Q3 2022 Comstock Resources Inc Earnings Call
Okay.
Good day and thank you for standing by welcome to the third quarter 2020 to Comstock Resources earnings Conference call. At this time all participants are in a listen only mode. After the speaker's presentation there'll be a question and answer session to ask a question. During this session doesn't need to press star one one on your telephone please be advised that today's.
Is being recorded I would now like turn the conference over to your Speaker today, Mr. Jay Allison Chairman and CEO . Please go ahead.
Good morning, everyone and thank you.
Welcome to the Comstock resources third quarter, 'twenty, 'twenty, two financial and operating results conference call.
Can view a slide presentation during or after this call by going to our website at Www Comstock Resources' dotcom and.
And downloading the quarterly results presentation.
You'll find a presentation entitled third quarter 2022 results.
I am Jay Allison Chief Executive Officer contract with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Ron Mills.
Our VP of finance and Investor Relations.
Please refer to slide two in our presentation to 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.
You flip over to slide three.
I'd like to announce to you that contract resources.
Just posted the greatest quarterly results and our 30 plus year history as a public company with our revenues almost exclusively coming from selling natural gas.
We set new corporate highs in almost all financial metrics, including operating cash flow free cash flow net income EBITDAX and oil and gas revenues.
Our balance sheet has now become a fortress.
Our leverage down to 0.9 times and our quarterly dividend is now possible.
In order to have a day like today you have to rely upon many of you and many of you that are not even on the call.
We say, thank you to our equity stakeholders, who trust us with their hard earned money and especially the Jerry Jones family.
Say, thank you to our banks that provide us for their credit facility and our bondholders along with all the hundreds.
Of oilfield service companies to assist us and promoting excellence in drilling and completing our haynesville and Bossier wells.
Now many of you have asked about our western Haynesville region.
Circle are well in Robertson County started producing in April of this year. It has continued to have a flat production rate of around 30 million cubic feet of gas per day.
We've also drilled our second well in this region, which is near the circle Alma call. The KZ Black which was successfully drilled and completed that is expected to be turned to sales. This month.
Note that the circle as well was shut in for 30 days, while we were completing the KC black oil.
The Comstock team of 240 work hard to produce tier one results, which I'll share with you starting on slide three.
We cover the highlights of the third quarter one this slide three.
Our operating cash flow of $533 million.
Our $1 92 per diluted share was the highest in our corporate history.
After funding our drilling and completion activities regenerated 286 million of operating free cash flow.
This allowed us to retire $250 million of bank debt, which brought our leverage down to a 0.9 times.
Our adjusted net income for the quarter were $326 million.
The $1 18 per diluted share and our EBITDAX for the quarter came in at $598 million, 93% higher than last year's third quarter revenues for hedging for the quarter came in at 692 million, 76% higher than last year's third quarter.
Our Haynesville shale drilling program is going well as demonstrated by the 17 are 15, two net operated wells that we reported on this quarter with an average initial production rate of 29 million cubic feet per day.
Excited to announce the reinstatement of our quarterly dividend to common stockholders. Our board of directors approved a quarterly dividend of <unk> <unk> per share to be paid to our common shareholders on December 15th representing a yield of approximately two 5% at our current stock price.
Now I'll turn the call over to Roland borrowers to comment on our financial results Rolling.
Thanks Jay.
On slide four we recap the very strong third quarter financial results we achieved.
Pro forma for the sale of our Bakken properties, which was completed last October our production increased 1% to one four bcf per day.
The recently completed third quarter.
Our record high EBITDAX in the quarter grew by 107% over 2021 pro forma third quarter to $598 million, driven mostly by stronger natural gas prices.
We generated $533 million of cash flow during the quarter, 126% increase over 2021 third quarter on a pro forma basis, that's another corporate record.
Our cash flow per share during the quarter was $1 92.
It's up a dollar from the third quarter of 2021.
We reported adjusted net income of $326 million for the third quarter.
That's more than two five times higher than the third quarter of 2021, and our earnings per share came in at $1 18, as compared to 35 cents in the third quarter of 2021.
We generated $286 million of free cash flow from operations in the quarter, 218% higher than the third quarter of 2021.
And the growth in EBITDAX and the retirement of $250 million of debt in the quarter drove our leverage ratio down to under one times as compared to two three times in the third quarter of 2021.
Improved natural gas prices were the primary factor driving the strong financial results in the quarter on slide five we provide a breakdown of our natural gas price realizations in the quarter.
During the third quarter that quarterly Nymex settlement price averaged $8 20, and the average Henry hub spot price averaged $7 96 assets.
So Darren during this the.
The third quarter, we nominated 77% of our gas to be sold at index prices tied to that contract settlement price and then we saw a 23% of our gas in the daily spot market.
So the expected Nymex reference price for sales in the third quarter would have been $8 14.
Our realized gas price during the third quarter averaged $7.72, which reflects a 42 said differential.
That was a little higher than normal due to wider regional differentials.
And do they invest significantly due to a weaker Houston ship channel prices, which are all due to the Freeport shut down.
Houston ship channel and the other Texas Gulf.
Host indexes are usually some of our premium markets.
In the third quarter, we were also 49% hedged, which reduced our realized gas price to $5 36.
