Q1 2021 Comstock Resources Inc Earnings Call
Ladies and gentlemen, this is the operator today's conference call is scheduled to begin shortly please continue to standby E P.
Thank you for your patience.
Again todays conference call is scheduled to begin shortly please continue to standby we thank you for your patience.
[music].
Yeah.
Ladies and gentlemen, thank you for standing by and welcome to the quarter, one 2021 Comstock resources earnings Conference call. Please note that today's call east being recorded.
At this time all participants are in a listen only mode. After the speaker's presentation. There will be a question and answer session to ask a question. During the session you will need to press star one on your telephone.
If you require any further assistance please press star zero.
I would now like to hand, the conference or P. Your speaker for today, Jay Allison Chairman and Chief Executive Officer, James <unk>. The floor is yours alright. Thank you good morning, everybody.
Oh, well call, but if you would look to the first quarter 2020, one results and welcome to the Comstock resources first quarter, 2020, one financial and operating results Conference call. You can view a slide presentation during or after this call by going to our website at www Comstock resources Dot com and downloading it.
The quarterly results presentation.
And there you'll find a presentation titled first quarter 'twenty to 'twenty one results.
And I am Jay Allison Chief Executive Officer of Comstock with me is Roland Burns, our President and Chief Financial Officer, Dan Harrison, Our Chief operating Officer, and Ron Mills.
P a financial Investor relationship.
Note that the four of us will be presenting today, but always wanted to take the time.
Thanks to all of the 205 employees within the Comstock umbrella.
And all the consultants and the service companies that we deal with to create the results and we have today, so I want to thank everybody.
And look forward to page two please refer to.
Slide two and our presentation and note that our discussions today will include forward looking statements within the meaning of securities laws, while we believe the expectations and such statements to be reasonable there can be no assurance that such expectations will prove to be correct.
If you flip over to three what we tried to do and our.
Our first quarter financial operating results press release, we tried to outline 10 bullet points that you could look at even if you didn't read the risks and the release and.
I would tell you what the quarter looked like so this is kind of a high a lot of those 10 bullet points that we sent out earlier, we covered the highlights.
The first quarter on slide three.
And the first quarter, we reported adjusted net income of $63 million or 25 cents per diluted share production for the quarter average 1.281 Bcf per day.
And was 98% natural gas.
Our average daily production and the quarter was 6% higher than the fourth quarter of 2020, but 7% lower than the first quarter 2020 current.
Including a realized gas laws and our first quarter average realized price was $2.88 per Mcf per day.
Up from $2 16 per M Cfe and the first quarter of 2020.
Revenues, including realized hedging losses were $332 million, which were 22% higher than the first quarter of 2020.
Adjusted EBITDAX of 262 million was 30% higher than the first quarter of 2020 operating cash flow for the quarter was $207 million or <unk> 75 cents per diluted share during the first quarter, our total capital spending was $169 million incurred.
<unk> 6 million, which pant and leasing activities for the quarter.
We generated $33 million of free cash flow after preferred dividends, which is a good start to reaching our annual free cash and coal goal of $200 million. Given this quarter is modeled to be our highest capex quarter for the year.
And March.
We refinanced 1.15 billion of our higher cost senior notes with 125 billion of six and three quarter, New senior notes, the refinancing and created annual cash interest savings of $19 $5 million and extended our weighted average maturity of our notes two six.
Seven years up from four nine years and April our bank group reaffirmed our $1 $4 billion borrowing base and Dan Harrison, where we'll review the results of our successful Haynesville shale drilling program as well as reported on our results and reducing our greenhouse gas emissions later in this report.
And if you'll flip over to slide four we recap the March towards refinancing we completed.
We completed two note offerings to issue a total of 1.25 billion of new six and three quarter senior notes due 2029 and the proceeds from the offerings were used to refinance approximately half of our higher coupon notes.
Through a tender offer we redeemed 375 million of the seven and a half notes due 2025 and $777 million over non and three quarter percent notes due 2026, the refinancing transaction reduced our reported annual interest expense by $44 three.
And reduced our annual cash interest payments by $19 $5 million.
The lower cash interest expense will also drive significant improvements and our cash interest cost per Mcf per day produced as we expect interest per Mcf P.
And to fall to under 40.
