Q2 2019 Earnings Call
Good morning, and welcome to Earthstone Energy's Conference call.
At this time all participants are in a listen only mode. A brief question answer session will follow the formal presentation.
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As a reminder, this conference is being recorded.
Joining us today from Earthstone are Robert Anderson, President, Mark Lumpkin, Executive Vice President and Chief Financial Officer, and Scott The ladder Vice President of Finance.
Mr. T. lender you may begin.
Thank you and welcome to our second quarter Conference call before we get started I would like to remind you that today's call will contain forward looking statements within the meaning of section 27, a of the Securities Act of 933 as amended and section 21 E of the Securities Exchange Act of 934 as amended.
Although management believes these statements are based on reasonable expectations. They can give no assurance that they will prove to be correct.
These statements are subject to certain risks uncertainties and assumptions as described in the earnings announcement, we released yesterday and in our annual report on Form 10-K for 2018.
These documents can be found in the investors section of our website www dot burst stone energy Dot com.
Should one or more of these risks materialize or should underlying assumptions prove incorrect actual results may vary materially.
This conference call also includes references to certain non-GAAP financial measures.
Reconciliations of these non-GAAP financial measures to the most directly comparable measure under GAAP are contained in our earnings announcement released yesterday.
Also please note information recorded on this call speaks only as of today August seven 2019 that any time sensitive information may no longer be accurate at the time of any replay.
Every replay of today's call will be available via webcast by going to the investors section averse Downs website and also by telephone replay.
You can find information about how to access those on our earnings announcement released yesterday.
Today's call will begin with remarks from Robert Anderson, providing an overview of our second quarter accomplishments and a review of our operations.
Followed by remarks from Mark Lumpkin regarding financial matters and performance.
And concluding with remarks from Robert regarding our current and upcoming operational plans.
I'll now turn the call over to Robert.
Thank you Scott and welcome to everybody joining us this morning, I know, it's been a pretty busy morning.
In the second quarter, we again set new records for both adjusted EBITDAX and average daily production with the adjusted EBITDAX of approximately $33.6 million driven by our highest quarterly production to date of approximately 12700 Boe per day.
As production grew 13% sequentially from the first quarter of 22019.
Well, we didn't bring any new wells on production during the second quarter. The three operated wells completed in the Midland Basin in the first quarter contributed to this strong growth.
As you might recall recall in March we achieved an average rate of approximately 13400 Boe per day.
Per day, therefore, just a moderate decline going through the second quarter.
Our wells are continuing to perform in line with expectations with our first half reported production profile, beating our own internal forecasts. We are proud to be generating peer leading operating margins with first and second quarter 2019, realizing adjusted EBITDAX per BOE, we have $32, a nine cents and $29 an 11 cents respectively.
We have a slide in our investor presentation, with which illustrates this peer benchmarking analysis for Q1 based on all that.
All in unhedged cash margin with Earthstone coming in at $25.34 per BOE, 30% above the peer average of course, our strong hedge position is boosting those margins even further.
Mark will walk you through pricing and hedges in more detail, but I'll just comment on natural gas prices in the Permian, which were negative for much of the second quarter. We are fortunate that we have our 2019 natural gas and basis nearly fully hedged at a net price after basis of approximately $1.70 per and then b to you. We have similar similar hedge prices in place for a meaningful portion of our gas volume forecasted in 2020 as well.
We have also been working on optimizing our capital program for 2019 and have made some enhancements that result in some guidance changes, which Mark will review in detail. We expect our revised capital program to result in bringing on 14 gross Midland Basin operated wells and 10 gross Eagle Ford operated wells from late in the third quarter through the end of the fourth quarter.
We will also spud an additional five gross operated wells with this capex.
Based on both well performance year to date and our revised capital program. We now expect an exit rate of 14000 to 15000 Boe per day.
Between our updated 2019 exit rate expectations and the approximately 50 million.
Estimated 2019 capital expenditures that will have very minimal impact on our 2019 sales volumes.
We will we will be very well positioned to begin 2020 with strong production.
In July we closed a wellbore development agreement or what you all might call a drillco arrangement with an industry partner that covers an eight well program in 2019 on our Central Reagan County assets with an option for up to 11 additional wells next year.
This agreement is structured as a wellbore only agreement and the drill go partner does not earn any acreage.
But they will earn 35% of the working interest in these wells by paying a higher portion of the capital costs. The Drillco will enhance our drilling economics and provide greater optionality in our future drilling plans as we meet our limited drilling obligations on an accelerated basis.
