Q4 2021 Comstock Resources Inc Earnings Call
Thank you for standing by and welcome to Comstock Resources fourth quarter earnings Conference 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 on your <unk>.
Telephone please be advised that today's conference maybe recorded should you require any further assistance. Please press star zero I would now like to hand, the conference over to your host Chairman and CEO Jay Allison. Please go ahead, yes, thanks for that introduction.
On behalf of the 200 and stay for Comstock employees and the board of directors I'll make a few opening comments and then we will go to the to the results.
Okay.
First Comstock shift I think I think as Ron Mills has talked about at the analyst.
Comstock shifts to longer laterals.
The 10500 foot laterals in 2022 versus the 800 foot laterals in 2021.
You should all know that it's expected to create great value on a per well basis going forward we.
We had better cost efficiencies, we should have a lower decline curve. Thus an increase in well performance will review that on this call later one.
The higher capital efficiencies associated with the longer laterals did allow us to more than offset the impact of higher service cost.
Fourth quarter 2021, so you can see that in our numbers.
We have seen higher service cost.
We will use commitment from from.
From the board and from management.
Use of free cash flow to pay off the revolver and redeemed the remaining 244 million in the 2025 bonds. That's our goal.
We do have a target continue to have distributor ratio with one five or less.
Think we can get there in the second half of 2022.
Does open discussions up on returning capital to shareholders.
We might have that question.
Our drilling inventory, which is the Holy Grail of E&P companies I think Thats why you have a lot of M&A.
And the last year or two years, but our drilling inventory has never been more valuable or stronger because in 2021, we made great strides in extending our lateral link colocation by 25% from our average lateral length at the end of 2020 year 6800, 40 feet and today.
About 8520 feet.
If you look at that 25 years worth of drilling inventory based upon our 2022 activity.
We've got 1633 net locations, 53% of those were Haynesville, 47% are boettcher and just think I mean 902 net locations with lateral lengths.
Peter longer.
On the operational front, which is I think thats the nucleus of this company.
I'll, let front, we increased our drilling footage per day by 25%. We went from 800 feet to 1001 <unk> per day.
You make money.
Our average lateral length wells from the fourth quarter 11443 paid to the region as we drilled 415000 foot lateral wells to St tool to Bossier, two haynesville well through <unk> and we're just as of.
This morning, we.
The $2 15 that put virtual sales.
Again in spite of higher service cost, we're able to lower our drilling and completion costs due to improved operational performance and improved capital efficiencies associated with the longer laterals drilled in the fourth quarter 2021, which that will be carried over into 2022.
We have a few slides to take you back.
2018, and be accountable for our performance I was kind of a turnaround year.
This year. This is Jerry Jones, and his family investors Comstock and since that time Comstock is surface.
As the only pure play Haynesville producer.
So welcome to the Comstock resources fourth quarter, 2021 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' Dot com and downloading the quarterly results presentation, there you'll find a presentation entitled fourth.
<unk> 2021 results.
Im Jay Allison Chief Executive Officer, John talked with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Rod Mills, our VP of Finance Investor Relations. Please flip to slide two.
Refer to slide two in our presentation and note that our discussion today will include forward looking statements within the meaning of securities laws, while we believe the expectations in such statements should be reasonable there can be no assurance that such expectations will prove to be correct. Our fourth quarter 2021 highlights slide three we cover that.
Highlights on the fourth quarter on slide three in the fourth quarter, we generated $105 million of free cash flow from operating activities, increasing our total free cash flow generation for 2021.
$262 million.
Including the impact of our acquisition and divestiture activity, our total free cash flow for the year was $343 million.
For the quarter, we reported adjusted net income of <unk> 9 million or <unk> 37 per diluted share our operating cash flow for the quarter was $250 million or 90 cents per diluted share our revenues, including our realized hedging losses increased 37%.
The $380 million, our adjusted EBITDAX for the fourth quarter was $297 million.
41% higher than the fourth quarter of last year.
Production increased 12% in the quarter to 1348 Bcf a day.
In the fourth quarter, we completed 215000 foot Haynesville wells, which had IP rates of 48, and 41 million cubic feet equivalent per day, both of which are new corporate records to Dan Harris, who will review in a moment during the quarter. We also closed on the sale of our Bakken properties and closed a bolt on.
<unk> for $35 million, if you flip over to slide four I will go over some of the major accomplishments in 2021.
We significantly reduced our cost of capital by refinancing $2 billion of our senior notes in March and June , which saved us $48 million in cash interest expense and extended our average maturity from four seven years to seven one years, we also reduced the amount outstanding under our bank credit facility by 200.
$65 million with our free cash flow and asset sale proceeds and improved our leverage ratio to two two times as compared to three eight times in 2020.
We had another successful year in our Haynesville shale drilling program, we drilled 64 gross or 51, nine net wells, including 415000 foot laterals are the wells, we put to sales had an average IP rate of 23 million cubic feet equivalent per day.
Grew our SEC proved reserves by 9% to $6, one Tcf Pea with a PV 10 value of $6 $8 billion, we replaced 199% of our production at a low all in finding cost of $60.
Per Mcf.
Highlighting our attractive cost structure, we achieved a 78% EBITDAX margin one of the highest in the industry. In addition, we achieved a 12% return on average capital employed.
And a 27% return on average equity.
In 2021, we added 49000 net acres.
Our acreage position perspective for the Haynesville and Bossier through a leasing program and acquisitions totaling $57 7 billion or $1178 per acre.
Several big steps in 2021 on the environmental front.
Early in 2021, we partnered with BJ introduce solutions to deploy next generation natural gas powered Titan.
Fleet, which is expected to be put in service in April the most significant step we took was support her with MRI huge certify our natural gas production under the <unk> methane standard.
Flip over to slide five and we recap the bolt on acquisition in East, Texas that we did close late December for purchase price of $35 million.