For the fourth quarter as compared to 48 since this quarter and additionally to lowering our cost of capital. We also increased our weighted average maturity of our senior notes to six seven years up from $4 nine years, we will look to refinance and more of our non and three quarters senior.
After they become callable in August of this year with that now I'll turn it over to Roland to review the financial results for the quarter and more detail Rolling Alright, Thanks, Jay and slide five we summarize our reported financial results for the first quarter of 2021.
Our production for the first quarter 2021 totaled 113 Bcf of natural gas and 326000 barrels of oil.
This is 8% lower than the production, we had and the first quarter of 2020, but 6% higher and what we're producing and the fourth quarter of last year.
Our oil and gas sales, including a realized loss from our hedging increased 22% to 300 and.
$32 million and the first quarter, despite the lower production due primarily to higher oil and gas prices oil prices and the period average $47 and 87 per barrel and our gas price average $2 79 per mcf, including hedging losses.
Natural gas prices were up 37%, partly due to the high Nymex index, Brent the higher Nymex index prices, we had in the quarter and partially due to higher spot prices we realized in February.
Our production costs were also up 2%, while our G&A was down 8% and our DD&A was down 1% and the quarter.
Adjusted EBITDAX came in at $262 $1 million, 30% higher than 2000, Twenty's first quarter.
Operating cash flow was $206 $6 million, which was also 30% higher than the first quarter of 2020.
We reported a net loss of $138 4 million and the first quarter or <unk> 60 per share, but that reported loss was mainly due to a $238 $5 million charge related to the early retirement of the senior notes from our March 4th refinancing transaction.
And and unrealized loss from the Mark to market of our hedge positions at the end of the quarter of $13 $1 million.
Adjusted net income, excluding the loss and early debt extinguishment and the mark to market hedging loss.
And certain other unusual items was a profit of $63 $3 million or 25 cents per diluted share.
Slide six we cover our hedging program.
During the first quarter, we had 70% of our gas volumes hedged, which reduced our realized gas price to $2 79 per mcf from the $2 86.
Per Mcf, we realize from selling our production.
We also had 37% of our oil volumes hedged, which decreased our realized oil price to $47 87 per barrel versus the $50 69 per barrel we received.
Our realized oil and gas hedging losses, and the quarter totaled $8 $4 million.
Since we last reported earnings we've added another 40 million cubic feet per day of natural gas swaps.
For 2022 and at a M.
Settlement price of $2 70.
Per Mcf.
For 2021, we have natural gas hedges covering 936 million cubic feet per day of our 2021 production, which is about 69% of our total expected production this year.
63% of those hedges or swaps and 37%, our callers, which gives us exposure to higher prices.
For 2022, we have natural gas hedges, covering 174 million cubic feet of our 2022 production and additional 120 million cubic feet of swaption that we expect to get exercised.
Going forward, our primary focus is only adding to our 2022 hedge position.
Continued target.
To having 55% to 70% of our production hedged over the next 12 to 18 months.
On slide seven we summarize the shut in activity during the first quarter, we had 80 million per.
Per day, or six 4% of our natural gas production shut in.
And the first quarter as compared to about six 6% and the fourth quarter of last year.
During the February Winter storm, we shut in as much as 500 million cubic feet of our production over the course of several days due to road closures, which limited our ability to haul produced water.
And time associated with downstream pipelines and plants and then other freezing problems that we had and the field.
Excluding the shut in related to the storm activity, we would have had about 4% of our production shut in and due to routine to offset frac activity and other workovers.
We anticipate returning to a normal 4% to 5% shut and level and the second quarter of this year.
On slide eight we detail our operating costs per M. Cfe.
Operating cost.
Per M. Cfe average 55, and the first quarter, it's about 1% lower than the fourth quarter of last year.
That was comprised of gathering costs of 26 cents per.
Production and other taxes of eight sets and other field level.
Operating cost of 21 cents per Mcf.
On slide nine we detail our corporate overhead cost per M. Cfe.
And that was that average, 5% and the first quarter, which is up about one set from the fourth quarter of last year, we do expect our cash G&A cost to remain in this five to six range going forward.
On slide 10, we detail the depreciation depletion and amortization per M. Cfe produced that average 95, and the first quarter, one set higher than the 94 set right and the fourth quarter.
So overall, our our operating cost structure was very was very comparable to where we were at the fourth quarter last year.