We have been using some of our excess transportation in the Haynesville to buy and resell third party natural gas this generated about $11 million of additional income in the quarter and that average it added about nine sets to our average price realization in the quarter.
On slide six we detail our operating cost per Mcf and our EBITDAX margin, our operating cost per Mcf averaged ADT stats in the third quarter.
<unk> hired in the second quarter.
Our gathering cost increased by five sets.
And that's primarily due to the impact of higher fuel costs used in the transportation of our gas, but also due to higher production from some of our higher gathering rate areas.
Our lifting cost increased <unk> and our production taxes increased <unk> due to the combination of higher realized prices and an increase in the statutory severance tax rate in Louisiana that became effective in July .
G&A costs came in at six the same as our second quarter rate.
Our EBITDAX margin after hedging.
Came in at 85% in the third quarter the same as the second quarter.
On slide seven we recap the first nine months of this year and what we spend on our drilling and other development activity.
In the first nine months, we spent $729 million on development activities, including 653 million on our operated Haynesville and Bossier shale drilling program. We also spent $23 million on non operated wells and 54 million on other development activity, including installing production tubing offset frac protect.
<unk> and other workovers.
In the first nine months of this year, we drilled 52 or 42.5 net operated Haynesville operator.
At net operated horizontal Haynesville wells and then we turn to <unk> 53, or 40 to $44 two net operated wells to sales.
These wells had an average initial production rate of 27 million cubic feet per day.
We also had an additional two net non operated wells that we turned to sales.
In the third quarter, we spent $242 million at our development and exploratory activities, including 227 million on our operated Haynesville and Bossier shale drilling program. We also spent 4 million on non operated wells and $11 million in other development activity.
Sure.
On slide eight we show our balance sheet at the end of the third quarter of this year.
We had $100 million drawn on.
Under our revolving credit facility at the end of that.
Third quarter.
The.
And our debt balance and that growth of EBITDAX drove our leverage ratio down to zero.
0.9 times in the quarter on an annualized basis as compared to the $2 three times that we're at for the third quarter of 2021.
We plan on retiring the remaining $100 million outstanding on our revolver in the fourth quarter using our free cash flow.
So we ended the third quarter with financial liquidity of more than $1 $3 billion.
Now I'll turn it over to Dan <unk>.
Discuss the operating results in more detail okay. Thanks Roland.
Overall slide nine so this is an upsell.
Data on our average lateral length, we drilled since 2017.
So the year to date average lateral length has increased slightly up two 9790 700 feet.
This is based on the 53 wells that we've turned to sales so far this year.
So this currently puts us over 1000 foot longer than last year's 8800 foot average lateral in by the end of the year, we anticipate our full year average to be approximately 10100 feet.
Year to date, we've drilled 17 of our extra long lateral wells thats, our wells with laterals greater than 11000 feet.
Included in this group, we've had nine wells with laterals greater than 14000 feet.
And I'll add that we're actually drilling our 18th 15000 foot lateral at this time.
Our longest lateral drilled and completed to date still stands at 15200.
And 91 feet.
By year end, we anticipate turning 64 gross wells to sales with an average lateral.
10100 feet.
On slide 10 is our latest D&C cost trend through the third quarter. This is for the benchmark long lateral wells with laterals longer than 8000 feet.
So this quarter 10 of our 17 wells turned to sales were in this benchmark long lateral group.
The D&C cost averaged $1405 a foot in the third quarter, which represents an 11% increase from the second quarter and a 35% increase from our average 2021 full year D&C costs.
Our drilling cost for the quarter was 597 to eight.
So the 25% increase quarter to quarter.
Our completion cost for the quarter was $808, a foot, which represents a quarter to quarter increase of only 3%.
The increase in our drilling cost reflects the true cost inflation numbers, we've experienced year to date, we have seen it affect all services.
Across the space.
This witness marketplace and costs for the quarter, we've been partially protected by the high inflation costs on the completion side through the deployment of our first natural gas powered Frac fleet, which is playing a significant role in keeping our cost down.
Locking in long term cost of horsepower and also drastically cutting our diesel usage.
As we mentioned before in the last call we've contracted for a second natural gas powered Frac fleet and we do expect to take delivery.
Sometime late in the first quarter of 2023.
Slide 11 is a summary of the new well activity for the third quarter.
So we've turned 17, new wells to sales since the last call.
We had really strong well performance this quarter with individual IP rates, ranging from 17 million a day up to 40 million cubic feet a day.
With an average test rate of 29 million cubic feet a day.
The wells were drilled with lateral lengths ranging from 5328 feet.
As to 15310 feet long.
The average lateral was 9899 feet.
Included in this group, where our three most recent 15000 foot completions.
These 15 K wells tested at rates of 30 to 32 million cubic feet a day and the average length of these was 15075 feet.
The group also includes the first three wells, we've drilled and completed on our Nacogdoches, Texas acreage since we restarted our Haynesville drilling program back in 2015 the.
The initial test rates for these three wells exceeded our expectations with IP rates, ranging from 33 million a day.
Up to 40 million cubic feet, a day with laterals, averaging 7477 feet.
Based on the initial results on the Nacogdoches acreage, we do plan to add activity. There later next year.
