NBL
#We'll book them by year end.
Obviously it will be set up to be booked with FID but just as far as actually reflecting it externally, it will show up at the year-end reserve booking.
Is what as critical, <UNK>.
Eagle Ford ---+ it's still a sizable position.
When you look at the resource, it's still close to 0.5 billion barrels.
And it's going to be a nice impact, especially as we finish out a number of these wells in the South Gates Ranch this year.
I think longer term, the real driver will be our ability to define the Upper Eagle Ford as a key target and do some of those tests.
We'll have some of those tests later this year.
It's still a very nice contributor.
<UNK>, those are all things that we're looking at.
I think as we get through this year and talk about what changes, if any, we're going to be making to type curves, we'll roll out some commentary as to why we think performance might be better.
Let me take the second question.
I'll turn the first one over to <UNK>, since he's driving all that timing and the project.
On the second question, as far as timing on selldown, I think for Leviathan selldown that's probably best after sanction, obviously, and as we get a little further on in the project.
But we'll be open to looking at when we can get the value that would make sense.
I think on Tamar, what we've talked about is I think we still have five to six years on that, five years from the timing standpoint.
But I would expect probably over the next couple years you'll see us bring that down to the 25%.
A lot of interest in that opportunity especially when you look at the cash flows.
On to the first part of that, I'll let <UNK> talk a little about how he sees the progression of construction work over the next couple years.
Yes, <UNK>, we're moving into the development phase there now.
We have started the procurement of the raw materials for both the subsea and the platform construction project.
I'd expect that would lead us to move into cutting steel early second quarter to mid-year.
At the same time, then, we'll be moving toward bringing a drilling rig into the field to start the first development drilling sometime around mid-year to, again, mid second quarter.
<UNK>, I would have to echo your comment.
That's one of my favorite slides in the pack on slide 12.
I think the results are just phenomenal, what we're seeing there.
But let me turn it over to <UNK> and I'll contain my enthusiasm there.
I don't think we want to give away too much of what we're doing.
But we're definitely controlling flowback on those wells.
And I would say they're staying flatter for longer under that controlled flowback than what we've modeled for a typical type curve.
And then once we start seeing decline we see shallower decline than is modeled in the type curve.
The combination of those, if you can picture a flat production profile versus a declining type curve, over time the cumulative outperformance versus the type curve just continues to widen until the actual production starts to decline as well.
That's what we're continuing to see on these wells.
As we get out to 90 to 120 days we're continuing to see widening performance versus the type curve, over 50% above, as we've noted in the comments.
We'll see how much longer that lasts before we start to see some decline and what the ultimate uplift to EUR is.
I'd be surprised if it's 50% but it will certainly be more than what we've got modeled in the type curve.
Again, we'll gather some more data, continue to watch the wells and later this year probably come out with some new type curves for that area.
Yes, <UNK>, I think on the cost side, as we said, we'll focus mainly on 3,000-pound average in the Delaware this year.
We'll probably continue to have some higher than that.
But on average that's probably a pretty good number to assume.
In the DJ, again, probably 1,800 pounds for average, some higher than that as well, but that's versus a 1,400-pound type curve.
I think as far as what we assume for production, we're certainly looking at the early results in both areas, and as we've said repeatedly, very encouraged by it.
But also, until we have enough data to really increase the type curves, I'd say we're continuing to be a bit conservative in how we're modeling production in those areas until we have more long-term data.
Yes, excited about the Wolfcamp B.
This is the first Wolfcamp B well that we brought on as Noble Energy.
I'd say it's producing right in line with our type curve expectations.
It's pretty flat right now, so we'll get some more data.
That's another one where we've got less than 60 days of data on, so we obviously need to see some more data.
But very excited about that as our first Noble operated deeper test in the area.
When you look at 2017 in the Permian, probably about 80% of our activity will continue to be focused on Wolfcamp A upper and some lower.
But we will start to test more Third Bone Spring, more Wolfcamp B and so we're excited with these early results.
On the Upper Eagle Ford, also quite excited.
We've talked in the past about how we're looking at areas where historically the Upper Eagle Ford compared similarly to the lower Eagle Ford.
And then with our enhanced completions we thought we could increase performance on both of those zones to where they would be very nice programs.
I think the first well that we've got on supports that assumption.
We're very happy with the production we're seeing out of this first Upper Eagle Ford test.
It's actually as good or maybe even a little better than some of the recent lower Eagle Ford wells that we've had in the area.
But it's one well so we need to get the second well online.
We need to get extended production from both.
We need to get some tests in some of the other areas.
We've talked about some Upper Eagle Ford test in the L&E area that we've got coming on later this year as well as a pilot in North Gates Ranch.
All that data will inform our conclusions as we go forward but very excited with what we're seeing in the early days.
I think some of what you're seeing is a reflection up in the DJ as we moved more product through the pipeline.
It results in a little higher transportation cost but it's more than offset on the netback revenue.
So that's really stood out over the last quarter and into this quarter.
It could be.
I think the companies that have the large contiguous positions will benefit probably the most with the ability to put a larger percentage of their wells into the longer laterals or design them for longer laterals.
So, yes, we'll have to see how it plays out.
We've seen the efficiency improvements over the last two years.
I think I've always said I don't think we're at the end of that.
I think a big driver of that will be some of this longer lateral and higher proppant concentrations.
As <UNK> said, we're only going to do what creates real value for us in the price world that we're in.
<UNK>, we haven't given an update on them in the pack but performance is still very strong on those wells.
I think, in general, you're right.
I've heard the same thing, that as you move to the gassier areas the optimum proppant concentration could be lower than what we see in the oil areas.
