.
Truest your.
Your line is open Bertrand.
Hey, guys.
Jay I'm sure you're tired of talking about how good the western Haynesville is but maybe I could ask one more on it.
I love it keep asking those questions alright. So the first one came on at 37 today and then the <unk>.
Excellent came out even higher at 42 and it sounds like the.
He surprised youre.
<unk> midstream guys a little bit.
Were you guys expecting that level of consistency I know, it's only two wells, but when you look at your core position there as kind of a much larger variation. So I'm just trying to find out if that was also a surprise to you guys or if theres something different geologically that.
New business is going to happen.
No I think obviously I think the geology I mean, we as far as the variability we expected the same out of both wells.
We did two both of these wells initially we typically they flow our well completions up the casing for Cui.
Quite some time before we'll take them up down here in the Western Haynesville both of these wells.
We're basically teamed up from the get go.
We did run we have $2 782, then we ran into the <unk> and the <unk>, we ran three and a half inch tubing and the KZ well.
We want it around three five inch stayed in the circle and well, we basically couldnt get our hands on the stream when we needed to and so that that's one of the reasons why we didn't really probably go to a higher op right on the circling almost just.
We're just basically trying to manage technically.
Critical velocities erosion rates and all of that.
So that did lead us so the KZ with a beggar tainment allowed us to basically tested a little bit higher rate.
I'll tell you the well performance in our core area.
<unk> has provided us with the cash flow to Derisk it.
The western Haynesville et cetera free cash flows that we bought all that acreage.
And to kind of your western Haynesville questions.
Because the western Haynesville has performed so well.
That's one reason why Jerry Jones, and his family that owned 66% of the company.
So do you know what we're going to demonstrate our confidence in the future of the company and the great potential.
The upside in the equity we're going to convert our preferred into common.
<unk>.
Maybe because the core is solid but our real raise it as we've got we've got a lot of potential that we barely barely talked about in the western Haynesville or just had two wells I mean, it's a very beginning of the game.
But if we can solidify that and continue to talk about it as broadly a year from now as we have today then.
We will be that company that can provide this gas on a global basis, because of where our footprint is where the LNG shippers are spending their money.
That is the goal.
Alright, and just following up.
The two rig program in the in the.
Western area is is that just the best way to kind of not get over your skis is two rigs just the most efficient way to drill it why did you settle out on kind of two there and then five in the traditional.
What we did initially we said let slip they play tell us.
How many rigs we need.
And so you have to have the one rig we drill the well we move the rig off.
And we produce the well for a while.
See whether we should drill a second well.
Also in the first well like Dan said retrieved it up not to produce as much gas as it could have produced all of sudden we move that rig back down and we're drilling and it tells us to put a second rig one.
Now you might look at the acreage footprint and say well at some point in time, we're going to put a whole lot of rigs home and that answer is no either.
Right now in our model, we add a rig a year or two.
All of the acreage that we've leased now if all of that acreage ends up being tier one acreage, which who knows but if it did and that's what we would have our drilling.
Greg rigs anyhow.
Most of our core acreages HB paid so we can have the swing back and forth. We can toggle this back and forth.
It's unusual to.
How we looked at this Dan, yes, I totally agree with that.
One just one extra playing out would add is we've.
We knew this would be a little bit of a learning curve on these wells down here versus our core we've been drilling literally.
Just the industry's thousands of wells up there pretty much.
Predictable and consistent.
So here in the Western Haynesville, we have seen some pretty good progress just on these first few wells that we've drilled as far as <unk>.
How fast we're drilling them and where we feel like we can go in the future obviously get much faster and.
So.
Kind of where we think we're going to end up on speed is also don't change the cadence of our activity down here in the western Haynesville and as.
As we do speed up and drill these wells faster than at some point you can drill at a speed that's essentially like adding another rig to the play so.
Kind of going to keep an eye on that.
That will also factor into when we add the additional rigs.
That's great color guys and then really my last one just.
Depending on where the gastric falls out.
Could have some free cash flow, especially because you are kind of committed to drilling within your.
Your cash flow. So you might have some free cash on top of it with your revolver kind of pay down is there a strategy that the rest of that cash would maybe fund an increase in the dividend nice and slow oriented maybe you hold the cash or do you address the 'twenty 930 notes.
A little ahead of schedule I, just where does that ex FX cash go.
Well, we've always said publicly and this is our goal is that we would want to hold the cash we'd want to kind of set a goal of creating at least a half a billion dollars of our cash had a reserve that we can find acquisitions et cetera.
So I think thats kind of where we would once we kind of have that established then we cannot we'll look at other return of capital.
So given that tighter environment, we're in now.
Obviously that a return of capital is probably pushed all that out.
For the future because I think we want to build this cash reserve first with the with additional free cash flow we generate this year.
Okay does that maybe look.
Materialize until like a tender offer for that after you get that cushion or is it.