And we also will continue to pursue drilling the longer laterals as they offer a hedge against inflation.
Regarding our activity levels, we did add two additional rigs early in the third quarter. We're now running a total of nine drilling rigs and three fulltime frac crews.
Looking ahead and in a more general sense, we plan to shift more of our drilling activity from Louisiana and Texas.
As we spread out the activity to maintain our takeaway capacity maximize where we can drill the longer laterals and to protect our acreage.
I'll now turn it back over to Jay to summarize the outlook.
All right Dan add a just a comment for a start.
The final presentation to enact acreage was a tier three set of acreage.
That we had initially and you can see from what Dan has reported the IP rates.
And those lateral lengths, it's now become closer to a tier one area.
So we will have increased our inventory of tier one.
As we move some of these rigs over to the neck acreage.
Hugo over to.
Slide 12, I'll direct you to slide 12, where we summarize our outlook for the rest of the year.
We're on pace to generate significantly more than our targeted $500 million of free cash flow, we've already exceeded that at the end of the third quarter and at current commodity prices, our free cash flow could rate somewhere around $800 million.
Of course, the first priority of the free cash flow generation has been reducing our leverage which we've done we've retired $250 million of debt during the third quarter and we expect as Roland said to repay the $100 million remaining borrowings outstanding under our bank credit facility in the fourth quarter, maybe even this week or next week as discussed.
On our last conference call and as Dan Just mentioned, we have nine rigs operating in our Haynesville drilling program.
The two recently added rigs are expected to be active.
On our western Haynesville acreage position in 2023, we should move to a second rig in this area probably late November early December .
We'll use those rigs to de risk and delineate the play.
Did budget about 65 to 75 million for bolt on acquisitions and leasing activities for the year, which includes the $54 million already spent in the first nine months of the year.
Now that we've exceeded our leverage goals.
We're starting a return of capital program in the fourth quarter.
Board of directors as I said earlier is authorized reinstating our quarterly common stock dividend.
Fourth quarter dividend is $12.05 a share and will be paid on December 15, and lastly, we will continue to maintain and grow our very strong financial liquidity.
Which totaled and again more than $1 3 billion at the end of the quarter. So with that let me turn it over Rob you can give some specific guidance for the rest of the year.
Thanks, Jay on Slide 13, we provide.
Our financial guidance for the fourth quarter of this year and full year.
Fourth quarter production guidance range is 142 to $1 five two bcf per day and the full year guidance remains unchanged at the prior level of $1 39 to 145 Bcf per day.
During the fourth quarter, we plan to turn to sales eight to 10 net wells.
We now anticipate our 2022 full year production guidance to be biased towards the low end of that.
Our range due mainly to the timing of turning.
Wells to sales for.
For the year, we now expect.
Turning to sales, 1% to two less net wells.
This year than when we last provided guidance in August .
The 2022 development Capex guidance remains $925 to $975 million.
As Dan mentioned earlier that 2022 wells will have an average lateral length of about 14% longer than last year, which is helping to offset some of the cost inflation we've seen.
In addition to the drilling program.
We expect to spend up to $65 to $75 million, including both bolt on and leasing activities of which $54 million has already been spent this year.
Our low cost are now expected to average 18 to 23.
In the fourth quarter and 19 to 24.
For the full year.
While our gathering and transportation costs are expected to average 28% to 30 <unk> both in the fourth quarter and for the full year.
Production and AD valorem taxes are expected to average 20% to 24 in the fourth quarter partly.
Partly due to.
Commodity prices and partly due to severance tax rate in Louisiana.
DNA rate expected averaged <unk> 95 to $1 five in the fourth quarter.
Our cash G&A is expected to average RMB $709 million this quarter and totaled 29% to $32 million for the full year and the noncash compensation portion of that is approximately $2 million this quarter.
Cash interest expense is now expected to total $38 million to $40 million during the quarter.
Which would bring the full year of cash interest up to about $158 million to $162 million.
Our effective tax rate is still expected to remain in the 22% to 25% range and we continue to expect to defer 75% to 80% of our taxes.
We will now turn the call back over to the operator to answer questions from analysts.
Catherine.
Turn it over to Q&A. Thank you as a reminder to ask a question you will need to press star one on your telephone please.
Please standby, while we compile the Q&A roster.
Yes.
Our first question comes from Derrick Whitfield from Stifel. Your line is open.
Thanks, and good morning all.
Good morning Derik.
With my first question I wanted to focus on the circle and resolve and early indications on your second Bossier well in Western Haynesville.
Since the last call what incrementally can you share with us on the potential of the <unk> and your view on the repeatability of that result, based on your and industry results.
Yes, Derek this is Dan.
Jay mentioned set of wells have been producing flat at 30 million a day.
Since we put it on in April we did shut it in when we Frac. The KZ black was in the vicinity, we started that frac back on.
While October the fire. So we had the wells shut in just for precaution for 30 days, we just recently put it back on here. The last few days and we're ramping it back up to that 30 million a day rate but.
Yeah, everything looks really good on the second well, we will get it turned to sales. This month, we expect it to be just as good.
Maybe a little better than the circle.
And we don't see anything really on the horizon of what any of these future wells are going to be anything less than the circle.
