Q2 2023 Comstock Resources Inc Earnings Call
Okay.
Thank you for standing by and welcome to the Comstock Resources second quarter 2023 earnings Conference call. At this time all participants are in listen only mode. After the speaker's presentation. There will be a question and answer session to ask a question. During this session you will need to press star one on your telephone to remove yourself.
From the queue simply press Star one again as a reminder, today's program is being recorded and now I would like to introduce your host for today's program, Mr. Jay Allison Chairman and CEO . Please go ahead Sir.
Thank you Jonathan I wish you control natural gas process, we'd all be a little happier.
Your introduction.
Welcome to the Comstock resources second quarter, 2023 financial and operating results Conference call. You can view a slide presentation during or after this call by going through our website.
Www, Comstock Resources' dotcom and downloading the quarterly results presentation.
You'll find a presentation titled second quarter 2023 result.
I am 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.
I'll flip over to slide two please refer to slide two in our presentation and note that our discussion today will include forward looking statements within the meaning of securities laws, while we believe the expectations of such statements to be reasonable there can be no assurance that such expectations will prove to be correct.
I want to take the time to thank each of you listening today on this call and those who will listen later on.
As we all know this year continues to be challenging as we.
We've had weak natural gas prices, coupled with a highly inflated drilling and completion costs.
Looking beyond this year, we are very optimistic about natural gas, but the growth in demand for natural gas driven by the growth of LNG exports from the Gulf Coast are expected to improve natural gas prices next year and the years beyond that.
The demand for LNG should grow from the 12 Bcf we export today.
21 Bcf by 2027 per day and beyond that the total demand may hit 40 Bcf per day for LNG.
Not that many years out.
So.
We are optimistic about the prospects of a western Haynesville play basketball to very early results of our first five wells, which Dan will talk to you about later.
As we continue to move up the learning curve on drilling these deeper wells.
We've also exceeded our expectations on growing our already expansive acreage position.
Our older ground leasing efforts the investments that we're making this year in the western Haynesville well.
We will pay substantial dividends in the future as the demand for natural gas grows we're making this investment this year to build on the foundation for the future.
At the same time, we've been mindful to protect the strong balance sheet and financial liquidity, we created last year, when we had stronger natural gas prices.
So for the next hour, we will go over the second quarter results, which were marked by very low natural gas prices were a little noisy on the disruptions caused by violent storms in June that we had in east Texas.
On slide three you feel flipped there.
On slide three we summarize the highlights of the second quarter. The financial results were heavily impacted by the very low natural gas prices that we realized in the quarter oil and gas sales, including hedging were 285 million in the quarter.
We generated cash flow from operations of 145 million or <unk> 53 per share and adjusted EBITDAX was $182 million with positive working capital contributions, we only had about $20 million to cover the overspend during the quarter.
Our adjusted net income was just over breakeven for the quarter.
We drilled 21 or 2017 to net successful operated Haynesville and Bossier shale horizontal wells in the quarter with an average lateral length of 10887 feet.
Since the last conference call, we've connected 15 or 12 net operated wells to sales with them.
An average initial production rate of 21 million cubic feet equivalent per day.
We're having great success, our western Haynesville exploratory play in the early innings, our fourth and fifth wells four recently to ourselves with strong production rates, including our first well in the Haynesville shale.
The first four wells have been completed in the Bossier shale. We've also been very successful in adding to our extensive lease position.
Low gas price environment is contributing to our success by keeping competitors are way.
I'll now turn it over to Roland to discuss financial results Roland Yes. Thanks Jay.
Slide four we cover our second quarter financial results. Our production in second quarter was one four Bcf per day, which was 2% higher as compared to the second quarter of 2022.
Low natural gas prices significantly impacted our oil and gas sales in the quarter.
285 million, which were 53% lower than.
2020, two's second quarter, EBITDAX was $182 million and we generated $145 million of cash flow during the quarter.
We reported adjusted net income of $1 million for the second quarter.
As Jay said, just above the breakeven level as compared to $274 million in the second quarter of 2022.
On slide five we have the financial results for the first half of this year.
Production in the first half of 2023 also averaged one four bcf per day, which was 6% higher as compared to the same period last year.
Oil and gas sales in the first half of 2023 totaled.
$676 million, which were at a third lower.
In the first half of 2022, EBITDAX was $476 million and we generated $400 million of cash flow during the first six months.
We reported adjusted net income of $93 million for the first six months of 2023 as compared to $409 million in the first six months of 2020.
Okay.
On slide six we show our natural gas price realizations in the quarter during the second quarter.
The Nymex settlement price averaged $2.10 and it was very close to the same.
Daily average Henry hub spot price in the quarter, a $2 12.
Our realized gas price during the second quarter averaged $1 81 reflected a 29% differential to both the settlement price and.
And our reference price.
This differentiated returned to more normal levels in the quarter due to improvements in the Houston ship channel and Katie have prices following the restart of the Freeport LNG facility.
In the second quarter, we're off to a 49% hedged which improved our realized gas.
Price to $2 25 sets.
We've been using some of our excess transportation in the Haynesville to buy and resell third party natural gas.
This generated about $3 million of profit in the quarter and improved our average gas price realization by another three.
On slide seven we detail our operating cost per Mcf produced in our EBITDAX margin our operating cost.
Per Mcf averaged 84, the second quarter, one penny higher than the first quarter rate.
The increased unit costs related to the startup phase at our Western Haynesville area.
We will see improve as we connect more sales of our own gathering and treating facilities in the future.
Gathering costs were flat at 36 during the quarter and our lifting cost were also unchanged at 27.
Our production taxes increased <unk> <unk> compared to the first quarter level.
Our G&A.
<unk> came in at six cents per Mcf, which is down <unk> <unk> from the first quarter rate.
Our EBITDAX margin after hedging came in at 63% in the second quarter down from 73% in the first quarter due to the lower gas prices, we experienced in the second quarter.
Okay.
On slide eight we recap our spending on our drilling and other development activity for the first half of this year.
So the first six months, we spent a total of $647 million in development activities, including.
$590 million on our operated Haynesville and Bossier shale drilling program.
Spending on other development activity, including non operated projects installing production tubing, the offset frac protection and other workovers totaled $57 million.
And the first six months of this year, we drilled 39 or 39 net operated Haynesville and Bossier shale wells and turned another 36 or 24 eight net operated wells to sales.
