Q3 2021 Comstock Resources Inc Earnings Call
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Today's conference is scheduled to begin shortly please continue to standby. Thank you for your patience.
[music].
Yeah.
Good day, Thank you for standing by and welcome to the Q3 2021 at Comstock Resources, Inc. Earnings Conference call. At this time, all participants are in a listen only mode. After the speaker's presentation. There will be a question and answer session to ask a question Juergen.
That session you will need to press star one on your telephone keypad. If you require any further assistance. Please press star zero.
I would now like to hand, the conference over to your Speaker today, Mr. Jay Allison Chairman and CEO the floor is yours.
Thank you. Thank you.
Every once in a rainy outside in Frisco, Texas.
Guess winters into years coming our way you know what a great time.
To be at the natural gas business, especially in.
In the Haynesville well want to have a couple of clarifying statements before we start the actual third quarter 2021 results.
With our Bakken properties of the contract for that $154 million, which most of you are aware of and closing expected in the coming weeks.
We did pre announced that we would accelerate completion activity towards the nine four net haynesville wells this year to bring those volumes forward.
To encourage strong prosecute Barbara for natural gas the <unk>.
Increased production from those wells really will appear in the first quarter of 2022.
Now I thought it would be a good time to talk about the direction of the company.
The direction of Comstock is to continue to focus on capital efficiency in the Haynesville.
And generation of free cash flow.
Specifically over the next several quarters, we plan to use that free cash flow to pay off our credit facility.
To retire the seven and a half bonds in May of 2022, then.
With our debt reduction goals are met we want to establish shareholder dividend.
So with that opening statements I don't want to go back on and welcome everybody to the Comstock resources third 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 Dot Gunstock resources dotcom and downloading the quarterly results presentations.
There, you'll find a presentation entitled third quarter 2021 results.
Jay Allison Chief Executive Officer, Comstock with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Martin Mills, our VP of finance and Investor Relations, if you'll flip over plus 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. The highlights. This is a slide three the third quarter 2021 highlights would cover the highlights.
The third quarter, one in slide three.
And the third quarter.
We generated $84 million of free cash flow after paying preferred dividends and increasing our year to date free cash flow generation to $137 million.
Given the strong outlook for natural gas prices, we now expect to significantly exceed our original annual free cash flow generation goal of over $200 million for the quarter. We reported adjusted net income of $91 million or 34 cents per diluted share our production increase.
25% in the quarter to $1 424, Bcf, a day and was 98% natural gas revenues, including realized hedging losses increased 86% to $394 million, our adjusted EBITDAX in the third quarter grew by 109%.
To $309 billion operating cash flow for the quarter was $225 million or <unk> 92 cents per diluted share and again, we announced the sale of our Boston properties for $154 million, we expect to close the divestiture in the next several weeks.
We're using a portion of the proceeds from that sale to accelerate completion of this $9 forward net drilled uncompleted wells.
<unk> from the stronger winter pricing.
We've now started completion operations, those wells, which Dan will go over with in a minute. The big completed by year end with production January of next year and we recently engaged in my Q to initiate the independent certification of our natural gas production under the Mou methane standard Dan will also cover that.
In his part of the presentation. If you flip to slide four we cover our announcement to sell the bulk of the assets on slide four.
We recently announced that we are selling our non operated Bakken shale properties to northern oil and gas for $154 million.
Assets sold include interest and 442 or 68, three net well bores.
June 30 at the proved reserves associated with the properties totaled $10 8 million barrels of oil at $44 2 billion cubic feet of natural gas, we expect to close that transaction. Several weeks I'll now turn it over Roland Burns our CFO to cover the.
Third quarter 2021 financial results Roland.
Thanks Jay.
On slide five we summarize our financial results for the third quarter of 2021, we had a very strong quarter, which was driven by that 25% production increase combined with substantial improved oil and gas prices. Our production in the third quarter totaled 129 Bcf of natural gas 346000 barrels of.
Oil.
That was 25% higher than the third quarter of 2020, and its 4% higher than what we were producing in the second quarter of this year.
Our oil and gas sales, including the losses that we realized from our hedges increased by 86% to $394 million in the third quarter.
Our oil prices in the quarter averaged $58 58 sets and our gas price averaged $2 96 per Mcf.
That's after the impact of our hedges.
Our realized hedge natural gas price in the quarter was 49% higher than the third quarter of last year.
Our production costs.
I'll say it were up 36% in the quarter, reflecting the higher production level.
Combined also with higher production taxes, resulting from the stronger prices that we realized.
Our G&A, though it was down 10% at our depreciation depletion and amortization was up 30% in the quarter.
Adjusted EBITDAX came in at $309 million, that's 109% higher than the third quarter of 2020.
Our operating cash flow that we generated was $255 million, 174% higher than the third quarter of last year.
