CPE
#We always like to reserve the rights to do that because it gives us some flexibility, <UNK> but we feel I think pretty comfortable with barring any sort of real dislocation of oil prices sub 40 that we want to stay on this path.
We do see some strong returns on the portfolio in all three of our areas to accelerate here with the balance sheet in the position it is and more importantly the internal cash flow generation that I think we're showing with improved cost structure goes a long way to, not relying on outside capital whether it be bank financing or otherwise.
As <UNK> said, I think this is probably a little bit biased that we can move this to the upside on a three-year look into 2018 that we hope to deliver on bringing a third rig back early 2017.
Continue to see results out of the Wildhorse area, out of the A, the Lower Spraberry to B put that together in terms of a development program to gives us the conviction to stand up another rig going into 2018.
If there is a bias, I think that we've been pretty measured in terms of the assumptions that we're using in terms of tight curves and such and probably giving us hopefully a conviction later in 2017 to be looking hard at fourth rig.
<UNK>.
Absolutely.
Again we're excited about what we have again.
We think we're looking forward enough to manage the operational risk.
I just don't want to go drill a bunch of wells and not be efficient about it so I think about infrastructure, I think pipeline productions and I think about water disposal and water sourcing and importantly land over relationships.
We deal with at lot of land owners in a very highly professional manner that are all important to us that gets to the root of our reputation of doing things well and doing things right and really delivering on what we say.
It pains me that the Carpe Diem production happened in the second quarter because, we expect to be able to deliver on the results that we talk about.
And so if anything, we will be measured in going forward.
We will be I think focused on trying to accelerate and bring value forward more so than slowing down.
The only thing that I think is going to stop us is like Joe just mentioned, a major downward movement in commodity prices and I just don't see that.
Well this is a interesting topic around here because we've been at three before and there was still a lot of capacity on this team.
I've thrown out at least conceptually for us to be prepared and these are wild numbers so don't be putting any of this stuff in your models but to be prepared for six.
The only time I ever saw any widening of the eyes of my team when I threw out ten one time.
So we're very comfortable with increased activity.
We're not stressed at all.
We have a very talented team and we can take on a good bit more.
Well, that's why I'm trying to spend an awful lot of time studying it so that I can comfortably get behind the additional cost associated with it.
I have a couple of meetings scheduled for the next couple of weeks to get further detail into some of the results that have been published that are very exciting around it.
But certainly nano surfactant should deliver enhanced results over time.
There's no question about it.
What you're doing is as you're fracking that well and you're adding that surfactant, you're actually freeing oil that should be ready to produce near term fairly quickly.
So certainly the early time results should be higher than what you've seen in the area.
What I'm trying to get more comfortable with is the longer term benefit related to the EUR.
If its a short term acceleration you can justify the cost okay but I'm trying to get more comfortable with the enhanced EURs around some of the published data and once I get comfortable with it and the cost cycle, then I will be ready to go forward.
You were question is exactly why I've been a little hesitant in jumping right in and doing some because as you guys know, I've said this over and over.
I like the benefit of having fairly good offset operators around us that can prove up some of this technology for us.
And I'm getting excited enough about some of the more published ---+ more recently published results that I'm anxious to kind of try one on my own.
Again, I'm not going to throw out any numbers on this call.
I'm trying to get more comfortable with it myself.
I will try one, I promise you I will give one a shot.
I just don't know which well I'm going to do it on yet and after I get those results, I will be very comfortable about describing exactly what we delivered because I do get a little hesitant about some of the publishing results only just being around the best wells so there's a whole plethora of information out there that I'm digging into that's getting me more and mover comfortable with the technology.
What I'm uncomfortable with is the cost.
Especially in an appreciating environment.
Not from what we've seen so far.
The other zones within Monarch outside of the Lower Spraberry.
We haven't done a lot of down spacing test there is yet.
So I would suggest that that's zone specific.
The Lower Spraberry sets up nicely with the thickness and really the enhanced porosity in the Lower Sprayberry to an oil in place to support a higher density of wells.
It may or may not fit well with a higher density in the Wolfcamp B or even the Wolfcamp A as we test it here in the near term.
But going from 11 to possibly 13, I can see that happening.
But I really want to get to the point where I have several offset pads drilled next to wells that I've already tested downspacing on.
That's really going to be the longer-term test.
So I'll still be talking about this in the next two years probably, before I really narrow down what the optimum spacing might be.
I attribute a lot of that to infrastructure investment actually.
I think it's planning ahead.
