Q2 2022 Comstock Resources Inc Earnings Call
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The conference will begin shortly to raise your hand during Q&A you can dial star one one.
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Okay.
Thank you for standing by and welcome to Comstock Resources' second quarter fiscal year 2022 earnings conference call. At this time all participants are in a listen only mode. After the speaker presentation. There will be a question and answer session to ask a question. During the session you will need to press star one one on your telephone.
I would now like to hand, the call over to Jay Allison Chairman and CEO . Please go ahead.
Alright. Thank you you've got a good tone. This morning, you start everybody on Friday may.
I would tell you we're thankful to be a.
Our natural gas producer in the Haynesville, which we think is the best basins in North America to have dry natural gas so.
Welcome to Comstock Resources' second 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 www Dot Comstock Resources' dotcom and downloading the quarterly results presentation.
Find a presentation titled second 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 Ron Mills, our VP of finance and Investor Relations.
Flip over to two please refer to slide two in our presentation and note that our discussions today will include forward looking statements within the meaning of securities laws, while we believe the expectations of such savings to be reasonable there can be no assurance that such expectations will prove to be correct.
Now.
Start to real presentation slide three the second quarter 2022 highlights.
I'll cover the highlights of the second quarter on slide three.
And the second quarter, we generated $190 million.
Operating free cash flow.
Shall retire $231 billion of our senior noted notes, including the redemption of our seven five senior notes. We have said when we acquired Covey Park, and we repurchased 26 again of.
Of our six and three quarter senior notes in the open market.
We brought our leverage down to one two times, our EBITDAX for the quarter came in at $515 million or 105% higher than last year, our operating cash flow increased 133% to $458 million or $1 65 per.
Sure.
Revenues after hedging for the quarter were $604 million at 86% higher than last year. Our adjusted net income for the quarter was $274 million or dollar per diluted share. Our haynesville drilling program is going well as demonstrated by the 14 or.
12, six net operated wells that we reported on this quarter with an average initial production rate of 26 billion cubic feet per day.
We completed a very attractive bolt on acquisition, which included approximately 60000 net acres perspective for the Haynesville and Bossier shale and a 145 mile high pressure pipeline natural gas trading plant for $36 million.
We also achieved certification for our natural gas production under the <unk> standard for methane emissions measurement.
<unk> incremental stewardship.
I'll now turn the call over to Roland Burns to comment on our financial results Roland.
Alright, Thanks Jay.
On slide four we recap the very strong financial results, we had for the second quarter.
Pro forma for the sale of our Bakken properties, which we completed last October our production increased by 1% to one four.
Cubic feet equivalent per day.
On a pro forma basis, our adjusted EBITDAX for the quarter grew by 122%.
Over 2021 second quarter to $515 million and it was driven mostly by stronger natural gas prices.
We generated $458 million of cash flow during the quarter, 159% increase over 2021 second quarter on a pro forma basis.
Our cash flow per share during the quarter was $1 65.
Up from 71 sets.
For the second quarter of 2021.
Our adjusted net income for the second quarter was $274 million, a 454% increase from the second quarter of 2021 and earnings per share came in at $1 as compared to <unk> 20 in the second quarter.
2021.
We generated $190 million of free cash flow from operations in the quarter, 586% higher than the second quarter of last year.
The growth in EBITDAX in the retirement of our senior notes in the quarter.
Drove a substantial improvement to our leverage ratio.
Which improved in the quarter to 1.2 times down from two nine times in the second quarter of 2021.
Improved natural gas prices were the primary factor driving the strong financial results in the quarter.
<unk> of our gas price realizations as presented on slide five during.
During the second quarter, Accordingly, Nymex settlement price averaged $7 17 sets and the average Henry hub spot price averaged $7 39.
So during the quarter, we nominated 83% of our gas to be sold at index prices tied to the contract settlement price and we sold the remaining 17% of our gas in the daily spot market.
Therefore, as expected Nymex reference price for ourselves for the second quarter would have been $7 21.
Our realized price during the second quarter averaged $6 93, reflecting that 28 said differential our differentials stay tight in the quarter as we only have 10% of our production subject to the wider regional index says that parallel in Carthage.
In the second quarter, we were 54% hedged, which reduced our realized price to $4 85.
We also generated $2 million of margin from third party market in the quarter, which added <unk> average price realizations.
On slide six we detail our operating cost per Mcf.
And our EBITDAX margin, our operating cost per Mcf averaged 74 sets in the second quarter.
<unk> <unk> higher than our first quarter rate.
The increase is directly related to the higher natural gas prices were realizing as production taxes increased by <unk> in the second quarter.
Our gathering costs increased by <unk> for the quarter, which was primarily due to the impact of higher fuel costs or the higher value of natural gas that's used in transportation.
