Q1 2022 Comstock Resources Inc Earnings Call
Today's conference is scheduled to begin momentarily until that time your lines will again be placed on music hold and this is the operator speaking todays conference is scheduled to begin momentarily until that time your lines will again be placed on music hold thank you for your patience.
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Ladies and gentlemen, thank you for standing by and welcome to Q1, 2022 Comstock resources incorporated earnings Conference call. At this time, all participants lines are in a listen only mode. After the speaker's presentation, there will be a question and answer session.
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I'd now like to hand, the conference over to your first speaker today, our chairman and CEO Jay Allison. Thank you. Please go ahead.
Thank you I know, it's a busy day in the world of earnings for oil and gas.
If you're an analyst for stakeholders. Thank you for the time that youre going to give us.
Welcome to the Comstock resources first quarter 2022 financial and operating results Conference call. You can view a slide presentation during or after this call by going to our website at <unk>.
Www Dot Comstock Resources' dotcom and downloading it.
Ordinary result presentation. There you will find a presentation entitled first quarter 2022 results.
Jay Allison Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Rod Mills, our VP of finance and Investor Relations.
Please refer to slide two in our presentation. There's a note there.
Our discussion today will include forward looking statements within the meaning of securities laws, while we believe the expectations in such statements to be reasonable there can be no assurance that such expectations will prove to be correct to pure flipped over to slide three and hand on.
What a great day to have an earnings call I mean natural gas has a 13 year high.
So gas I'll look to is at 850 for the 12 months representing eight forties.
It gives a company on <unk> hundred drilling locations in the Haynesville Bossier, which is a natural gas play nearest to LNG export terminals and yes free cash flow was up to probably $1 billion in 2022 at these prices and with our hedges in place and yes.
Someone has to come out and tell you that the oil and gas patch has some inflationary pressures there we're doing that at $8 54 natural gas price. It should be expected. If you look on three we cover the highlights of the first quarter on slide three in the first quarter, we generated $68 million.
Our free cash flow from operating activities with the free cash flow, we reduced our debt by $85 million during the quarter, our EBITDAX for the quarter came in at $333 million.
Operating cash flow of $297 million or $1 seven per diluted share revenues for hedging were $408 million.
Our adjusted net income for the quarter was $136 million or <unk> 51 cents per diluted share. Our haynesville drilling program is going very well as demonstrated by the fifth chain operated wells that we turned to sales since our last operational update that Dan Harris for review.
You momentarily the IP rates for these wells averaged 29 billion cubic feet per day. So now I'll turn the call over to Roland Barthes go over our financial results Roland.
Thanks, Jay and slide four we compare some of the first quarter financial measures to the first quarter of 2021.
Pro forma for the sale of our Bakken properties, which we completed last October our production increased 3% to one three Bcf a day.
Our adjusted EBITDAX for the first quarter grew by 33% to $333 million driven mostly by stronger natural gas prices, which is also supported by the fact that we were a little less hedged than last year. So we were only 52, we were early yet.
About 67% hedged this quarter versus in the 70%.
Area last in the fourth quarter last year.
We generated in the quarter $297 million of cash flow, which was a 52% increase over the first quarter of 2021.
And on a per share basis, that's $1, seven which was 75 cents higher than the first quarter of 2021.
We reported adjusted net income for the quarter of $136 million, 114% higher than the first quarter of 'twenty, one and our earnings per share were 51 cents as compared to 25 cents in the first quarter of 'twenty one.
We generated $68 million of free cash flow from operations in the quarter, 73% more than we generated in the first quarter of 'twenty one.
The growth in our EBITDAX.
And the Paydown of debt that we have we achieved in the first quarter drove a 30% improvement to our leverage ratio, which improved to one nine times down from two seven times in the same quarter of last year.
Improved natural gas prices were the primary factor driving the strong financial results and this quarter on slide five we break down our natural gas price realizations on the slide we show that Nymex contract settlement price and the average Nymex spot price for each quarter, including this most recently completed first.
Quarter.
During the first quarter there was another significant difference between the correlate Nymex settlement price, which was $4.95 per Mcf in the average Henry hub spot price, which is $4 60.
And this difference is primarily due just to the high settlement price that the February contract had.
During the quarter, we dominated at 69% of our gas to be sold at index prices, which are more tied to that the contract settlement price and then we sell the remaining 31% in the spot market.
Therefore, the appropriate Nymex reference price for our sales in the first quarter would have been about $4 84.
For Mcf.