The acquisition included $18, one net producing wells and.
17331 net acres in Harrison lay on Vanilla Robinson, and <unk> counties with the acquisition. We added 57, nine net drilling locations, which represents approximately one year's worth of drilling inventory.
The acreage is 94% held by production.
The acquisition also added the lateral lengths on 44 of our existing drilling locations to be increased.
I'll now turn the call over to Roland to discuss financial results Rolling.
Yes, Thanks Jay.
<unk> six in the presentation, we compare some of our fourth quarter financial measures to the fourth quarter of 2020.
Our production increased 12% to 135 Bcf a day.
Adjusted EBITDAX grew 41% to $297 million.
We generated $250 million of discretionary cash flow during the quarter, 62% higher than 2000, Twenty's fourth quarter and.
And our adjusted net income totaled $99 million during the quarter, 186% increase from the fourth quarter of 2020.
We generated 105 made a free cash flow from operations in the quarter.
Or $204 million. If you include the impact of the acquisition and divestiture activity, which most of that occurred in the fourth quarter.
This free cash flow contributed to an improvement in our leverage ratio, which improved to two two times down from three two times at the end of 2020.
Our cash flow per share during the quarter was <unk> 90 per share.
From 56 in the fourth quarter of 2020, and adjusted earnings per share was 37 per share as compared to 14 sets in the fourth quarter of 2020.
Yes.
On slide seven we show how much Comstock has changed since 2018, when Jerry Jones and his family invested in the company.
Production growth has averaged 117%.
Over the last three years EBITDAX has gone from $287 million to $1 $1 billion at a compounded annual growth rate of 97% cash flow has grown from $206 million.
Back in 2000 $18 million to $908 million this year in 2021, averaging 114% over the last three years.
Adjusted net income has grown from 29 million to $303 million at a compounded annual growth rate of 319%.
And free cash flow from operations has grown to $262 million and our leverage ratio has improved from four five times.
To two four times on.
On a per share basis cash flow has gone from $1 96 to $3 29.
And earnings has gone from 27 to $1 16.
On slide eight.
We provide a breakdown of our natural gas price realizations and this is an important slide to understand the quarterly results as we've had a very volatile nymex contract during the fourth quarter, which has continued into the first quarter of this year.
On this slide we show how the Nymex contract settlement price.
And we show the average Nymex spot price for each quarter. So.
So during the fourth quarter, there was a very significant difference between the.
The quarter's Nymex settlement price of $5 83 stats.
And the average Henry hub spot price of $4 74 sets.
So during the quarter, we nominated at 67% of our gas to be sold at index prices, which are more tied to the contract settlement price or the <unk>.
The final price that they the contract comes off the market at and then we also saw 33% of our gas in the daily spot market.
So if you use those percentages.
The approximate Nymex reference price for looking at our activity in the fourth quarter would have been $5 47.
Not $5 83 steps.
So our realized pricing from the fourth quarter averaged $5 22.
Which reflects a 25 cent differential from that reference price, which is fairly in line with our historical results.
In the fourth quarter, we were also 72% hedged so that reduced our final realized gas price to $3 per Mcf.
On slide nine we detailed our operating cost per Mcf.
And the EBITDAX margin.
Operating costs per annum Cfe averaged 67 from the fourth quarter that was <unk> <unk> higher than the third quarter rate.
Our lifting costs and gathering costs were both up by one set but production taxes were down by three.
Higher G&A cost of eight sets.
Was also higher in the quarter and Thats, primarily related to year end adjustments.
For bonuses.
We do expect our G&A to go back to average somewhere between 6% to seven stats from Cfe.
In 2022.
Our EBIT margin, including hedging came in at 78% in the fourth quarter.
Unchanged from our third quarter margin.
On slide 10, we recap our fourth quarter and full year 2021 drilling and completion cost in the fourth quarter, we spent $140 million on development activities.
<unk> 14 billion of that related to our operated Haynesville and Bossier shale properties.
We also spent $8 million on non operated wells and we had $15 million that we spent on other development activity.
In the Haynesville in our Haynesville operations.
We spent an additional $3 million for our properties outside of the Haynesville.
For the full year, we spent $628 million on development activities 554 million was related to our operated Haynesville and Bossier shale properties.
We also spent $74 million non operated activity and for other development activity outside of just drilling and completion.
We drilled 51 nine net operated haynesville horizontal wells.
And we turned to $54 two net wells to sales in 2021.
We also had an additional two two net wells from our non operated activity.
In addition to funding our development program. We also spent $58 million on acquisitions.
Most of that.
Are those acquisitions related buying and drilled haynesville shale acreage.
Slide 11 covers our proved reserves at the end of 2021.
We grew our SEC proved reserves from five six tcf to.
The $6, one Tcf and.
In 2021, and we replaced 199% of our production.
Our 2021 trillion activity added 797 Bcf of proved reserves and we had about 89 Bcf of positive price related revisions.
We also added 203 Bcf of proved reserves through our acquisition activity.
The reserve additions were offset by a divestiture of 100 Bcf, which is primarily our Bakken shale properties.
Our all in finding cost for 2021 came in at a very attractive <unk> 60 per Mcf.
Our drill bit finding costs for 'twenty, one came in at <unk> 71 per Mcf.
Our reserves are almost 100% natural gas following the sale of our Bakken properties. The PV 10 value of our proved reserves at SEC pricing was $6 8 billion at the end of last year.
In addition to the $6 one Tcf SEC proved reserves.
We have an additional two four tcf of proved undeveloped reserves, which are not included in that number as they are not expected to be drilled within the five year window required by the SEC rules.
We also have another four four tcf.
Of tupi or probable reserves and we have seven two.
Tcf of Threep or possible reserves for a total overall reserve base of 21 Tcf at three basis.