To support our capital program, including the Drillco, we have secured a second rig and are currently running two rigs on a temporary basis in the Midland Basin.
We contracted a top performing high spec rig with ENHANZE pump capacity at a similar day rate is the rig we have been running over the last two years in the Midland Basin, and which we plan to release later this quarter.
With the upgraded equipment and crews we expect the high spec rig to operate more efficiently, resulting in fewer drilling days per well, thus, we expect well cost reductions as a result of the new rig and associated services.
I will give some details later on the positive results, we are already seeing with his new rig, which we deployed in June .
We have increased our activity in the Eagle Ford, where drilling is underway on a seven well program on our pen Ranch project.
And we will then continue on to drill three wells on our Davis project.
We expect to start completion activity in the Eagle Ford in the third quarter and to complete all 10 Eagle Ford Wells by year end. These 10 wells largely complete our internet our anticipated Eagle Ford development activity and we currently expect to focus 100% of our 2020 capital program in the Midland Basin.
I will turn the call over to Mark to provide more details on our new guidance and financial results and then I'll review a few operational items. Thank you Robert.
And do you have the increased operated drilling and completion activities that Robert described and anticipation of lower non operated activity. We're revising our 2000 I think capital budget to 205 million from previously $190 million and this includes reallocating some of our spending from Midland Basin. Non operated two operated drilling locations in both the Midland and Eagle Ford basins.
This revised budget assumes temporarily running two rigs in the Midland basin until sometime around the end of the third quarter before dropping back to one rig and also assumes completing a 10 gross well program in the Eagle Ford.
We are raising our average daily production guidance for 2019 to a range of 11215 to 12250 barrels of oil equivalent per day from our previous guidance of 11000 to 12000. This was largely due to well performance to date and really isn't driven by added capital expenditures, we've not made any changes to our guidance on our 2019 production mix, which we still expect to be around 65% oil, 19% Ngls and 16% natural gas.
As Robert mentioned with our revised capital plan for the balance of the year, our internal expectations for how we end the year and begin 2020 are now significantly higher with 14 of our anticipated 17 gross Midland Basin, operator wells and all 10 of our gross Eagle Ford Wells expected to be online from some time and the later part of September through the end of the year, we do expect to achieve meaningfully higher production volumes at year end 2019, and in the first quarter of 2020 than we previously expected.
We have now put out new guidance on 2019 exit rate of 14000 to 15000 barrels of oil per day barrels of oil equivalent per day, which was a significant increase versus our prior internal forecast in terms of the incremental 15 million of capital expenditures and our revised budget, though it won't really impact 2019 and production volumes given the timing, we do expect an incremental approximately 1.4 net wells online and an incremental approximately 4.8 net wells spud, which will largely be ducks all by year end.
This feeds into our increased expectations for production growth in 2020, as we now expect a significantly higher year over year percentage increase in volumes in 2020 on a one rig Midland program versus the percentage increase we're likely to achieve in 2019.
Now, let me turn it over to financial metrics for the second quarter, our sales revenue was $44.5 million compared to $37.2 million in the second quarter 2018, and $40.7 million in the first quarter of 2019.
This topline growth was driven primarily by higher sales volumes, which averaged 12699 barrels of oil equivalent per day, representing 13% growth compared to the first quarter and by higher oil prices crude oil sales contributed $40.8 million or 90% of 92% of total revenues and our production mix during the second quarter was 61% oil, 21% NGL with the remainder natural gas.
We realized higher oil prices in the second quarter, averaging 57, 90, $857 or 90 cents per barrel of oil before realized gain on derivatives boosted in part by continued improvement and the differentials in the Midland basin compared to $50.30 before realized gains on derivatives in the first quarter.
On the natural gas side, a combination of weak index prices and wide negative differentials on our Midland basin gas for much of the quarter resulted in average natural gas price before the impact of realized gains on derivatives of approximately 10 cents per Mcf, which compares to approximately $1.32 cents per mcf in the first quarter.
On a similar note weakness and NGL pricing resulted in an average price of 14 hours a nine cents per barrel in the second quarter versus $21.66 per barrel in the first quarter.
All told this resulted in realizations in the second quarter for oil NGL and natural gas of about 97%, 25% and 4% of Nymex, respectively compared to the first quarter averages of approximately 95%, 39% and 42% of Nymex.