Our realized gas price during the first quarter averaged $4 55.
Reflecting a 29% differential which is more or less in line with the prior quarters.
In the first quarter, we were 61% hedge so that reduced our realized price to $3 53 since the first quarter realized price after hedging was still 27% higher than the first quarter 'twenty, one and it was 18% higher than the fourth quarter of last year, even though nymex prices were down in the quarter.
And this was mainly due to the decrease in the percentage that we were hedged and this first quarter versus the fourth quarter of last year.
We also generated third party marketing income in the quarter of approximately $4 million.
Using the spare capacity, we had on some of our premium marketing contracts. This added another three star overall natural gas price realization in the quarter.
On slide six we detail our operating cost per Mcf and our EBITDAX margin operating costs per Mcf averaged 69 cents in the first quarter <unk> higher than the fourth quarter rate.
Our lifting costs in production and severance taxes, both increased by <unk> <unk>, while our gathering costs remained unchanged.
Our G&A costs, though came in <unk> <unk> lower at <unk> in the quarter.
Our EBITDAX margin after after hedging came in at 81% in the first quarter.
Crude from the 78% margin, we had in the fourth quarter of last year.
On slide seven we recap our first quarter.
Spending on drilling and other development activity, we spent $224 million on development activities in the quarter 187, meda that related to our operated Haynesville and Bossier shale drilling program.
We also spent another $14 billion on non operated wells and $23 million on other development activity, including a lot of workover work and to be not that we did on older wells in the quarter.
In the first quarter, we drilled 15 or a $13 one net TASS operated horizontal haynesville and Bossier wells and we turned 20 or $14 six net operated wells to sales in the quarter. We had an additional six net non operated wells that we turned to sales in the quarter also.
Slide eight we show our balance sheet at the end of the first quarter, we had $150 million drawn on our revolving credit facility at the end of the quarter after repaying the $85 million during the quarter.
The reduction in debt and the growth in the EBITDAX, we had in the quarter.
Continue to drive substantial improvement to our leverage ratio, which we said earlier, it's down to one nine times in the first quarter compared to two seven times in the quarter the first quarter of 'twenty one.
We plan on retiring an additional $394 million of debt over the rest of this year, including redeeming. Our 2025 senior notes on May 15th we have already issued a formal redemption notice for those notes.
We're targeting to have our leverage below one five times levered and <unk>.
2022, and these high gas prices are making that happen very very quickly.
We did in the first quarter with financial liquidity of almost $1 $3 billion.
Now I'll turn it over to Dan to kind of talk about our operations in the first quarter.
Okay. Thank you Roland.
Over on slide nine.
This is a graph that shows the progression in our average lateral length drilled by year going.
Going back to 2017, along with our current average lateral length for the quarter and a record longest lateral completed to date.
Since 2017, our average lateral length has grown 725 feet on average every year.
And our average were at 9858 foot average for the first quarter as we continue to integrate more of our extra long laterals laterals greater than 11000 feet.
Into our drilling program.
By year end, we anticipate our full year average lateral to increase further to approximately 10250 feet.
As of today, we have drilled 615000 foot laterals.
Four of which have been completed including a record a longest lateral completed today to 15291 feet.
We're currently drilling an additional two wells with 15000 foot laterals.
In 2022, we anticipate drilling 24 extra long laterals exceeding 11000 feet with 15 of these wells.
Having laterals exceeding 14000 feet.
We are expecting the longer laterals to play a key role in minimizing the impact of inflation as we move into a higher cost environment.
On slide 10.
This is a plot of our updated D&C cost trend for our bench Mark long lateral wells. This includes all our wells with lateral lengths greater than 8000 feet.
Our D&C cost averaged $1124 a foot in the first quarter. This is an 8% increase compared to a full year of 2021 D&C cost.
In the 9% increase versus the fourth quarter of last year.
Our drilling costs increased 13% in the quarter to $450 a foot while.
While our completion cost increased 5% up to $673 a foot.
It's also the cost increase is primarily due to the higher cost of services that have arisen during the first quarter.
With the sharp increase in commodity prices and demand for services in the last couple of months, we have experienced additional cost improvements.
As mentioned earlier, we see these longer laterals as a means for us to further improve our efficiencies to alleviate some of these cost increases.
Slide 11 is a summary of our first quarter well activity.
Since the last call we have turned to sales 15 additional wells.
The wells were drilled with lateral lengths ranging from 4428 feet up to 15291 feet.
With an average lateral of 10115 feet.