Slide 12 shows our balance sheet at the end of 2021.
We had $235 million drawn on our revolving credit facility at the at the end of the year after repaying $265 million during 2021.
The reduction in our debt and the growth of our EBITDAX drove a substantial improvement to our leverage ratio, which is down to two two times in the fourth quarter on a standalone basis as compared to three eight times in 2020.
We plan on retiring $479 million of debt in 2022 that would include redeeming. Our 2025 senior notes, we're targeting to be below one five times levered in 2022.
And we ended 2021 with financial liquidity of almost $1 2 billion.
I'll now turn it over to Dan to discuss our operations.
Okay. Thanks.
Roland.
Flip over on slide 13.
This is where we show our average lateral length, we drilled by year going back to 2017, along with our estimated average lateral link for this year and also a record longest lateral and longest lateral that we've completed to date.
2017, our average lateral length was 6233 feet as we were drilling primarily a mix of 4500 7500 foot laterals.
We had just started drilling our first 10000 foot laterals.
In subsequent years through 2020, we slowly increased the number of 10000 foot laterals that we were drilling which allowed us to gradually increase the average lateral length.
In late 2020, we successfully drilled and completed our first laterals exceeding 12500 feet.
And our average lateral length in 2020 had increased to 8751 feet.
Now through the end of 2021, we have successfully drilled and completed 415000 foot laterals.
With two drilled to the Haynesville and two drilled into the Bossier.
2021, our average lateral length increased to 8800 feet.
Our record longest lateral to date is 15155 feet and was drilled and completed in the Haynesville in late 2021.
Building on the success of our 15000 foot laterals, we now anticipate our average lateral length to increase by 19% in 2022 up to 10484 feet.
In 2022, we anticipate drilling.
Approximately 21 wells with laterals longer than 11000 feet, none of these being 15000 foot laterals.
Continuing to execute our long lateral strategy.
We will be better able to maintain our low cost structure.
The higher price environment.
On slide 14, we highlight the improvement in our drilling performance, which is based on the total footage drilled but.
The number of days from spud to TD.
Our drilling performance was relatively stable from 2017 through 2019 in the 700 foot per day range.
'twenty, our drilling performance improved 15% to 800 feet a day.
2021, our drilling performance improved an additional 25% to just over 1000 feet per day.
While our record fastest well to date, we drilled last year at an average rate of 1461 for you today.
The performance improvements have been achieved via drilling the longer laterals combined with sounds rolling practices include tool reliability and execution at the field level.
With our goal of drilling longer laterals in future years, we expect to maintain our drilling performance at a very high level.
Yes.
On slide 15 is our updated D&C costs, three and four benchmark long lateral wells.
These are wells with an average lateral length greater than with a lateral greater than 8000 feet.
Our D&C cost averaged $1027 a foot in the fourth quarter, which is a 2% decrease compared to the third quarter.
And flat compared to our full year 2020 D&C cost.
Breaking this down our drilling costs remained essentially unchanged for the quarter at $413 a foot, while our completion costs were down 4% quarter.
Quarter over quarter to $615 a foot.
In spite of the higher service costs, we began to experience during the last quarter.
We were still able to achieve slightly lower D&C cost due to improved operational performance and improved capital efficiency associated with the longer average lateral length that we drilled during the quarter.
Our average lateral length for the quarter was 11443 feet. This is the longest quarterly average lateral length, we've achieved to date.
And was accomplished.
Primarily due to the completion of our first 215000 foot laterals.
That were turned to sales during the fourth quarter.
The higher capital efficiencies associated with the longer laterals allowed us to offset the impact of the higher service cost during the quarter.
While we do continue to see service cost.
Further increase into this year, our ability to execute on the longer laterals with more robust economics will help cushion to partially offset the negative effects of the higher power service call.
On slide 16 is a map outlining our fourth quarter well activity.
Since the last call, we have completed and signed 16, new wells to sales.
The wells were drilled with lateral lengths ranging from 8504 feet to 15155 feet with an average lateral with 10500 AC.
The wells were tested at IP rates that ranged from $12 million up to 48 million a day.
With a 23 million cubic feet per day average IP.
The results. This quarter include our first two planned 15000 foot Haynesville laterals.
<unk> $32 29 to <unk>.
HC number one and number two wells.
These wells were completed with laterals were $14 685 feet and 15155 feet.
And tested at rates of $41 million and 48 million cubic feet a day.
The seven wells with a lower IP rates are in canola county in the liquids rich area of the Haynesville.
The high Btu gas in this area will generate a yield of 25% to 40 barrels plant products.
This will enhance the economics from a dry gas well with similar production about 20% to 30%.
Also during the quarter, we successfully drilled two additional 15000 foot laterals into the Bowser as mentioned earlier these two wells.
We turned to sales late last night, and we will be reporting on those on the next call.
Regarding activity levels, we did finish out 2021, running five rigs and three frac crews.
We're in the process now of adding two rigs increasing our rig count to seven who will remain at the seven.
Seven rig count throughout the remainder of this year.
We plan to continue running three fulltime frac crews throughout the rest of the year.
On slide 17. This is a detail of the 2021 drilling inventory.
The drilling inventory is split between the Haynesville and Bossier locations divided into four categories.
Our short laterals up to 5000 feet medium laterals that 5000 to 8000 feet.
Our long laterals at eight <unk>.
11000 feet and we've got a knee.
Strong category now for the wells beyond 11000 feet.
Our total operated inventory currently stands at 1984 gross locations.
420, net locations, which represents 72% average working interest across the operated inventory.
Based on our.
Our non operated inventory currently stands at 1425 gross locations and 213 net locations and this represents a 15% average working interest across the non operated inventory.
Based on the recent success of our new.