That's terrific and as my follow up I wanted to ask a gas egress question based on the broader weakness in <unk> and Houston ship channel really one of the region.
With the understanding that that re <unk>.
And that weakness has been driven by pipeline outages and Freeport wanted to ask if you could share your macro views at really the basin level and more specifically to.
To what degree can the haynesville production grow over the next year in your view and how much excess takeaway.
Do you own over current production levels.
If you look at our program, we intentionally added the two extra rigs to go to nine.
And we did that several months ago, we broadcast it may be.
Six months ago that we might be doing that.
When we forecast our production growth, particularly with the western Haynesville.
Our core area for <unk>.
Seven rigs will be on that core area.
Always project pipeline and takeaway.
Look to see if we're going to drill 80 wells grocery year it might be turned to sales six years. So are those where that takeaway is we've.
We've done that.
Williams, or ATC or with enterprise et cetera, I mean, I think our marketing group is ahead of our drilling schedule. So even though we think that takeaway is extremely thought it might be 90, 95% pool I think at a few VP plan.
And youre not going to run in some of the problems that some of the smaller companies have but the other thing that we have.
Which he comes into play now is our expansive acreage footprint.
It's not like we're in one or two counties in Texas are 67 parishes in Louisiana, where in all of the above.
So if you go back Derek and you've looked at how we spread our program out.
Quarter to quarter to quarter year to year, you can say that it will heavily drilled in one area and not another because of a takeaway issue maybe.
But because we do have that 400000.
<unk> and growing.
Got a lot of room to avoid some of the pipeline takeaway issues.
Yes.
Derek This is Ron just to add a couple of comments to that.
We recently added about 300 million a day of additional.
Takeaway two our transportation portfolio.
As we continue to look ahead, and just see where our needs are and yes. There are a lot of.
They were brownfield projects Greenfield projects, both in the Haynesville, especially redirecting gas to the Gulf Coast markets.
So yes, we continue to evaluate those takeout parts of those we like it we like to have just like we have a diverse acreage position, we'd like to have a diverse transportation portfolio. So we have options to move our gas around it or <unk>.
And the areas that have that.
The most takeaway.
So.
I think your other question was we do have about 200 million a day of spare capacity that we actually are.
You're buying and reselling third party gas that we plan to use up so.
We just.
And next year's drilling program. So we think we're pretty well positioned but we'll continue to be front run that.
As the Haynesville production grows and as the demand grows in the Gulf coast and being able to get the gas down to those those users and Derek as Roland said, we have added more firm transportation.
Because we think ETF interruptible, you'll probably be interrupted so we've added more firm.
That's terrific sounds like you guys are well positioned.
Thank you.
Thank you.
And we have a question from Charles Meade with Johnson Rice. Your line is open.
Good morning, Jay to you and your team.
Hello Charles.
Jay I wanted to ask a question about those.
<unk> well results in.
So you put these in presentation that those are start rates, particularly in light of the.
77% 7100 foot lateral lengths and I am curious it sounded like in your prepared remarks, it sounded like that was an uptick.
Versus your internal expectations previously so I'm wondering if you could talk a bit about that is there a different completion design are you are you targeting a different zone is there may be something that you've that you've learned from the <unk>.
The.
Western Haynesville that Youre that you bring it back this way just tell me what's going on there.
Yeah, Charles I thought it might be a pull that question out of you. If I commented on it after Dan presented you didn't cover it.
Wanted to colored so this is his chance.
So Charles.
We haven't drilled any wells down there since 2015 when way back when gas prices were low that was just kind of one of the areas that we did not look at spend on our capital because.
We'd looked at the wells had been drilled up and.
And David I, just didn't they didn't really compete when you looked at the other areas, we're drilling and where we needed to maximize.
Our performance. So we do have I think about 35000 net acres down there so gas prices improved.
<unk>.
Basically.
We needed to move a rig down there and basically put a new vintage frac on those wells. There is other offset activity in the area that is showing that the results are good so.
So we drilled two haynesville and one Bossier it was a three well pad.
The footprint, we had just allowed us to drill a 7500 foot lateral we could have drilled them a little bit longer if we had the footprint was there.
But in the bottom hole pressure is a little higher that's a little bit deeper down there it's about 14000 foot TVD.
So.
We'll put the bigger vintage newer frac job on it like we've been doing everywhere else.
The performance looks really good now.
Let them, let them produce out for a while obviously and confirm that.
What the EUR is going to look like but.
And out of the gate they look really good.
Alright. Thank you it looks like you probably have three months of data on those on those productions, so that'll be interesting to follow that.
And.
And my second question is on.
This slippage of the turn in line schedule or the completion schedule that.
That you guys mentioned can you talk about.
I guess, what what what the drivers were there a with with an eye or what's kind of an aim at.
Are these are these one time things or is this representative of up service tightness that.
That has some some likelihood of.
Reappearing in 'twenty three.
So Charles this is really just a one time thing we had silver or three full time Frac crews. We had we took our lower performing frac crew and we had the opportunity to upgrade and pulling another frac crew that we thought was going to be a lot better have better performance.
And we made a switch here just in the last few weeks, but what it did was it took one of our three well pads. It was going to turn to sales in December and it pushed it into.