We have continued to benefit from a strong hedge book in 2019 with realized gains in the second quarter of $4.6 million, which brings our realized commodity hedge gains for the year to approximately $10 million our hedge position remained strong with hedges for 2019, equating to approximately 82% at 83% of our production guidance for oil natural gas.
And we have also continued to modestly add to our oil hedge position with incremental swaps in 2020, which are currently at an average price, including differentials of over $60 per barrel and have initiated a moderate level of hedges for 2021 at an average price, including Midland basin basis hedges of near $56 per barrel.
Similarly, we are well hedged through 2020 on the natural gas side on both the underlying commodity and on Wahab for full details of our current hedge position. Please reference our investor presentation.
We achieved a company record quarterly adjusted EBITDAX level in the second quarter of $33.6 million, which was a sequential increase of 4% from the $32.4 million in the first quarter and up 64% from the same period last year from an income standpoint, we recorded adjusted net income in the second quarter of $14.9 million or 23 cents per diluted share.
Now looking at our expenses our lease operating expense came in higher than our forecast, but was partially offset by a lower than forecasted cash DNA expense.
Ella we per BOE, ie averaged $7.44 and the second quarter compared to $6.61 in the first quarter Workover expense has been the primary driver of our elevated eight of our elevated aleem some of that work with strategic to boost production at low incremental costs, but a large portion of the workover costs was related to Frac hits on our producing wells. We have also experienced increased lowi for saltwater disposal as some frac hits have caused increased water production for a period of time.
As a result of what we have reported in the first half and are now projecting for the balance of the year. We have revised our guidance for lease operating expenses to be in the range of six hours and 25 cents to $6.75 per Boe, we or a one dollar increase over our previous guidance, we expect to be able to further improve our lower unit cost in the second half, particularly in the fourth quarter and are aiming to achieve continued low unit cost improvements and to 20 point.
Our cash DNA expense per BOE, a day average for 2013 cents in the second quarter compared to $5.01 per Boe in the first quarter.
We continue to manage our DNA tightly and with total DNA below our internal forecast in the first half and what DNA for barely afford ours in 54 cents in the first half tracking below our full year guidance. We are also reducing our guidance on the cash DNA share range of four hours and 50 cents to $5 and $55 per Boe.
For the full year, which is a 50, which is a 50 cent decrease versus our prior guidance.
We reported net income for the second quarter 2019 of $19.5 million compared to a loss of $38.4 million in the first quarter and net income of $1 million to $1.5 million in the second quarter of last year.
As described in previous calls GAAP requires us to disclose the amount of net loss or income associated with the controlling interest, which essentially reflects our class a shares accordingly from a GAAP perspective, we reported net income attributable to Earthstone energy inc. of $8.8 million or 30 cents per diluted share compared to a net loss of seven point $17.2 million or 60 cents per diluted share in the first quarter 2019, and compared to $650000 of net income or two cents per diluted share in the second quarter of 2018, you can also refer to today's earnings release.
And our 10-Q for further information.
Lastly, let's move on to the balance sheet and liquidity at June Thirtyth 2019, we had outstanding borrowings under our credit facility of $110 million and a cash balance of approximately $5.8 million. We currently have 215 million of undrawn capacity on our borrowing base facility for total liquidity of approximately $221 million at quarter end. So our liquidity continues to remain strong.
I will now turn the call back over to Robert for more discussion on our operating activity.
Thanks Mark.
Our 2019 drilling program is continuing to to perform well based on production performance from the first half of the year and our ongoing focus to safe and efficient operations. We currently have two rigs running in the Midland Basin, one of which will be released before the end of the third quarter as I've already mentioned as well as our one rig in the Eagle Ford Shale will which will be released prior to the Andy the year as we finish up our 10 well drilling program. There late in the second quarter, we completed the drilling of our five well Midstates project in Midland County, we have a 67% working interest in these wells, which have approximately 10000 foot lateral sections targeting the wolfcamp, a and b intervals.
We have started completions on these wells and expect to have them online around the end of September the completions are progressing on schedule as we just wrapped up around 180 successful stages on the first three wells and our fracking the last two wells now.
Our frac efficiency continues to average about eight eight to 10 stages per day with costs similar to earlier in the year, we expect to maintain this frac crew and related services completing wells from now through November .
We moved the legacy rig drilling up in the Midstates block to our block one bolt on area in Central Reagan County, where we are where we are just finishing up drilling on a two well pad targeting the wolfcamp b upper.