On slide 11, we show our balance sheet at the end of the first quarter, we had $550 million drawn on our revolving bank credit facility at the end of the quarter and we expect to use our free cash flow that we generate this year to pay down a portion of that revolver.
Throughout 2021.
We also have $2 $3 $6 7 billion of senior notes outstanding comprised of 244 million of our seven 5% senior notes due in 2025 873 million for our non and three quarter percent senior notes due in 2026, and then 1.25 day and of the new six and.
And three quarter senior notes due in 2029.
We also show our revised maturity schedule on the slide 11, you can see they are 1.25 billion of our debt now has been pushed out to 2029.
With the quarter and cash position of $77 million, our current liquidity stands at $927 million.
On slide 12, we recap our first quarter capital expenditures and the.
First quarter, we spent $163 million on development activities.
$150 4 million was related to our operations our operated Haynesville shale development program.
We drilled 21 and there are 19 net task operated horizontal Haynesville wells and we were a turned 10 of those wells to sales or non net task and the quarter.
And the first quarter. We also spent $12 seven day and our non operated wells and other development activity.
In addition to funding our development program. We also spent $5 8 million leasing exploratory acreage and the quarter.
We're currently running six operated rigs for 2021 drilling program.
Expect to drop one of those operated rigs this month.
And based on our current operating plan for this year, we expect to spend approximately $510 million to $550 million and trail 67 operated Haynesville wells or 56 net wells to US and then turned about 55 or 49 net wells to sales.
Okay.
We continue to be very focused on generating significant free cash flow. This year, and we continue to target generating over $200 million of free cash flow and 2021 as we planned.
Our capital spending.
I'll now turn it over to it and to report and more detail on our operating results this quarter.
Okay. Thank you Roland.
Flip over to slide 13, you'll see a map outline and summary of the 13, new wells that we've turned to sales since the last call.
Are the new wells were located on our East, Texas, and Desoto parish acreage over in Louisiana.
The wells were tested at rates ranging from 19 million cubic feet, a day up to 32 million cubic feet a day with an average IP rate of 25 million a day.
These wells had a lateral lengths ranging from 4568 feet up to 13043 feet.
With an average lateral length of 8132 feet.
This included our longest lateral completed to date.
13043 feet. This was on a Robert CTV number two H world. It is located and Harrison County, Texas.
We currently have nine additional wells that we have in various stages of completion.
We are currently running six rigs and three frac crews at this time.
Roland mentioned earlier, we're gonna be released and one of our drilling and roots are here and just the next couple of days.
And we will be continuing to operate at five rigs for the remainder of the year.
We will also anticipate.
Running an average of 2.3 frac crews for the remainder of the year.
Over on Slide 14 is the updated D&C cost trend for our for our long lateral wells.
These are the lateral wells that the lateral links that have greater than 8000 feet and link.
During the first quarter, we continued making progress and pushing our total D&C costs lower our.
Our D&C cost averaged <unk> thousand and $10 a foot and the first quarter, which is 2% lower than our 2020 average D&C cost.
Our drilling costs and the first quarter dropped significantly to $365 a foot. This represents a 15% decrease from the previous quarter and a 20% decrease.
Our full year 2020 average drilling cost.
This is a reflection of the increase and drilling efficiencies and the faster drill times, we have continued to build upon since late last year.
Our completion cost and the first quarter increased to $645 a foot. This represents a 10% increase from the previous quarter, and a 13% and increase versus our full year 2020 completion cost.
This increase is entirely attributed to the larger Fracs, we resumed pumping late last year.
Youll pump and the higher sand and water volumes.
By maintaining our industry, leading drilling performance, we have the ability to absorb the higher completion cost associated with the larger stimulation treatments and still be able to maintain our low overall cost structure and the future.
On slide 15, we highlight our continued improvement and our emission intensity over the past three years and.
And late 2020, we updated our website to include a sustainability section and the highlight our ESG efforts and provide our ESG performance metrics.
As a primarily dry natural gas producer our emission intensity ranks attractively relative to industry peers.
Since 2018, our emission intensity has improved to $3 one two kilograms per C O two equivalent representing.
And representing a 38% improvement.
Our ongoing focus on greenhouse gas and methane emissions combined with the use of dual fuel drilling rigs and then the drivers behind this improvement.
We remain focused on continued improvement and our ESG metrics.
And we signed and we recently signed a three year contract with BJ energy solutions.