These wells had an average IP rate of 23 million cubic feet per day.
Slide nine recaps, our balance sheet at the end of the second quarter.
We ended the quarter with only $20 million of borrowing.
Borrowings outstanding under our credit facility, giving us $2 2 billion in total debt. We ended the second quarter with financial liquidity of almost $1 $5 billion.
I will now turn it over to Dan to discuss the operating results. Okay. Thanks Roland.
Slide 10 is a breakdown of the current drilling inventory now that we have at the end of the second quarter.
Selling inventory split between Haynesville and Bossier locations is divided into four buckets.
A short laterals up to 5000 feet medium laterals saw between five and 8000 feet are long laterals at eight.
<unk> 8000 to 11000 feet and our extra long laterals past 11000 feet.
Our total operated inventory now stands at 1782 gross locations and 1359 net locations.
This equates to a 76% average working interest across the operated inventory.
The non operated inventory stands at 1278 gross locations.
And 166 net locations, which represents a 13% average working interest across the non operated inventory.
The success of our long lateral drilling program allows us to modify our drilling inventory where possible to extend future laterals out into the 10000 to 15000 foot range.
Breaking down the gross operated inventory.
We had 313 short laterals 291 medium length laterals 719 long laterals and 459.
Extra long laterals.
Our gross operated inventory are split 52% in the Haynesville and 48% in the Bossier.
We now have 26% of our gross operated inventory of 459 locations and our extra long lateral bucket.
Which is greater than 11000 feet on a full two thirds of the gross operated inventory has laterals exceeding 8000 feet.
The average lateral length now stands at 8947 C. This is up slightly from the 8928 foot we had at the end of the first quarter.
Our inventory provides us with 25 years of future drilling locations based on existing activity.
Slide 11 is a chart that outlines our progress to date on our average lateral length drilled based on the wells that we've turned to sales.
During the second quarter, we turned 17 wells to sales with an average length of 11244 feet. Thanks.
Thanks to the continued success of our long lateral program.
The individual well lengths range from 7338 feet up to 15552 feet.
And our record long lateral still stands at 15726 feet.
During the second quarter eight of the 17 wells, we turned to sales at laterals exceeding 11000 feet.
Cleaning for the head laterals out past 14000 feet.
To date, we have drilled a total of 56 wells with laterals over 11000 feet and we drilled 28 wells with laterals over 14000 feet.
During the second quarter. We also had two additional wells that turned to sales in our new Western Haynesville acreage. The <unk> number one well was completed.
In the lower section of the mid Bossier, while the Mccullough Ingram number one is our first well completed in the Haynesville.
These wells are our fourth and fifth new vintage wells now completed and producing in the western ISIL.
Based on our current schedule, we are planning to turn another 37 wells to sales by year end.
17 of these wells will be extra long laterals that extend beyond 11000 feet and 13 of the wells will be over 14000 foot long.
Upon successful execution of our 2023 year and average lateral length is expected to be approximately 11000 feet.
Slide 12 outlines our new well activity.
We've turned to sales and tested 15, new wells since the time of our last call.
The individual IP rates range from 16 million a day up to 35 million cubic feet a day with an admirable average test rate of 21 million cubic feet a day.
The average lateral length was 10671 feet.
With the individual laterals ranging from seven 338 feet up to 14767 feet.
Included this quarter are.
Are the fourth and fifth new vintage wells on the Western Haynesville acreage.
The Dagens number one was completed in the lower section of the mid Bossier had a 9565 foot long lateral and we turned the well to sales in may.
We tested the well with an IP rate of 34 million cubic feet a day.
The Mccullough Ingram number one well is our first well that we've completed in the Haynesville interval.
It had at 8256 foot long lateral and the wells turned to sales in June .
The IP rate achieved to date is 35 million cubic feet a day, but we are still playing in this well and we are expected to achieve a higher IP rate in the very near future.
Beyond these last two wells that we turned to sales. We are currently in the process of completing our sixth and seventh wells on the western Haynesville acreage.
We expect to tired both of these wells to sales within the next couple of months.
In addition, we are currently running one rig on our western Haynesville acreage, but that will soon increase back to two rigs later this month.
Slide 13 summarizes our D&C costs through the second quarter for our benchmark long lateral wells that are on our legacy core East, Texas, and North Louisiana acreage position.
This covers all wells, having lateral is greater than 8000 feet.
During the quarter, we tired 15 wells to sales on our core East, Texas, and North Louisiana acreage in 13 of the 15 wells were our bits Mark long lateral wells.
In the second quarter, our D&C cost averaged $1523 per foot.
Which is a 4% decrease compared to the first quarter and our fifth still a 15% increase compared to our full year 2002.
D&C cost.
Our second quarter drilling costs came in at $653, a foot, which is a 2% decrease compared to the first quarter.
A portion of the drilling cost decrease is attributable to a longer average laterally.
We had this quarter versus the first quarter.
Our second quarter completion costs came in at $870, a foot, which is a 5% decrease compared to the first quarter.
We have seen our service costs began to decrease during the second quarter. Following the drop in activity levels. Since the first of the year. We expect these service cost will continue to decline throughout the third and fourth quarter.
At the end of June we dropped a rig from the fleet, which has is currently running six rigs. However, later this month, we will be taking delivery of the new rig which.
This will take us back to seven rigs, which is the level. We will we plan to stay at through the end of the year.
And also on the completion side. We are also running three frac crews and we will stay with.
With refractory level through year end.
So that's kind of a summary of the operations I will now turn the call back over to Jeff. Okay. Thank you Dan if.
If youll turn to slide 14, our direct you to slide 14, where we summarize our outlook for 'twenty.
2023.
We look back on this year in the future.
View it as a year, where we built a foundation that will drive our future growth.
Our business plan for this year is focused on positioning comstock to benefit.
From the substantial growth in demand for natural gas in our region that is on the horizon, driven but the growth in LNG exports.
And to that end, we are working to prove up our new play in the western Haynesville with a two rig program and complete our leasing program that we currently only have one rig active in the western Haynesville as Dan mentioned, and we have leased approximately 90% of our targeted acreage and we're almost at the <unk>.
Finish line.
We're making big investments for the future of this year at the same time, we are managing our drilling activity level to prudently respond to the lower gas price environment. We continued to experience is relevant talked about earlier.
We released two rigs on our legacy Haynesville footprint in late March and mid April in order to pull in our activity in response to lower natural gas prices and are currently operating six rigs as.