We did report a net loss of $293 million in the quarter or $1 26 per share, but that was all due to the very large mark to market loss on our hedge contracts of $393 million.
That resulted from the surge in oil and gas futures prices since the end of the second quarter.
Adjusted net income excluding.
The unrealized hedging losses and certain other unusual items was actually a profit.
$96 million or <unk> 34 per diluted share.
On slide six we summarize the results for the first nine months of this year.
Production for the first nine months averaged three 372.5 Bcf a day, which is 7% higher than the same period in 2020.
Oil and gas sales, including realized hedging losses for $1 $1 billion, 47% higher than the same period last year.
Oil prices were at 36% higher at $54 24 per barrel and our realized natural gas price averaged $2 72 per Mcf.
Both of those including the.
Effect of our hedges and that was 39% stronger than 2020.
Adjusted EBITDAX for this period.
As increased 61% to $823 million operating cash flow at 658 million has increased 80% from 2020.
For the first nine months. This year, we did report a $615 million loss or $2 66 per share again. This was due to two items the large mark to market loss on the hedge contracts.
And a charge for early retirement of debt related to our March and June refinancing transactions.
Adjusted net income excluding the unrealized hedging losses in the charge for early debt retirement, and other unusual items was $209 million profit or <unk> 80 per diluted share.
Yes.
On slide seven we cover our hedging program.
During the third quarter, we did have 70% of our gas volumes hedged, which did reduce our realized gas price to $2 90.
Per Mcf from the $3 79 per Mcf that we realize from selling our production.
We also had 40% of our oil volumes hedged, which reduced our oil price to that $58 58 per barrel versus the $66 11 that we received.
Our realized hedging losses in the quarter were $117 million.
For the remainder of the year, we have natural gas hedges covering 967 million cubic feet, a day, which is about 70% of our expected production in the fourth quarter.
58% of those hedges are priced swaps and then 42% our callers, which also gives us exposure to the higher prices.
For next year, we have approximately 50% of our expected production hedged.
But 46% of those 22 hedges or swaps.
And 54% or more than half, our collars, which give us exposure to the higher prices that we're seeing for next year.
I also want to point out that since the second quarter report, we've only added.
New hedge contracts covering 75 million a day of our gas production and those were in the form of white collars.
They had a $3 floor and they had a weighted average ceiling of $5 58 sets.
So these these positions are not out of the money is that some of the comments that you might have seen this morning are saying they do help us achieve the 50% requirement that we have to hedge our production.
Our bank credit facility now that requirement is going to melt away as our leverage falls below two so as we achieve our leverage goals next year will no longer be required to hedge our volumes.
Slide eight we summarize the shut in activity during the third quarter.
We had 80, what about 81 million a day or five 8% of our natural gas production shut in during the third quarter as compared to three 8% in the second quarter. The shut ins. This quarter were mainly due to the really high level of completion activity that we had both for our own activity and offset operators and yes. That's net.
<unk> order to protect the older wells when we when we frac a new well nearby.
On slide nine we detail our operating cost per Mcf.
Our operating cost averaged <unk> 60 in the third quarter.
<unk> hired in the second quarter rate. This increase is mostly due to higher production taxes coming from the higher oil and gas sales we had for the quarter.
Our gathering costs were <unk> 27.
The production and AD valorem taxes averaged 13 sets in the field level operating cost.
<unk> 'twenty.
Both the gathering and fill up our cost were fairly comparable to our second quarter rates.
Slide 10, we detail our corporate overhead cost per Mcf.
And our cash G&A cost per Mcf fee remained at a steady five cents per mcf in the third quarter.
Slide 11 shows the DD&A per Mcf, they produce that averaged 98 in the quarter.
<unk> <unk> higher than the 96 set rate we had in the second quarter.
Proceeding to slide 12, we kind of recap our balance sheet at the end of the third quarter we.
We had $525 million drawn on our revolving credit facility at the end of the quarter and we expect to use our free cash flow and proceeds from the Bakken sale to further pay down that balance during the rest of the year.
On October 22nd.
Our bank group reaffirmed our $1 $4 million borrowing base.
And right now we have just under $2 5 billion of senior notes outstanding comprised of the $244 million of the seven 5% senior notes due in 2025 125 billion of the.
Six and three quarter percent senior notes due in 2029 and $965 million of our new five and.
Five to 7% to 8% senior notes due in 2030, we currently plan as Jay mentioned to retire the 75% bonds next may.
With the free cash flow that we're generating.
The reduction in our debt and the growth in our EBITDAX. So far is driving a substantial improvement to our leverage ratio, which has now fallen to two three times. If you look at the third quarter on a standalone basis, we see this improving further over the next few quarters and we expect this to to get below one five.
Items in 2022.
At the end of the quarter, our financial liquidity has grown to over $1 billion.
On slide 13.
We give a recap of the third quarter capital expenditures.