Voyages and the second and natural gas fuel pressure pumping fleet and the Haynesville and.
As we will discuss further on the next slide.
On slide 16, so we cover our recent partnership with Vijay to deploy the second and next generation fracturing fleet and the Haynesville starting in early 2022.
BJ is tight and fleet is fueled by 100% and natural gas for well completions.
And this is expected to drive continued improvement and our C O two and methane emissions.
While also improving our well economics by taking advantages of the efficiencies that the tightened fleet can provide.
With the tightened fleet the C O two emissions are expected to decrease by 25%.
Prior to our conventional diesel powered equipment.
Methane emissions are expected to improve by 60% compared to diesel only powered equipment and more than 95 per cent.
Compared to dual fuel options.
With only eight pumps required by the tightened fleet versus 18, and our conventional frac fleets.
The new fleet will decrease our required pass us by more than 30%. While also meeting the most stringent noise noise requirements and North America.
The three year contract locks and the current low completion cost that we have and it provides us the opportunity for cost saving efficiencies.
All while reducing the environmental impact of our future well completions.
I'll now turn it back over to Jay to summarize the outlook for the remainder of the year.
Noticed the thank you Dan and we noticed that BJ put a press release out today on the relationship.
They are formed now would comstock on this through natural gas powered completion.
And <unk>. So that's the second one is for non press release, the fuel load and then.
And I'll go to slide 17.
And you disclosed seven table, we summarize our outlook for the remainder of this year.
Our operating plan for this year is expected to provide for modest production growth and most importantly, really to generate as Robin said and excess of 200 million of free cash flow.
Our primary focus so this year. This is our drumbeat for the year.
It's to do three things one improve our balance sheet to reduce our leverage and three lower our cost of capital.
Our March refinancing transaction was a strong first step to reducing our cost of capital with the $19 $5 million of annual savings and interest payments if natural gas price to stay at current levels. We would expect our leverage ratio to improve to around two five times at the end of 2020 one.
Down from about three eight times at the end of 2021 and annualized basis. The first quarter is already down to two seven times.
We remain focused on maintaining and improving our industry, leading low cost structure and best in class well drilling returns.
And with our industry, leading low cost structure, our haynesville drilling program generates some of the highest drilling returns and all of North America, our large inventory of Haynesville Bossier drilling locations provide us with the decades of drilling inventory.
Currently hedged his role and set about 69% of our 2020 one production to protect our high drilling returns.
And we have a very strong financial liquidity.
$927 million.
So now I'll turn it over to Ron and he can provide some specific guidance for the rest of the year Ron.
Thanks Jay.
On slide 18, we.
Show the guidance table you will note that it is unchanged from from February when we when we updated the guidance. So despite the impacts of the winter storm our production guidance still remains and the one 303 to 145 Bcf a day.
<unk>, our Capex guidance remains on the development side $510 million to $550 million, which.
It has been mentioned a couple of times contemplates the.
The.
Dropping of one of our operated rigs and the next couple of days.
In addition to those development expenditures, we still expect to spend.
Up to $10 million or so on and on leasing expenditures.
Hello.
And and gathering and transportation costs remain and the 21% to 25 cents per unit range and $23 27 per range.
Per unit range, respectively, while production and AD valorem taxes are expected to average eight to 10 cents per M. Cfe.
DD&A rate is still to be and the 90 to $1 per Mcf range and our cash G&A is expected to remain and in this 5% to seven cent range I will now turn the call back over to the operator.
For Q&A from analysts who cover the company.
Thank you and ask a reminder, he would die cast a question. Please press star one.
And if you would like to withdraw your question Alright and teams. Our first question comes from the line austerity Whitfield from Stifel. Your line is open.
First with your operator original guidance on page 12.
You guys are reiterating full year production guidance, despite a one and half net well decrease and your wells to sales.
And that's that simply time, but seemingly implies improving production performance per well.
So could you speak to some of the drivers.
You cut out a couple of little bit Derek, but I think youre asking on slide 12 versus the February conference call the number of wells.
M turned to sales on operated standpoint is down about one five wells and and asking.
Are you asking how.
Yes.
To.
Provide some of the drivers as to why the production and still the same despite of one and a half less wells turned to sales.
That is correct and sorry for the connection if there was an issue. So my thought processes, perhaps that simply timing, but that would seemingly imply improving production performance per well and if so could you speak to those drivers.