January it pulled up a couple of other pads there were some data shuffled around but thats basically what caused that.
Got it so really detail.
Yeah. It doesn't change anything long term and it's not a sign of anything as far as.
The cruise or supply chain or anything like that it was just a one time event swap.
Our lowest performing frac crews or another.
Yes, and Charles It has nothing to do with well performance our inventory.
We think gasoline.
Yes, I think we will see a pickup next year with the efficiencies on the southern Frac crew, we picked up I think it's going to help us push.
Pull forward turned to sale dates that we had next year, so that will that will be.
That will help out.
Great. Thank you.
Thanks Charles.
Our next question comes from Fernando Zavala with Pickering Energy Partners. Your line is open.
Hey, guys. Good morning, Thanks for the time.
Was wondering if you could talk a little bit about your activity levels in 2023, and how you would flex activity with perceived oversupply in the natural gas market next year.
Well, we really haven't set our 'twenty three budget, yet and yes, thats something we evaluate.
As we get as we kind of get towards the end of the year here, but I think yes, we will definitely be looking at the strength of gas prices to determine our activity level.
And looking at.
We have takeaway, we don't drill wells that we don't think we have good markets for.
So that's to come and we'll monitor that.
I think one of our big initiatives.
At Comstock is to really start to build up long term supply contracts, where we're going to we're looking to lock in direct customers.
And really stabilize the markets for our gas in the future.
Given our connectivity to a lot of the industrial users and.
LNG facilities.
That's kind of how we are looking to position the company.
In the future it really happened.
And not be relied on the day to day market or the clearing clearing market, but more.
Sure.
Have a much better.
Outlook on <unk>, we know our customers want this this gas and supply them on a long term basis.
Makes sense.
Youre focusing on trying to prove up that western haynesville.
Acreage. So is there like any price point, where that would shift and maybe you would move one of those rigs back to your core haynesville.
No we don't see that happening at all we see.
Delineation wells.
And we've got the rigs that we need to drill the western Haynesville.
We've got them scheduled with pad sites.
We have takeaway for all of those wells that are planned in 2023.
Completion crews as Dan had mentioned in place.
To handle the non rig program with seven rigs in the core area into delineating the western Haynesville.
As Roland said I mean, we we're now looking at maybe some end users for chemicals or industrial.
Users that may want to contract.
Our gas so they have it so.
Once the LNG demand of anywhere.
811, <unk> matures by 2026.
Some of the end users locally along the Gulf Coast I mean, they will have they will have gas provided.
Someone it may be that might be comstock, which sell directly to them at the same time, we will we're kind of reach out and see what the LNG market is.
Because we have to remember, we're very predictable with our 16 100 plus.
Plus locations are very high margins low cost we have predictability we add in again. This this lack of leverage so I think we have all the earmarks for LNG exposure.
When it when it appears when we're ready for it.
Got it that's helpful. Thanks for your time.
Thank you.
We have a question from Neal Dingmann with <unk>. Your line is open.
Good morning, all.
My first question is just on well cost specifically I think expected cost per foot.
Looking here it looks like your presentation suggests that 'twenty two cost per foot are up about 45% year over year and I'm. Just wondering one is that am I correct in that 45% and then secondly, and maybe more importantly, I know you don't have 23 guide out yet, but how youre thinking about 'twenty three on a cost per foot given inflationary pressures.
But he is experiencing but also obviously the nice longer laterals and other things you all are doing.
Yes, no thats a day and so we definitely I think youre pretty close on that percentage number I mean, if you just compare it to where we were at 2021, which is really the low point.
I mean, obviously, we don't want to go back to that where the gas prices were but we were still seeing we're still seeing the inflation numbers move one up a little bit we've been.
Really when we picked up this gas Frac fleet, we were really fortunate there that is really <unk>.
<unk> on the completion side and I think when we get that second fleet next year.
Two out of our three fleets running on gas and with the <unk>.
Horsepower locked in for the long haul, we're going to be in good shape there.
<unk> side I think it was where we're going to see obviously the costs are going to continue to move up as long as the demands there.
We're seeing it just across all services I mean, obviously, we've seen the rigs we've seen the.
We've seen it in obviously the diesel will use a lot of diesel and oil based mud.
Cementing directional tools that made us just really kind of across the board.
That's that's where we're going to be battling.
Those cost the longer laterals are helping tremendously.
Sure.
The wells in Texas are a little bit cheaper to drill over there we drill faster in Texas, We've got the acreage in Texas to drill a lot of long laterals.
So that's going to help us there.
Have you locked in some of those the nine rigs fee like do you have longer term contracts from any of those.
So we have we have.
That's a medium term contracts in some of our rigs, but we don't have any of them currently locked in at long term, but we are we are evaluating some at the moment.
Okay, and then maybe Dan Sneakily, just my second question on pretty general, but broad strokes just wondering when you when you turn more to you mentioned turning more towards wells.
Wells in Texas next year versus a lot of that.
Nice, Louisiana Wells you have done this year any just early thoughts on well returns you think it'll be pretty comparable.
As you start drilling and completing some of those.
I think theyre going to be pretty comparable.
The the better the better higher profile wells, our <unk> side.