We have some really good performance from this group as a whole with the individual wells tested at rates ranging from 24.
<unk> cubic feet, a day up to 37 million cubic feet a day.
And with an average IP of 29 million cubic feet a day.
The first quarter results also include the completion of our third and fourth 15000 foot laterals.
And these same wells also represent our first 215000 foot laterals that we've completed into the Bossier.
The BSM CLA five 817 number one and number two wells were completed with laterals of 15000.
291 feet and 15373 feet.
<unk> tested at rates of 24 million cubic feet, a day and $27 million a day.
We are currently running seven rigs and three frac crews running full time across our acreage.
And on a one last night I did want to mention that as early last month, we have deployed our first 100% and natural gas powered Frac fleet.
The operation of the fleet is off to a good start we've been pleased with our progress.
I will now turn it back over to Jay to summarize our 2022 outlook.
Alright. Thank you Dan. Thank you all again, what a great day to have an earnings call with <unk>.
54 gas being a pure publicly traded Haynesville Bossier producer.
Sure.
Greg corporate background, if you go to 12.
<unk> you to slide 12, where we summarize our outlook for the rest of the year.
We expect our 2022 drilling program to generate 4% to 5% production growth year over year.
And we now expect to generate significantly more than the targeted $500 million of free cash flow at current commodity prices.
Given current strip prices on our existing hedge position, we anticipate generating anywhere from 800 million to a $1 billion and free cash flow in 2022.
Top priority or the first priority of the free cash flow generation is to reduce our debt level to pave the way to re initiating a return on capital program. Once certain goals are met we plan on reinstating a dividend and we will set the initial dividend at a conservative level to be sustainable even in a low <unk>.
Gas price environment, we are redeeming the 244 million outstanding on our 2025 senior notes on May 15th and we expect to pay the $150 million of remaining borrowings.
Standing under our bank credit facility. We are also earmarking up to $100 million for bolt on acquisitions and additional leasing activities.
We're targeting a leverage ratio as I've mentioned earlier of less than one five times before initiating our return of capital program.
Again, with a rapidly improving leverage profile and substantial free cash flow generation expected for this year, we are looking towards reinstating our shareholder dividend as early as the fourth quarter of this year as expected we are experiencing cost increases for our drilling program. This year given the high active.
City level and the Haynesville the longer lateral lengths as Dan mentioned this year's program will.
Create improved capital efficiency to partially offset some of the higher service cost.
Lastly, we will continue to maintain and grow our very strong financial liquidity.
I'll now turn it over to Rob to provide some specific guidance for this year Ron.
Thanks, Jay on Slide 13.
We provide financial guidance for the second quarter and the full year 2022.
We are providing the initial second quarter production guidance of $1 three one to 138 Bcf a day and the full year guidance has remained unchanged at prior levels of $1 39 to 145 Bcf a day.
During the second quarter, we plan to turned to sales 11% to 15.
Net wells the biggest change on the guidance page is the development capital, which.
For the full year, the guidance is $875 to $925 million, which incorporates an additional 15% increase in service costs from our prior estimates when we last provided guidance in February our.
Our 2022 wells will have an average lateral length being approximately 16% longer than last year, which is helping to offset some of the inflation.
In addition to those D&C.
Dollars that we'll spend it on the drilling program, we could spend up to $100 million on bolt on acquisitions and new leasing.
On the cost side LOE is expected to average 20% to 25 in the second quarter and for the full year, while gathering and transportation costs are expected to average 26% to 30 in both the second quarter and the full year.
As gas prices have increased.
Our production and AD valorem tax guidance is increased to 14% to 16 per Mcf.
Is that just related on gross pre hedge.
Sales revenues.
<unk> rate is expected to remain in the 90% to 96 per cent per Mcf range, well cash G&A is expected to total $7 million to $8 million in the second quarter and 29% to $32 million in 2022.
On a quarterly basis, the noncash G&A is expected to run approximately $2 million per quarter.
Cash interest during the second quarter expected to total $38 million to $42 million and $150 million to $260 million for the full year, which includes the impact of the redemption of our seven 5% notes here in the middle of this month.
Effective tax rate for the year expected to be 20% to 25% and we now expect to defer 75% to 80% of our taxes given the significantly improved commodity price outlook, we no longer are we.
We now anticipate our current taxes, representing a larger portion of reported income taxes.
Now I'll turn the call back over to.
To the operator to answer questions from analysts who follow the company.
Thank you as a reminder to ask a question. Please press star followed by the number one on your telephone keypad again that is star one to withdraw your question. Please press the pound or hash key please standby, while we compile the Q&A roster.