Yes.
This is Dan and I think that's mostly just the cadence of the completions. We did have a few some wells and we're working with the model some of those wells just shifted.
To the first of next year from the end of the year.
So basically it affects the number of wells that we turned to sales, but it really doesn't affect the production because its production is coming on right at the end of the year.
Doesn't affect the production for this year.
Okay, and then maybe as my follow up for Dan and I wanted to focus on the Roberts well you noted in your prepared remarks.
Based on your experience to date, where do you believe the efficient frontier is for Comstock and lateral links and are you sensing any material degradation and frac efficiency at that way.
So I'll answer the second one first no we're not we're not experiencing any.
Degradation and Frac efficiency.
And that I think will be longer and we do have longer laterals planned and our schedule and the future as far as what.
And what the sweet spot is going to be I think it was your first question.
And kind of remains to be seen but I mean, we feel pretty strongly about being able to drill 15000 foot laterals I think.
For us I think the risk of drilling and completing the 15000 foot laterals drilling them, especially as.
And it's probably.
Not real high on our list, but it's going to be.
Just the risk of.
When you're completing the well and you've got to do any kind of well intervention work up and when you get out to laterals that long. It requires you to use a rig to do any kind of a clean outs or anything versus coil. So.
And just kind of changes the risk profile, a little bit, but we definitely think the value is there to get longer up to 15000 foot.
Definitely increase value and better returns.
Well, it's a data point, if we can extend these wells, we drilled 12 to 13000, plus but this last quarter, but.
But if we can extend and our average world and 13% to 15000 foot lateral.
I mean, that's like one of the shorter laterals being drilled I mean, so you don't have to have surface or intermediate.
Can you can get rid of those costs and it's just a horizontal length that youre drilling so the economics superior dollars that you're spending a lot more chance to drill.
And the lateral length and like Dan said.
We don't see a lot of issues and the drilling of it.
And we've been able to complete these.
But pretty consistently.
So we do think there is a lot of value upside value that does not in any of these numbers.
If we can continue to extend these laterals, which was your question.
Thank.
You really to your question.
I would agree with your assessment. Thanks again for your time guys.
Yes.
Thank you next question comes from the line of scale demand from tourist your line is open.
Hey, good morning, guys, and it's actually a bird tray and selling and for Neil.
The first question.
The drilling efficiency gains and <unk> that you saw was.
Thank you guys and talking to faster drilling times was that just you know while you were drilling or is that in between wells was there was there something driving that more specifically just seemed like a box dropped quarter over quarter.
So Dan you might give some statistics that we bid given from some of the service companies on our auto Bracco and you're a little bit.
<unk> been able to do well, yes, no and this basically is a reflection on our drilling group I mean, we've.
Got several of the records set for the amount of footage was drilled and 24 hours and intermediate hole and and the lateral.
And it's really and just a combination of several things we get a lot of questions on that front.
I mean, we're drilling a lot faster to intermediate case and point, we've really cut down the number of days there and we're drilling the laterals a lot faster I mean, we are average 10-K lateral.
Days to TD was probably on the high Twenty's.
Just a couple of quarters ago and prior to that and now we're you know and the high teens to low twenties.
So it's a it is a culmination of everybody's efforts.
And it's just things getting better on so many fronts.
That got us to this point and.
And we saw we saw glimmers of this actually earlier than that but until you get your entire fleet.
Operating at this level of efficiency and it doesn't show up and your numbers. So we have gotten into that we've gotten to that point into the fourth quarter and really and the first quarter and.
And that's what's driving the percentage decrease you know we're reporting on today.
And I again said 18 to 20 days to drill these wells, maybe 30 days to complete them.
Most of these wells you know we have two wells on a pad site.
And if you look at the Frac stages, I mean, maybe three or 404 complete.
Completion for day, we're pretty consistent on that even with more water and more sand.
We increased our completion golf and little bit, but we lowered our drilling cost.
$1010 a foot.
I think thats going to be the norm.
From here out.
And we haven't had haven't had a lot of really issues either on the drilling or completion side. So I think that that tells you that we're drilling within the fairways of our footprint, either and Harrison Pinola, our Caddo parish or Desoto parish I mean, we've got a really good footprint that acreage and we're drilling unit.
Income ended in 2021, we've got we've got a great set of inventory, we're drilling and we push some of those locations into 2022.