Extra long lateral wells, we've modified the drilling inventory to take advantage of our acreage position and where possible we have extended our future laterals out further to the 10000 to 15000 foot range.
And our new extra long lateral bucket, we capture all our wells that now extend beyond 11000 feet long.
And in this bucket. We currently have 397 gross operated locations and 287 net operated locations.
These are split 50 50 between the Haynesville and the Bossier.
So to recap our total gross inventory, we have 436 short laterals 392 medium laterals 750 mile long laterals.
Now 397 extra long laterals.
The total gross operated inventory has split 53% in the Haynesville and 47% in the Bossier.
Also by extending our laterals, we had increased the average lateral length in the inventory from 6840 feet.
Now up to 8520 feet, which is a 25% increase.
And in addition to the uplift in our economics, the longer laterals will help to reduce our surface footprint on future activity and also further reduce our.
Greenhouse gas and methane intensity levels.
In summary, our current inventory provides us with over 25 years of future drilling locations based on our planned 2020 to activity levels.
With our ability to execute on the new ultra long laterals are drilling economics or more robust.
And it enhances the value of our acreage position.
I'm going to turn it now back over to Jay to summarize the outlook for 2022.
Well like we said earlier, our drilling inventory, which Dan just said.
It is a holy Grail of E&P companies has never been more valuable is stronger than it is today. If you go to slide 18, I'll direct you to kind of the summary.
For our outlook for 2022, we expect.
2022 drilling program to generate.
4% to 5% production growth year over year.
We would expect to generate in excess of $500 million of free cash flow at current commodity prices.
In 2022, the lateral length of the wells in this year's program is expected to be 19% longer than the 2021 wells. The additional investments, we're making this year and our drilling program will pay off in the future years as a lateral length per well will have a lower <expletive> .
Client rate than the shorter laterals and 2022, our operating plan is focused on repaying $479 million of debt, including redeeming. Our 2025 senior notes, we continue to have an industry, leading low cost structure.
It gives us best in class drilling returns we are working on the certification of our natural gas production has responsibly sourced gas under the <unk> standard.
At the end of 2021 will hit financial liquidity of almost $1 2 billion, which is expected to increase further in 2022.
We repaid the remaining borrowings outstanding on our bank facility. So Ron I will turn it over to you to give some guidance for the rest of the year.
Thanks, Jamie on Slide 19, we provide the financial guidance as.
As shown on the slide first quarter production guidance of $1 two four to one nine Bcf a day and the full year guidance is $1 39 to 145 Bcf a day.
During the first quarter, we only plan to turn to sales about 15% of the planned.
To be turned to sales for the year and those wells have a little bit lower working interest than the wells later in the year.
As a result, the majority of our of our wells turned to sales and production growth are expected to occur during the second and third quarters of this year.
The development Capex guidance is $750 million to $800 million, which is based on a similar number of turned to sales wells as last year and.
Incorporates an expected 10% increase in service costs and the impact of.
Our average lateral lengths being 19% longer this year.
As a result.
If you.
You factor in the 10% inflation in the 19% longer laterals to the midpoint of our guidance would actually represent about 3% to 5% of an improvement in inefficiencies.
Mostly related to the longer laterals, we've also budgeted for $8 million to $12 million of additional leasing costs.
Our LOE.
Expected to average 20% to 25 in the first quarter and 18 to 22.
For the full year, while our gathering and transportation costs are expected to average 23 to 27 in the first quarter and $24 28 for the year.
Production and AD valorem taxes expected to average 10 to 14 since here.
Based on current price outlook.
Our DD&A rate is expected to average 90% to 96 per Mcf.
Cash G&A is expected to total.
$7 million to $8 million in the first quarter and 29% to $32 million.
In <unk>.
2022, with noncash G&A expected to average almost $2 million a quarter cash interest is expected to come in around 38% to $45 million in the first quarter and $152 million to $162 million $160 million 2022.
That incorporates the planned redemption of of our 2025 notes.
Later this year.
From a tax standpoint.
The effective tax rate guidance of 22% to 27%.
Is it in line with where we've what we've been reporting and going forward, we expect to.
Defer 90% to 95% as taxes with the cash taxes being.
Related to state taxes, I'll now turn the call back over to the operator for the Q&A session.
As a reminder to ask a question you will need to press star one on your telephone again Thats Star one.
Touchstone telephone to ask a question to withdraw your question press the pound key.
Standby, while we compile the Q&A roster.
Okay.
Our first question comes from the line.
Eric Whitfield of Stifel. Your line is open.
Thanks, and good morning all.
Good morning.
With my first question I wanted to focus on the outputs of your 2022 plan and your confidence in executing against it when we analyze the balance of the year for Comstock to set up certainly seems positive to us based on potential positive production revisions in the institution and a return of capital program.
And specifically on production year 2022 production plan on average appears to be outpacing consensus estimates by about 2% for the balance of the year after adjusting for Q.
Q1 guidance with that said and with your activity being more steady state relative to past years could you speak to your confidence in executing against this in light of the tighter labor and service price environment.
Yes, Hi, this is Dan so we.
We're fairly confident we can execute the way that we've got it planned.
We kind of factor our scheduling based on the most recent cadence that we've been at and we've had a little bit of that.
Kind of already built into the numbers at the end of last year.
So we we foresee that to be kind of at the same pace going into this year. So I'd say, yes.
We feel pretty strongly we can execute the way we've got it laid out this year.
Great and for my follow.
We did have a few hiccups.
During the weather a week or so ago.
Hauling sand and some driver issues.
We've seen that but I don't think its impacted Dan it hasn't impacted the overall.
Kind of schedule, we did start seeing a little bit of it in the fourth quarter was kind of spotty.
And we've kind of got that built into our scheduling and our dates so basically just based on that latest.
Level of.
Cadence there I mean, thats kind of what we see for the rest of this year.