As we await delivery of a new rig.
We remain focused on maintaining the strong balance sheet, we created last year.
Now our industry, leading lowest cost structure is an asset in the current low natural gas price environment as our cost structure is substantially lower than the other public natural gas producers.
As stated in our press release, we plan to retain the quarterly dividend of $12.05 per common share and lastly, we will continue to maintain our very strong financial liquidity, which totaled around $1 5 billion at the end of the second quarter.
I will now have a Ron provide specific guidance for the rest of the year Ron.
Thanks Jay.
On slide 15, we provide financial guidance for 2023 third.
Third quarter D&C Capex.
This is expected to range between $240 million to $280 million and our full year D&C Capex guidance remains unchanged at the 950 to $1, one 5 million to one $5 billion range.
While we're seeing signs of deflationary pressures on service cost. We believe most of those improvements will be seen in 2024 in terms of infrastructure and other spending we continue to budget.
$15 million to $30 million.
During the third quarter and $75 million to $100 million of $70 million to $125 million for the full year.
Thanks.
In addition to what we spend on our drilling program noted above we now anticipate spending $70 million to $85 million this year for leasing activity.
Our LOE is expected to average 24% to 28 <unk> for both the quarter and the full year, while our gathering and transportation costs are expected to.
Be in the 32 to 36 range for the quarter and the year.
Production and AD valorem taxes are expected to remain in the 12 to 16 <unk>.
Mcf range.
While our DD&A rate is expected to remain in the $1 five to $1 15 per Mcf.
Cash G&A is still expected to run around $7 million to $9 million in the third quarter and a total of $32 million to $36 million for the full year, while the noncash G&A represents roughly $2 million per quarter of that number.
Due to the increase in sofa rates. The cash interest expense is now expected to total $40 million to $42 million for the third quarter.
$160 million to $165 million for the year.
Tax rate remains in the 22% to 25% range and we still expect it differ between 95 and 100% of our reported taxes this year.
Ill turn the call back over to Jonathan to answer questions.
Certainly.
Our first question.
Yes.
And our first question comes from the line of Charles Meade from Johnson Rice. Your question. Please.
Good morning, Jay and Roland and the whole Comstock crew there.
Good morning Charles.
Jay I Wonder I Wonder if.
If there is there is some more detail you can offer on these on your western Haynesville wells.
Not just these two most recent ones but in general.
35 million a day congratulations on that that's a great Scott right.
Right.
There's more there's more what defines a world where it comes on right.
Some of the best wells on the.
On the Louisiana side.
We're delivering Ips of 40, or even $50 million a day, so how would you.
What are the other data points and I'm thinking decline, but there may be some other things that you can talk about that that will help us contextualize, what you're doing in the western Haynesville with these kind of 35 to 40 Ips versus the best stuff, we're seeing on the Louisiana side.
So Charles.
Probably I'll turn it over to Dan.
I don't know how.
People know each one gets.
Thank you a chart like this.
I want to go backwards and say, how many acres have release and I've mentioned it at the end of the commentary that is probably 90 plus percent through leasing our acreage position.
And we're very careful about disclosures on what we're doing until we release it all of it.
All of the acreage that we want to lease to be recognized and that we know the mineral owners we have.
We are in discussions for them. So I think that's a good place to start so we can get to the end of that in 2023, and then I would just comment all the wells that we've drilled.
Remember that this play is unlikely.
The play in Louisiana that Youre referencing that.
We've read about.
But we have a much bigger block.
Our contiguous.
We have our own takeaway. So we don't have any infrastructure issues on the horizon and.
And the wells that we've been drilling or are the inferior wells theyre not the haynesville wells there the Bossier wells. So we typically your haynesville well will be 15, 20% better than Youre boettcher.
And really no one to our knowledge is drilled these wells to the depth that we've drilled amount with the lateral length that we drilled are matched with the heat that we've encountered.
As effectively as we have.
And that includes the circle in which was a boettcher the KC blackbirds to Bossier, The Campbell, which has proved that we could drill extended laterals.
12700 <unk>.
And then charge you get to that <unk>, which is a lower bossier. So we're that we're delineating the upper lower same thing for the Haynesville, then <unk>, which is the haynesville.
Dan commented on Nikola Ingram.
At the same time, we have completed that case CMS.
Good practice, and we've got to stick by building out the Fracs.
And then we've got the linear that where we are where we're completing right now.
And then we're drilling the glass.
<unk>.
I think it's.
I always say, it's the early innings look really good.
But it is early innings, we're still trying to.
A rep is present up under the tree before we disclose to the world, where we're trying to do so let me make those comments and then I'll, let Dan give a little deeper on that okay.
Yes, Charles So one of the things I wanted to just add to what Jay said is we are being very conservative in how we're drilling the wells down.
Obviously, there are a lot.
Deeper TVD here.
<unk> got a lot we've got a lot better bottom hole pressure.
Productivity is really good.
We're not we're obviously not trying to just to get a.
Super stellar IP rate on what the well can do right now because we are really managing the wells based on the drawdown and.
Just trying to make sure that we produce them out according to the type curves that we got created.
But the wells look really good and the drawdowns look good.
The pressure is also I'll say this mccullough well thats in the Haynesville.
Hello, one with more pressure at the same choke size is what we've seen on any of our Bossier well. So we definitely are seeing a lot better deliverability on the haynesville well versus the Bossier wells.
So we think it's going to be we think it's going to be pretty good and looking forward and the drilling into display. The haynesville is going to always be our primary target.
When we first started in the play we knew it was going to be tougher drilling these wells due to the depth and the temperatures and we did specifically target drilling to the Bossier interval initially just from a drilling standpoint.
Just to give ourselves the best Asics and SaaS. It gets started so we've made great progress technically drilling the wells and dealing with the temperatures.
So we turned our attention to drilling.
Some of the deeper targets.
<unk> been able to do that successfully and we think that will bear out with a lot better wells in the haynesville.
I think that as Greg go ahead.
On a go again.
We've circled the wagon.
If this remaining 10% that we're trying to lease it for some reason we don't get it.
We've circled arrived and started three years ago in August and.
Very low cost that we paid for the acreage and you know the drilling commitments for <unk>, where we go from 2% to 33 to four rigs origination groups that you all of this footprint.
With that Western Asia, we bought we did buy that infrastructure, when we bought legacy pinnacle plants et cetera.