Your first question comes from the line of Derek Whitefield with Stifel. Your line is open.
Thanks, Dan Good morning, all.
Yeah.
With my first question Jay I wanted to focus on your 2022 plan and your confidence in executing against it and consideration of the operational environment. You guys are facing in the tightened and services supplies and labor.
Have there been or do you expect any business impacts beyond inflation and.
And if I could add a second part to that question are there any unique factors specific to Comstock that makes you more susceptible to the industry inflation.
Yes. This is Dan I'll say.
As far as for the first part of your question on the long laterals somebody we've got good relationships with all of our suppliers.
We don't really see any.
Really additional risk in that regard.
As far as.
The second part I think what it is is on the Capex increases, it's really just probably more of a bolt on.
Little bit of a localized demand for services here with the ramp up in the number of rigs just in the Haynesville area and the high gas prices.
It's just been it's really been across the board we've seen it in all services that kind of started out with really probably the bigger ticket items.
The rigs the frac crews, but obviously the cost of diesel.
It was dragging up everybody else's Costa services also.
I would also add that we do use two or three different service companies as far as drilling contractors and in two or three different Frac company. So were not isolated with one company.
As Dan said, we do blend it out and we do have competitive bids.
And this is where we've landed.
Got it.
My follow up.
Looking out beyond 2022, and thinking about your unique position in the LNG corridor.
How do you envision the role that Comstock will play in the multi year opportunity ahead of us to address European supply need.
And further how would you like to position Comstock in the value chain for LNG offtake to maximize your exposure to higher prices.
Well you know as of April 1st, we're selling gas correctly to ever LNG facility in Louisiana.
So that's only a month ago, when we were doing that I think that.
As you're well aware of where our location of our appeals or it's the closest major gas field.
Two LNG export facilities.
We've got more on dedicated guests than any other producer there I believe so.
We plan on being a material supplier of gas it's needed.
Both in Asia and Europe .
And that's really that's driven by the location that we're at.
And we started doing it you know 14% of our current guests so to LNG facilities.
And then 66% you talked about costs is sold to.
To the Gulf Coast market that your LNG market.
We're well positioned to do that with the high margins and low cost that we can.
Continue to put up quarter after quarter end.
And the success, we've had like that Dan has hit on the drilling of the wells less 15 wells you see the.
Extended laterals had.
And even the efficiency we've had in our inventory we took our inventory from about 1900 locations to 1600.
And all of those became more valuable than where they located they are located.
Near where the guests to go when it is LNG overseas.
Eric I had anticipated.
Yeah, I would just add that that is kind of the direction.
We expect to be selling more and more of our production directly to the LNG shippers and.
Constant.
Cogs looking to develop long term relationships.
With them and continue to tie more and more of our gas to the Gulf Coast.
Texas versus the regional hubs of Carthage and Perry Bill.
That's very helpful. Thanks for your time.
Thank you good question.
Your next question comes from the line Oh manage how do we even need Goldman Sachs. Your line is open.
Hi, good morning, and thank you for taking my questions.
History.
I appreciate the comments on costs and inflation I wanted to get your thoughts on what Youre doing differently on supply chain services to manage cost today not only just for 2022 program, but also looking ahead between 'twenty three.
Yes. So this is this is Dan.
I mean, obviously we've got.
Our first 100% gas fleet that we just put into service.
A month ago, we do we did signed a long term deal on that so thats going to keep us somewhat protected over the next few years on our.
Our frac cost we have.
We enter into some longer contracts when we can we bought though.
We bought ahead on all of our pipe tubing casing.
So we do stay kind of protected on that eventually those prices do roll off in the future and you're buying you're buying that.
Future process.
To look out even further but.
I think the main thing is just with our level of activity the relationship with our vendors.
We feel pretty protected therefore future cost increases I think we got a little bit of leverage there.
Great. Thank you.
And then the other question was on our non operated activity you mentioned you could potentially be hired and trained when you do any impacts to production from higher non op activity this year or next year.
So do you see any increase in chicken production offsetting any production benefits.
Most of the industry is bringing online minutes in Q2 and Q3. So I'm just trying to understand if there is any risk to growth.
Yes, good questions outside this is Roland.
Yes, the non op activity, we did see additional non op cost here in the first quarter we.
We saw some non op re fracs, which are not right.
Quite common in the lower price environment.
We don't have a huge exposure to non op, because we have very high working interest, but we have some and and the projects are also there.
