EGN
#Well, we're hopeful we are going to see that kind of uplift.
We tried ---+ we tried gen 2 down in Glasscock, and we got a very good uplift from gen 2 to gen 1.
So our hope is that this particular frac job across the footprint is going to result in a pretty good uplift.
I don't know of any reason right now that that would not be the case.
Yes, it's a great question.
It's one of those highly subjective things.
We will have a few more wells on gen 3 that we get productive history on at the end of the first quarter.
But it's not going to be a whole lot, so my suspicion is we wouldn't ---+ we could change our minds.
But the earliest that we would think about doing that would be the second quarter, and I'm not sure we'd do it then.
It's just going to depend on how long we've seen these results and how many we've seen, how consistent they are.
How's that for a non-answer, <UNK>.
Well, we just don't know.
Well, I'm not sure we have enough data to know, and particularly since these wells were sort of stand-alone wells.
We did see oil cut very quickly, and we are very pleased.
But I'm not sure that we've got enough data in hand to know a definitive answer on that.
<UNK>, I've ---+ and I think <UNK> said it.
The one thing we've been pleased with is these wells have cut oil quicker than the previous generation fracs.
Now, we don't have a lot of them and it's early time, but it's always good when you see that happening quicker.
It's pretty even at the end of the year.
And I think it's going to be pretty fairly balanced as we move forward.
Obviously, if we've got an odd number, there will be one more in one basin versus another.
But it's a pretty even split, <UNK>, as we have thought about it.
Give me that second question again, <UNK>.
I'm going to address that one first.
Well, I can tell you this.
We are going to have a lower inventory of uncompleted wells, as we said, coming out of 2017.
But we've got an awful lot of development work that we're doing in the Midland that's coming online that will push into that next quarter.
So I don't think ---+ unfortunately, <UNK>, we haven't really provided any quarterly guidance for 2018 and 2019 yet, but we do feel very confident on our annual 20% growth rates.
And that's probably the best I can do for right now.
We really haven't looked forward to 2019 in terms of a quarterly guidance yet.
Well, the realizations have been higher, and that market has turned around.
And I'm forgetting what percentage we budgeted going forward there for that, <UNK>.
This is <UNK>.
One of the issues is that natural gas liquids prices have increased, and therefore some of your fixed costs that you've got related to transportation and fractionation are less as it relates to the gross NGL price.
And I think we laid out in the press release our expectations on realizations.
Well, <UNK>, I think as we look later in the year, we look at a lot of different things ---+ what kind of performance have we got; what kind of pricing do we have; what bolt-on acquisitions have we been able to do.
Anything we've got out there right now is subject to change.
And I think those are all things that we will look at.
Now, as it relates to gen 3 frac performance, as you know, we have a lot of wells that are already producing.
And I think we put in the press release that we had about 8.9 million barrels of production related to wells coming online.
So that's the number that I think you need to think about when you are thinking about the performance.
Obviously, it won't be on the entire production number that we forecasted.
Well, go ahead.
And maybe ---+ I don't know if I got directly to your question or not, if you need a follow up.
There's a good bit of drilling on the Tiger wells.
One of the reasons that on the slide our working interest drops a little bit on the drilling program is because we partnered on that particular acreage that the Tiger wells are on.
We only have 70% working interest; another has a 30%.
And there are some reasons that we want to go ahead and drill that acreage up this year.
So we do have a good bit more going in that Tiger unit.
And I think it's pretty consistent with what everybody else is talking about in that particular area.
A lot of people are talking about overall well costs up 10%.
If you look at 15% on pressure pumping, it's less than 10% on the total well costs at this point.
We do.
We have ---+ the tank battery is what it takes to get it off the lease, which is what ---+ the most any of our competitors will allocate.
So these costs are DC&E.
So they have the tank battery equipment, which is roughly about $200,000.
Now, they don't have saltwater disposals and all that kind of stuff, which nobody else allocates as well.
So this is drilling, completion, and equip the wellhead.