So all of those things give us a tremendous competitive advantage.
Even if we were to stop leasing today are stopped buying today.
And we're going to get a big Blue ribbon now.
While we want to make sure is that.
We're accountable to you.
A new trust us for where we're spending our money.
And at that.
That will complete this journey by the end of this year and we'll have more disclosure on these well results. So great question.
And we've tried to introduce as clear as we could with the.
The set of facts, we have okay.
Yes.
It's great detail, Jay and it makes sense that you guys are.
Our holding holding some cards close right now that makes sense I'll just you can count me among those eager too.
To hear more when you want to offer more but Jay you also kind of touched on the one question I wanted to follow up on and that is the leasing and that you're up your increased capital budget release and it was a great data point that I hadn't heard from you before I believe that you're 90% done.
But is your view.
Target changing or is your view of what you want changing does that does that.
How does that play or not play into the increased.
Lease acquisition budget.
I think when you look for years ago, two years ago, one year ago.
Come up with a budget and.
As for your dividend to the geology, it's all back to farm geology right.
And you want to clean up maybe the middle you've found that there is some acreage that fits that's opened in the middle.
So you add forecast six 8000 acres in the middle It really declined it up to make all of the acreage that you own more drill a board. So you can exchange or laterals again as Dan Harrison said, we're trying to get these wells 10000 11000 foot laterals.
And not not.
Not stock kind of spotty out there whether this whole program as you've seen that's why we gave a whole slide on the lateral lengths.
<unk> 8000, 10000, 15000 foot laterals, we're trying to grow in this so that when you see all of it at one time, you can say Oh now I see why you added a couple of million dollars to clean up some some spots in the middle that we didn't know would be available to lease as top that we've really extended the peripheral we kind of understood.
That long time ago. So there is there is nothing that we're really trying to acquire on the peripheral of any material size that we have found at all at all.
So, it's just a clean up like a moth plan things up.
I appreciate the visual J, thanks for taking my questions.
Thank you one moment for our next question.
And our next question comes from the line of <unk>.
Erik <unk> from Stifel. Your question. Please.
Thanks, and good morning all.
Good morning, good morning.
Well My first question I wanted to focus on the trajectory of your 2023 guidance. If we assume the low side of your production guidance range. The implied guidance for Q4 projects an average rate of about one five Bcf per day, which is up from $1. Four in Q3 would it be fair to assume your exit rate for.
For the year could meaningfully exceed one five.
Given the timing of the turn in lines.
Yes.
Sure.
Derek it's Ron.
The absolute exit rate.
We've never provided that it depends on the actual timing of when windows turned to sales occur.
Two to average one five.
Close to one 5% for the quarter, if you try to back back into that number.
There is a chance that the exit rate can be.
Above that to help create the average if you but in terms of.
In absolute exit rate, that's something that that we wouldnt provide but your your.
Your math, we've given you the third quarter you have the first half and so to back into what we would need to get to that that low end of the range Youre average for the fourth quarter.
Is is where it should be.
Yes, Derrick category.
Or less is saying that ear and felt like we planned I think that the.
I think there's been yes.
The slower kind of hook up, especially.
Yes.
We have one area, that's a month and a half.
Hind in because it really supposed to be online at the very end of the second quarter and so you can take a lot out of the third when you take a method and a half away. Yes. Four of these days that would probably be high volume wells.
And so yes, so thats, a little setback, but I don't think that in the long run it just pushes that.
Yes that production out in the future, hopefully, where we get a higher price for it.
Yes, it could certainly be for two it just from the standpoint of timing.
With my my follow up.
Wanted to.
I guess ask a question about the western.
Haynesville exploration program with the understanding that Youre still in the early stages of their learning curves could you speak to what you've experienced and operational efficiency gains again I understand you are drilling for different targets and thats going to require.
Different degree of caution and.
But again just to.
Help us understand how you guys are tracking progress wise.
Okay.
Yes, Eric This is Dan I'd say, we've made really great strides.
Obviously, these arent easy wells to drill I think everybody realizes that.
<unk> had a pretty good challenge here, starting with these wells, but we've.
We have made really good progress.
The vertical part of the whole has got some difficulties associated with lost circulation zones.
It's got a really thick Travis peak, which has some really hard and abrasive and slow drilling.
We've made really good strides there.
As far as just shave an awful lot of days.
The KZ MFS and the linear which over the last two wells we drill are you.
Kind of look at where they are located.
MS. We've shaved off probably 20 days on that well its route over near the circle on the Campbell.
In the case, the black and we drilled it 20 days less than where we started just due to the strategy and the vertical part of the hull.
And then really kind of separate it into those two buckets. The other part is just the lateral and just dealing with the temperatures that these TVD depths and we've made we've made really good strides there.
Saved off a bunch of days in the lateral we've gotten better at handling the temperatures.
We've just gotten much better at.
Tweaking or bottom hole assemblies of motors that we're running in these high temperatures.
Getting better performance, we're getting longer runs.
And really just those two things coupled together faster up there in the vertical and that hard.
Try to speak section and better motor performance and the temperature and the laterals is what.
Where we've made our headway and so like I said.
The last well overall in kind of that southwest enter the play where we've got the circle on the KC the Campbell.
The case of EMS number Carla this last well.
We're 20 days faster so.
Conversely kind of over on the other side in Leon County, where we've got the linear and the dinkins that linear we shaved off a bunch of days compared to the bank and so and we're not done we've got we got several things kind of got a runway of some other things that we're going to be doing we think are gone up let us save additional days off here in the near future.
Derik I'd make a comment that.
Before we.
Disclosure of all of this we built a pretty big wall around this hundreds of thousands of acres that we've leased.
And again, there's a few we need to pick up not many.
And it's going to be really hard to be competitive with us CFO right because of all the reasons <unk> and Gabe.
It's a play to achieve you have to spend some money and have a big acreage position.
And we are committed.
That we think will allow us to deliver that gas that youre going to need in 2027 28 29.
But I don't want to assure you we're not drifting you can see the answers that you gave when you ask great questions. So you can see our commitment and you can see the well performance but.
I think you also have to know that we feel like we took great ownership and putting up big fence around the play as far as the part that we want.
Before we start disclosing everything which should do if you value it.
Yes.
That's great guys sounds very very encouraging.
Okay.
Thank you one moment for our next question.