Are you comfortable with your free cash flows and by the time you get to $25 26 in the gas demand comes back that won't really be a worry about those notes.
Well I think there is.
I think.
As far as looking at their retirement additional debt I think that we really have to prioritize our free cash flow then as you.
You mentioned the dividend share repurchases, our bond repurchases and I think.
To the extent we would once we establish this cash reserve I think then we will look at those those three forms of return of capital.
And decide which one to pursue which one has the best opportunity, yes, you'd have to see where the algorithm Marty.
The bonds trade at.
Okay.
Yes, we have great maturity runway great.
Cost of debt that we really the balance sheet. We just I think we got it in.
We are really great shape here.
In 2002 that was what the year afforded us to do and so.
We're able to navigate the lower prices because of our great cost structure, just like we navigated those low prices back when we didn't even have the great balance sheet.
So.
That's what our view is that well it sounds like you want to stay flexible and I think the market's rewarding you today for being flexible sale. It sounds like a good morning guys.
Thank you. Thank you good questions. Thank you.
Thank you.
Our next question comes from the line.
Jacob Roberts.
Of Tudor Pickering, Holt <unk> company. Your line is open Jacob.
Good morning, guys.
Good morning morning.
Curious and I know, it's very early days, but if you could provide any guidepost on the western Haynesville D&C costs that you're seeing in the comment you just made about the days to drill just curious if you can provide some context, there and then maybe the trajectory that we might see from the circle <unk> activity as well.
Yes, it's a little too early to make any comments on that good question.
Fair enough I guess for my second 125 years of inventory at certainly a long runway just the appetite maybe not in the near term, bringing some of that value for it in the market.
I think any company needs to have a lot of inventory I mean, I think <unk>.
Even during Covid, there was billions tens of billions of dollars of.
Of M&A to high grade inventory.
I think what we've done we just said we returned to sales 55 wells a year.
We've got a lot of inventory doesn't mean, you have to drill a bunch of those wells I think if we de risk our core areas and we have thousands and thousands and thousands of locations I mean, who knows and.
And that's going to be worth a whole lot of money without having to drill all of those wells.
I'd like to have 40 years of inventory and I don't feel I have a need to sell to anybody any of my inventory just because I have a lot of it.
And one of the most effective ways to which we've done.
To develop the haynesville as but given the fact that the wells have a high decline initially and Theres a lot they need a lot of takeaway when they come on and then.
Five years later they.
Yes.
Yes, they are producing a lot less is the kind of space your development out over a long period of time, otherwise you have to make very very large.
Infrastructure investments, which are in a very prudent way to develop it. So I mean, given the nature of our play I think the way we develop it over this longer timeframe as the most cost effective way to get the reserves, even though you don't get the net present value, but overall you get you don't have to either over commit to.
Our passive infrastructure Bill that you won't be able to use five years from now so I think thats just the nature of the play we are in and I think we've been.
Prudent in the way that we do that and that's why we've given our large footprint, we actually move around areas not because we're trying to we don't drill are very tier one area. All the time, because we only have room for maybe a couple of wells a year to put into it based on the existing infrastructure. So we can rotate.
The drilling program around to balance out the infrastructure needs and given the activity level now is higher with other operators, that's even more critical than it used to be.
Because.
Yes, theres only so theres not a lot of extra capacity out there I mean again I think LNG buildout is going to run its course.
And this demand will pick up in the next several years and we just want to be positioned.
To non oversupply the market to provide half of much cast the market needs.
We'd like to provide that in the Haynesville Bossier.
Great appreciate the time guys.
Yeah.
Thank you.
Great.
I'm sorry, our next question comes from the line of Leo Mariani of MK <unk> Partners. Your line is open Leo.
Yes, guys.
I was hoping you could talk a bit more about just confidence in the western haynesville.
You said, you've got two wells out there, but it sounds like you are committing to a fair bit of infrastructure dollars it sounds like.
Keith and chunk of that $100 million that you're spending on infrastructure in 2023.
Are there other industry wells in and around you guys that are giving you more confidence is there a geologic model where you look at the position and think that.
A lot of what you have in the acreage is more homogeneous than it can produce margin. Its results can you provide a little bit more color around confidence and their willingness.
To run a couple of rigs there and spending infrastructure dollars.
Yes.
Come and layout.
We've done our own homework with our geological staff.
We really we had to say like an OE technically have we advanced enough to technically drill these wells vertically and laterally.
<unk> nine 2010, we did when we when we've deepened the cotton valley to hit what is now the Haynesville Bossier in the core area.
We looked at our own geology, when we looked at our own seismic look our own well logs from.
For wells that have been deepened in this particular area.
And then we have least part of that acreage in and there is another company that has drilled a couple of wells, but.
We don't go by what they've done or are doing we're really doing this with our own team.
With our own information and we like the results.
So.
That's why we went ahead and bought the critical line in at acreage included in the clinical line.
So this is a kind of a self created extension to the play that we think.