And that was offset by a <unk> drop in our other lifting cost.
Our G&A cost came in at six at the same as our first quarter rate and our EBIT margin. After hedging came in at 85% in the second quarter up from 81% in the first quarter.
On slide seven we recap our first half.
This year spending on drilling and other development activity.
In the first six months of this year, we spent $497 million on development activities, including $426 million on our operated Haynesville and Bossier shale drilling program.
$263 million.
Our Capex was spent in the second quarter.
In the first half of this year, we've drilled 31 wells or 27%.
<unk> seven net wells operated horizontal Haynesville wells and we've turned 36 or 29.1 net operated wells to sales.
These wells had an average IP rate of 26 million cubic feet per day.
We also had an additional 1.2 net non operated wells that we turned to sales in the first half of this year.
Slide eight recaps, our balance sheet at the end of the second quarter.
We had $350 million drawn on our revolving credit facility at the end of the second quarter after.
After having used the revolver to fund part of the redemption of our 2025 senior notes on May 15th.
We also repurchased $26 1 million in principal amount of our 2029 senior notes at a discount for.
Our $25 million during the quarter. So in total we retired $271 million in principal of senior notes during the second quarter.
The reduction in our debt and the growth in our EBITDAX drove our leverage ratio down to one two times in the quarter as compared to two nine times in the second quarter of last year.
We plan on retiring the remaining 350 million outstanding on our revolver later this year using free cash flow from operations.
And then we ended the second quarter with financial liquidity of almost $1 $1 billion.
Now I'll turn the call over to Dan to discuss the operations.
Okay. Thanks Roland.
Over on slide nine so this just shows our average lateral length for the wells, we've drilled six 2017.
Our app, our lateral lengths averaged 9612 feet in the second quarter, almost 16 wells that we turned to sales.
Among the 16, new wells were five extra long wells with laterals greater than 11000 feet. The longest lateral this quarter coming in at 12237 seats.
To date, we have drilled 915000 foot laterals for these have been turned to sales three that are currently completing and two that are waiting on completion.
We're also in the process of drilling our 10 15000 foot lateral.
The longest lateral drilled and completed to date stands at 15291 feet.
By year end, we anticipate turning 69 gross wells to sales with an average lateral length of 10050 feet.
18 of these wells are expected to be longer than 11000 feet and nine of the wells being 15000 foot laterals.
We've been really pleased with our progress to date drilling. These 15000 foot laterals. They are playing an increasing role in offsetting some of our cost increases we're experiencing in this deflationary cost environment.
Sure.
Slide 10 shows our latest D&C costs ramp through the second quarter for our benchmark long lateral wells. These include all our wells with lateral lengths greater than 8000 feet.
13 of the 16 wells that we turned to sales during the quarter were long laterals.
Our D&C cost averaged $1362 per foot in the second quarter, representing a 12% increase.
From the first quarter and a 21% increase from our average 2021 D&C cost.
Our drilling costs were $478 a foot for a 6% quarter to quarter increase.
While our completion cost increased 17% quarter to quarter up to $784 a foot.
The cost increases we experienced during the second quarter were purely driven by the cost inflation, we're seeing across the basin.
On Slide 11. This is a summary of our second quarter well activity.
Since the last call we have turned to sales 14 additional wells.
Wells were drilled with lateral lengths ranging from 5373 feet up to 12237 feet and.
And had an average lateral of 9577 feet.
The individual wells were tested at IP rates, ranging from 12 million cubic feet, a day up to 37 million cubic feet a day.
With the average IP settling in at $26 million a day.
Our second quarter results also included the completion of the first wells drilled on our western Haynesville acreage in Robertson County, Texas.
The circle Liam number one H well was completed in the Bossier shale with a 7861 foot lateral.
The well was tested at 37 million cubic feet, a day and has been flowing for approximately 90 days with an average rate of 30 million a day.
I'll now direct you to slide 12, where we discuss our natural gas powered completions with the BJ tightened fleet.
Back in April of this year, we deployed our first tight fracturing fleet, which is fueled by a 100% natural gas.
The first two pads that were completed using the site fleet, we eliminated $1 4 million gallons of diesel fuel.
To replace by cleaner burning natural gas.
The environment was positively impacted by removing approximately 2000 metric tons of greenhouse gas emissions.
In addition to drilling the longer laterals to help offset our higher cost of services. This fleet has played a key role in helping us minimize our completion cost as the cost of diesel has increased significantly.
The completion can also in those first two pads were reduced by 53% compared to using one of our conventional diesel fleets.
So based on the initial results we have recently entered into a contract with BJ energy services for a second Titan natural gas powered fleet.
And we expect this to be in service in the first quarter of 2023.
I'll now turn it back over to Jay to summarize our 2022 outlook.