Thats why the drilling activity was concentrated there in the past few years.
Texas Wells typically will IP lower they will make a little more water, but they got a little flatter decline.
Agency cost is lower in Texas, So I think maybe it could be just slightly less but I think it's pretty comparable overall when you package the lower D&C cost.
Compared to the Louisiana Wells and then likely.
Like we mentioned, we're looking at takeaway capacity we can't.
Can't concentrate a lot of activity in any one area you were just kind of keep it everything spread out to make sure we don't create any issues there.
Thanks, Dan for the time.
Thank you.
Thank you. Our next question comes from you May counter with Goldman Sachs. Your line is open.
Hi, Good morning, and thank you for taking my question.
My first question was on.
On your free cash flow allocation plans I mean, your balance sheet has improved considerably every initiated quarterly dividend.
As it looked at 2021.
Would love your thoughts on free cash flow location afterwards balance sheet reduction any further.
Foremost catheter don't switch Youre contemplating.
If there is any additional free cash flow that you're earmarking.
For the Western Haynesville area.
But thats a good question and yes, yes.
We're going to be very conservative.
Pharmacy.
What we do with the free cash flow.
As we kind of approach and formalize our capital budget for next year, that's going to be the first step in understanding what we need to invest in the western Haynesville and the base Haynesville.
And then I think we're very comfortable that the dividend we put in as a sustainable dividend. That's that's rock solid even with the much lower gas price.
That we have now in the futures market and so we will be conservative on.
Promising.
What the level of dividend is and then what other forms of return of capital we may want to employ but.
Again.
Yes, the balance sheet definitely has always come first so we're not going to we've got this new fortress balance sheet with tremendous liquidity seen a much lower cost of capital.
And we have we're not going to sacrifice that for any anything so that's going to continue to be the top priority and then we'll be very prudent and careful on.
On return of capital that we put in place next year, but there is a there is as you identified a very large gap between.
How much of the free cash flow, we've earmarked for the dividend and what we expect to generate.
But even prove up our conservative nature.
Rebroadcast it once we get leverage less than $1, five which we did that.
Last quarter, we still waited another quarter in order to initiate the dividend so.
Those actions tell you what we're going to try to do with that free cash flow will be very conservative with it.
Great. That's very helpful color and then I guess on the next question. Thank.
Thank you said the macro environment has been waiting for the data.
We have seen gas prices really tradeoff recently.
I was wondering how you're thinking about your hedging strategy.
As you would think towards next year noticed that you didn't add any hedges this quarter.
We are now on the gas price and gas went from <unk>.
$9 85 to $6 30 or whatever it is.
Hit model falls significantly, but its up significantly from where it was and I am looking over here at Dan's cost per foot.
The price of natural gas went up a whole lot.
A greater percentage than nickel foot went up.
So when we look at that we say if we do have a a fortress balance sheet.
If we're not looking to spend billions and billions and billions of dollars on M&A, because we don't think we have to because of the inventory that we have in the derisking thats going on.
We may look at.
At hedging and little different glasses.
2020 vision may be different than others.
We feel like.
Once we get into 2023 at this point in time.
Today, we're probably properly hedged.
With half of our production hedged at $3 or almost $10 ceiling.
As we get into the December see what the winter looks like.
What the storage really is it looks like and see what happens.
The oceans as far as the need for this gas and see where prices end up we'll always look at that.
It does.
We typically have 8% hedged all the time.
But I think our liquidity and our free cash flow number.
We will drive that.
That answer a little differently than it has in the past.
That's great color. Thank you. Thank you so much.
Yes, Sir thank you.
Thank you we have a question from Philips.
Philip.
Johnston from capital one your line is open.
Hey, guys. Thank you maybe just to follow up on the return of capital question, you mentioned that 50 cent dividend is very.
Sustainable and conservative.
I guess as you get more comfortable with returning more capital over time should we think about that base dividend.
Slowly marching higher over time or with the first priority is sort of the <unk>.
So look to other forms of returns whether its variables buybacks et cetera.
Thats a good question I think I think definitely valley.
<unk> the level of the dividend and as to the extent that we.
We say that production base is larger and then that and then that dividend is very sustainable at a higher rate I think thats something that will be the first thing to look at each quarter as we progress and.
We would look at other.
Potential.
Return of capital strategies, such as buybacks I don't think that.
Variable dividend is something that we think is that.
Something that we want to commit too given the.
Most of the shareholder feedback we've got has not been very favorable on variable dividend. So I think that I think we'd be looking at.
Maybe additional debt reduction just to continue to strengthen the balance sheet and then.
Potential share repurchase program in the future when we think that makes sense.
Yes, Okay, and then I guess, just the decision to allocate couple of rigs to the Western Haynesville next year.
I think that as well.
A little bit longer to drill any wells in your traditional areas of development. So can you maybe.
Talk about just the balancing act between wanting to delineate that area on one hand with sort of the tradeoff with maybe.
Less efficient capital program in the near term just in terms of.
Wells per rigs relative to this year.
Yes, that's a great that's a great observation because to the extent that you reallocated those wells back today.
Our traditional haynesville they would.
David create a lot more capital.
Because you know that.
They would drill a lot more wells so they would be more completion cost so so.