In the third quarter, we spent $162 million on our development activities and 143 data that was on our Haynesville operated shale properties.
We drilled 13 or 11 seven net.
New operated Haynesville Wells and then we turn.
27% or 22, four net wells to sales in the third quarter.
We also spent about $90 million on non operated activity and other development activity.
In addition to funding our development program, we also spent $5 million.
Leasing.
New exploratory acreage.
We're currently running five operated rigs for our 2021 drilling program.
Plan to remain at that level for the rest of this year.
Okay.
Based on our current operating plan for this year, we expect to spend.
$590 to $630 million.
Which which will include drilling $52 five net operated Haynesville wells and then turning 54 four net operated wells to sales.
The increased spending from our earlier budget is related to the acceleration of the completion activity.
An additional nine four net drilled but uncompleted wells.
Accelerating this activity allows us to bring these wells on several months early versus our prior schedule, where completion activity was not going to begin on any of these wells until January 2022.
So this is being funded with part of the proceeds from our $154 million divestiture of the Bakken properties.
We are going to remain very focused on generating significant free cash flow.
For this year and as we look into 2022 and with the current gas prices, we anticipate significantly exceeding our original target of $200 million of free cash flow generation for this year.
That incremental free cash flow and proceeds from the Bakken sale will be used to also accelerate our deliberate delevering plans.
And now we're excited.
To be able to be on the verge of accomplishing those getting our debt down to a level that we think is.
Bright level for the company and having a leverage ratio. That's all set that right level. So I'll now turn it over to Dan to kind of report on operations in the quarter.
Thank you Roland.
Over on Slide 14. This is a map outline will show on the area of our most recent well activity.
We have completed 15, new wells since the time of our last call.
These wells were drilled with lateral lengths range from 4578 feet up to our hubs in sales and 530 feet.
The average lateral length being 7925 feet.
The wells tested at IP rates that ranged from 11 million a day up to 30 million a day with a 22 million a day average IP rate.
We currently have 13 additional wells.
<unk> been drilled at a rate that are waiting on completion.
Our activity levels. We are currently running five rigs and three frac crews our activities will remain steady at these levels through the end of the year.
While we expect the number of our ducks to further decrease by by year end.
Over on Slide 15 is the updated D&C cost trend for our benchmark long lateral wells. These include all of laterals that were drilled.
Greater than 8000 foot lateral links.
For the third quarter, our total D&C remained flat at $1051 a foot.
As compared to the second quarter.
And two.
<unk>, 2% higher than our full year 2020 D&C cost.
Our drilling cost in the third quarter increased by 5% to $410 a foot compared to the second quarter, but 10% below our drilling cost in 2020.
The quarter to quarter drilling cost increase was mainly attributable to rising pipe prices and a slightly lower drilling efficiency, we had due to lower average lateral length drilled in the third quarter.
Conversely, we experienced a slight quarter to quarter decrease of 3% and our completion costs.
The decrease resulted from a higher completion efficiency that was able to achieve during the third quarter.
As a result of the rapid increase in commodity prices during the third quarter, we have already experienced some increase in service costs.
Looking ahead to the fourth quarter and early next year, we anticipate a 10% average increase.
In service cost as the demand increases.
We plan to partially offset these higher service costs and increasing efficiencies by drilling longer laterals.
In September we successfully drilled cased and cemented $2 15000 foot laterals on the same pad, which we believe is the first in the basin.
Both laterals were drilled to the Haynesville formation in both of these wells are currently being completed.
We expect to have these wells turned to sale turned to sales by mid December.
We're also in the process of drilling two additional 15000 foot laterals in the Bossier formation.
We expect to be finished drilling these wells before year end and the wells will be completed during the first quarter of next year.
On slide 16, we will cover our recent agreement with <unk> key to initiate the certification.
Of our natural gas production in North, Louisiana, and East, Texas under the <unk> methane standard.
And Mark he will oversee an independent third party audit data assessment of methane emissions.
From our companywide gas production, which is primarily made up of our Haynesville and Bossier shale gas production.
Responsible energy solutions will serve as the third party auditor for the certification process.
The certification will cover two Bcf a day of natural gas production that we produce for our sales and our partners.
This initiative demonstrates our commitment to producer of natural gas under strict environmental standards.
It will also allow us to deliver differentiated responsibly sourced natural gas to our customers.
This process is expected to commence by the end of this year and we anticipate we will achieve certification during the first half of 2022.
I will now turn it back over to Jay to summarize our outlook for the remainder of the year Alright, Dan and thank you again to kind of reiterate what Dan said this.
Certification, we hope to cover all the all the gas we produced and then our partners that's a two bcf.
The middle of next year, So I think that's a big.
A big step for us.
Were cautious before we hired <unk>.
We think they will do a great job at it.
<unk> cost. So if you look at the 2021. This is on page 17 kind of the outlook.
I can tell you.
Really excited about the quarter.