We have such high returns, it's very difficult not to participate so we don't like to count on non op activity for you given your guidance on production. So hopefully there'll be a little upside from as those come on.
And we see it.
That's part of the overall level of extra Capex, we had to provide for was just higher level of non op. That's out there that we kind of expect and really want to participate in because.
There are such high return projects.
With the high commodity prices and shut in time, yes.
Our first quarter, we we had about a 4% average shut in time, which is very normal.
For us four years to 5% is kind of what we always expect.
We've tried to manage that better by grouping, our our kind of completions together in larger kind of units. So we can kind of get that done at one time like the seven wells that we that we actually had to put.
Put online all at the same time kind of in our high kind of production area of Elk Grove.
So we tried to manage that as best we can.
We're fairly.
Hum.
We have some offset operator influence over our over our production but.
Our acreage is fairly blocky and.
Yes, more or less.
Yes.
And how much were shut in just by our own activity, but we do try to schedule and plan to minimize that because that's a big factor.
And yeah, but always it but really.
To keep it in that.
3% to 5% level as kind of the norm we expect.
As you are asking the questions about.
Non op opportunities and cost.
It probably is a good time to address that we said, we'd kind of earmarking, a 100 million for bolt on acquisitions.
That number out I mean, we're not may not spend that number. Another reason, we threw that number out as if you remember in December .
We had on East, Texas bolt on acquisition for $35 million and we picked up about 58 net drilling locations thats about a year's worth of inventory at 94% of that was HP.
44 of our existing Comstock locations, our laterals extended because this new acreage. So we did put put a number out there to earmark that.
If we see something like that then don't be surprised if we would go forward on it.
It's not that we have to spend that but we just wanted to throw that out there to show you that.
Even if we spent that on bolt ons and additional leasing activity.
We've got this $1 billion of free cash flow etcetera, we think that our leverage ratio will come down.
Material it might be below that one five times, so that we can take a serious look at it.
Reinstating a dividend that's why we put that out there just for total clarity kind of like we have clarity that you should expect inflationary pressures at $8 58 for natural gas in the Haynesville.
Got it I appreciate your comments thank you.
Sure.
Your next question comes from the line of Neal Dingmann with true is your line is open.
Good morning Al just on that last question, maybe I'll ask just a bit of a call just on the Oss and placement.
Guys.
Probably boosted the anticipated cost I think for the rest of the year by about 16% for overall 22 I'm just wondering.
Given the uncertainty with inflation and you and most others are kind of rig are well to well on your rigs and tracks.
Type of confidence do you have that.
Going to be high enough for the rest of the year.
I think it's a really high number I mean, I think we're one of the first ones to come out with.
A 10% number I mean, maybe at the end of the year and then in our <unk>.
Drilling is up.
Cost dropped by 13% our completions were up like 5% on our total.
D&C cost of about 8% I think that we've got a pretty good handle on it.
And I think we've added a little bit more to it.
Just for wiggle room to make sure that our second third and fourth quarter numbers for good now.
Again, you take.
You look at a six <unk> environment, which was we were at last Friday.
This is an 854 environment, even the 12 month trip.
You may see a little more of this we don't expect it.
But but but.
But we want to be honest about it.
Where we are right now, but no we don't expect and I think we're the first ones to come out on an earnings call and say, yes someone has come out and tell you that.
The oil and gas purchase inflationary pressure.
Done that I think we've given the right number of <unk> given the rise signal.
So if you bake that in your numbers I think we're going to be will be pretty pretty correct at less.
Hello gas goes to that 10, plus dollar number and.
Everybody made mobile a little bit more money to drill and complete wells.
Good Thanks for the guide and then just follow up for maybe you roll in or Ron just isn't really on cash returns.
Just wondering ballpark how quickly today at today's strip now I mean, you mentioned started the call obviously fantastic prices. So how quickly at today's strip, you anticipate being able to starting to cash return program.
And will this I forget what you all have exactly said well. The program. Initially consist of just exclude see dividends as you mentioned about wanting to pay out high enough for the holders of would you consider some buybacks as well and this begins.
That's a good question, yes, obviously with the.
A bunch of much higher commodity price environment is accelerating everything but yes.
We don't want to get ahead.
Our plan so the centerpiece of our this whole year is the bond redemption.
We're coming up to that we want to check the box there and get the debt reduction all completed which probably happens.
A lot quicker than we thought earlier and then really I think we are signaling that at least by that.