I think as we when we added that as we take that into account that the wells take longer to drill so at actual looking at the amount of capital per operated rig, yes, theyre going to actually going to keep that number lower but yes, we're very dedicated to continuing to delineate the play by play will tell us.
What's needed.
Proceed based on results and so so far the results have been excellent and so if we continue to have excellent results will continue to put in.
The resources.
And so that's.
I want to.
Push that play too hard because we want to learn from each well H well I think we've.
We.
Continuing to improve the drilling and completion design made.
<unk> made changes to things as we as we're learning about this play.
Again, we're going to let the results tell us what's needed and we're going to be patient and.
That push it too hard, but we're very excited about delineating the play.
Yeah, Thanks, Dan I'll just add.
We are all up we're pretty good learning curve, we've learned actually quite a bit on these first two wells we totally.
Expect as we just get a fee the fee further wells into the program.
See the cost and I think the dual times and all that are going to speed up the calls to come down so.
We're pretty confident we will see.
See that in the near future.
Philip.
Sure.
We're flooding.
We've set some pop even on our third well the Campbell will.
So we've got one that's been producing the circle and we've got one that we expect to turn to sales this month.
With further drilling a third well the Campbell.
So as Dan has commented Tom drilling results I think what we've learned from all of these wells.
And quite frankly, I think we're getting better on all of them.
Hopefully we can report on the Campbell.
Next call. So we'll see what happens it will be in February .
Sounds great guys I appreciate it.
Thank you.
We have a question from Paul Diamond with Citi. Your line is open.
Good morning, all thanks for taking my call first of all I wanted to jump into with just about kind of circling back on <unk>.
The potential timing and progress you guys have made on those kind of longer term contracts egencia permission.
And the next few months or is that more of a long term strategy.
I think thats more of a as part of a long term strategy I mean, I think that is that the shift I mean, there are a lot of opportunities out there that we've been approached with and we don't want to jump on the first one and found out that that's not the best opportunity.
So we're putting a lot of effort into evaluating the future markets.
And.
Lock it up yes longer term customers.
You have done some of those already and then.
But I think over the next yes.
Six months.
So I think thats kind of when you could maybe expect us to kind of come back and provide more color on kind of where we see our long term markets.
Understood. Thank you and just a quick follow up you guys have kind of.
Laid out.
Non rig plan seven in the core and then some split between higher single doses.
Macro perspective is there anything you guys can foresee that would cause a shift in that or is that pretty much set in stone for the next 12 to 18 months.
Yes, so our schedule I'd say I mean, we always shuffle things around as needed, but I would say, it's pretty well fixed for the next 12 months and we've got we've got.
The rig lines are built out for a couple of years, but.
We move projects around as needed if something arises but we.
We've got the <unk> acreage.
It takes little bit longer lead time in Texas to get wells drill ready so.
Probably middle to late next summer rig returning back on the Nacogdoches acreage.
We will have we will have a second rig in the western Haynesville, what we mentioned earlier, probably late this month or next month.
And the next year or so.
We definitely have the ability to move some things some stuff back over to Louisiana, but.
I would say to answer your question really it's fairly well fixed for the next 12 months with some minimal moving around.
Well as we commented earlier, we don't have any long term rig contracts. So if for some reason the market crash, which we don't see that we're pretty nimble you've seen us in the past we need to get rid of some rigs. We can do that if we need to add a rig or two you can see we're pretty nimble to do that too. So we're in the <unk>.
<unk> of the non rig subsequent <unk>, we haven't given any guidance for 2023.
Today.
Understood. Thanks for the clarity.
Thank you.
Our next question comes from Noel Parks with Tuohy Brothers. Your line is open.
Hi, good morning.
I don't know.
Yes.
Just a couple of things.
And your your leasing budget I think it was.
About $54 million you've leased year to date just curious what you are you are picking up with those we saw it.
Expired.
Lisa.
Never leased acreage just wondering kind of what's what's still out there to buy.
Now all of the above I guess.
And again that includes maybe where are our acquisition that we made so it's a combination of.
Maybe we acquired held by production properties that have the deep rights still available hasn't been developed at <unk>.
Some of the Chunkier parts of that and then new primary leases.
So it's just all of the above we have we've really grown our land department this year and to focus on.
Exploiting these opportunities that we see in the Haynesville. So.
We've added a lot of personnel have a lot of activity going on at the ground floor.
Yes.
Sacred if we can extend the lateral length of these wells.
We still have dollars budgeted for that if we can pick up.
Any deeper rights like Ron said, it's HBV.
We think this isn't a fair way of where we are.
Gathering.
We've looked at that aggressively to particularly if we can extend the lateral lengths and some of the acreage we already own.
The budget I think the more important part of that budget is.
When youre looking at.
At the analyst reports.
We're not budgeting for a big M&A activity.
Okay.
Right great. Thanks.
And talking about just as.
All the liquidity you have and the free cash flow you'll be generating.
I guess I was wondering about a couple of areas.
Wondering if any thoughts about or non operated holdings in the region and quite a bit of of trading of non op interest kind of across the industry.
And whether that's something to you.
Willing to pick up or something you want to try to get away from and also I'm wondering if we do face sort of an uncertain.