And our next question comes from the line of Jacob Roberts from Tudor, Pickering, Holt and company. Your question. Please.
Good morning.
Good morning, good morning.
On the hedging front, we were hoping for the thoughts on the 2024 market for contracts and what percentage of protection you ultimately think will be appropriate for next year.
Yes.
Yes, Jacob this is Robin yes, yes, we've started to put in some 24 positions as we kind of show in our presentation.
We're not really ready to talk about our strategy at.
But you can kind of see where we're starting out and then as we see opportunities that meet our goals. We will continue to execute on our 24 hedging program.
We typically hedge 40% I still think thats, probably a good a good.
Good visual out there.
We will see what happens process ever come our way in a month or so.
We did put the swap and at $3 50 gas for $130 million a day.
And we are very we want to have that revenue stream.
Almost guaranteed for some type of page because particularly as we're as we're.
We're derisking to western Haynesville, So you need to know where we got our eyes on that for looking at it.
We make decisions daily about it.
Great. Thank you.
My follow up would be on the divestiture proceeds showing up this quarter could you provide some color on what that was and maybe the opportunity set for those types of transactions in the future.
Yes. Those are just some non operated interests that we settled in yet like last year he has to OE.
So as we see.
We have opportunities to sell non operated interests that are not part of our core.
We kind of execute on that.
But that's a fairly very very immaterial small part of the company. So I wouldn't say that there is a.
A lot of.
Potential for that in the future.
Thanks, I appreciate the time.
Thank you one moment for our next question.
And our next question comes from the line of <unk> from <unk> to your question. Please.
Good morning.
Good morning.
Good morning.
The first question on an LNG I think I know the answer to this but I just wanted to get your thoughts on a few of your peers LNG strategies. Some of them are taking full control of their volumes all the way to a destination and some are going through third party traders.
Another segment wanted just retain a Henry hub premium agreement. So just wondering what fits best with Comstock long term and.
Or maybe the decision just comes down to where Jonathan moves gas prices.
And those are all great strategies.
We continue to evaluate.
We are already a big supplier to.
To the LNG.
We think thats going to the share of gas that we produce that goes directly to LNG shippers is going to continue to increase.
Especially with the big expansion coming in the next two to three years and we're still evaluating where it is common stock would it be to we want to get it.
The highest kind of benchmark to Henry hub price do we want to participate.
Participate.
Yes.
Yes, the international pricing and we are actively exploring that and then talks to.
To come out with that so I don't think we have.
Have an answer for you yet on which one we think is best.
Can you say our competitors are.
Kind of approaching it in different ways.
I think though if you look at where our footprint is.
We're two or 300 miles away from where these third is $100 billion of.
Of export chipping facilities are being built.
You look at the majority of the new acreage is on dedicated.
Good thing.
The relationship that we have with all of the X quarters, we deal with all of them.
If you look the fact that we've been in this area probably 35 years. So.
<unk>.
And then you look at the liquidity, we have you look at the at the volumes that we produced it might be oil produced in the future.
And you look at the demand out there thats kind of how we started we think theres about <unk> a day of export LNG doesn't include Mexico.
But you can say youre going to have another nine base between now and maybe 26, 7%.
And then thats for that extra 17, or 18 base might come from we want to position the company to.
We have great float in the stock great liquidity, great inventory and these low cost that we currently have.
So whatever whatever is the best.
For an upstream company I think we're going to have we're going to have we're going to have.
The ingredient to make it better whether thats like Robin said.
And if we can capture some international prices long haul gathering.
We're going to have the flexibility to look at all of those things.
But I can assure you that we're not going to tire chef into some type of a commitment.
That if prices dip, but we get hurt we're just not going to do that we don't have to do that.
So we're going to protect.
Yes.
And the stakeholders in the analyst.
We had to run this thing right.
Yes.
Alright, I appreciate that answer and then.
Maybe on the D&C costs.
You mentioned it in your prepared remarks, it seems like a portion of maybe that 4% decline quarter over quarter came from longer lateral.
Our laterals in the quarter, but could you maybe talk about where the the rest of that came from and maybe specifically, which items youre seeing some deflation on them, which items are holding their ground.
Yes, I would say.
Pretty good piece of it probably was the longer.
The longer lengths I mean, obviously you the longer we get our cost per foot comes down. So we look at that every.
Quarter, we look at what the average that group of wells averaged in so.
Back there.
Slide 13, when you look at that that's the specific group of wells four in the second quarter. The benchmark wells that we report on the.
The average length for the second quarter was.
Nearly 12200 feet.
We were only 10800 feet plus or minus in the first quarter. So that obviously lends itself to.
Cheaper D&C cost and really I would say just the other part is we're starting to see that.
Deflation.
I think starting to turnaround and come back down since the activity has dropped off at the first of the year.
Just kind of slight really in the second quarter, but a lot of the stuff. We report on our second quarter wells.
Drilling at the first of the year, So just kind of start to turning the corner and come back the other way.
Which is why we'll see it continue to come down in the third quarter and fourth quarter. When we report on those.
Specific items.
Really we haven't seen a lot of movement on pipe prices, but we have seen the rig rates come down.
And the Frac crews get cheaper.
Just just which is obviously just straight straight tied to utilization.
Hello efficiencies the Frac crews you Mike.
Yes, so the efficiency of the Frac crews have gotten better I mean specific to our crews that we're running.
Just we've seen our stage counts per day have increased.
We're just really happy with what the grades so.
Just they've gotten faster more efficient.
So even if you're paying the same price or cost per foot comes down we can get the wells down faster, which leads us to get we just get production all faster. So all of that stuff adds up to a really good answer.
Yes, the one thing I'll comment on that question is.
We've got the core which is a 1500 locations in the thousands of acres hundreds of thousands.
And then yet we focus on a lot of this call is one on the western Haynesville.
It's unusual to have it's almost like two different companies two different sets of assets.
You are managed both of them right and if you do that.
You protect your balance sheet.
And you can end up with some connection evergreen for you could end up with particularly as you mentioned LNG demand coming our way.
So that's where we are I think we are.
We're in the center of that scope.
But really good flex debate.
Thanks, guys.
Thank you one moment for our next question.
And our next question comes from the line of Gregg Brody from Bank of America. Your question. Please.
Good morning, guys.
Good morning, Justin.
Sorry to cut off the reciprocation I'm, just I'm not sure the haynesville.
Just as you think about the capital required.