By the fourth quarter for sure hopefully reinstate the dividend that we have that had since 2014.
But those are all very key and I think after that we have guided that hey, we do want to invest in.
And our overall footprint in the Haynesville, So, we're saying we earmarked $100 million.
Toward lease acquisition bolt ons might not be able to spend all of that this year, but it's a priority.
So that's the reason why we signaled that and.
And lastly, you know I think we will consider other forms of return of capital after after all of those things.
Have been completed.
I think in the.
And the scope of that question, we need to tell you that we are not chasing.
Any large corporate acquisitions.
So you can you can put on X to that we're not chasing any of those.
It should we're going to target these smaller bolt on ones and we've been successful in doing that.
The other thing.
You could put a big Exxon, we're not looking to make an acquisition in the haynesville to scale up production.
At an expensive price, we're not looking to do that either so if you look at where we would be spending money you can mark those two out.
Where we'd be spending money it is not out of basin.
It's the Haynesville Bossier.
Uh huh.
And if you look at what we'd be doing that money, we're going to get this leverage ratio down as low as we can get it.
We would look to reinstate a dividend that would that would that would be there even when gas prices are lower.
It's important and I guess, the other comments you ask about inflation.
If if if gas prices go up.
You know, we're going to have a lot greater increase in free cash flow versus what the inflation might be.
So.
I was just going to mention that Jay I think that's exactly right I. Appreciate the details. Yes go ahead I'm sorry, I think the other thing to add is that as we progress through this year.
Less hedged every quarter and we're participating more in the higher prices, even this year's hedge position as well.
A little more than half into collars. So yes, we're participating a lot more in the higher prices.
And as we progressed through this year.
Every quarter, we will participate more and then in 'twenty three we are participating almost fully in the.
Futures prices.
So that's a big change that house will happen in the company compared to kind of last year.
Great details thanks, guys.
Your next question comes from the line of Charles Meade with Johnson Rice. Your line is open.
Good morning, Jay and Roland into the rest of the contract crew there.
Sure Charles.
Jay you touched on this this 100 million for bolt ons, a bit already but I wanted to explore this a little bit more.
You already made the point <unk> been successful with these deals.
In the last several quarters, but what has changed.
What has changed that makes you went up.
Prepare the market to prepare analyst for $100 million. This year as it is at the opportunity set that's changed that the opportunity.
Looking richer or is it perhaps alternatively your appetite for <unk>.
Going after these bolt on deals has changed.
Thank you for some but I think what's really changed Charles I think there are we think there are good opportunities and we do think we're going to do some and so we have.
<unk> unique to us we've got opportunities to do that.
We really as people are looking at the free cash flow and debt reduction goal is going to be finished when we don't have a lot of pre payable debt. We just wanted to set aside that thats something that we want to have established and we want to have that money reserved for that opportunity. It's not that we are.
Probably take that.
It's not a huge change in the availability, but we just wanted to say as people are looking we just wanted to make sure. The market's focus that hey that will be something that will be due and also.
Out of the free cash flow, we're not going to do it with additional leverage and that's really what we're just trying to properly signal is as we're getting very close to our return of capital programs being put in place we want to have everybody. They can have all the right priorities.
I think we wanted to have enough wiggle room out there with the audience Charles like you and others that if we added some new acreage or if we did a bolt on.
And the $30 million to $35 million range kind of like the last one that it wouldn't be a surprise to you in other words, we didnt. We wanted you to put that in your numbers because even when you put it in your numbers.
Really really strong that was.
This followed a foreshadow of what we're doing is just trying to be have clarity to tell you what we might be doing if that opportunity comes along.
Got it right I think if I understand right its because youre deleveraging is happening more quickly you guys want to make sure. That's in the picture too. So some people have the right China.
<unk> spot four for year end.
Right.
Absolutely correct.
Explain our appetite for that type of activity, we think thats a number that well encompasses.
We could possibly do it may take more than a year to do that but.
You will see us spend dollars and we as we can pick up additional acreage even in the first quarter. We had yes, we had a modest amount of that spending in that category, but I don't think you can look at us trying to buy some controls that would.
<unk> increased the amount of wells, we have to drill either in other words I think this is a good point.
The bolt ons, we did in December was 94% HP P. J gave us two years' worth of drilling and it increased our lateral lengths on existing locations that we had in other words.
It compliments us like that that's what we're looking for those are a little harder to find but we're just we're broadcasting that if we did find something like that.
We think you'd want us to do anyhow.
Shedding those dollars aside period got it got it.