About what the fourth quarter looks like particularly what 2022, it looks like 2018, 19, where consolidation years 2020 was it.
Covid year in 'twenty, one and 'twenty two.
The delevering year. So it's a focus on free cash flow was relative said focus on creating a strong balance sheet.
But we have this extensive inventory of drilling 93, 4% of this acreage is held by production.
Dan and his group have done a really really good job, we continue to be low cost operator, but.
I would like to direct you to slide 17, we summarize our outlook for the remainder of the year.
Our original operating plan, which is what we told you.
For this year.
To provide production growth close to 10% and most importantly generate in excess of $200 million of free cash flow well. We're currently on track to significantly exceed the targeted $200 million in free cash flow as Robert stated the primary focus this year is to improve our balance sheet.
Our leverage and lower our cost of capital.
Our March and June refinancing transactions have reduced our cost of capital with a $48 million annual savings and interest payments for free cash flow is being used to reduce our debt or.
Our leverage ratio has already improved to two three times in the quarter down from three eight times at the end of 2020.
And based upon our current plan and the price outlook, we anticipate our leverage ratio further improving to less than one five times in 2022.
We remain focused on maintaining and improving our industry, leading low cost structure and best in class well drilling returns.
With our industry, leading low cost structure, our haynesville drilling program.
<unk> some of the highest drilling and returns in all of North America.
Our large inventory in the Haynesville Bossier drilling locations provide us with decades.
<unk> drilling inventory.
We will also focus on lowering our greenhouse gas emissions and have demonstrated our environmental stewardship with our recent partnership with my Q to certify our gas as responsible sourced.
We have very strong liquidity right now over $1 billion of liquidity.
So with that.
Ill turn it over to Ron to give you some guidance for the remaining three months Ron Thanks Jay.
On slide 18, we provide our guidance for the fourth quarter.
He is just the last three months.
On the production side, we expect production to average between one <unk> and 145 Bcf per day.
That incorporated that'll be plus or minus 99% gas.
And that incorporates the sale of the Bakken, which is anticipated to close sometime in <unk>.
Around mid November development capital is as mentioned is.
$115 million to $135 million, including the impact of the spending related to the acceleration of the 13 or nine four net DUC completions in order to benefit from the stronger winter pricing.
We are using a portion of the Boston sales proceeds to fund that acceleration in those docs are now expected to all be online.
Sometime in late December to the end of January versus the original budget.
In the February March timeframe.
That budget anticipates remaining at five rigs at our current five rigs over the remainder of this year.
Also anticipates spending another $1 million to $2 million on the leasing activities.
Low cost on a unit basis in the fourth quarter are expected to average 19% to 20, <unk>, which is down from our prior.
Annual guidance of 21 to 'twenty five.
Gathering and transportation costs are expected to remain in the 23% to 27% range.
Production and AD valorem taxes are expected to average 12 months 2014, which is up from the prior guidance of eight to 10.
And that is all related to the impact of higher oil and gas prices.
DD&A rate of 90 to $1 unchanged as is our cash G&A guidance of five to seven.
I'll now turn the call back over to the operator, and we will take questions from analysts who cover the company.
As a reminder to ask a question you will need to pass final one on your telephone keypad again body style one on your telephone keypad.
First question comes from the line of John <unk> with sales from Stifel. Your line is now open.
Thanks, and good morning all.
Good morning.
With my first question I wanted to focus on your revised 2021 capital plan an early outlook for 2022.
Following the Bakken divestiture and Duck announcement, I think there was some investor concern that Comstock would maintain a higher activity trajectory heading into 2022.
Based on the additional capex out into the 2021 plan with the understanding that you're not formally guiding into 2022 at this time.
Should we Directionally think about activity as we approach 2022.
I think we haven't given guidance for 2022.
Net net net we're probably going to have a 4% to 6% from a year over year.
Growth.
That's kind of our goal we havent back in to what the budget would look like I mean, we've got to see where natural gas prices are.
Thank God.
We're not overly hedged so were in good shape there.
And again.
Our direction of the company, where we're going to do we're going to use.
That free cash flow.
To play down the seven 5% bonds to pay down or pay off our bank facility.
<unk> established shareholder dividend, we're not going to try to Rick The party.
We're going to have a 4% to 6%.
<unk> is our goal right now, but we have not put out any guidance.
Thanks, and for my follow up I'll actually focus on the bigger picture item that you just closed with there.
As we model your fee free cash flow profile at strip. We project you will achieve your targeted one five net debt to EBITDA leverage next year and with free cash flow yields on our models in the 30% range for 'twenty two 'twenty three we see.
Really material potential for return of capital.
Dividend in your prepared remarks would it be safe to assume return of capital would take the form of a modest fixed dividend plus variable dividend or share buyback.
Color you could offer on preference between return of capital options would be greatly appreciated.
Well I think again, we used to have a dividend.