And then after that we'll move it to a two well pad targeting the wolfcamp a in the same project area. All four of these wells are approximately 10000 foot laterals and we will have a 65% working interest after giving effect to our Drillco agreement after drilling the second two well pad, we expect to release this rig.
Utilizing the new high spec rig, we recently drilled a three well pad on our TSR H unit in record time, we drilled approximately 60400 feet a whole and 46 days the wells average lateral length of approximately 12000 feet.
We had several days with more than 3500 feet of lateral drilled which set new records for our drilling team.
These three wells are also included in our Drillco and we have a 65% working interest.
As mentioned on our last earnings call. These TSR H. wells are spaced about 1100 feet. Apart in the same landing zone are about 550 feet between wells. They are significant distance from existing producers on our TSR H block and will aid us in assessing assessing the optimum spacing for this area.
From a non op standpoint, we're participating in a 15 well project on the Martin Midland County line targeting five different zones in the Spraberry and Wolfcamp, we have about a 20.5% working interest and expected net capex of approximately $29 million through completion.
The current expected timing on completions on this project is largely in the first quarter of 2020 versus our prior plan that completions would occur before the end of the year, which has resulted in a shift of capital from 2019 2020 for this component of our budget.
To spend a moment or two highlighting well performance the strong results of our new wells and the continued performance of our base production all contributed to our record second quarter production.
Our Upton County Wells that were completed in the first quarter are producing below the million barrel equivalent type curve, but still with very attractive economics.
I will remind you that these type curves are based on our own well dataset and cover various acreage positions as well as different targets from Midland and Upton counties.
As our well population increases in Upton County, we will breakout type curves by county, specifically for context, the Upton County Wells in 2019 have a similar estimated ultimate oil recovery is Reagan county, but have a 71% oil component and start out at higher rates and therefore, ultimately generate better economics.
Lastly, we continue to focus our.
We continue to focus on enhancing our operating margins managing our leverage and the efficient execution of our capital program.
Operator with that we'll now turn it over for questions.
Thank you.
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Our first question comes from the line of Neal Dingmann with Suntrust Robinson Humphrey. Please proceed with your question.
Morning, Robert and team.
Next quarters say, Robert My question is around the Drillco.
What sort of spark that I guess was lit lets just start there and are there other drillco opportunities.
At this time are not really exploring any other drillco opportunities in what sparked that is this is kind of status.
Ammo for us that we've always done these kind of things when.
We want to either.
Accelerate obligation drilling and get that HBP status behind us.
Or also earn a little better economics in a particular area because we're bringing them in on a small promote.
And then lastly be able to extend our capital to the highest rate of return projects in our portfolio. So I think all those things.
Hey, good sense for us.
No they didn't and could you tie one of these if you saw.
I guess my thought is given sort of the rational market if.
Acquisitions end up being fairly reasonable out there could you tie one of these into an acquisition to make it even more.
Accretive more quickly.
Sure we.
As you know we're open to looking at a lot of different arrangements when we look at.
Acquisitions, and bringing in a partner too.
Facilitate something in an area is something we always consider.
Okay, and then last if I could just on looking at sort of trajectory it looks like you've got.
Quite a bit of activity to end the year and into next year.
I know without realizing you don't have 2020 out could you or Mark just may be talk about.
How you see.
Trajectory, but are you seeing things sort of kind of comparable to what they are now and just flowing into 2020 or.
What it what do you see it seems like you're having a pretty good balance now.
Yes, let me take the first step of that were nil.
First of all I think people do recognize but I'll just highlight this anyways.
We havent brought a well online since March so we have effectively been in a natural decline from March really through probably late September and the way weve been thinking about things, we do expect to get these midstates wells online late in September , but it's going to have a very minor contribution to third quarter production. So essentially we're on a decline until those wells come on line and again, we brought three wells online on a gross basis in the Midland Basin, all in the first quarter and will bring 14 gross wells.
Online in the Midland Basin from the very end of the third quarter through the end of the fourth quarter. In addition to that 10 gross.
Wells online in the fourth quarter in the Eagle Ford. So obviously you know we said before our Capex program was very back end weighted from a production standpoint, we're at 13400 barrels a day in March and that held up pretty good started off the quarter and then there's been a natural decline we ended up at the at the 12 seven yes, we think that number is definitely going to be trending down a decent bet in the in the third quarter and we'd expect that third quarter to be are our lowest volume.