And then my follow up question is on your Capex trajectory over the year, if we look at.
What you did <unk> and then your guide for <unk>. It looks like <unk> is is the peak capex year, but capex quarter, but then it trails off significantly in the back half of the year. So it is activity going to follow that same trajectory or is there something else in there.
The picture that.
I should be thinking about.
So it's really the timing.
The biggest production growth quarter is going to be the third quarter and so you end up spending more money in the second quarter ahead of the production.
And so it is just.
In our in our current D&C schedule is the.
The timing of the completions and when those wells are turned to sales.
But but it's not it's not you guys. So it's maybe a reduction in completion activity in the back half of the year, but it's not a reduction in rig activity if I understand right.
No it's not.
I think.
Dan mentioned.
The number of of.
Long lateral wells, we were going to we were going to drill.
This year end.
Even even the number of greater than 14000 foot and so some of it's probably the timing of when those those drilling and completion dollars are spent but it's no change in in the rig count or the.
Frac fleet count, Yes, we use some of the Charles we use some of our are our operated rigs and operated frac crews for for.
For third party activity, including the.
What we do with our majority stockholder and I think just the way the schedule works.
The activity on that front is as is.
Ramping up in the third quarter.
Compared to the second where maybe I think we're probably using almost 100% of the.
Of our operated <unk>.
Services for our own staff, so I think that there is.
I'm pretty certain that we do have.
Our ramp up of activity.
And at Wells that we have a little bit lower working interest, which also have a kind of influence on how that the cadence of the capital spending.
Right. That's all helpful detail. Thank you Roland Thank you Ron.
Thank you.
Your next question comes from the line of Phillips Johnston with capital One your line is open.
Hey, guys. Thanks.
Okay.
Just to follow up on the earlier.
Question, you mentioned about 14% of your volumes are being sold directly to LNG shippers and that should grow over time.
Give you more exposure to Gulf coast pricing, rather than more regional pricing.
My question is is there any potential over the next few years to sign long term contracts that are more directly linked to international gas prices and.
Maybe capture.
Some of the economic rent on the large.
Or about there.
Yes, that's a great question I think that right now we see directly supply in the LNG shippers, but probably more at Henry hub pricing I think we do have.
Our new long term supply agreement with one of them. That's a 10 year agreement that has.
It's priced off of Nymex very tightly off an IMAX nymex minus a penny or so.
But as far as participating in.
International pricing I think that's.
Yeah that that's something we're exploring.
I think you actually have to own the facilities I think as you start to potentially invest in owning the facilities I think you can probably achieve that.
Because you actually physically need to be able to participate in that market to do that the right way, we don't when I try to do that through derivatives and have.
Have unusual price changes cause us.
Not to be correlated with our physical sales, but I think that we're exploring that and I think other maybe producers are exploring it may be that we have an equity in these facilities and then from that viewpoint than you would have the ability to do that.
To use some of that capacity you own two maybe.
Actually selling in a different market.
Yes, yes.
Question Thats the logical.
Good.
For us to look at is we have been looking at it.
Okay guys. It sounds good thank you.
Your next question comes from the line of Steven that correct with Keybanc. Your line is open.
Hey, guys.
Based on our math it looks like production has increased by about 9% in the second half of 'twenty two versus the midpoint of your second quarter production guidance at the bottom end of your full year 2000, 22022 production guide.
Do you see any challenges in hitting that number.
I mean, one curve for our drilling schedule.
No.
We would have updated guidance if that would have if that would've been the case I think.
When I when I look at it.
Kind of a sequential growth rate.
I don't know if I get all the way up to 9% in in.
In the second half of the year.
To get there.
I'm in the mid <unk>.
The upper single digits, but I don't think going all the way up to 9%, but yes, we did.
Earlier, we increased our rig count increased our activity levels.
Began this year, but if you are if you really look at the way that the.
When you start drilling.
And yet you do these.
We do these wells and multi well pads two to three to four together. It takes almost six months before you start seeing the fruit of that investment and I think that's really the second half of the year. Yes. It was always the higher growth part of our year as we are seeing.
Yes.
The investments we started to make in as early as they have been this quarter starting to come online.
We do have I think we have.
Some increases that we expect in the second quarter as we've got to take that.
And that lag is why the third quarter as is the highest growth.
<unk> growth period of the year.
Yes.
It's just really the nature of these or we drill high volume wells.
Yes.
Perfectly because theres only so many of them. They just don't come in a balanced way and so that's kind of the nature of our business. It's.