Let's say, we would reinstate our dividend it's been so long we hit our dividend in 2014.
We believe back then.
If you had the locations do you have the balance sheet and you had the low calls can you had the.
The geographic region.
<unk> forecast for the next two to three or four years of pretty consistent growth, even with variable commodity prices.
You should be a dividend yielding company. So again, we would want don't want to get the.
Cart before the horse.
We want to make sure that we do get these leverage ratios.
I think we're going to be what the process is really are and where the budget that we have with the cost we have and we do think theres going to be some inflation I think that one five leverage ratio, we're going to we're going to kind.
Kind of like we said 200 million in free cash flow in 2021, and we're going to we think materially beat that I think that we're going to beat that one five leverage ratio, which means for your point.
We're going to have quite a bit of just Scott who is going to be cash.
On the balance sheet, because we will have to pay down our RVO will have hopefully $1 4 billion completely undrawn and our only debt that will be there will be a 2029 and 2030 and again Thats why I go back and say win win.
With the consolidation years for US there was a lean years.
2018, 2019, and now what we've got to do is we've got to cultivate what we bought in those two years and you get rid of the Covid year.
No.
Again, I think are key to use it.
It's just production growth because you do need a little bit of growth.
And does that includes bringing the.
<unk> ducked forward.
From the latter part of 'twenty, one over to the production of 2022, so you'll see a little bit.
Our production there so does that kind.
Got a beat around the bush here since we didn't give any guidance because it gives you.
So youll look.
And our confidence about what we're doing or do I need to talk some more.
I think thats a fire. So I think there's a tremendous amount of free cash flow yield above and beyond what would be required to pay off the debt and I think the markets. We'd certainly look for clarity over time with how that would take form and clearly we have some time left to chip away at the debt.
Certainly you guys are in a great position. So that's very helpful and thanks for your time.
Yes, again, I know, what you're leaning into and we're leaning into the same thing I mean.
The day that we could have.
The board meeting.
And we have hundreds and hundreds and hundreds of millions of free cash flow and just cash there we've solved in all of our liquidity et cetera.
Listen we're going to be good stewards of that money.
Your money and are making shareholders' money okay.
Yeah.
Thanks, Jamie.
Your next question comes from the line of Austin, All client from Johnson Rice. Please go ahead.
Good morning to all.
Good morning.
Now they are up to 50% hedged on <unk> forecasted 2022 volumes and.
We expect leverage ratio to get below two times.
Satisfied with the current hedge book or is there anything that would lead to more hedging for 2022 volumes.
We're very satisfied with what we've accomplished our goals for 2002.
We have now.
We're very hedged in 2003.
But for the next.
Our typical just to kind of get out there 12 months to 18 months hedged so yes.
We finished up that.
Pointed out with very wide collars, because we do believe gas prices are going to be strong next year.
And.
So.
And we like that structure, but as we as we accomplish our leverage goals I mean, the need for hedging at.
At a high percentages really it goes away.
We expect to.
To be a lot lighter than the percentage that we hedge going forward.
It was a process that we've not seen for years you wish we didn't have that much hedge but.
We're probably not overly hedged based upon the peers.
But as Roland said is not our plan to put it in any more hedges period.
We think we did accomplish our goal.
With that amount of hedge I think the banks are comfortable with it.
Everybody is comfortable with it so we're going to keep it status quo right now.
Thank you for that color and my follow up as Al said.
Expect to see about 10% service cost inflation.
Or is that mainly in labor or is that in steel.
Due to the bottleneck.
Yes, I think I think there is an article about the Havent have nots that came out today and I do believe this is going to be correct I think that if you're a smaller producer out youre going to have a hard time getting part you're going to have a hard time getting rigs better.
Better not exorbitant and price.
I think that if you are like a comstock or larger producer.
You keep grew four five rig busy at a time.
Our cost will still go up maybe that 10% is our number overall on our drilling cost is going to go up a little bit we think frac offs youre going to go up a little bit there have been so low for so long.
But we've worked that inflation number in our 2022 budget internally. So the numbers that we kind of alluded to in 2022, we've got a.
We've got a 10% inflation factor in those numbers and Thats, a pretty big inflation number if you look at it what kind of Capex number we might run so Dan you want to comment more on that yes, I think you hit the nail on the head I think for some of the really smaller operators out there that don't have big programs and often they are going to be challenged on.
Securing pipe securing rigs in securing frac crews, primarily those three things.
We're in pretty good shape on our pipe.
Being being secure out through the second quarter of next year.
We have seen I would say overall percentage increases thats, probably the largest increase we've seen to date has been on steel pipe prices.
We're up 15, 17% right now versus first of the year, we think that will ease up some more into next year.
We know the rig rates are going to the increase in going into next year, but I think when you average out all of the services that make up the daily spread rates when we're drilling and completing these wells.