Gas environment next year.
Any appetite for taking some of your liquidity and exar.
Consciously deciding to build up.
Like could be a more ability to be opportunistic about one year to bring things on.
And those are some good questions on that non operated activity.
Yes. It is a very active area a lot of.
Buying and selling non operated interest we're more of a seller there we really don't like to be in properties that are operated by us.
So we typically yet.
Trade interest with adjacent operators. So we can each have our own operated projects to.
To the extent that we see there's a very active market for for participants they like to buy non operated interest in the haynesville. So.
So some interest to them, especially where we see lower return opportunity, we see a lower return.
Project compared to other projects in our portfolio. So we're probably more of a seller of that non op, we certainly arent a buyer.
Never be interested in buying non operated projects is that we want to we want to make sure that we protect our very low cost structure and are very good margins and we felt like they are the best in the industry. So most of the other projects that we see from other operators that have inferior.
Have inferior.
In that area, although that.
Gas prices have been high so it's not like those aren't very profitable projects. We just we just want to protect our our numbers.
Well known I think we'd like to control, where we spend our money.
Good thing is we've got such a large acreage footprint that we do have a lot of value a piece coming in is.
As a non op. So the question is we participated in those maybe we participate because we want to find out what's going on in that area.
Again like Robin said.
We have.
Accounts daily come in they would like to buy all of the non ops. So they're very easy to to sell down right now and we balance that with how much what is our budget for the year.
To try to hit a bunch of numbers to try to use those dollars to best we can to create.
The greatest return, we can with our own operations group.
We're pretty selfish.
That front.
And on the question about <unk> I think that we just don't like.
To put that kind of investment in wells and have.
That our drill because.
Yes.
We don't think it's the right way to manage the business. So.
From that both from that.
Landowner standpoint as far as drill.
Drilling the well and not put it on production.
I just think that's not something that we ever look at it as a good strategy and so we've never done that on purpose. Every now and then you can have a few dogs that get created.
Because of some issue, but it's rare.
Great. Thanks, a lot.
Thank you Bill.
Thank you and our last question comes from Leo Mariani with MKS Partners. Your line is open.
I just wanted to follow up a little bit on the the recent basis issues that you've been experiencing.
It looks like the Haynesville is a basin as kind of continuing to grow in the next couple of years do you guys foresee this could become a large ratio in 2023 and I guess do you have any strategies to mitigate that it does.
Well, it's a seasonal issue too because at this time of year is just that it all is last three years in a row October .
October and part of November is always wider as kind of the shoulder the transition from.
From yes from the injection into withdraw its always sloppy.
So that's nothing new.
Yes, I think what is that I think what's new or in this quarter is not so much we manage the Perry avail, Carthage basis differentials very well with our golf access.
I think what's different this quarter is that the Texas golf.
Markets, which have been premium markets, maybe some of the best premium markets have really turned around because mainly because of the freeport, where theyre, putting all of that gas into storage versus say data.
Using it for LNG. So that event I think that happened has really turned that Houston ship channel KD market into.
A wider market and that's what's that's what's affecting us really because we are protected against the other ones for the most part.
Okay. That's helpful. And then just on the dividend it looks like it's a decent sized committee.
Yes.
You both here.
That's almost 140 million Bucks.
Year.
Is that something that if you did see some weakness in gas for a couple of quarters next year would you guys be willing to borrow in the short term and pay the dividend or by the time, we might drop a rig or something.
Well I think that we've set that dividend level, where we just don't see that absolute complete collapse in prices that we can't support that without borrowing.
So it's a very conservative dividend.
And so that's why we said it's actually the exact same dividend we had in 2014, so its alone the <unk> for us.
Yes.
I guess, the right conservative level and I don't think that we foresee.
Any real probability that that we could maintain that without Bari I mean, I think that are looking at to extent that gas prices are prices, where that low we'd see pretty significant reductions in our capital budget, either either from us dropping activity because it didn't make sense or.
Because service cost would retreat to the low levels that they were back when prices were low in 2020.
So we think there are natural.
A lot of cost will track prices and Theyre also contract when prices.
The other way.
So yes, so we think given taken that account, we just don't see that scenario.
You mentioned being that possible.
Yes in fact, the board as we run a model at $2 $53 gas to $3 gas.
You don't cut back your Capex budget, which we would cut back that budget.
And in India, and all of those runs that we looked at.
We didn't.
She is using the bank credit facility for dividend payments at all.
Okay. Thanks, guys I appreciate it.
Thank you Leah.
I am showing no further questions in the queue I'd like to turn the call back to Mr. Jay Allison for any closing remarks.
Sure again, it's been a one flower.
The quarter has been great.
Look at natural gas prices are solid.
<unk> solid drilling locations are solid recovery at both locations.
The western Haynesville as Dan has mentioned.
It's been performing like Clockwork, So we're very positive on that.
And.
We're just going to continue to protect our liquidity.
And in and deliver on the news flow that we project, we will have in the future.
So things are good natural gas is needed and we've got a lot of it. So thank you for your time.
This concludes today's conference call. Thank you for participating you may now disconnect.
The conference will begin shortly to raise your hand during Q&A you can dial star one one.
[music].
Yes.
Yes.
Okay.