Is going to provide the world with that extra gas that they need.
Okay I appreciate that answer and then.
Just in terms of your D&C Capex budget for 2023.
Barely wide from the low end to the high end can you provide a little bit of color in terms of what gets you to the low end or the high end.
I think there is.
Slide mainly because of that.
Exactly inflation, how much yet.
High end, we assume inflation doesn't.
It does it just continues to run.
Rapid like it has in the low end, we hope to see some.
Improvements in prices. So it is really service prices that are that because our activity level. We think is.
It's fairly mapped out.
Based on what we wanted to today, but the cost of services.
Is where you're going to need a lot of maneuvering room, I think to figure out what.
What the ultimate Capex is going to be.
Yes.
Okay. That's helpful for sure and you guys alluded to this a little bit earlier in terms of flexibility is sort of add rigs there are sort of drop rigs, but I'm just kind of curious what would it take for you guys to do that and if we did get let's say a spike in prices. Later this year would you maybe elect to kind of hedge some of that before.
Sure.
Rigs I mean, it seems like the gas market has been probably the least predictable its ever been and it feels like in the last year, it's been very hard to see kind of where it's been going here.
Well I think thats it.
I think the next couple of years.
There's probably going to be a lot of volatility in gas.
Very little things can drive it.
Up or down I think and so and.
Sure just because you get a big spike in gas one month that it is going to stay.
And the shale development committing to a rig and committing to a program like that and the way we drill wells on pads in the development mode, because it's much more cost effective.
It really is a longer term decision. So you got to kind of get very comfortable with the six to eight months plus kind of time horizon to wanted to add that activity versus yes, it'd be very reactive to just one month spike.
Because it takes if you add that it can take that kind of time that an ad.
So you have that flexibility, but they are.
And our contracts to allow us to do it but they are in the middle of drilling pads and all that so it's not very practical all to remove a rig in the middle of a project.
It's got to wrap it up so yeah. So it's a longer term decision.
So I think we kind of make those decisions kind of as we go into the year.
And then.
Just as we have to.
But that kind of try to overreact.
One way or the other given our very strong balance sheet, great liquidity I mean, it's just wanting to prudently meet our goals is our objective.
That a worry that we're going to out spend.
Spend our resources.
Okay I appreciate the color.
Thank you Leo.
Thank you.
Our next question comes from the line of.
Paul Diamond of Citi. Your question. Please Paul.
Okay.
Apologies Paul Your line is open. Please go ahead.
Hello <unk>.
Buying stock that's a good thing.
Hi, sorry can you hear me.
Yes.
Yes go ahead.
Thanks for taking the time.
No I kind of just wondering as jump into so you say you have flexibility to add or drop additional rig I just wonder if you could get into a bit of color on where your priorities would be for.
For that marginal rigor activity, whether thats near the two that came out of core should we expect that next marginal want to either come out or go back into that same core acreage or does.
Does that priorities kind of shifts more towards the western haynesville.
The closer we get.
The long term.
The quick drop any rigs they would come out of our core not the western Haynesville.
Understood. Thank you.
I just kind of the other point is given the recent volatility we've talked about on the call today and kind of a longer term view of.
Much much.
Much greater level of demand.
And the longer term has that shifted at all you guys strategy around hedging.
We added some more in.
Last quarter or is it still or is it still kind of run rate to that kind of strategy you guys have been using for the last several quarters.
Several months ago, we looked at again these two way collars with a floor to ceiling.
And we did add another $250 million a day in the third quarter I think were like 34% hedged for the whole year.
Tim We did look at the $3 floor and whatever the ceiling might be.
We ended at 250 million a day.
Think we always and ranch in charge of that Ron Mills, we always look at putting some two way caller in.
So we'll keep looking at that we don't think that today's the day to do that we did that a couple of months ago, because when prices keep falling thats not when you need to make those actions.
We're we will throttle back and forth to maintain our fortified balance sheet and we can do that.
With the election.
To keep the rigs.
Some ducks et cetera, we've got a lot of a lot of controls on our on our panel.
So.
And we will look at hedging.
Understood. Thanks for the color.
Thank you. Good question. Thank you at this time I would like to turn the call back over to Jay Allison for closing remarks, Sir.
Again, it's we've been on this and our 16 I think you are still there after the.
Extra 16 minutes I know they always say the pure past actions probably predict your future actions.
I think what we want to tell you is that we have made.
Possible decisions in the past.
Year after year after year, they have been responsible and we will continue to make responsible decisions in the future why.
To protect our fortified balance sheet and to Derisk the western Haynesville.
We thank you for supporting us in the past and we thank in advance for continued support us in the future.
As we as we derisk, the western Haynesville and create.
The gas that the world needs.
In a spot that it needs in the United States. Thank all of you I appreciate it.
This concludes today's conference call. Thank you for participating you may now disconnect.
The conference will begin shortly to raise and lower Johan during Q&A, you can dial star one one.
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