Still feel right now that 10% across the board increase is a pretty good number.
We'll see where we're at.
Middle of next year.
Good barometer too because we used a couple of different drilling companies will use three different fracking company. So we are not disconnected to one company can be good or bad, but we do have.
Kind of a smorgasbord of.
Companies that have helped this euro per year per year achieve.
Our consistent low drilling and completion costs and I think theyre going to be team members in the future what are the midstream we've got several midstream partners.
That are looking at us as a pure play haynesville producer with proximity closer to LNG takeaway facilities.
We'd like to do some more business with us and we are eager to do business with them.
We can we can lock up peckerwood capacity.
<unk>.
I appreciate the color that's all from me.
Thank you.
Next question is from Bertrand <unk> from Jefferies. Your line is now open.
Good morning, guys.
With the announcement of you accelerating some of those turn in lines into the end of the year is that something that maybe we should think about could be a reoccurring thing for the company you know some of the northeast guys who've done this where each year they kind of load up their turn in line schedule right before the winter or or maybe there's just room for you to do it with choke management.
I think that.
What we want to do going forward, especially given the service.
The service companies being busier is to keep a consistent level of activity that matches or so.
The Frac services to match our drilling activity.
This year, we didn't have that type of play and we kind of get caught up but I think going forward, it's going to be much more we have to control the cost of our services. If we can have consistent level of activity versus trying to create or not so Dan you might add to that yes, I would say really kind of.
To the heart of your question. This is a kind of see this really as a one time event, we got caught up on our notes we've been clear and we've been carrying some ducks really throughout the year. This acceleration.
These 13.
Gets us called up.
A normal cadence of when you or the Frac crews are coming in behind the rig we're always going to have between five and 10 depths just the way that they are.
No.
The definition of it but.
We think going into next year.
Just kind of maintain at high single digit level.
Normal cadence frac crews coming behind the rigs and don't really see bill.
Building any higher than that going forward and enrolling made a good point.
When times get busy like this it's really important to schedule your crews had minimal gaps.
That you don't have to drop crews or add crews that can be really challenging.
When things get to be in high demand.
But I think if you look at the footprint, we have on our acreage.
There could be some takeaway issues in the Haynesville people.
Don't have a bigger footprint, so we spread our production out.
Kind of a front runner takeaway.
That's another plus that we have and remember the reason we have the ducks in 2020, we went for probably $2 five months without fracking, a well and we had four rigs drilling wells. So you get kind of compounds over what we looked like at the end of 2020 going into 2021.
We had the five rigs in 2020 once we've just never got caught up on the ducks.
Okay.
Okay. All right that's great guys and then really just a follow up.
You guys are trying to target longer laterals can you maybe just talk about your willingness to.
Is that part of the leasing budget that you want to core up your acreage, maybe do swaps or is that incremental savings not necessarily worth it and youre just going to target the longer lateral locations that you already have.
Okay.
Well. So this is diane it'll certainly affect maybe some of our trades, but really the driver is just.
Better efficiencies when you draw a long way from five case to 10-K as you know the returns are so much better.
Efficiencies are better.
Cost per foot comes down and so really this is just a natural extension.
From 10 to 15 to now that's in Louisiana.
You've kind of got the three buckets on the Louisiana side, you got one section our section and a half or three sections, but in Texas, It's a <unk>.
Little more random.
Some will be 13, some 14000 footers. So it's just kind of.
It's a little more just random lengths between 10 and 15.
We like I said, we've drilled.
Case these first two.
Really well we drill in the next two now.
Kind of pending the results of these which we feel pretty good about we're going to have several more.
We're going to drill next year and probably even more in 'twenty three.
That's going to help combat this.
Higher service cost environment by getting our cost down.
You just get more efficient than any other company standing up some of the inbound calls have been and what do you think about the 10000 15000 foot laterals your ability to drill them and complete them.
Any any any other comments that you want to make to the public. So yes, I mean, we feel great about Joel on the 15000 foot laterals and really complete the one thing thats different.
Out of 15, K it has a little bit of a different risk profile of maintenance.
You run into some issues. It can cost you a little more time and money to remedy those issues when you're that far out in a lateral so.
We have to take those learnings into consideration but.
We're all learning curve for the <unk> case, I mean, we just.
Just right out of the shoot I think we did a great job almost <unk> and.
It's only going to get better I think we will all obviously the tools.
From our vendors to.
To improve.
We will get better from here, so I don't think theres any doubt.
With a 15000 foot laterals are here to stay.
We usually have dialed in all the operation superintendents and they will tell you. We've said most of the records in the Haynesville I think it's Rod Dan correct, a lot of a lot of the records set a lot of records. So again we.
And I don't think anybody has drilled and completed more of these wells, we have listened, but you've taken that day.
So again we.
We don't we don't read the book to figure out how to do it most of it.
And in that part that we don't know we read it intensely so.