Dan and thank you Roland if you go to <unk> I would direct you to slide 13, where we summarize our outlook for the rest of the year.
Where you are on pace to generate significantly more than our targeted 500 million of free cash flow, which at current commodity prices could approach $1 billion.
First priority of the free cash flow generation remains as the reduction of our debt level.
Paved the way to Reinitiate, a return of capital program.
We did redeem $244 million outstanding on our 225 senior notes.
The 15th and we repurchased $26 million of our 2029 senior notes at a discount to par in June .
We expect to repay the $350 million remaining borrowing outstanding under our bank credit facility by year end.
We are investing a little more in our Haynesville drilling program by adding two operated rigs it before the end of the year, which will drive additional production growth in 2023.
We're also are marking 50 million to $75 million for bolt on acquisitions and leasing activity for this year, which includes the $43 million already spent in the first half of this year.
With our additional investment in our future growth and our plans to repay an additional $350 million of debt.
We'll have substantial free cash flow to start a return of capital program.
We have now exceeded the leverage goal, we set and now expect to reinstate our shareholder dividend during the fourth quarter of this year and lastly, we will continue to maintain and grow.
Very strong financial liquidity.
Now I'll have Ron provide some specific guidance for the rest of the year Ron Thanks, Jim on Slide 14, we provide updated financial guidance for 2022.
Third quarter production guidance is $1 37 to 144 Bcf per day and the full year guidance remains unchanged at the $1 39 to 145 Bcf a day, we provided back in May during the third quarter. We currently plan to turn to sales of 11% to 15 net wells.
Our development Capex guidance is $925 to $975 million, which incorporates the addition of two rigs.
Okay.
And is up from 875 million to $925 million.
We provided an in may that.
In 2022 wells have an average lateral length, it's about 14% longer than last year, which is helping to offset some of the cost inflation.
In addition to what we spend on our drilling program, we could spend up to a total of $50 million to $75 million on bolt on acquisitions, and new leasing which includes the $43 million. We've already spent this year.
Our LOE is expected to average 20% to 25, both in the third quarter and the full year while our.
Gathering and transportation costs are expected to average 26% to 30 in both third quarter and the full year.
With the higher prices for natural gas, our production and AD valorem taxes are now expected to average 16% to 18 per Mcf.
While our DD&A rate is expected to average 90% to 96 per Mcf for.
For the year.
Cash G&A is expected to be 7%.
The $8 million in the third quarter, and 29% to $32 million for the full year, while the noncash portion of our G&A is expected to total approximately $2 million per quarter.
Cash interest expense is expected to total 38% to $45 million in the third quarter and 152 million to $160 million for the full year, which includes the impact of.
The redemption of our 2025 notes.
In may on.
On the tax side, our effective tax rate is still expected to average 22% to 25% and we still expect to defer 75% to 80% of our taxes.
This year.
I'll now turn the call back over to the operator to answer questions from the analysts who follow the company.
Latif.
Thank you as a reminder to ask a question you will need to press star one one on your telephone please standby, while we compile the Q&A roster.
Our first question comes from the line of Austin, <unk> Cohen of Johnson Rice and company Austin at Cowen Your line is open.
Good morning, Jay and to your team congrats on a strong quarter.
Thank you your first question.
Our first question is with the second tightened. So you would expect it to be in service and <unk> 23.
That a good timeframe for the additional two rigs or should we think that David I was trying to get them earlier.
So the two rigs we got one that's just started got underway in the second additional rig is coming later this month end of this month.
Q1 of 2023 for the next tightened fleet is.
Is accurate.
Now I remember the first time, we are supposed to have received in January of this year and we didn't get it until April so that's the guesstimate to date right now.
Thank you I appreciate that has a follow up.
You showed impressive results from your circle unwell and Robertson County could.
Could you provide some more details as to.
Why this was chosen for the step out exploration and as a follow up.
How many locations you see on the acreage.
Yes, let me.
We've we've.
We've managed to step out on the circle and we've managed to.
We've managed our management style has been like this numerous times.
You've followed us a long time, if you if you go back to 2015, we drilled a bossier well in Desoto parish when it wasn't popular drill Bossier wells, we had drilled eight successful haynesville wells before that so we wanted to test the Bossier.
It kind of kicked off a bonus program and then five years ago.
We had a footprint in Caddo parish and we wanted to test it and we drill several wells and it turned out to be not as same thing in Harrison County, five years ago, we wanted to firm up our position there and that work and even if you go back even to this last quarter.
We drilled three wells in Nacogdoches, where one was at Bossier to our Haynesville <unk> and.
We're bringing those online today.
Good so we really stepped out on the same thing with historical in our table wanted to see if we could technically drill a well out there it looks good we reported it but.
One well is only one well will test our technology on the next well in what we call this as well.