Obviously, if something changes, we'll have to go back and revisit.
<unk>.
Scheduling and dates are a little bit.
I think the key is we do have our drilling contractors lined up we do have.
Service companies lined up.
So it is derisked as best you guys can't at this point it seems and then for Mike.
My follow up I wanted to focus on return on capital.
After achieving your targeted one five.
<unk> times net debt to EBITDA leverage ratio later this year.
Could you speak to your near term and long term views on return of capital and now the near term could take form later this year.
Sure Derrick that's a good question and obviously.
Front and center as that is the first achieve our debt reduction goal, which as we have.
Yes.
$479 million of pre payable debt and we think that.
That will be achieved first and then after that we do.
See additional free cash flow.
The company would be generating later in the year.
We are still evolving and our return of capital theory, and we obviously have a majority stockholder to to consult with but I think.
I think our first goal will be to establish a sustainable dividend.
Had one in 2014.
Excited to put that back in place and.
So as this year progresses and we.
See that where gas prices land very volatile first quarter, so far with gas prices.
Yes.
The right time to put that dividend and debt reduction target.
<unk> first and achieving net leverage ratio happens first but.
And that after after establishing a base dividend I think.
Again, I think we could change our mind, but I think we'd like to have a share repurchase authorization in place.
Sure.
And.
That is another supplement to the return of capital.
And I think the beauty is we've had a dividend before so it is not something new.
We had to remove it we did remove it.
So to.
To tell you that we should have board discussions.
Because our leverage ratio will allow us to open those discussions up to talk about this I mean, that's a beautiful thing to talk about.
I think we will be there more sooner than later.
And remember the joneses owned 60% to 65% of the company so.
They're very interested in having the stock perform properly.
So I think when we weigh a dividend.
Is that what the market is looking for that guaranteed yield.
So we'll assess all of that and we'll make a good decision.
And we've laid the groundwork with our.
Bond Refinancings, we did we've laid the groundwork for this strategy as we go forward.
I think it's all in place and placed in our our debt instruments are <unk>.
<unk> to the rating agencies commitments to the bondholders I mean I think we.
And we want to have a very balanced approach, but we've laid the groundwork for a return of capital program hopefully that we get to initiate this year.
That's great very helpful. Thanks for your time.
Thank you. Our next question comes from Charles Meade of Johnson Rice. Your line is open.
Good morning, Jay do you and your whole team there.
Good morning always good to hear from you.
Yeah, Jay I think we got some of the detail from Dan on this.
On.
When youre going to add rigs I think what I heard is that you are on the.
In the process of adding two rigs right now.
And I'm curious about how what the implications are for how your.
How your production is going to progress over the year I think Ron mentioned that <unk> and <unk>, we're going to be the big.
We're going to be the big growth quarters, but can you tell us how how should we think about.
How you're bringing those rigs on when they're going to be contributing production and what the shape of the year. It looks like we have.
<unk> at first quarter production plant and it is really just lower well completions number of completions and Robert talked about that.
You had mentioned, it's really before growing our production in the second quarter and third quarter 2022, and I think from there on out will have some pretty predictable growth.
Charles we are in a transition.
From the shorter laterals to the longer laterals.
All oriented we're in like the six month transition and it takes a while like we said in the fourth quarter. Our average lateral length was over 11000 foot and thats, because we drilled those 415000 foot lateral wells and I know Dan script. He didn't know we returned to sales of two Bossier wells. So he changed his script, but.
We did term note sales by less not early this morning, but it takes a little longer but it's certainly more efficient.
On the dollar spent.
Think as you see in the quarters to come if we can abate this decline curve from 40% at the <unk>.
That's going to help that's going to help with our Harvey yield thats going to help with our model.
And it's going to it's going to it's going to lower our costs. So we will have the six rig is here will have a seventh rig.
And we've got a drilling schedule little intellectually I think.
We complete two extra wells this year.
<unk>, where we were in 2021, but it's just a pure transition to a more cost efficient way.
That we think will generate more free cash flow and again I think if you go to that.
If look at the basin oriented.
<unk> principal we're in we're not we're not.
Not condensed into a small area.
We can spread out into Texas, and Louisiana with distributor program.
And that's why I think youre going to see is while we've added all these these laterals.
Even in the diversified property that we bought if you look at where our existing footprint was we extended laterals.
So the existing locations 44 of those were extended.
<unk> acreage that we added.
Thank you guys see some more of that alright, a couple of comments to that specifically I think we do have.
The seven rigs operating right now, but one thing we'd normally when you think about rigs we do it.
At least half of one of those rigs will be used for our contract drilling services, which really don't have that in effect. Our budget. So I would say, we're really six five rig to deliver our budget. The other half will be due in work.
That's not in our budget.
And.
So I think that's how I view it but I think the production is more weighted to the second half of the year. There is this kind of a six month transition period.
I think when you go longer term I think that the longer laterals. So we do see.
Right now if we keep it the same activity level.
And 23 have at higher production growth than kind of the rate. We're on now that's going to be the benefit of <unk>.
Go into these longer laterals.
And the timeframe the other thing thats kind of extending the production timeframe on these wells is the practice.
Completing more than two wells at a time and we typically we always want to complete at least two wells, but there are a lot of projects where in order to minimize shut.
Shut in activity that you have to have for that group.
Grouping multiple pads and that also does create delays production coming on and I think Thats also kind of incorporated theres more of that in this year's plan than in the previous years, where we may have five wells seven wells multiple multiples more than two.
Yes.
Coming online at the same time as we do multiple pads together to minimize shut in time.
And Charles I think if you look at our growth chart.
Youll see second and third quarter fourth quarter, I mean production goes pretty substantially in <unk>.
If you look at the 2022 program, where we had 13 wells.
That have laterals greater than 11000 feet and half of those.