In terms of production number for sure what that was probably a 10 handle on it maybe even low tens.
As kind of how we're thinking of it and that of course depends a little bit on how do we get a week or two of Midstates productions or is there not really any significant production from the medsafe pad, but as you think about the fourth quarter and that should give you some kind of.
Wait a backend of of how we're thinking about third quarter versus fourth quarter. If you think about the fourth quarter, we've really got wells coming online all throughout the quarter.
And some of the providing the exit rate guidance was to communicate that but our expectations have changed and we recognize that we have not put our exit rate guidance before but we think it should help give folks a bit of a marker for how we expect to start the year out I think based on our current midpoint of our production guidance, we would be up 18% in 2019 over 2018, and we think running one rig next year will be.
A pretty pretty significantly higher percentage of growth from 19% to 20 versus what the midpoint of 19 implies versus 2018.
Does that help I mean, we're still not at depth at north of that having.
Go ahead, Mark we're still going to have a pretty decent better completion activity into the first quarter.
Both as as Weve got probably some some operated ducs, but really.
Some of the completion activity. If you can probably piece. This together from looking at our old and new guidance has gotten pushed out on the non op Midland basin into really the first quarter of next year that will be.
Kind of non op ducs that get completed likely sometime in the first quarter and.
We will continue to kind of help us crank out some some pretty nice new volumes.
And again, I think big picture, hopefully that give us some color on kind of how we're thinking of things.
Versus how we are thinking of things probably last quarter.
No that helps mix exit helps as well thank you all.
Thank you. Our next question comes from the line of Brad Heffern with RBC capital markets. Please proceed with your question.
Hey, good morning, everyone.
You guys talked about how in the second quarter, the well performance was better than what you projected internally I'm curious if the new guide fully incorporates that for both.
The legacy wells the base production and incorporate that for new wells or if thats still remaining upside.
Now we've got everything incorporated we run in now.
Model everyday I think Scott's doing something but weve updated for our mid year Internal Reserve report and it's got all that re forecasting built into it.
Brad and the one thing I would add there is like as we look at what's happened year to date, I mean, not just the second quarter, but including the first quarter, our oil volumes on our PDP and including kind of the three wells. We brought on the first quarter. They are definitely above our curves.
And what we've seen happen is some moderate improvement our outperformance on the oil side and then the gas and NGL side has been just well in excess of that in terms of incremental volumes versus our projections. We've kind of adjusted for that we still think we are going to end up the year about 65% oil in the third quarter, we definitely would expect that to tick down even below the 61% we had in the second quarter, but as we get a bunch of new volumes on line with higher oil oil content in late third quarter and fourth quarter, we expect to get around that 65%.
Okay got it.
And you guys talked about no eagleford activity in 2020.
Is that the plan sort of in perpetuity and can you remind where we stand on the HBP there and if you would just let the remaining acreage count.
We wouldn't let it go.
And it is subject to a lot of things Theres some activity.
In and around our northern block of acreage and we're watching that to see what latest frac techniques and designs.
How they impact results and then commodity prices. So you know right now as we look out to 2020, we're not planning to spend any eagle Ford capital, but in oil prices improve and.
These new wells.
Perform like we hope they would then we could spend a little capital up there, but again it would be very.
Minimal amount of capital compared to our overall program for 2020.
Okay.
And then finally I'll just ask the requisite M&A question you guys have obviously done the drillco here.
But are there any deals out there that you are seeing or how does the deal flow luck. I know you guys are always trying to add.
And we all we are always trying to add I'd say it's.
Probably more than frozen at the moment, it's just.
The whole macro environment and has created.
The situation that there just isn't a lot of deal flow at the moment. So we're knocking on doors, creating are creating as much.
Discussion as we can about opportunities we will continue to do so.
Okay appreciate it.
Thank you. Our next question comes from the line.
Duncan Mcintosh with Johnson Rice and company. Please proceed with your question.
Hey, good morning, Robert.
Hey.
The running two rigs in the third quarter and then dropping your legacy Rick I was wondering if you could provide some color around the efficiencies you kind of expect with the new higher spec rig.
Well, we had we were off to a really good start when we drilled a three well pad because it was using that high spec rig and.
From a.
The amount of footage per day kind of staying on average if you want to look at it that way.
It's been.
Very successful implementing that rig.
We're seeing some cost savings on.
Holding those numbers for you.