To keep going there and expand can you talk a little bit about how youre thinking about.
Potentially raising capital.
For that.
For that to expand into next year.
But Greg this is rollout I think the area that addition to the drilling cost, which you've kind of outlined wanting to go from.
Basically I got three rigs next year that kind of keeps us on track.
Only in all of our acreage.
In addition to that capital there'll be there'll be a need for building out our midstream assets, both trading in and gathering.
Yes, not really so much for next year, because we've made those investments and the upgraded our our pinnacle play out to handle next year's volumes, but it will be as we look ahead there are longer.
Larger investments to make so there I think we're looking at we're exploring.
Of credit, creating a midstream kind of.
Separate.
The entity that will kind of handle those.
Those capital needs in the future as we build that out.
Which also allow us to control.
The midstream and processing versus relying on a third party.
And so you'll see a lot of the wells spinner drilled in the western Haynesville from here forward.
And our system only one is in it right now.
So it just barely starting.
But we see a lot of value in maximizing the value of the gas price, we get but also maximizing the.
The ability to control their timing is to maintaining controls so we might seek partners to.
Partnering with us in building out that.
Building out that infrastructure over the next five years.
So you've done over the next five years do you think you will seek out a partner.
Over the near term is there a timeline that that's how you are thinking about that.
There is not a near time.
Basically the capital needed for <unk>.
For next year, Yes, we havent spent that we just stay debates we made some minor.
Grades to what we bought last year and the legacy acquisition that was just a great purchase for us, which gives us theyre running room to grow our volumes.
To handle next year, but as you look ahead.
Items beyond that have a lot longer lead time construction time, so we're planning for that but we see those expenditures coming out in the future, but we're planning that wanted to create a structure for that is that that midstream costs.
Is that burdened, our our drilling and completion budget and that could be more like it's been in the past, yes, I think again at the answers we are going to do what it tells us to do.
When we bought <unk>.
Acreage in the critical line in the high pressure of 145 mile High pressure line back in second quarter 'twenty to it and we spent some money to repurpose and upgraded.
We have takeaway capacity within this 90% of the acreage plus if we own.
Two to produce that gas in 'twenty three 'twenty four mid way through 25, so as we de risk this stuff over the next months and quarters and years.
And we'll see what the need is to have a midstream.
And ill tell us where we need to do we are we're not going to ask permission.
To sell our gas to anybody that we want to control our midstream.
So when we drill these wells won't effectiveness sales, we want to have a home for a long haul there is a home.
Now the question is how did you get it there.
And we've got plenty of takeaway between 'twenty three 'twenty four 'twenty five.
Yeah.
Got it and then just on the cost per well.
Do you see that progressing.
Obviously, we have some service cost deflation, but.
Do you think we could see some.
And some material improvements next year or do we need to get to a more of a development mode for that to happen.
This is Dan will definitely when you get into development mode. Youll continue to see obviously efficiency gains and improvements lower costs.
We did obviously Robin we cranked up and got started in the place when we had all of the deflation kicking in just basically ride as we started on the harvest dwell but.
We have made great strides like I mentioned before and just the number of days to get the wells drilled so that's dropping the cost and we do see the costs coming down into next year based on some other things that we've kind of got coming down the pipe.
Any time, you run more rigs and you start drilling more wells and you just get more practice at doing anything you'd get a little better at it and we will get more efficient just in that regard.
That's very helpful. And then just for the pesky credit analysts that that status that they are counting on some things just could you.
I know the working capital is a tough one to.
<unk>.
To figure out it, especially from my perspective I was wondering if you had any insight on how to think about.
That's going to trend the rest of the year and then also just I noticed an asset sale about $41 million.
So what you saw in Europe at that time.
The updated guidance.
Sure Greg.
Yes, the working capital you know I think the best way that to trend it since our activity level.
No.
Yes, there is.
It reduced down for the level of last year, but now it's fairly stable with the seven rigs that are then that means you're kind of at that part of the working capital the payables probably stays consistent.
The other item driving working capital, obviously as the prices right and so we had a very very low prices.
Net debt as at.
As as it is.
<unk> will get collected.
A big contribution where working capital this quarter, but then as gas prices improve.
As we go forward in the year you Shouldnt you won't see more of that Youll see the opposite.
<unk>.
So it's really I think you can if you are really thinking about it just think about I think our if our spending levels stay at a fairly constant.
Change in working capital just going to be driven by gas prices, so that higher gas prices go the more.
There'll be we'll be giving back some of that working capital.
And the lower lower obviously you get some so that's basically how I think you can see it play out the rest of the year. This year, obviously, the second quarter. The big contribution came because prices hit rock bottom.
Is there a ballpark.
In terms of how much of a reverse $100 million of gas or is it or is it a question to the 180.
Well it all depends on how good yes.
Tell me, what the gas prices in the future and I could give you a number.
So.
If it's modestly improves then it's got a modestly due that if gas prices dramatically improve to where they were last year, obviously than it is a big number.
And so I don't think that.
Unless it gets as big as it was last year, that's what you're seeing is all of that flush through.
And the numbers on that yet proceeds some sales last year this year.
Any opportunity to sell non operated non strategic properties, if they can meet our return criteria.
We always like to do that.
We answered before the whole non operated as part of our production and reserves is very small so theres not a lot of material future.
Staff to do.
We're always open to doing that.
And that sales in Europe , and your guidance then.
Yes, I think yes, I think and plus we've seen two things in our guidance not only did we choose to sell off some non operated production, but we also see a huge reduction in non operated.
Activity because of the Haynesville you notice the rig counts down a lot of the other operators have pulled back activity, especially the private ones. So we just compared to last year.
A lot lower non operated activity going forward.
I think that again will probably track.
How strong gas prices are to when that would come back.
Okay.
Is that a big part of our numbers anyway, so you're really talking about.
A couple of percent here or there.
I appreciate the time and the insight guys.
Pass the mic back.
Thank you one moment for our next question.
And our next question comes from the line of Noel Parks from Tuohy Brothers investment Research. Your question. Please.
Hi, good morning.
Good morning.
Just a couple of things.
Thinking about a couple of timing related issues and I apologize if you touched on this already but.
We sort of have these couple of one time.
Corrections or changes or transitions ahead.
We had this interest rate environment now the highest it's been a long time and presumably at some point that reverses.
So Jeff just thoughts on how cost of capital might be a fit.