15000 foot lateral so we have put those into we floated those in but I think you're going to see first quarter. It will be lower within second third and fourth quarter will continue to grow and Youll see that as Rolla mentioned into 2023 will hit.
<unk> two is the norm of drilling longer lateral wells and completing them.
Got it.
It's helpful detail, particularly about the about the contract drilling piece Jay I wanted to go back to you mentioned those 215000 foot Bossier wells and I recognize we're just not only in the early days in the early hours here on how those wells are performing but I wonder if you could just share anything more about about.
About what the drilling and completion with like for those and particularly I am curious.
Do you do you have any sense.
Whether you are actually really able to effectively stimulate all the way out to the toe or are you are you, reaching some kind of technical limit there yes.
Yes, let me I want to comment and I'll turn it over to Dan, but if you remember we've got.
3% of our locations were Haynesville and then the rest of the Bossier and what we chose to do trials, we chose to say instead of drilling for 15000 foot Haynesville Institute to Haynesville to budge.
So we did the two haynesville and as you know I mean.
The $80 million to $89 million a day for both of them I think is 48% and 41 so.
We've got two great wells, there and then I think on the Bossier.
Remember we go back into the.
Probably December 2015.
One of the first companies to drill a bossier. There was there was really successful and kind of started disclosure drilling you can ask Ian to goes the world et cetera, where labour here I mean, they looked at that will so we have drilled a bunch of <unk> before so Dan was confident that we should drill. These proposed rules so daniel to comment on those and I did turned to sales.
And we expect it to be really good wells, but they did turn to sales by less not this morning.
I'll just add that we did.
415, K laterals that we drilled on average the mozer's drill a little bit faster than we did drill the fastest for those four wells.
One of these Bossier wells, we drilled it to TD and 29 five days. So that's that's pretty pretty strong performance there.
Sorry for asking him out to TD.
Same as the 10-K, we didn't have any issues on these two bossier wells.
Drilling out all the plugs got all the way out to the end of the laterals with no issues. So.
That's when you start out the first few wells always have a few hiccups could you give a little better from there and we certainly expect that to happen on our.
Future 15000 foot laterals will get a little bit faster and a little more efficient.
Thank you for the color.
Thank you.
Thank you. Our next question comes from New Dingman of true Security. Your line is open.
Good morning, guys can you just follow on what you were saying just on the <unk> 16 outlines all youre Bossier opportunities I'm just wondering how you all think maybe in broad terms. Our average terms how you think about the overall economics on some of the just say your core Bossier area versus the Haynesville.
So the economics of the Bossier wells.
We're going to get a little bit more like the east, Texas Wells will get a little bit lower Ips on the boilers with a little bit flatter decline rates.
The economics of the Haynesville.
Basically where we drill in the we're always going to be better than the than the Bossier is just across the inventory.
But.
I'll go into the <unk>.
The economics Youre looking at.
If you just kind of look at a set gas for us.
<unk>.
We ran these back before the lower gas process, but an average 7500 foot lateral versus a 15 K with just kind of how we look at the wells that we're drilling either drill one or the other.
Youre looking at 100% rate of return on a 15 day, well and Youre looking at something Thats closer down to 60 or 70% return of 7500 foot lateral.
And we expect to get better with these 15 days, we saw what happened with the 10-K's and so we've already outlined several things where we.
Where we know we can make some improvements.
The almost 15 days.
So that was just going to ask for my follow up you guys. Certainly are getting some better returns just on overall not just as you said, Belgium on haynesville longer laterals I'm. Just wondering could you talk about the improvements you'll continue to see is it just purely the longer laterals or are there some improvements on even completions that are part of this upside in <unk>.
I just had a good job of sort of showing us that per foot upside that you're seeing and I'm. Just wondering is it purely because longer laterals or what else is driving that.
The drilling those early performance is basically across all of the laterals.
The better drilling practices.
Some of that is the better tool reliability from our vendors.
As all of the laterals, regardless of link, but it becomes more profound when you start drilling the longer laterals do you get a bigger bang for the Buck from those things.
So.
I can't remember what your second part of your question was.
No that was it I just didn't know besides longer laterals, if theres things and complete on the completion side that youre doing that certainly on returns and returns on a per foot are improving I didn't know if there are other things completion speaking.
Driving these returns as well so the completion side is just an efficiency gained from getting.
Getting longer.
That's a little bit more kind of just a ratio.
I think on the drilling side, we're probably seeing a little bit better gains.
The Fracs is just basically the performance of our Frac crews.
Certainly expect to get an uplift when we go to our natural gas fleet in April we expect to see a little bit better performance there.
Our stages and clusters have been pretty consistent.
So we've been pretty we've been pretty much at about the same performance level on the Frac side stages per day like Jay mentioned.
We've definitely seen probably a bigger pickup on the drilling side just to kind of recap recap that answer.
Got it thank you guys great details.
Thank you. Our next question comes from Leo Mariani of Keybanc. Please go ahead.
Hey, guys just wanted to get a sense of what your appetite is these days on the M&A side, obviously you've done.
Some deals over the last several years to really kind of increase the size of the company and the inventory and what do you think kind of the outlook is these days are there other haynesville properties out there how do you think might be a good fit for Comstock.
We.
We're always ask are we looking outside the basin and the answer is no. So I get rid of about 90% of the whole world there and I think that within the basin Leo as you know.
Most of the Haynesville producers have been have been consolidated.
<unk> got.
<unk> got two out there.
We're still kind of lingering.
I understand one of them may be for sale right now.
But I think I think we do shop, all the time I think <unk> got a shop in order to be a compulsion bar.
We do shop, we look.
As of right now I think our 2022 2023 plan is continue to add incremental valuable acreage around.
Our existing footprint.
That will enhance our laterals. So we don't we don't really see a lot of activity on the M&A front at all.