And it sounds like so you're saying it really is just the drilling speed. So it is more sustainable and it wasn't just a bunch of wells close to each other for the quarter or anything like that.
No no not at all at all of that definitely the footprint and definitely an improvement.
That's a great question note yes.
And then really my my second one is just on the P. J energy agreement and the completion rate that you locked in was that that 365 per foot.
The fixed and 45 per foot you show one.
On slide 14 or is that some sort of did the agreement assumed from inflation that way you can lock in three years, a couple of people or.
So basically it lets us lock and the horsepower cost for three years. So you know if there is if.
If you see the gas prices are up and the activity really picks up like we've seen the rig count just here in the last week pick up and you see the inflation.
And the completion call somebody and we'll be we'll be ahead of the game save and money because we will have these completion cost locked in.
No you don't lock and of course and water stuff like there Brian is stuck in the order logging and the horsepower and also which is the bulk of the the bulk of the job, but sand calls freight all our chemicals those will still fluctuate with the market.
Amazing part of the footprint environmental footprint is a lot smaller.
Vijay crude and gas will replace an existing BJ crude with this new P. J crude coming in early 2022, and you looked at the admissions.
And two are our methane emissions out of their materially better.
So so those are all positives that we need.
That's perfect. Thanks, guys.
Thank you.
<unk> and comes from the line of Katherine <unk> from Citigroup. Your line is open.
Hey, good morning, everyone just sticking on the drilling efficiencies and obviously you. Just commented you are getting a bit faster and then looking at the guidance on slide 12.
Moved up total operated wells drilled by size Youre Ducks expanded just about lower wells turned to sales.
It is inclusive of already dropping a rig here and that.
Is there a possibility that you would be able to reduce your rig activity further and maybe bring those wells drilled back down to the original guidance.
Or is that kind of a bit higher on a continuity program a program into 2022, and just kind of get a feel of when you'd be able to kind of reach read more cash flows.
Through the better drilling efficiencies that you've been experiencing.
So we'd have.
These faster drill times and nicely faster cycle times with the on the drilling side have is kind of whats create and are a little bit larger DUC list and what where you would have normally had.
As far as the number of rigs decreasing further.
We don't really see that right now, we're just running the number of rigs to keep us basically and maintenance mode on production.
And so you know to keep our production growth and the basically and the single digits five rigs and looks to be about the right recipe for us.
Yes, and we've said we're going to have modest growth I think that's what it is and mainly Felix in 2022, 3% growth something like that its modest but we're going to have a lot of Dutch carried over I will take a lot of that is from efficiency again, we said that we're going to drop per rig this month.
So I think that'll that'll help and then I think we've always advertised.
That we were going to increase the amount of sand and water. So if you look on that slide 14.
And that's probably a good number for the completion side that $645 a foot and then on the drilling side I know, Patrick but goes listen and <unk>.
And the office listening and he's VP of ops and.
He pushes really really really hard to make sure that our drilling costs are down it has done a great job. It shows up on slide 14.
I think we have the best group out there of course.
Our opinion and the numbers I think show it but if we can decrease those we will I think the good thing is is very predictable, we're very consistent with these wells.
25 million a day IP rate, we're not trying to tricky with P rate, we drill and all four corners of our acreage and then.
The 320 plus thousand.
Net net acreage, we have and the almost 2000 locations I mean, they're really good quality, it's decades and all we do now just this year's gave you a preview of what.
50 completed wells might look like for the year and.
Fairly all about the financial integrity, we need to keep hedging like Roland and Ron are doing gas process look really good I think that the whole sector is going to be disciplined.
Youre, a public oil company youre going to be disciplined and the same thing with gas and we take the Appalachian group is kind of locked in swing area might be the haynesville.
Because where LNG is and because of pipelines are added all we're trying to do is give you. The basic route to tell you. This is a great engine and a company to invest and if you're looking for low cost high margins.
And run by Dan and and relevant Patrick and the whole group. So it's a good story.
Okay.
And Thats it from me I appreciate the color.
Thank you next question comes from the line.
<unk> Becker from Keybanc Your line is open.
Hey, guys.
Just wanted to see do you guys think that the lower number of tools and you talked about earlier and 'twenty. One can maybe push you and need the lower half of your 'twenty, one capex guidance.
And I think it does.
