CXO
#Hey, <UNK>, it's <UNK>.
Just to reiterate what <UNK> said earlier, you have a lot of things going on.
You have new assets coming in, old assets going out.
You have changes in interest assumptions in different asset areas.
But the net effect is the same capital, and roughly the same net wells.
Yes, we're comfortable with what we've come out with before on that, <UNK>.
So the short answer is, yes.
We're still very optimistic about the Avalon in that area.
Thanks, <UNK>.
That's correct.
It's well productivity, is the main driver.
It's about half and half in Upton and Midland County.
Yes.
Yes, the impact of that property trade for our Company was a pretty large impact.
And that's the kind of thing, the kind of asset high-grading that I think we ought to continue to do.
Landing them both at the same time and closing two deals on the same day, or announcing two deals on the same day, is a little bit of a trick.
But in general, as we progress through the year, continuing to consolidate Tier 1 core acreage and sell off stuff that is further out in the drilling queue, is an activity that I hope we will continue to see.
Yes to the first two.
And the lateral length, I think those are all two-mile laterals down there.
A mile-and-a-half to two miles.
All right, thank you, <UNK>.
Yes, right now the north is a lot bigger than the south.
We've had good results from second Bone Spring, Avalon and Wolfcamp in the north.
And primarily, what we're doing in the south is Wolfcamp.
So I think that will be expanding, but we're very pleased with the performance of the North Harpoon area in the southern Delaware Basin.
It competes with anything we're doing in the northern Delaware.
And as we've stated, we think that the efficiencies will continue to drive costs lower and production higher.
We like both those areas.
The Avalon oil is just as ---+ I mean the rates of return, the productivity, the prospectivity, is just as good as anything we have.
We're really high on it.
One of the big drivers was that trade, where we're doing more drilling now, more of our capital in the southern Delaware Basin around North Harpoon.
That's a big driver.
Yes, in our prepared remarks we said we added two rigs immediately on those acquired acres.
I'd like to dispel that notion that we've been primarily a Delaware Basin player.
I mean, we bought Henry Petroleum back in 2008, and they were one of the first movers in recognizing the oil potential in the Wolfcamp on the western side of the Midland Basin.
So we inherited a lot of that knowledge, expertise.
I think we were an early mover over there.
It's just been, with all our Delaware activity and everything we're doing in New Mexico, all that really good Midland Basin stuff got lost in the bigger picture.
But I think we've got some of the best Midland Basin acreage that there is.
Our well results compare with anything that anybody else is turning out in the Midland Basin.
And we now have completed the infrastructure kind of investment that we needed in place, so that you could run a multi-rig pad drilling development kind of program.
So we're ready to devote more capital there.
When we come out of this cycle and things start rolling rapidly again, I think it would be good for Concho to have multiple growth drivers.
The last time we came through this growth cycle, the growth of the Company was really driven by the northern Delaware Basin.
I think next time, we'll have multiple growth drivers.
I think that will be a better, more diversified Company.
We've got 110,000 net acres, and we like the great majority of it.
Yes, is the answer to all those questions.
The longer lateral length is primarily coming from the Midland Basin and the southern Delaware Basin.
And that's where we just really put the rigs on.
No, I hope they get better.
One thing you're dealing with, with longer laterals though, is just the mechanical ability to move that much fluid out of a two-mile lateral.
So I think as the industry goes to longer and longer wells, the initial 24-hour, 30-day rates aren't going to move as much as the 60- and 90-day rates.
Because these wells, in the first initial days, you just can't make that much more fluid out of that sized hole.
But I think they will hold up better, and you'll get better economics.
Our DUC inventory is down to about ---+ what is it.
30.
30.
And in general, because the conditions have changed a little bit, there's not as much tightness in the supply for frac spreads.
So the balance of inventory of wells waiting on being completed and wells drilling, I don't think you need quite as many wells waiting on completion as you had in the past.
There's more flexibility in the system because of excess capacity of frac spreads.
It's just a basis of partners joining or not joining in the wells, and our net interest in those wells, at this point in time.
Yes, so as we've said in the past, we've come down significantly from 2015 to 2016.
And going from 2016 to 2017, there may be some modest shallowing in that decline curve, but not anything comparable to the change between 2015 and 2016.
That's right.
A more steady base, is a way to think about it.
I'm sorry, could you ---+ try that again.
I think that our long-term strategy that we've had works well in cycles like this, the way we think about our balance sheet and our leverage and our activity.
And I think what's going to differentiate Concho going forward is our ability to grow within cash flow.
And so when you compare us to other companies, I think our growth will be differentiated, or better, and we'll be drilling within cash flow, while others will probably be outspending their cash flow.
Thank you.
Yes, in general, we're experiments with everything.
But specifically to your question, one thing we've done to reduce expenses ---+ early in the process of drilling these wells, several years ago, we would put electric sub-pumps on the wells, so we could move the fluid faster.
That was very expensive.
And so as we've tried to optimize things, especially at lower oil prices, we'll put mechanical pumping units on them earlier.
They move less fluid, but it kind of flattens the decline curve.
So it's not really choking them back, but it's controlling cost, and not using as many sub-pumps.
Sure.
The pace will slow down markedly, and we're going to stay consistent with the budget that we laid out in the beginning of the year.
Yes, it's, again, consistent with the 10%.
It's embedded in that 10% of non-drilling and completion capital in the budget.
And I don't believe we broke it out beyond that.
You bet.
Good morning.
Yes, I think the Permian is in better shape than the other basins, because the Permian seems to be the place right now that all the equipment wants to come to.
We spoke about the rig count.
The rig count is at a historic low right now, at about 130 rigs.
So there's a long way to go to add back equipment and people, even to get back halfway to where we were two years ago.
So I do think that, in general, it will take the industry some time to respond to increased activity.
But we need some increased activity just to get back to normal.
So I think we have a lot of spare capacity right now, and we're likely to have spare capacity for some time to come.
All right, thank you.
All right, thank you once again.
I know that it was a busy morning, and I appreciate you dialing into the Concho call.
It was a really good quarter.
We look forward to talking to you again at the end of second quarter.
And thanks again for your interest in Concho.