Okay. That's helpful.
And there's certainly been a fair bit of discussion on this topic, but.
If I just kind of take.
High level look at some of the changes in the <unk> program versus 21, it looks like the number of wells are turning to sales is roughly the same but you are getting kind of 19% more lateral feet. This year, so certainly a pretty big step up in fee.
Pleated here, but let me just kind of overall look at the production growth.
I'll call it 45% this year, it's a little bit lower than it was last year. When you guys look at that do you really think this is mostly just.
Timing issue and really the benefit here is 23 I know we talked about this a little bit just wanted to kind of clarify that yes, thats a great question and I do think it's a timing issue because I do think that we get to 'twenty three you kind of see.
A similar growth rate of 21.
I think I think it's the <unk>.
<unk> transitioned to the longer laterals.
That timeframe also kind of not running consistent number of rigs during.
And we're not running as many rigs in the fourth quarter, obviously, I think that a lot of that is all timing I think this year with a more consistent program.
That's starting it out here.
Towards the end of the first quarter.
And maintaining that through 'twenty, three you'll see more consistent growth.
Doing a lot more long laterals.
Allstate will reap the benefits from these longer laterals.
Especially in the second half of this year and then all of next year.
And then you with hopefully a little bit lower decline profile from the longer laterals, which they provide.
You don't have to invest as much.
So you create that capital efficiencies, but it takes a while to show up in the numbers.
I think again, you look at the inventory I mean.
Got really impactful inventory you look at our margins they've been really high.
Look at the operations group, I mean euro per year per year.
They delivered stellar performance you do more from 5000 foot laterals to set a photo puts a 10000 foot to 15000 foot.
As Dan has said and I think our efficiency, which is our operational efficiency.
Very predictable I do think there is some pain for six months and transitioning to.
These longer laterals would certainly be worth it.
Yes, no that's helpful and maybe just lastly, if you guys can you talk about kind of the the outlook that you expect for Haynesville.
Price differentials here, obviously, there was a little bit of noise. There in the fourth quarter, we bid week versus spot, but maybe just kind of going forward here in 'twenty two.
Give us a sense of what type of differential youll see for Comstock in any basin dynamics discussed.
We've seen real stability in our differentials because we've taken a lot of steps to protect that including locking that and with longer term sales contracts and even <unk> been.
Putting at a basis hedge there so it really that wasn't that noise at all that's why we tried to show the real noise was mid week versus the spot price, which we haven't experienced that.
I don't think it a long time and the overall gas market.
I mean, it was very very.
Very volatile in the fourth quarter and the difference between those was found dramatic.
It creates a large differential it's easy to.
Type model those separately and I think generally yes.
70% of our gas is going to be tied to that contract price and 30% is tied to the spot price. Both prices are available and you don't need to assume it's 100% either way because it can't be.
It's impossible to go 100% in the index market you have to deliver that gas.
That is you just haven't seen that as being important to separate in the past because there hasnt been a very big difference between those two numbers.
January and I look at the first quarter January you didn't see a big difference between those two numbers, but February dramatic difference you had the contract close at a.
At $6 26, a very high number immediately spot market was lower than that.
So.
We don't know how that progresses this year, but obviously you're going to be some of that in the first quarter to keep an eye on and see what happens to March.
Also see February spot market can catch up to that contract price. It would be nice got a little ways to go to do it.
Okay. Thank you guys. Thanks.
Thank you Leo.
Okay.
Thank you. Our next question comes from Fernando Zavala, Pickering Energy Partners. Your line is open.
Hey, good morning, and thanks for the time.
I was wondering if you could give some numbers around base decline trends in 10 year and 'twenty two and beyond.
Relative to 2020 insulin <unk>, one with obviously the tailwind as longer laterals hitting into year end 'twenty two and beyond.
You cut out a little bit was the very beginning part of the question that Youre asking.
Yes, if you can give some numbers around base decline trends into yearend 2002 and 2023.
In terms of base decline.
Currently I think Jay referenced kind of.
Right around 40% 40 plus percent.
Over time as you as we transition to those longer laterals.
That should have a positive effect on that decline rate with the shorter lateral wells.
When you think about bringing them on and the way you manage the managed pressure flow back.
Kind of take into account, maybe a flattish declined for five or six months on the longer laterals, you expect that to be.
Nine to 10 months and depending on either the longer lateral longest laterals could be up to up to 12 months. So over time as you get more of those wells in your production base that corporate decline rate should.
Should start moving down I don't know if it had in 2022 has that much of an impact that should start to show up in 'twenty, three and even to probably a greater extent in 'twenty four but.
The benefit of that is if you can go from call it 40% too.
The mid <unk>.
That has a dramatic impact on maintenance capital requirements going forward and it just really makes your whole program a lot more efficient, yes, and if you step back if we were predominantly 5000 foot laterals.
We would have to be talking about in excess of 50% base decline rate and I think you saw that you see some of that.
Other operators in the Haynesville have that lateral length is the major difference.
Between what we even have now and versus higher decline rates.
It's all of the lateral length is the major difference.
Yes in that.
Yes, I think if you again drove these long laterals for a while as Ron said, you don't have to spend as much capital.
To grow your production, 4% because you don't have a steeper decline that's the goal.
Alright Thats helpful. Thank you and I guess that goes to.
My follow up question.
How you all are thinking about activity in spending balances in 'twenty three is like you said.
The benefits of the longer lateral is start showing up in 2023. So.
Are you do you have options right to scaled back.
Activity and stay within that 4% to 5% growth just how you all are thinking about that.
But it's kind of early for us to think about it but I mean, I think yes, I think if we don't pull.
Pullback.
We'll have <unk>.
The numbers would tell us we should have higher growth rate in 'twenty three if we stay at a constant level well target.