Well that sounds good that's all for me guys.
Thank you.
Again, Please press star one to ask a question.
Next is from Leo Mariani from Keybanc, you May ask your question.
Hey, guys just wanted to ask about activity, if I sort of saw this correctly it looks like fourth quarter activity out in the field is roughly the same as it was in the third quarter.
And I guess you guys are expecting capex to go down.
Quite a bit in <unk> was just looking for some color behind that.
I think the activity is a lot less.
Yes, we do say, we're running five rigs, but two of those are really working.
With properties would have an interest and working for the the Jones partnership.
So the drilling activity actually in the.
In the fourth quarter as well as a lot less given the number of rigs running.
For our own account.
And completion activity.
And then Lee on completion.
We brought on.
Turning to sales during the third quarter about 22, net wells and that's going to be closer to 10 in the fourth quarter.
So.
Is it a lot lower activity quarter.
Yes.
Okay, Yeah, I guess I thought you guys are running the same type rigs and three crews each quarter, but it sounds like maybe there is.
Some working interest differences, there as well and perhaps some timing on the payments.
Yes, I think the crews that will average for on our account again.
Significantly less than three for their own closer closer to two to five crews.
Okay. That's helpful.
And then just I wanted to touch base on taxes here a little bit.
So it looks like we started to maybe see some cash taxes kind of creep in.
The numbers here in 2021, I understand it might've been some onetime payments in the third quarter, but can you speak to what your overall expectations are in this current commodity price environment are for cash taxes as we get into next year.
Yes, there were no payments cash payments of taxes that went out at all but.
But we do.
We pick.
We had an increase to the current tax provision and that's all that's all state state taxes not federal.
And so I think the taxes were highly influenced this quarter by the very large.
Mark to market losses, which creates some unusual items you are not able to kind of forecast the same utilization of the Nols and staff.
When you have cumulative losses, just under the accounting rules, but those are those don't match reality reality as we forecast very big profits and we will be able to utilize.
Yes.
The Nols.
Even though we can't show that for on a.
Accounting rules so.
But overall I mean that yes, there is with the high profit levels, we will have some level of state taxes.
They will have.
Sure.
Probably or several years out before we start forecasting yet federal cash taxes.
Okay. Thanks, guys.
Probably 678 years I haven't heard issue of taxes.
So that's a pretty good but a bad word there that's a good thing I hope we have more of those questions in 2022.
Your next question comes from the line of Noel Parks from Tuohy Brothers. Your line is now open.
Hi, good morning.
Morning.
Just a couple of things I wanted to run by you.
And I apologize if you may have touched on this.
Earlier, but.
Since we've had these other fairly large haynesville transactions.
Over the course of the year.
Curious as far as acreage trading.
Trying to clean up leases.
Have some of those assets.
Changing hands.
Helpful or.
Hindrance as far as just just dealing with.
With other operators.
Hey, this is Dan.
We got several of those working right now and I would definitely say that it's going to be a big help.
Some of these deals are not closed and really taken effect yet but.
For instance, we have.
One in particular, where we're already talking with.
The.
The new operator, so I think that's going to definitely be.
The big benefit more than Hendrix anyway going forward. The reset is a win win for both sides. We have acreage that can extend our laterals will they have acreage that can extend hours. So.
It's definitely it's.
A two lane road, so I think everybody wins on that.
Great and.
On the ESG front.
Interested in your choice of.
Q scandalous I just wonder if you could talk a little bit about why you chose that particular one.
Paul.
Seeing that there.
Had than other.
Other vendors that have been participating in the base.
Back and forth.
As far as what's being used.
Yes.
Yes, there wasn't really a lot of there's not a lot of potential people that we could use but we just I mean, we went with the marquee because we like the transparency.
Just looking ahead down the road, we feel like.
We're going to be in really good shape partnering with them.
<unk> got a really strong standard and.
Of course, they really pretty much all about emissions and.
We have really our mission intensity retina methane intensity right now is really really well I mean, we can score.
Well with that as it is now so we just need to focus on some of the other things with them and we think.
We think theyre going to help us.
No.
Achieve that.
Great. Thanks, and just one kind of related and this one may be for Roland.
Just curious I know, it's very early to be to be thinking about this but.
Do you have any sense of what the accounting might look like for gas deemed RFG in terms of if the commands a premium.
Is that Jeff.
Just part of or.
That's just part of realized price or is that some sort of other.
Other categories other category.
Revenue just wondering if I had to come up yet.
I would assume that the accounting will be just.
Shown in higher price realizations, and that's really the as you enter into a contract with the purchaser.
Youll agree on standards and then you'll have <unk>.
<unk> like our audit like we will have here to certify those standards to the purchaser and then there'll be willing to and.
Then under that contract.
If you achieved those standards they will pay you that premium to what otherwise they might be buying the gas for that's that's the theory and I think as we are able to directly connect especially with.