Obviously our experience so far has been limited to those Mosier wells.
And, so, as we drill more wells in the Mustang area later this year, we'll start to get a better handle on that ourselves.
But that is a possibility.
I think when you look at the performance of those initial Mosier wells and the proppant concentrations that those were pumped at ---+ I can't remember exactly what it was, I think it was around 1,400 pounds per foot, which in and of itself is enhanced relative to the historic frac designs in those areas, it's just not as enhanced, if you will, as the oilier areas.
We're quite happy with that.
We'll continue to watch those wells.
And as we move into the gasier areas in the coming years ---+ not in a big way any time soon, but in the coming years ---+ we'll test different designs there, just like we have in the oily areas.
We've talked about Wolfcamp A, upper and lower, as well, and both will be a focus for us in 2017.
I think when you look at our existing position prior to Clayton Williams where we're going to drill around 30 wells or so, probably two-thirds of those are in the upper, a little less than one-third maybe in the lower, and then a few Bone Spring wells.
I wouldn't say we've spent a whole lot of time looking at it yet.
We don't have the deal closed yet.
But it's certainly something that we're keeping an eye on, others' activity.
As we get the deal closed and start to ramp up activity we'll keep an eye on it.
Near term I think you're going to see most of the activity on the Clayton Williams acreage continue to be Wolfcamp A, as well.
But, you're right, we didn't put any value, really, on anything beyond the Wolfcamp A.
So, to the extent other zones, whether it's Third Bone Spring, Wolfcamp B or C have value potential going forward, that's just additional icing on the cake, if you will.
I think they perform quite well, <UNK>.
When you look at the onshore economics that we rolled out in November, DJ economics were very strong, 30% to 50% returns.
That was at the type curve assumptions, so 1,400 pounds per foot.
It would be equivalent to the black line on the Wells Ranch plot that we released again today that were, in the early days, showing 50% performance above.
So, clearly that outperformance adds possibly substantially to the economics.
Again, we continue to drive efficiencies and costs down where we can, too.
So, economics are only getting better.
They certainly compete with anything else in the portfolio.
And it's in an area that we continue to focus a large part of our capital program on, drilling roughly 150 wells this year and bringing on 120 or so.
From an activity standpoint, <UNK>, I think we're staying consistent with what we've been talking about which is going to be DJ and Delaware.
That's going to be dependent on performance but what we've seen, there's nothing that would change our mind at this point.
If you look at our plan through 2020 it shows increasing activity over that plan.
Then it's just a matter of how fast and any changes over that period of time.
As <UNK> said, too early to tell but we're sure watching it awful close.
I think there's a number of areas we're excited about.
We're not spending as much as we did a few years back, and we're probably not spending it in as many areas, but what we are spending it on we're pretty excited about.
The project in Suriname, for example, was a very large opportunity that our folks have worked with partners to continue to progress and we're excited to get that drilled.
I think the same thing goes for what we picked up offshore Newfoundland, the acreage we have in Gabon and continuing to look at that area.
<UNK> here, I probably ought to turn it over to her to give some of her comments.
Generally I still like West Africa if you get the right opportunities.
We're excited about what we have in Gabon and we're looking at other possibilities.
We're also evaluating Mexico.
We've decided the last couple bid rounds not to participate but we're still evaluating it and looking for the right thing with the right economics on it.
That's a good question, <UNK>.
I think it could be a combination of both.
Again, as I said before, I think we'll continue to work through why we think we're getting better performance than we expected to see.
And as we get later in this year and start to update some type curves we'll roll out some information as to where we think that's coming from.
I think, like we've talked about, we've got some developed, drilled uncompleted wells that we're focusing on this year.
And then we'll continue to watch the longer-term outlook for gas price as we move through the year.
In our plan we had planned to bring a rig in later this year.
Of course, that's always dependent on how it's competing in the portfolio and the economic outlook.
I think overall in the area we'll continue to look at what makes sense for us to do relative to what others' plans are in the area.
And if there's something that makes sense for somebody else that they have a plan to do differently and it fits in their portfolio different, we're open to looking at that.
But for right now our plan is to focus on the uncompleted wells this year that have very good economics, very competitive, and then evaluate the rig as we're getting closer to later this year and looking into next year.
Difference between Niobrara and Codell.
I think just given the nature of the formations, it's a little bit easier to pump into the Codell.
But I'm not sure as far as the performance of that whether we've seen a whole lot of difference.
Yes, <UNK>, I think it's both.
We actually had fewer completions in the fourth quarter of last year than the third quarter.
And then looking at 2017 we've got the fewest number of completions in the first quarter of all the quarters through 2017.
It's just a bit of a low spot over those two quarters in the completion activity.
Typically I think we've seen that through the winter period in past years, too.
So, that's what's driving it.
I think if you go back and look at the last four years, first quarter's been the lowest quarter for us three out of those four years.
I think, as you said, it's too early to give the outlook and trajectory for 2018.
But I think in general, and I'll go back to my comment, if you look at history, historically the first quarter, the first half has usually been less than the second half, just based on activity and also accounting for winter months, et cetera.
So, I would expect, without having a clear view of it yet, that I'll be surprised if it's not a little bit of the same.
I think as far as spending, we're continuing to look at over the next four or five years.
And what we laid out for our plan was the ability to spend within cash flow in a $50 world.
If we get a $60 world we're probably generating excess cash flow with the plan we've laid out that would drive us to look at what we could accelerate, especially if we're seeing the results like we're seeing in these programs so far.
So, we'll continue to develop that and lay it out as we go.
I just want to say thanks to all of you for fitting the call into your schedule this morning.
Look forward to having follow-up conversations with many of you over the next several days.