Alright. Thank you I appreciate the color that's all from me.
Okay.
Thank you.
Next question comes from the line of Omar Charterer of Goldman Sachs.
Your line is open hi, Thank you good morning, and thank you for taking my questions.
My first question is on production outlook guidance calls for a step up in production in the fourth quarter wanted to get your thoughts on cadence of completions in the second half and also given you have added two rigs in grain.
Any initial read on production next year would be ready Hudson.
Yeah and on production yet, yes, we see obviously more completions I think we're kind of expecting around 19, or so wells BN.
Kevin coming online in the fourth quarter at about 14 or so in the third quarter are currently.
Quite a lot of it depends on when they come out in the quarter. So we were.
I have seen kind of a longer kind of drill times just due to inefficient.
Inefficiencies just out there due to supply chain issues.
And.
And so I think thats kind of push some of the production a little bit later in the year. This year, but we do see getting out of these wells online that we kind of a plan for this year.
Yes.
Yes, it's early for us to start given a lot of guidance for 'twenty three production, but yes, we are.
Obviously, adding.
Yes, more rigs and so as we get probably that probably.
Maybe later on in the year, what kind of gave a really good outlet to what we expect for the for next year.
Got it that's really helpful.
And acknowledging that you sell most of our volumes on the Gulf Coast markets I wanted to get your thoughts on the recent Betty will differentiate what is driving the weakness.
When do you expect that to be alleviated.
Yes, I think youre talking about.
<unk> basis.
Yes, the differentials there at the main regional hubs.
Vale in Carthage.
And I think those are really reflect the tightness of transportation in the Haynesville, yes that we've seen.
Production has increased some there and there's also been more.
A little bit more maintenance than normal going on which is aggravated the situation we.
We see some of that loosening up as we get to into October as.
As far as the maintenance being over and some new capacity come into that basin too.
Maybe a little bit of tightness, but given the tight market.
Yes, that's why you've seen that differentials have especially at <unk>.
The volatile and maybe elevated here.
We.
Expected as for years and.
We really have moved to lock in a lot of our gas sales to Gulf coast indexes.
And got more access to transportation to be able to deliver gas to the Gulf coast indexes. So we still have.
Yes somewhere around 10%.
Of our basis still or is that subject to the wider differentials.
Even some of the gas we saw it very well we've tried to do it under longer term sales agreements where we.
We've been able to lock that in closer to that 2025 area that has been historically and that served us pretty well this summer so.
No.
And to <unk> point, we are selling gas directly to every LNG facility.
Louisiana, Yes, we see that increasing especially as we go into next year and we continue to.
Engaging talks we want to be a big supplier to that especially at the Louisiana LNG shippers.
Have a lot of gas that we can deliver.
Them so.
That's the ultimate driver of demand in our region.
And that's where we can probably get the best price realizations were market over two BS a day and produced right at one four BS.
And if you look we have about $1 7 billion a day with direct access to users relative said this premium Gulf coast marketed sales, yes. It is.
This year we've had.
We've added we've added some additional income through marketing third party gas and that's really because we we do have some extra capacity in some of our Gulf coast transport that were not able to use yet for our equity <unk>.
Production, so as we have that excess capacity in.
The difference between the Gulf Coast indexes in the regional differences.
<unk> have been pretty significant we've been able to do.
We've got to go to some third parties and help them get a better price and then also make some margin for ourselves by using some of that capacity, but as we need that capacity as our production grows in the area.
I will just use it for our equity gas first.
Good rent rollover mentioned I mean, we probably through David care, and the marketing group Whitney et cetera.
We try to pre planned as for year year, and a half out, but we have 400000 plus acres in that footprint really provides us a lot of flexibility to optimize the drilling activity, where we're going to put these wells and drilling.
No great color. Thank you so much.
Thank you.
Thank you. Our next question comes from the line of Mill Dingman of Truth Securities. Your question. Please know Damian good morning, guys.
Two rigs that you talked about arriving later this year, Jamie just wondering I know, it's early any thoughts on the tenure of these rigs and what type of contracts you would walk into these rigs.
So this is Dan yes.
All of our rigs, we've gotten our own either basically well to well contracts or six month contracts. The rig companies have been reluctant to.
And are any long term contracts.
Just in the kind of <unk>.
Recent past year or so.
We're looking at rates that are up probably overall, I mean, youre approaching 50% from a year and a half ago or so so.
Just kind of seeing where the market goes I mean, we're going to.
We're kind of sitting where we're at status quo for the moment.
Go from there as far as deciding on long term contracts.
Yes, I think that makes a lot of sense and then just lastly.
Next question on LNG, specifically, all continue to be positioned very well Jay you pointed out really think given the basin on to benefit from potential LNG projects. So I'm just wondering again I know, it's early not a lot going on but could you give any color on just any potential new LNG contracts you might be seeing out there.