It gets a little lumpy. This is that it really is is the fact that we added the two rigs back in February by the time those flow through the pipeline.
Time to drill the wells complete the wells, you'll see that show up until later in the year I mean, thats really the primary at the Ats.
Yes, the easy answer.
Okay, great. Thank you.
Thank you.
Your next question comes from the line of Noel Parks with two brothers. Your line is open.
Hi, good morning.
Good morning.
I will stop.
To ask you about.
Lang from just sort of give us some perspective.
Can you talk about the technical piece and the land piece.
Enabled an increase the lengths you've already taken.
<unk> taken them over let's take them over 10000 this year.
Versus 8800 last year. So if you go to sort of break that out that'd be great.
Well I'll start with the land piece.
You have to have the land piece available obviously to even have the opportunity to drill the 15000 foot laterals.
It's a little bit different between Louisiana, and Texas, and Louisiana, Obviously, you got sectional unit so.
You've kind of got some preset.
Links you can you can pick the drill you can drill one section you can drill.
10-K, two sections, where you can drill three sections of the 10-K or you can drill.
200, 7500 foot laterals instead of 115000 foot lateral.
Over in Texas, you basically got the acreages and units that are just random sizes and shapes, though.
Really it's just kind of more random links I mean, you could have some 11000 foot laterals 13, just any number that you want to make it if you've got a big enough position.
So we're fortunate in Louisiana that we do have a lot of areas, where we can drill to have the opportunity to drill a 15000 foot laterals.
And we do it is obviously way more economical and the benefits are so much greater to drill $1 15, and $2 75 hundreds.
And on the technical side I mean, really we were very confident we could drill 15000 foot laterals.
The ones, we've drilled to date from.
From a tactical perspective, we've had no issues drilling 15000 foot laterals and completing them.
Getting them to sales so we've been super excited about what we've accomplished to date.
We're super confident in our ability to execute on the long laterals in the future.
We even foresee maybe a few laterals longer than 15000 foot in the near future.
<unk>.
Any I think really for US you know with the increase in industry activity we've seen.
Just kind of the downhole tool reliability has suffered a little bit.
The amount of tools coming into the shops and go on back out maybe from acute quality control standpoint.
That's probably the biggest battle that we're fighting today, but.
As far as the 15000 foot themselves and making things more difficult that has not been the case.
Got it.
<unk>.
Oh I was just.
Just wondering about.
Your suppliers.
General and.
I understand what.
What youre, saying about.
With your size it's it's.
Easy to have some negotiating power.
The thing about the logistics and whether your suppliers have been able to maintain some stability in their labor forces are or are they.
Affected to a degree that affects you around about people hopping around.
Labor cost pressures and so forth.
Well, we haven't seen anything really to date I mean, obviously, we've part of these cost increases has been labor related.
We have seen coming from all of the.
Two rig providers in both of them basically have come forward with cost increases.
For the increased cost in labor.
So that's part of it.
I think on the service side as far as our tools.
<unk>.
They've had.
I think things got pretty tight maybe with some of their suppliers will just kind of services there.
Some of the tools, but.
That kind of comes across to us as a cost increase.
The way for them to try to mitigate that into.
Just just not let that affect our business.
Great. Thanks, a lot.
And there are no further questions over the phone line at this time I'd like to turn the call back to our speakers for closing remarks.
Alright, again again start this.
Just a great day for earnings call natural gas 13 year high. It's at 854, you look at that.
The performance, we've had quarter to quarter I mean.
We've had a great quarter with the 15 wells that we turned to sales in the first quarter 'twenty. Two if you look at just the catalyst for natural gas I mean, you've got international supply disruptions, you've got the U S inventory, 18% below normal you've got constraints on service sector, which we factored into our numbers.
You've got storage inventory low in both Europe and Asia, you've got the <unk>.
<unk> got Comstock.
The zip produce dry gas is the cleanest fossil fuel.
Its abundant it's needed just reliable.
You look at where we're comfortable that we're comfortable where we're headed.
Might be a $1 billion of free cash flow.
We're the only pure play Haynesville publically traded company, you've got 25 years of drilling inventory.
Again, we.
We really do we are an industry leader in margins good great free cash flow.
And we've got a low cost flexible gas marketing options, which are one of the questions was about so.
Take a look at us. Thank you for the time, if you could just spend it elsewhere. We appreciate it.
We'll put it in a good day's work for you. Thank you.
Ladies and gentlemen, this concludes today's conference call and we thank you all for participating you may now disconnect.
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