Well, the cadence of rig adds we had ---+ you know, if you look at the capital that we disclosed for 2018 and 2019, and you guys know about what it costs to rent a rig, it's predicated on a fairly ---+ you know, it's like a one-rig add sort of deal per year.
Now, it could be off a little bit, but it's not a stretch.
And the thing is we can do that with organization that we've got.
So you're not going to see a big jump in costs in order to basically double the production of the Company.
Yes.
<UNK>, actually ---+ that is a good oil cut.
It's not particularly unique to Wolfcamp A/Bs.
We've got 25 wells in our database.
They average, at this point, 85% oil cut.
So they are not abnormally high.
What we are interested in is to see how long a gen 3 well can maintain that high oil cut.
So as we go forward, but given what we are trying to achieve in the reservoir, we would like to see the GOR remain lower longer.
But as an original well production at this point, they are not abnormal.
They may be a few percent higher than our average.
Our average is about 85%.
But they are not abnormally high.
No, it just takes a little longer.
A lot of the wells we are bringing on are Midland Basin wells, and it just takes a little bit longer.
A lot of those are drilled in pattern development.
And we've always said that the first quarter was going to be flat to slightly down off of the fourth quarter.
We have been telegraphing that for months.
And that's ---+ hopefully, it does turn out to be conservative.
But I think that's what we planned it to be, based on the fact that a lot of our production starts to come on in that second, third, fourth quarter.
Yes, a variety of tests.
We've got one, as you pointed out, that will be on 60% of a section that's 30 wells.
We've got a lot of quarter-section tests.
We will do a little bit of stuff in the Delaware.
But most of that, again, we are probably not going to be talking about.
We.
d consider those results to be proprietary to us.
And so while we will be doing a lot of that testing, I.
m trying to think .
- trying to push things a little bit tighter, maybe in some cases looking at what it does if you do it a little bit wider.
We are continuing to work on spacing.
And frankly, in that regard we are probably a lot further ahead of other people in terms of how many wells we put in a section.
Well, <UNK>, we started out with a high number of crews first of this year, because we do have a pretty good DUC inventory that we are working through.
And we are also ---+ as we drill ---+ our drilling cadence will allow certain number of wells during this time to be drilled and completed toward the end of the year.
Then as we get to the end of the year, we are not DUC-ing wells per se, but we will go back to a more normal cadence.
And so at some points in time, we will have a number of wells available to complete; given our drilling halos and our fracking halos, we will have a space for two crews.
And at some points in time we will have space for five.
And that kind of tempo will basically go forward.
That's a more normal tempo, and it just depends on how many wells we have available to complete at one time in the queue.
I would just dovetail: it's not a concern about availability at all.
You shouldn't be reading availability ---+.
Crews are available.
It's just that's the number we are going to need to do what we need to do in 2017, okay.
Is it the $1 billion for ---+.
If we are high ---+ if we were near the high end in 2017, does that imply we will automatically be at the high end on 2019 guidance.
Well, it's going to probably depend on the lot of things.
I think you can ---+ the assumption, probably, is yes, because one of the reasons we had a range is we were trying to build in some service costs increase.
Now, if they jump way up, obviously that number may move some more.
But if they stay consistent with where we are, yes, I think it's probably not a bad idea to think we are going to be at the higher end of the range.
Well, it's basically that we are drilling more to the formations where we apply ESPs.
That would be the Lower Spraberry, the Jo Mill, and the Middle Spraberry.
We will also do some testing in certain areas in the Wolfcamp.
So we are looking to expand that program in the Wolfcamp some, if those tests work out.
It's all a matter of cost.
Is it going to be worth the extra cost to install the ESPs.
But the short answer to the question is: we are just going to do more of the formations this year and probably going forward than we have in the past.
Last year was our first real endeavor into the Lower, the Middle, and the Jo Mill on any kind of scale.
That's a great question.
The Delaware costs have been mitigated a good bit.
Most of that is going to be water sourcing and water disposal, where we've got deals in place that are saving us a good bit on water handling on both ends.
It's not really drilling.
Thank you very much.
Appreciate everybody's attention, and have a great day.