We again we.
Visited with all of the major LNG exporters period, I mean, because.
I think we have more on dedicated gas in any of their haynesville Bossier producer, but.
What we're trying to do we're trying to have enough uncommitted current volume to support transportation and long term sales for the partnership et cetera, we want to have.
LNG Cup again, saying, we want to show them. We had 1600 net locations in the primary area. We have takeaway we have 400000 net acres perspective.
We do market lot of gas I mean, we have.
I think the one of the key things is we've been in this area is probably 1991. So we have relationships with every midstream provider. So.
We have everything that they would want the question is what do you do with pricing view your exposure ship international pricing as <unk> is named game do you do in rehab one.
115% et cetera, which.
Support 80% of the contracts look like we just want to be in a position.
Have a competitive advantage.
For the stakeholders that we have.
When LNG continues to Boston I mean, we're looking at is probably year numbers.
Now it may be 2026, we expect the LNG port to increase off the Gulf coast by maybe six or seven BS, we know that the world demands more LNG. If you looked at even just kind of a global deal.
Russia, Russia exports more gas than anybody in the world multiple of two.
Multiple of two but 80% of that is pipelines, but it's still an issue with Russia. So 20% is LNG. If you look at the big LNG exporters I mean, it's the U S. We just surpassed Qatar.
And then it's Australia. So if those were all facts.
And we want to be tied in with the biggest footprint with more locations for the most and dedicated gas with relationships that we have.
These users are we know of.
So thats, where we are I think you're still early in the game, but you see all of these commitments.
The single largest financial.
But in a world I think we heard.
With venture Global's 13, plus billion dollar commitment for LNG and Gulf Coast areas. So we're right in the middle of this good storm as far we want to stay and continue to Derisk our footprints.
Well said Jay Thank you for your time.
Thank you.
Thank you. Our next question comes from Leo Mariani of MK partners your.
Your question please Leo Mariani.
Hey, guys wanted to follow up on the addition of the two rigs I just wanted to kind of make sure I understand where we're at and where you guys at five rigs prior to these two new rigs and that gets you to seven.
Right and it sounds like Youre signaling that these two rigs would stay in place for all next year. So it sounds like.
Fairly good step up in activity, if thats the case and it seems like that would lead to kind of much higher production growth. I know you guys had talked about kind of low to mid single digit growth. It looks like this may be you could put you closer to double digits here any thoughts on that.
I think again, we're going to add the two rigs as Dan answered. The question earlier, which is the first question that was asked Keith we're going to add the two rigs, we do think theres going to be a demand.
In 2023 for more guests.
This will not impact materially our production of gas in 2022, but youll see it grow in 2023.
You'll have that 4% production growth I think in 2022, we don't give a number for 2023 right now.
And lay out we were at seven rigs.
If you go back I mean, we've been at seven rigs or get better. This year. So this would increase our operated rig count to nine now one of these of these nine rigs I would say.
Half of our entire rig during the entire year is doing third party its drilling for <unk>.
For the Joneses, so, it's probably really eight and a half rig kind of it's kind of where we ended up.
Far as the cadence for the company that that's the kind of activity, we want to carry and a 23.
Okay. So at the end of the day like when you guys look at the decision to kind of step up the rig count obviously, the whole natural gas stripped futures curve has kind of moved up here I'm sure. That's a key part of it but are you also going to try to center. Some of this incremental activity and some of the new acreage you picked up any.
Texas and obviously.
Wells only one well, but you know it looks good so far their plans to kind of drill a bunch of others in that area.
I think it's too early to tell as we said we've got a starter well.
To start a well in Canada, we drill tomorrow, we had historical well in Harrison County, we drilled some more.
Broadly up at a store to a well <unk> drilled a bunch of them.
We had a big footprint of acreage in Nacogdoches and for 2019 2021, we didn't drill a one acre.
We're just drilled three wells two haynesville, one bossier and they look really good. So it's too early to say, what we'll do with that.
Okay, and then could you all just comment on hedging real quick.
You didn't really hedging versus the last update obviously prices have been pretty darn strong here. Thus far this summer just any update on hedging philosophy I know you've got hedges at kind of last into the first half of next year, and then youre sort of make it after that.
Yes, that's correct layer were kind of head through the first half of next year, and then 23, our hedge position is more than wide collars.
Yes.
Somewhere around $3 floor, and a little less than $10 ceiling. So we're much more exposed to the full gas prices in 'twenty three than we are in 'twenty, two where we're a little bit under <unk> for the second half of the area, we're just a little bit less than 50% hedged.
With.
So I think I think we really looked at hedging when we put in a lot of the hedges that are that are paying out and we have to pay out. This year. It was because we had a lot of leverage and back end. After we bought Covey park in into a at low gas price World of 2019, and 2020 with the advent of Covid.