With the LNG purchasers that kind of want to.
Overall achieve a.
To ensure that the product, thereby has been responsibly sourced and that they can take credit for that.
Moving their environmental goals.
We're there to help that process.
Now allow them to.
To show that the gas from producers like us.
And a large dry gas basin with high volume wells new equipment.
That we don't have.
Hi methane.
Leakage that they criticize here the overall natural gas industry for so I think that's why we think this is really important for us and the other dry gas producers.
Yes.
We can differentiate our product because we think not be tagged with other peoples.
Were they were they are achieving these standards. So I think even if we don't get a premium price, it's very very important.
For us achieving our own environmental goals.
Yes, I don't think.
If you look at the scoreboard like Dan said I mean.
We have such low THP intensity and you would put that in the press release.
And even though I think it was five one we lowered it by 38% since 2018 to this $3 one two.
Were very good.
The environment, but I think the end broker scoreboards.
Whatever we need to do to demonstrate that we're committed to the highest environmental standards, we're going to do that.
We don't flare gas plus of those things that are issues. We don't have to start with now we just have to make sure that we drill and complete and we produce these wells we don't have any leaky.
I mean again, we're so.
Fortunate.
To be a pure play really haynesville player.
Particularly as the Divesture of the Bakken So we welcome these challenges.
We've become a better company for the challenges.
Great. Thanks, a lot.
Your last question is from Kashi Harrison from Piper Sandler you May ask your question.
Good morning, everyone and thank you for taking my question.
Yes, yes, you're the last one I saved the best for last.
No.
Yes.
Yes.
You had talked a little bit earlier about takeaway.
In response to another question and I Wonder if you could just maybe dig into that.
A little bit.
How much takeaway do you think is in the haynesville to get from that general area down to the Gulf Coast I am trying to think through what the what the ceiling on haynesville production might be.
Over over the longer over a longer period of time.
Ron we hate to really get into that kind of overall, but because we know our situation really well.
And I, probably don't want to be real.
Specific on the whole basin, but yes.
Yes, we're situated really well and our goal is not only to have the takeaway, which we have.
Substantial takeaway, but have that connected more to the golf.
We will be as we go into this fourth quarter, and especially December will be less than 25% of our gas tied to the <unk> hub.
Which has a little bit wider differential that our Gulf coast indexes. So.
Our goal is to get that number to zero as the biotech.
A lot of initiatives working on that so we're more focused on direct access to the golf to get premium prices.
And as a backstop, we can sell the gas at the regional hubs.
But.
And you know what that comes from it comes from plan that we're asked all the time.
When can you drill a certain wells and we said well we go out into 2021 2022, and we figure out that we have ample takeaway at Apple.
<unk> prices to keep that low cost category. So.
As far as the Haynesville, we're always rate maybe there is a big day of availability, but we don't really know.
You never know till you test the market.
So.
That is helpful. Both on the comfort level on the macro level. Thank you.
Yeah.
I think the good thing about the Haynesville, though.
As the years progress.
You do have people putting still underground.
So if there is going to be demand and I think maybe this LNG takeaway.
<unk> expanded another two bcf in the next 18 months to two years.
So from standard 12, and a half for quarter, two 2014 base plus the export to Mexico.
I think.
The midstream is going to.
Provide.
The positive we need.
Period, I think theyre going to partner with.
With the comps start to get to get the gas to the Gulf.
So we're good.
Yes that ends our question and answer session I will turn the call back over to you for any closing remarks.
Okay again, I want to thank everybody for the most valuable thing you have time, so you spend about an hour of that with us.
We are by far the single largest pure play in the Haynesville.
And I think we're very fortunate to be there. It was through planning with the Jones family et cetera that we were able to get there and now all of a sudden you.
See the demand for.
For the desk and U S and on other others worldwide.
Global demand for gas.
It needs as they need it in Europe than it is in Asia they needed here.
I think LNG I think those days are looking positive to add some more export facilities within the next several years so.
I think again the key we shorted out an hour ago the direction of the company we wanted to do.
We want to have capital efficiency, I think Dan hit on that.
We will stay in the Haynesville, we've always said that.
We want to generate.
Significant free cash flow I think there is a lot of you had ask the model shows that that'll happen.
And then specifically what are we want to do I mean, we want in the next several quarters, we do want to pay.
We want to play off our or below where you want to use that free cash flow to do that.
We want to retire the seven five bond may of 2022.
And then as a lot of you alluded where you can do the rest of the cash for.
With all of those goals with the debt reduction goals.
We're going to look at it might be to establish our shareholder dividend and then growth in 2022 again, it's at 4% to 6% is what we would think.
And we've got not given out any guidance. Thanks look really good in the world with natural gas needful.
And particularly at Comstock. So thank you for your hour.
That concludes today's conference call. Thank you all for participating you may now disconnect.
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