And I think it's at five P M deposit <unk>.
Now we think that we think the guidance out there is pretty good for basically the plan that we have.
You never know what tomorrow brings.
And that's where we advertise per day John.
And there is always with the uptick and activity you know theres always the chance that you could still see a little bit of material cost increases on the completion side and even the rigs the rig counts going up so most of our rigs are in oil new oil contracts. So.
And that's always a possibility.
Got it and they are the only this is kind of a dull.
And the only longer term contract, we have and we said this is with Vijay.
All the rest of them reluctant and said where the two drilling.
Company oil fracking company.
Really well to oil.
Okay.
And then just to follow up and so.
So could you give some color on the production.
Production cadence here in 'twenty, one and just what you think you see as the high quarter for this year.
Steve relative similar to what we.
I think I answered in the first quarter as well, we're going to we will have sequential growth here in the in the second and third quarters, and then flattening out.
And in the fourth quarter based on the based on the cadence and the timing of.
Of completions that we currently.
And have modeled so severely.
The growth from.
And in the first quarter, we will.
And probably be split between the second and third quarter and and the fourth quarter flattens out.
And even maybe comes down just a little bit just based on the on the cadence of.
Which wells are turned to sales on which day.
Okay. That's it from me thanks.
Thank you once again, if you would like to ask a question. Please press Star. One next question comes from the line.
Humana and <unk> of Goldman Sachs. Your line is open.
Great.
Morning, and thank you for taking my questions.
My first question is I would say look towards screen and 22 gas and Jos.
The cover piece to be chopped coordination.
I wanted to get your thoughts around the expectation of that guidance.
Thanks is heading into next year and then within that context, maybe you can touch and plans.
Plans to manage and missed.
And our hedging program.
Okay.
Well and that yes. The question on gas prices I think we see a pretty constructive situation and building out for the summer with the gas storage being below average low and that below the five year average far below where we were a year ago.
And it really driven by.
Yeah really record kind of exports of LNG and <unk>.
And exports directly to Mexico. So that's all been very constructive despite the fact that the weather has not been overlaid constructive for the for natural gas.
This year, but.
And overall the situation looks.
It looks pretty promising and you know I think you've seen the natural gas futures market, especially for 'twenty one react recent.
Recently firming up to getting closer to that $3 level.
And so we're we're as as that spills over into 2020. Two we're really we need to put hedges and in 2020 day, where we're kind of at our targets for 'twenty one.
Yes, that's when we look at well hopefully build the 22 position.
At a higher kind of support level than we were able to do this year.
There are already off to a small start there with about 20% hedged for 'twenty two.
So we're patient and that's kind of why we.
We think over the course of the summer hopefully gas continues to firm further out and just the current month, but.
Obviously with our cost structure, our industry, leading low cost structure that we have.
And very high margins and our margins from <unk>, 79% here and the first quarter and those dose.
That was lucky with.
And with a better curve that we have and the.
The second through the fourth quarter. This year, the very better index prices, yes, we'd see those margins and being able to maintain those through this year, so really good backdrop.
Backdrop as set out there and our paid and for achieving all our goals for 2021.
And along with what we've done and you can see I mean, the recent hedges, we've added and 22, who have been swaps we continue.
To monitor the color market is as well as as the 'twenty two strip has moved up.
We've just taken the opportunity to do some swaps, but we continue to to to want to have a combination of both swaps and collars.
In our 22 hedge book, so that we we do create.
The base level of cash flow, but also have have some upside on a significant portion of our hedges when we get to that year and you know it.
<unk> point to swaps gave you a little more stability because you know there is $2 70. The callers gives you a little more upside and so as he said, we blend those and kind of like we did.
2021 and.
And the future we look at.
And the industrial demand is growing and in Mexico.
Through I think 80% of the gas that goes to Mexico, which is about seven <unk>.
He's a day comes from the Texas area some of that come from the Permian. If you look at where the LNG export facilities or we're exporting about 11, five BS a day, probably 10 and a half of that comes from where we are at the Gulf Coast area. So we see that as a strong market, we see Asia gas $7 gas and Europe at $8.
The spreads.
To recall, a couple of dollars to liquid THAAD and transport it over there and our gas is $3. So you look at the winter They had and Europe I think storage is low there you look at demand growth in Asia.
It sets us up for.
And really good I think next 18 to 24 months.