Free cash flow, what how do we maximize free cash flow generation, how do we maximize overall results what is the basin takeaway whats the pressure on the gas market. There is a lot of factors.
We're in a more unique basin, then maybe Appalachia, so yeah a lot of that.
What we really have to get closer in to see how this year progresses.
I've got a 2020, it's very too I mean kind of to your point, we don't have this $479 million of shorter term debt that we can pay off so.
Free cash flow number we're going to have a lot of.
Excess free cash flow over and above.
Whatever our Capex budget would be so 2023 will be a huge turning point for the company, but I think it starts in 2022.
Got it thanks guys.
Thank you. Our next question comes from Ray Deacon of Pet.
Petro Lotus go ahead.
Hey, good morning, Jay enrollment and Ron.
I had a question.
Had a quick question for Dan, which is if I were to look at the inventory number now and assume that.
This is the right assumption that most of those wells will be drilled 20% longer versus what you have shown there and would that reduce the amount of inventory in terms of number of wells.
By 20%.
I think we've actually yes, the new <unk>.
Inventory chart, we provide here.
And this is really actually reflects a lot of re mapping bad I mean, there will be a constant.
Interest in re mapping.
Yes, both through acreage trades, we've got I.
I think.
Other major everybody likes the longer laterals in the basin.
No.
As that now some of this consolidation has occurred there is a refocus now engaging with adjacent operators on acreage trades. So.
So we hope to continue to do that so yes, there'll be more re mapping to come but.
What we are presenting now is kind of a result of.
Re mapping a lot and changing the lateral length and change about 25% is a very dramatic difference from that inventory you saw before well I think and I was looking back at the numbers. If you. If you look at we have.
1633 net locations in.
Those that are greater than 8000 foot laterals, it's 902 of them and if you start at the end of last year is that we've said that there were 745 today, it's 902.
<unk> point.
That said re mapping and.
The diversified that we bought et cetera et cetera.
Swapping acreage with some.
Continuous contiguous offset operators.
That's the right math last year, and we plan on trying to do more of that because it's.
It's a win win for both both companies.
Got it got it.
Have you have you decided already where the two incremental rigs will go at the end of this.
This quarter.
Yes right.
The first.
The six rig basically spud its first well yesterday.
And we will be the seventh rig will be spud its first well probably late next week and we got both of those rigs are going to work in our Logansport area.
Okay got it got it.
Just.
One last question on <unk>.
Realizations, if you if you were to.
I know <unk> has the sales process on those for the significant additions to the rig count in the Haynesville do you think that differentials.
We would have.
Narrowed a bit if you hadn't had this big recent increase in activity is that does that.
Sure.
I think youre talking about.
Perry will Carthage differentials, I mean that rate differentials.
They were they did widen in the fourth quarter again, we just we only add like 10% of our sales subject to it because we can.
Kind of planned for that we've moved a lot of gas away from <unk>.
It is no longer our dominant index.
Index.
Yes, I think if you're an operator, that's 100% tied to that.
Yes, you should probably plan on higher differentials, but we're going to be so we're not going to be that tied to that end in 2022, when the Acadia and went into operation in December .
Big shift in the majority of our gas is sold at the Gulf Coast indexes, which they don't they 10 days stay tighter to Henry hub.
And then the gas that we can actually put it into the Gulf Coast indexes, we've really taken a lot of protective measures to try to lock in that differential close to that 25% number.
And not not.
Have too much gas exposed to.
A wider differential in those markets relative to the.
Katy and deal with the enterprise that was negotiated in 2018 early 19 and it came on in December of 'twenty, one so yes.
That's going to help.
Mitigate.
And you didn't see it much in 'twenty, one because it was only one month, but it definitely has probably helped us in the fourth quarter, a little bit with December and Youre going to see it help keep that differential from having.
Bye now.
No.
Yes in 'twenty two.
<unk>.
Different factors looking at the index price versus the spot price that's totally unrelated to that that's just the rig.
The rig count.
One step out for your question when we plan to drill these wells I mean, we look at the marketing side to make sure we don't have any takeaway issues.
Because in Appalachia, you do have a takeaway issue we haven't seen that.
When we plan these wells 2022 'twenty three we looked in advance on that.
Right.
My queue realization helped you at all in those in terms of realizations or lower gathering fees do you get access to different markets.
Well you hope to in the future I mean, I think that I think.
That's <unk>.
As we're able to.
Find purchasers that wanted to give us credit for that I would say, we don't have that now and maybe in our region right. Now are there more just didn't price, but as we are.
With the direct access to <unk> and being able to sell directly to LNG.
To the extent they have customers that want to lock in to responsibly source gas.
Yes, we have that mechanism will have that mechanism in place hopefully mid year.
And in 'twenty two.
So we're ready to that.
That could be the case, but.
We will see but I think that flexibility really will be valuable.
Got it that's great and just I guess one.
Last one I'm asking too many questions, but the breakdown of Bossier versus Haynesville.
Haynesville in 2022 et cetera is there much of a change versus 21.
So the write down in 2022 is going to be pretty similar to what we had in 2021.
Got it.
And the handling.
Yes, just a handful.
Okay got it.
Thank you at this time I would like to turn the call back over to Jay Allison for closing remarks, Sir.
Again, I want to thank everybody for.
For staying on from the beginning to advance the conference call then.
I guess I would close if you just took it the fundamentals of the dry natural gas.
The market, we don't think they've ever been stronger.
Particularly in the footprint that we're at and the reason we say that is this demand now is on a global basis due to the LNG export facilities.
That are near our Haynesville Bossier basis in our footprint so.
We're a pure play we plan on playing in.
Trying to reduce our cost extend our laterals and deliver the results 22 should be a watershed year of 'twenty three should be incredible.
Our inventory is strong so again, we thank you for your support.
And this concludes today's conference call. Thank you for participating you may now disconnect.
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