Fitting into your scenarios about development pace and then also what kind of in this lull now where the new LNG capacity near term has been has been limited, but it's going to ramp up sharply.
And the step function over the next next few years.
So I'm just wondering if if.
The fact that we know that that's ahead.
Does it give you any thoughts on on what sort of contract duration you might be looking at if youre trying to either do third party or a direct sale or other types of development <unk> range, you're thinking about.
Maybe a mode for the transition years, and then and then thinking ahead to maybe something longer term.
You might try to do.
Yes, those are good.
The first question yes.
Yes.
Rising cost of capital and interest rates I mean, I think thats, where we are so we're so thankful that we.
Locked in a lot of our interest rates last year. So.
No.
And don't really see having to go back into the debt markets too.
Yeah.
In a significant way to have to bear those higher interest costs.
That's it.
That's a.
Again, the issue for US and then if you look ahead too.
Yes.
From the LNG demand, obviously, that's a big part of our long term thinking and Huawei.
While we want to control, our midstream and create a lot of ability to connect to increase our sales to the LNG shippers and talks with them I think if you look at contact duration.
I think.
We can point to our most recent deal that we're about to finish up as a new three year supply contract with one of the large LNG shippers.
We were early on we did a 10 year so.
Yes.
Yes.
So we're not afraid of the longer term durations as long as long as Theyre happy to commit to buy it and we found them to be great customers always taken exactly what they they ask for.
So we see them as being a growing part of our market and.
And so I think it would really we.
We will be happy to sign longer term contracts that they are.
Out of the buyer.
As we obviously have the ability to get the gas to them into into guaranteed MF.
Our gas supply for as long as they want to contract for it.
Great Thanks and.
One question with this consolidation we've had in the Haynesville and you are of course early early to that was.
Covey Park.
And then has a lot of other deals following the years after.
I'm just curious.
You've done a lot with pushing.
Sorry, what the limits of the technology are at.
What's still can be achieved and can be gotten out of the rock and I'm. Just wondering are any of the <unk>.
Other entrants.
Are you aware of any of them struggling to make technical.
Progress and wondering whether that sets up the possibility for maybe some of them.
Looking to exit or maybe trim their physicians.
And the idea that maybe there's a little harder to work the haynesville they might have bought from the outside.
I don't think so I mean, we've seen are our other peers in the Haynesville, yes, do really well I mean, I think we're probably pushing the leading edge for the western Haynesville.
And may be one of our.
One of them is there with us.
I think generally.
I mean, I don't think we see that observation.
Yes, no I'd tell you where the biggest cheerleader for all of them I mean, we want whether you're an oil company in the Permian or your gas company in Appalachia.
Gas company in the Haynesville merger look.
We got a cheer for each other so.
Hope everybody is really good and we think they will be good.
Great. Thanks, a lot.
Thank you one moment for our next question.
And our next question comes from the line of Paul Diamond from Citi. Your question. Please.
Hi, good morning, Thanks for taking my call.
Just a quick one you talked a bit about how are you.
Development cadence in Western Haynesville, just wanted to see if there was any.
I'd deal over the next several years any idea on how the.
Breakdown sits between targeting haynesville versus the brochure.
Yes. So this is Dan.
It's a good question.
I stated earlier I don't know if you really heard me, but we stated earlier obviously.
R.
Our target really is to drill the haynesville.
Where we can its being a little bit deeper and being at this.
This is a kind of a high temperature play.
Look at that really closely just to make sure we're comfortable with the target that we're going to chase.
Any particular, well, which is why we targeted the Bossier initially when we put our first rig out here, we drilled our first four wells to the Bossier.
Kind of.
Got got kind of everything settled down a little bit we made some progress in dealing with the temperatures than we obviously with our fifth well we targeted the haynesville didn't have any problems getting that drilled.
<unk>.
<unk>.
The next two wells, we've targeted Bossier wells those are the two those are the two wells that were completing.
Now and then after that we're going to we've got several wells in a row, where we're going to be drilling haynesville. So if you just kind of look so if you just take a long term view.
<unk> through the end of 'twenty five but right now we're about 50 50 on what we're targeting Bossier versus Haynesville, but I will say that that was a smaller percentage of haynesville several months ago. So I think.
I think as we continue to make progress and get better at dealing with these temperatures that and get our days down on the wells I think we will see some of these.
Wells that are on our list of <unk> today, we'll probably.
It will become.
Probably become haynesville targets in the future.
But.
Today just.
Snapshot today looking out for the next.
Two and a half years, so 25 or about half and half.
Understood. Thanks for the clarity and just one quick follow up how do you guys think about the potential or the timing and potential for return of activity given the given the carbon so we can see kind of strength the 'twenty four and beyond curve.
I think everybody is waiting to see what.
That really materializes I think there is that in.
The gas market, where we're really.
We are still focused on the inventory levels and getting it weather is a huge factor this summer and next.
Coming winter will be a huge factor.
Determining what prices really do and I think.
The basin is on hold waiting to kind of see.
Yes.
Happens I think over the next as this year plays out because that will set the stage for for next year along with.
The demand for how quickly to those projects start to pull the demand.
They earlier they laid out there's a lot of factors to really drive.
The return of activity.
I think most operators are.
Just wait and see right now.
And then we go overall and we ask Ron to do this.
Again, what it could have showed a what if freeport had knockdown offline.
For all those months I mean, we do this every Thursday.
In our gas storage right now and the five year average, we got a surplus of 13% above the normal five year average, but at Freeport.
If that <unk> has been injected into stores, but then exported.
If you look at the number we would be today on the five year average we would have a deficit of about eight 8%. So so I still think the gas part so a little bit misunderstood.
Because I think we're doing the right thing, but fell sudden you take to visa day, six affordable and it's it's not being injected into storage it changes things so.
They have a 250 60 gas price right now is pretty remarkable.
Understood, Thanks, and crowded anytime.
Thank you one moment for our next question.
Okay.
Our next question comes from the line of Phillips Johnston from capital One Securities. Your question. Please.
Hey, guys. Thanks, just one question for me in the interest of time against but it's a follow up on Jonathan's question on the productivity of the.
Western Haynesville wells.
Yes.
I hope this isn't pushing too far, but if I'm not mistaken, Netherlands, so bulk circle and well at roughly three five bcf per thousand foot, which obviously is much higher than your legacy Haynesville wells.
Would you say then that all five of the wells brought.