And really because.
I think the public companies, particularly will be disciplined with growth and capex. Its associated gas, we're not fearful that theres going to growth.
We think these companies will be given dividends and volunteers back.
And returning dollars to their stakeholders, that's exactly what our focus is to improve our balance sheet reduce our leverage and lower our cost to capital.
So I think I think it's a good drug for this whole sector for 2021 22.
Great that's really helpful and.
And as my follow up as you do get an average to free cash flow generation and production growth to what time school and and given your favorable view of natural gas prices heading into next year.
I wanted to get your initial thoughts around activity net but it's like what do you think is a more sustainable activity.
Comstock and sustain.
For the next few years.
Well, I think and Dan and kind of I referenced it earlier.
And a five drilling rig program is again sustainable.
And low production growth kind of.
Model that we think the Companys Jarrett and to know that they.
<unk> start outperforming.
Yeah, the deficiencies Oh, maybe we can we scale that back in.
But.
And we're freeing up other parts of free cash flow not just from the Capex savings this new interest savings.
More and more free.
Free cash flow as we don't have to use as much of our margin to dip to service. They are fixed cost and hopefully you know theres more of that and the future I mean, we've only taken done half of that work and we'd like to do.
Two two and the next.
Next year, so finished that work and bring down our overall interest burden off of the alpha and the margin.
So.
And.
Yes, we think this will be a great year for building on that foundation, but you know, it's probably a two year project to really get the balance sheet to where the market and where you want it to be which is leverage.
Way below two times, so after a good start and but lots of work to do well and the strip looks good. It's 290 substitute go out eight or nine months at St 12, 320, I mean.
It is just now starting to probably act like we thought it would act.
And we're starting the summer months.
If you if you give us the top trip we have today I mean, our goal is to get our leverage ratio to the low twos high ones that is our goal I think that the value of this company will explode exponentially if we can do that.
And if Dan Harrison and his group with Patrick et cetera, and deliver longer laterals.
Because we have such a huge footprint.
We have so many tier one locations to drill.
And that's how we can create tremendous wealthier and.
And I think geographically, we're located better than any company, if youre looking for dry gas.
And youre looking to attach it to the LNG export area.
I think we're located Burger and any company period, I think thats going to be an attractive reason people look at this company zone equity.
Thank you.
Thank you once again, if you will die cast a question. Please press star one.
Once again to answer your question please per installed one.
There are no further question at this time I would like to turn the call back to Jay Allison for closing remarks.
Sure again, thank God I don't want you to know we again, we exited were like a family here.
And you hire us for Ron and company you'd give us money per bonds, you give us money because you believe and equity and we act like that we've collected for 35 years we've.
And we've read some notes I think theres 10, or so analysts that follow us we've read notes and.
I think today it's.
One of those kind of tipping point day. So I think everybody agrees with what we are giving you what we're trying to do and that the outlook is very favorable.
Again, we say, we have decades of locations and the Haynesville Boettcher and Thats unusual most companies have 10 years 12 years 15 years of locations. We have decades, we have industry, leading low cost structure, we're not trying to get there we have it.
We have high margin return Haynesville wells, we gave you those quarter over quarter at quarter. In fact, we advertise from the highs and North America, It's a big big geographical area, but we do.
We will hedge we talked about that to protect our drilling returns and we.
We do have tremendous financial liquidity, a year ago, we didn't but we issued the bonds and then we issued a bond just this year, we do now.
$927 million in and.
We will and we always have focused on reducing our GHT M issues, we're very proactive with BJ, if and when they went through their hard times and we're very proactive we use them and we supported them because we support the service companies, but we have we are watching ghd and we generate great free cash flow desk.
We were able to tap the capital markets last year to $1 billion and.
This year for big and $2 50, and we are near I think this was the border where near LNG market.
Export haynesville gas around the globe.
And this one time and a golfer.
If you look at the last Olympics from South Korea, Haynesville gas was used there to generate the power to lap the stadiums.
That's where some of this gas goes it's a global market. So we leave you with this.
And our drumbeat again, this year improve our balance sheet reduce our leverage and lower our cost of capital. If we do that we've got a blue ribbon coming.
And thank you for your time.
So we can do the rest of the year.
Thank you and again, ladies and gentlemen. This concludes today's conference call. Thank you for participating you may now disconnect.
And the Great day.
Inc.
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