It's planning for growth.
The companies that get out ahead of their programs without putting in the appropriate infrastructure and thinking about how that can be efficient with it, will have a higher LOE component.
Those who get ahead of that will be able to manage their costs and leverage that investment over a longer period of time.
Thanks.
In terms of the model that we have and laid out, as <UNK> said, we're looking at two well pads moving across that acreage position so we aren't ourselves planning on doing really any downspacing tests at this point in this plan, at least next year.
We'll see how things develop.
I think we're more focused on looking at stack laterals, Lower Spraberry, Wolfcamp A or adding the B in there doing a lot a lot of spacing tests.
There's some spacing tests going on as things are getting closer to program development in Howard County but, you know, right now we haven't dialed that into our program.
I mean we might change up some of the well locations as we get further into the program but right now we haven't put that into our plan.
Good morning.
We don't necessarily target any specific number.
You know, we want to have as many locations that fit the criteria on the bottom right-hand side that can deliver value at below, or around $50.
That's a world that we live in.
We think that incremental investment comes in the industry at $55, $60 so we need to be prepared to live below that.
In terms of, you know, how you characterize the inventory, we provided some math here.
Three or six or four years in each of the core areas, that's if you assume all those rigs are in that area and no where else , just focused there for the whole period.
So just with our delineated locations that are currently producing, so the upside locations that I don't think you've taken into account, they are producing offsetting our acreage.
We just haven't drilled them so we haven't put them in our account.
I think our real number then that we would feel good about is somewhere between and this is assuming four rigs, I think you had said five or six, let's say it's four, between 14 and 25 years.
The numbers in there.
It's certainly a comfortable range we would like to carry certainly north of ten years of inventory and investment that's very visible to us with having upside there but, at some point, how much inventory do you want to carry that you're not going to get after for 20 years.
We want to be cognizant of that.
So I guess to answer your question, we don't see those being inventory constrained, I think we're constrained by making sure we're efficient before we accelerate too much and pull these returns forward.
I don't think it has changed really all that much.
Second quarter we were free cash flow positive.
Third quarter, we do have some infrastructure investments to get ahead of but there's really no meaningful outspend that we're seeing there.
We're laid out a three-year plan so I'm not going to talk about any year specifically but under this three-year plan through 2018, in 2018 for the totality of the year we're looking at being free cash flow neutral.
That includes some quarters being free cash flow positive, pretty significantly.
So if you take the next ---+ start in third quarter in 2016 through the end of 2018 on average I think the out spend comes out to be $7 million on average per quarter.
And again that includes periods of, more or less than that from time-to-time.
I think our peak borrowing that we would potentially have under our borrowing base facility while we are a ramping up two rigs in a short period of time which is a lot, you're going to go in a cash flow negative position is probably an incremental $90 million to $100 million sometime later in 2017.
You know, if we assumed let's call it $42, $43 flat from today until 2018, we would still be at two-and-a-half times or less.
Yeah, this is <UNK>.
We're going to start with two well pads and just targeting the A for the first couple of pads and the team is already anxious to prove up the Lower Spraberry so then we'll bring the Lower Spraberry in a little bit later in the year and we'll be looking to test the B later after that.
We're very focused on delivering early time solid results in the A for now because it is the most worked and the most derisked and I think given what we've been doing in the Wolfcamp formation and other places around increased sand loading and downspacing has an application here and we'll be testing that as we go forward so we're excited about the A and as I said before, we're equally excited about the value component of the Lower Spraberry and then we'll watch others and if they're late to the game, we'll come in and prove up to be ourselves with the capacity that we have.
Again, we see potential in other zones and again as we just talked about inventory, we talked about inventory on things that we know work that have a high level of technical confidence around.
And again an advantage we've had is we've seen a lot of other people test additional zones and improve that up for us.
There's certainly more to be had in Howard county over time.
We're just not ready to put it out there as saying it's something we're ready to go, bring forward at this point in time.
If anything, it would be positive.
Again I think what Joe referenced in his comments in some of our older fields we've gone in and actually reduced, managed to the point where we're able to pull additional pressure off of the formation, get more stability in the down hole flow potential of a well.
Manage horizontal wells in a way that can both increase IP or production potential even in a draw-down condition.
And that's given us incremental oil and incremental gas and so over time, it will increase the EUR and bring forward value.
Once again we do appreciate everyone taking time to call in and certainly if anyone has any questions in the interim, don't hesitate to give any of us a call.
Thank you so much.