Bottom line the player tracking to a similar EUR or do you think there is a fair amount of variability.
Now I would think so I think it's a really good question number one.
It's a fair question I think that if you produced well for eight months.
Netherlands is exemplary reservoir engineers as they come in with a three five base I think thats a good starting point.
But as we've said we're in the early innings I think we need to get the rest of these wells producing.
And see what that real AUR is per thousand but the starting point is.
We were very pleased with the starting point.
And then we've got as you know you should go back East I will.
The competitive and economic and Thats, where you go to Dan in the group side will.
This is a big board game. So can you really get these costs down and.
Keep the EUR for the or toggle in one way or the other.
And deliver a brand new region that is competitive with the best of your Texas, Louisiana, Haynesville Bossier, and that's where you have to have a big footprint if that commitment.
And you have to have an April operations completion group.
This committed and dedicated to doing this.
Four years after year 50 years.
Within our budget that protects both the bondholders the equity owners, the banks, everybody, including the largest stockholder.
We're trying to thread that needle I think we've done it.
Okay, great. Thanks, Jay it sounds good.
Thank you, yes, a good question and I appreciate your question.
Thank you.
One moment for our next question.
And our next question comes from the line of Leo Mariani from Ross Your.
Your question please.
Hey, guys just wanted to follow up a little bit on activity levels here. So it sounds like youre going back to seven rigs kind of the end of this month here in kind of run that through the end of the year.
Just looking at 2024, I mean, obviously no one knows how it turns out exactly at this point, but strip prices had been pretty constant at around $3 50, plus or minus the small amount.
And in 'twenty, four and now at this point in time. So as you guys look to next year. It is seven rigs kind of feel like a pretty reasonable place to start the year and you think you can grow production.
With seven rigs given that you guys were running more obviously early this year.
Well I think your comment the script for 24 to $3 15, a script 25 is just shy of $4. So those are those are those are really good prices for our cost structure.
And I think that what we've done is contracted electric rigs on long term commitment. So if we need to add a rig or get rid of a rig or two we can do that.
Our goal is to keep 2024 pretty constant at seven.
We would have probably four in the cohort three and the western Haynesville, but all of that is subjective and we'll figure out in the fourth quarter, we want to change any of that.
Okay and do you guys think that's a level of activity that kind of lends itself to some kind of modest growth in production with that kind of seven rigs.
I think right now again, you've got to you've got to take out a little bit of the lumpiness that we've had.
And the performance, which is shutting in some of the Western Haynesville wells. Once you complete the others, you've got a model that Lumpiness and then of course.
And you always have to model and do you have other shut ins because of rig activity in your cohort.
We got a little weather delay so I think overall I think thats.
Right now Thats appetite we have.
As we get more.
Production from the longer laterals in the Western Haynesville wells, but we think a lower decline profile that are our core.
Haynesville that will hopefully reduce the need for.
Yes, more rigs in order to maintain production and grow modestly and so we'll as we get as we get into the fourth quarter is usually when we kind of set their budget there.
November December for next year, there are a lot of things will weigh in on that will also be just seeing kind of where we see that coming out in two weeks.
At seven as aggressive Thats, how we would kind of be looking at it now is we're just looking ahead and we can adjust that based on a lot of factors including gas.
Gas price environment of $3 50, still there or has that changed.
And how.
How we see that well performance maintaining that production.
Okay. That's helpful for sure and then just wanted to also ask a little bit on the western Haynesville here. If I heard you right. I think you guys were saying that there is still fairly limited competition for acreage over there, but maybe I didn't hear that correctly. So maybe just if you can speak a little bit too.
Kind of leasing competition, and then just maybe talk about others that are sort of drilling in and around there and then just wanted to ask about kind of what the plan is to prove up the position.
I think <unk> got five wells in at this point in time.
Think that.
Make something up and you guys can correct me if I'm wrong, but is it sort of by kind of mid next year or do you feel like you've kind of tested most of the acreage where you can release drilled the four corners and kind of the middle parts of this thing where youll have a really good look at it just kind of any timeline you can kind of provide this sort of proving it up I mean, it seems like you guys are five for five on the web.
<unk> with <unk>.
No issues at this point in time, so maybe just talk about your.
Timeline to kind of get all of this position prove that.
Well in our Crystal ball.
We would.
Again 90 plus percent of this acreage is leased.
We wouldn't be happy, but if we couldnt lease another acre it would be the end of the world for US I mean, we've leased 100.
Thousands of acres. Okay. So you don't want to get greedy, but we'd like to go ahead and get this remaining dribble that we have out there I think it would be a win for everybody.
So by the end of 2023, we should have this.
Reportable when you ask a question we can answer it.
Little former answer.
And then I think as far as the drilling program.
Goal is.
As to Derisk this whole acreage by the end of 'twenty four 'twenty five as you extend.
To extend these wells from footprint footprint, whether we go north South East and West.
<unk> so that.
And then some of these wells in 2024, Youll drill drill drill two wells per pad site. So we've got just as this abundance of acreage. So we can do that I think will call for store coming down there.
Some of them will be Boege Wilson will be haynesville well so.
The further we get down the road.
I think yes.
The more clarity we can give you.
The more comfort or discomfort orderly choose to have we can give you.
But that's you have to trust, what we're doing right now.
Okay. That's helpful color and then just.
Lastly in terms of some of the early wells in the play you're obviously starting to build up some pretty good production history are you seeing those wells hold in there pretty flat with fairly limited pressure drawdowns on some of those first couple of wells.
What we expected.
We believe we've demonstrated that we keep drilling these wells.
So obviously, we're not totally displace what we've seen.
And we're going to continue to drill the wells so thats.
That is that's about all the comment we can make right now.
Okay. Thanks.
Thank you. This does conclude the question and answer session of today's program I'd like to hand, the program back to <unk>.
Jay Allison for any further remarks.
Okay, Jonathan again.
In conclusion.
Kind of a broad.
But America and the world needs success in adding natural gas reserves and inventory.
We are attempting to deliver.
Management, which you've talked to some of US today. There is 204 244 people that are here of the Comstock.
Well all of the employees management, our board and our major stockholder.
I really do want to thank all of you for your encouragement and support as we report early results.
We want to thank you for your time.
Given us this morning, so thank you.
Yes.
Thank you, ladies and gentlemen for your participation in today's conference. This does conclude the program you may now disconnect good day.
Okay.
[music].
Okay.