<unk>.
So now that we're kind of the.
Balance sheet is really transforming.
And we've got to drive leverage under one times, we view that need to to hedge a large percentage of our gas is not necessary.
And to the extent that we do hedge in the future, it's probably going to be more like the white collars. We did for the first half of 'twenty three.
Okay. Thanks, Niccolo and again I think hopefully we can get our leverage below one this next quarter, that's our goal and hopefully we can pay off.
The majority of that $350 million, which is drawn on that RVO majority of that I mean, the vast majority.
And this next quarter.
Hedges I think we will.
We would do the same thing again.
We had we had to risk adjust.
Everything I mean, I think all of these companies did bottom put in swaps. We had swaps initially and then we put in the callers.
If you look at 2023 were good or bad I don't know what your opinion is but one of the late stage natural gas companies.
On the planet.
We will have $3 floors in almost $10 ceilings for half of the production we have in the first half of the year. They were completely opened the second half of 2023.
But.
We're committed to get our leverage ratio down we got it down a quarter sooner than we thought to that one too.
We're committed to give shareholder return program, we're pretty close to that in fact, we've got the leverage ratio to do that we've committed not.
The last last quarter.
We're not looking to spend $345 billion buying PDP with inventory, we think we've got a lot of inventory thats quality and hopefully we can we can add some more inventory as we drill some wells.
That's been our view and Thats been our drumbeat for a long time and we've executed on it and at the same time, we want to show you that we love the environment as much as anybody.
So we've got the second.
<unk> <unk> natural gas Frac fleet coming our way.
Okay. Thanks, guys.
No.
Thank you. Our next question comes from the line.
Fernando Zavala Pickering energy partners.
Your question, please Fernando Zavala Hey.
Hey, guys good morning.
I was wondering if the on the bolt on acquisition.
Infrastructure portion is that something that you're actively looking to do more of or was that just a one time opportunity that came with that package.
What we did and we kind of.
Broadcast so that we are trying to do this.
The last conference call, but.
Towards the third and fourth quarter of last year.
We added some deep rights on acreage that was H BP in the shallow rights wheat, we didn't operate.
We did a transaction that we reported on the fourth quarter 2021. So all we were able to do is we were able to kind of do the same thing it's a broader scope.
We were able to come in and acquire the deep rights on acres that are held by production. So we don't have to put a rig and start drilling out there immediately it's HB paid by another operator.
But at the same time.
We did buy this 145 mile high pressure pipeline.
In the natural gas trading plant for not a lot of monarch really $36 million.
If you look at the future of LNG in the U S. As the lowest cost provider of LNG in the world.
You can have the molecules with Jeff to transport it.
They're having trouble of doing that.
Appalachia area I mean, they might get this mountain valley pipeline now.
<unk> now built because of the maintenance deal but.
So I hope they do but we know that we can have midstream and our areas. So this midstream pops that we're buying and the haynesville, they're becoming more and more valuable as demand for feed gas feedstock.
<unk> gas LNG facilities growth.
We looked at it.
And we control it I think our costs will be lower.
And we thought it was a goodbye for where we're drilling.
Fact that all of this was AWP.
Just a good we thought is a good way to spend $36 million versus again.
Paying up in bond company, and adding locations that you have to buy PDP reserves.
Your question about would we like to do more of that I think I think in specific situations, where we see the opportunity.
To protect our cost structure and.
Guarantee ourselves low transport costs and see that we control.
The gas behind it that we'll consider.
As we end this year with a very strong balance sheet and a very substantial generation of cash flow.
So I think this is kind of.
One of the things, we probably wouldn't have done.
Three or four years ago, when we wanted to spend every dollar we cut on drilling but its something that I think is go forward and we see unique opportunities too.
To create better markets for our gas in the Haynesville and also <unk>.
Our transport rates slow.
Consider it.
Yes.
As opportunities come up.
Yeah, and again I think.
<unk> approach to you that we think are bedrock, which is our reserves and archived nickel group on our marketing group and our land group I mean, the 209 paper, where we think the bedrock in our reserves.
<unk> and.
And we like the area and we like the fact that.
We've managed to extend this stuff into Caddo and Harrison.
Now enter Nacogdoches area.
So so but that's really what we're doing we're just staying to basics, except this time, we're not digesting a big $2 $2 billion acquisition.
Note that we grew it.
And this is what has been the result of it and we think any serious low carbon outlook has to have natural gas as a fundamental resourcing. It.
And we've got the natural gas.
Which is as low carbon.
Got it thanks for that and then real quick as a follow up do you have an expected location count and average lateral length for the.
The acquired acreage.
And we do not okay.
That's it for me thank you.
Thank you our next question.