For a quarter and then hopefully we'll be able to give you some real live actual data on how much savings we're seeing by using this rig.
But we do expect to have a savings over the prior rig and maybe even.
That will translate into ultimately how much capital we end up spending this year. So I hope that we can.
Spend less than what the what the guidance is have to all five.
All right great.
My other question was already answered thank you.
Appreciate it.
Thank you. Our next question comes from the line of John White with Roth Capital Partners. Please proceed with your question.
Good morning, guys and.
Very strong quarter looks like everything's running just the way you want it to.
Thank you John almost everything John .
I'd now has always had a mouse right.
On the non operated Midland on your Capex in the non operated managed lend there was a large decline there is that.
Is that due to the company's withdrawing previously proposed wells or from you opting out of wells you previously thought you would.
Participating.
Neither.
It's just the activity pace.
That.
These guys have is it just got shoved out a little bit. So we're really just going to shift all of that activity.
Into 2020, we are still.
Participating in the same 20 wells.
That we had from the beginning of the year, it's just not getting completed as fast.
All right well proposals that were deferred.
They're not they're not even deferred there just things are taking a little longer in the field in one area, where they thought they were going to run multiple rigs on on this 15, while program, they're running less rigs on it than they had planned.
Yes, John we expect to get the same number of wells, but on a gross and net basis.
On the non up but the completions are effectively getting kind of push into the earlier part of 2020.
Alright.
Thanks for the detail.
Thank you. Our next question comes from the line of Mike Kelly with Seaport Global Securities. Please proceed with your question.
Hey, guys good morning.
First off I guess and I'm glad to hear that you had given those exit rate numbers before us drive myself nuts last night try and do those numbers [laughter] glad about currency.
But yes.
Question I really had I was just curious if you could give us a little bit more.
Detail around this drillco just.
What this carry looks like and then also curious on.
When this party has to say kind of yea or nay on their election to drill the wells with yet in 2020. Thanks.
Mike Some of this is a secret sauce that we probably aren't going to deliver so I won't.
I will probably drive you crazy because I'm not going to give you a very straight answer I'll. Just tell you that we're paying a little less than what our working interest is on the well so theres a little bit of promote built in there which is quite typical in these kind of deals and as we get to 2020 and have results on our 2019 program, we will propose wells and they'll have an option to participate or not participate it's pretty darn simple from that standpoint.
Got it and so are you thinking about this Robert if.
Is this kind of how you want to ultimately run two rigs is to have somebody come in and help.
In to help kind of shoulder that capex burden or I'm, just kind of curious if they say.
No.
You think about going to rigs alone next year, how how does that play out they say, yes or no.
It's a good question and we have sought thought a lot about it around here and I think a couple of things are going to happen. One is we are going to wait till we see what the environment looks like towards the end of the year.
And how these guys respond to the results we have on these on these wells one things for sure as I think we are going to.
Have improved economics, just on a gross basis, because our drilling times or less so our capital is going to be a little bit less in those wells and I think that will.
Satisfy them to want to participate next year, but if oil prices.
Tank.
Then maybe both of us want to delay or defer things are spread things out as much as possible. So again, the two rig program versus a one rig program isn't based on whether the drillco participates or not I think theres. Some other things that will drive part of that decision as well.
Got it understood. Thanks, guys.
Thank you, ladies and gentlemen, as a reminder, if you'd like to join the question queue. Please press star one at this time.
Our next question comes from the line of Jason Wangler with Imperial Capital. Please proceed with your question.
Hey, good morning.
Just maybe to dovetail on Mike's question on the next year's Wells.
Is that a well by well basis or is there a demarcation where they have to.
Except all 11 or not.
It's not a well by well basis and it's not all 11 at once it's basically by a pad Jason So we don't want them to.
Cherry pick a horizon, but they can sort of decide in or out on a pad basis.
Okay, that's kind of what I was curious and then it sounds like the wells for this year are pretty much already the pads are already pick them. So you kind of know where you're going through rest of this year with them.
You see at were Don Newman Youve Weve talked about every well in some form or fashion that they are in this year for those eight wells so yes.
And they are they're in all eight of this so perfect.
Thank you very much.
Thanks.
Thank you ladies and gentlemen. This concludes our question and answer session I will turn the floor back to Mr. Anderson for any final comments.
Now thanks, all we appreciate your interest and have a great day.
Thank you. This concludes today's teleconference. You may disconnect. Your lines at this time. Thank you for your participation.