Comes from the line no parks of Tuohy brothers.
Your line is open.
Okay.
Can you hear me.
Yes, Sir.
Clear.
Great.
Sorry.
Commented on this already I missed it but with your.
Your acquisition you also got the 145 miles of pipeline infrastructure I was just curious about what you.
What you thought.
The potential benefits of that we're just actually curious as to why the solid wood.
Would sell that.
So if you look at the whole maybe 3 million acres whatever it is the Haynesville Bossier encompasses.
And you look at midstream midstream.
It's becoming more and more and more valuable I mean, we could build out and we deal our guests for their for a major midstream company within that footprint and we have for a long long time.
We can build out where the Appalachian they are restrained from building, yet, but we think midstream.
Particularly <unk>.
If it's long midstream, we think in the core area.
That said the 145 miles long it's high pressure.
And it's underutilized for the most part we think that that.
Becomes more and more and more valuable again.
Our system and for feed feedstock gas or LNG facilities grows.
To see the need for a lot more midstream and in fact, one of the things we've been talking about during the call is the tightness of the market in the Haynesville then most of the analysts write about how tight it is.
Completely full in Appalachia, I mean, it's not a molecule more you can really produce and a midstream in the haynesville used to where you used to have four five BS.
Capacity now is probably $99 95%.
So we're pushing on that and at the same time you've got.
Tens of billions of dollars of commitments for LNG export terminals, along the Gulf Coast.
If you add all that up I think to think this midstream pop.
Is going to be very valuable yes. No. This was just a very unique opportunity of a company that's really being dissolved that that has had this asset that they weren't really utilizing.
And I think that this was this was that.
Just a very unique opportunity that we identified a long time ago and stayed around this company that we knew was trying to dissolve and.
And found a way to actually buy this from them in the quarter.
And as far as trading plant.
<unk> one trading plan.
No.
I'm sorry, you said you already own one trading yes, we have had.
Yes, we already have we have made today, Amy <unk>, yes, some gathering systems in.
Trading plant at our North Louisiana operations too.
Okay.
We could add to our Texas side yet.
Okay. So I think you can add to the Texas side.
Great.
Yes.
Oh and did you talk about.
Do you have any significant share.
Quantities.
Now aside from just what you would normally have for.
The way before fracking.
No I think our shut in activity it's been around this 4%.
Spend kind of what we expect.
Every now and then there is maintenance and that can be.
Not been of long duration for us so far and we don't foresee.
We see it as kind of a similar for.
For the rest of the year just as we typically expect three.
<unk>, 3% to 5% shut at all the time from Sam Walton simultaneous operations a little bit.
The maintenance here and there and that's kind of what we average for the first half of this year, so far about 4%.
Okay.
We do have we do see we have seen if anything longer.
To sales Timeframes right I think thats, probably been the only thing Thats a little different last year, we were super efficient there were a lot of it yes, yes last year.
All kinds of new efficiency records for drilling days and getting wells online in this year with supply chain very busy haynesville area supply chain, we've actually seen.
Those timeframe stretch out just havent been able.
Thanks Gil.
Get done, but not near as efficiently given its yes. The haynesville is a very busy basin.
One of the bigger rig increases the Permian and the Haynesville account for most of the big increases in rigs.
Yes.
That's just something we've had to deal with the share.
I'll add to that on the shut in volumes leave Jay mentioned, the tightness on the pipelines being pretty full but we have seen a little bit higher incidents of of really just highline pressure from all of our pipes that were connected to had been pretty prevalent this summer.
It's not really a big number and a needle mover, but its definitely something thats been pretty predominant this summer and I'm sure it'll be we'll.
We will be looking at that.
Go ahead into next year.
Like we said earlier, there is a little bit of that.
We'll see some expanded capacity in the Haynesville as we get into this fall.
Yes that was not going to be available. This summer so theres, a little bit of relief coming there.
Right. Thanks, Thanks for the thanks for the extra detail.
Really helps.
That's all for me.
Thank you.
Thank you again to ask a question. Please press star one one on your Touchtone telephone again Thats Star one one to ask a question.
Okay.
Thank you. Our next question comes from the line of.
Savannah, Leonard Banc of America Savannah, Atlanta Your line is open.
Hey, guys, it's actually Greg.
I just picked up Savannah phone line.
How are you today.
Hey, Greg.
Yes.
Just wanted to ask a couple questions. So obviously buying back to 2029 from a bondholder we have seen that.
A little bit of a surprise.
Curious.
Why did you go after the 20 nines as their philosophy about reducing senior debt further.
And then just one other question.
You reduced amount of money you were talking about spending on leasing I'm curious why you took the steps are.
That amount and nothing that open.
Okay. That's a good question, yes on the 29, so basically it's all right now it's our most expensive debt since we've retired the seven 5%. So it's next in line.
And we just saw the opportunity with kind of week in a week trading.
During that two to retire some extra debt with that with.
With fewer dollars and so that was just saying opportunity I think you saw other companies in our space took advantage of that same rail weakness in the trading of the bonds.
At the time window when.
When companies like us have incredible free cash flow so distant.
Just an opportunity we saw and took advantage of.
And.
Yes.
Another question about the bolt on.
Acquisition kind of leasing them out that we targeted I think we.
The year is more than half over now and we just don't see hitting that upper end of that other number.
We still so we don't we don't.
We do expect to have some more activity Pat.
Given kind of what we see ahead for the rest of this year.
I don't think we will have to even upper range of that $75 million for that.
So we just wanted to signal kind of what we're seeing like we we saw we saw more deals that probably didn't happen.
Back at the end of the first quarter, but wanted to signal that and so this is just kind of adjustment to expectations there.
Yes, Phil the 100 billion yen, we spent the dollars of 40 plus million. So there is another $235 million. So that's kind of out there thats floating to spin.
Is it is it your assessment that those deals went away or did they trade someplace else.
They're still out there some are gone some are percolating.
We expect in yes, yes.
We're looking at a unique staff thats really adds to our.
Yes, our current footprint that expands.
So.
We're not we're not out there just in the M&A market in general looking to find any kind of assets, we can well historically the greatest way to grows say no.
INR 100 times say knows that way when you say, yes, you've really you've really been sharpened to powered youre looking for so we said, yes on this one.
60000 net acres in the pipeline and the trading.
As long time to say, yes, and we said no and everything else, but that was that was a take or opportunity that we've worked for two years it wasn't like.
<unk> came in.
This came on the market or anything so unique assets that we thought could fit.
Fit onto ours, and we could utilize them differently than the purchaser seller.
Was doing it and we knew they were in.
The process of trying to liquidate the company. So that was that was that was a situation we've been working a long time.
We're excited to get it done in April .
<unk>.
And yet.
Do you happen to pick up any production with that is there no no production at all so it's all yes.
So it's all of the acreage saw HP paid those so thats very yes.
SG&A part we actually.
We actually partnered with another company, who wanted to own their production.
And so instead of having to spend a lot of money on that we were able to keep our expenditures.
Just to buy the part that we want it so that was a very unique part of that deal I mean, 60000 net acres H BP to 145 mile high pressure pipeline and a natural gas trading plant for $36 million.
Okay.
Thank God.
Okay.
I've got that summer cold.
I did legitimately.
And just a follow up so being optimistic about reducing debt if you see the opportunity in the market.
Does that does that is that something we should expect going forward.
Is there an absolute debt target that you are targeting.
Well I think of course, you would add.
Commodity prices stay as strong as they have you know there are say.
Say that we.
We have a lot of extra free cash flow.
That's something that we'll consider in the future.
If those two opportunities are there we have the free cash flow and theirs.
Opportunity to reduce debt at a good value. We do know that we will pay the credit facility down So that's front and center.
Go ahead, and just finish that off and this year with the second half.
After years of free cash flow.
I mean, our priority again as Michael said, hopefully we can get majority of the <unk> paid off in the third quarter, probably a little dangling them before.
And then we want to continued will add these two rigs but.
We're not going to add any leverage and our goal is to give the shareholders return period. The next thing we need to do is we need to step up and give a dividend and then we need to continue to test our inventory.
And become better at what we do and that's on top of the ground and that's the people that are drilling and completing these wells and marketing the gas.
Thank you very much for the time guys I appreciate it.
<unk>.
Thank you at this time I would like to turn the call back over to Jay Allison for any closing remarks, Sir.
Okay, Great I love the questions. Thank you for your time, it's the most valuable thing you have.
As we look the world LNG demands expect about 53 fees a day in 2022.
In the U S provides about 22% of that 11 12, BS a day. So we look at that backdrop worldwide because the commodity rehab is a worldwide commodity really effective as of 2016.
And then if you look at the worldwide energy shortage. It shows up by what charging coal prices natural gas prices and oil prices and if you look at the LNG market along the Gulf Coast. We added one LNG project in 2020.
In times of change to 2022, particularly after Russia invasion.
So we look at the U S. We've got the low cost provider of LNG in the world.
We have the natural gas is the world's fastest growing fossil fuel in America's number one power source and what we want to do is we want to continue.
To derisk, our footprint to continue to have really high margins low cost predictability and continue to have a pristine balance sheet. So that we can serve view.
Stakeholder, we worked for you quickly.
Worried conserved view return program, that's predictable and have inventory that last for decades.
We want to be pure company that no one is like.
So that's our goal.
Thank you for your time.
This concludes today's conference call. Thank you for participating you may now disconnect.
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