OXY
#That's a good question.
I don't think we've baked a whole lot of that improvement in in the forward look, so I think there's upside potential.
Our type curves represent the production from full-section development.
Your first wells may be better than the last well on a section.
So our type curves are based on the average and that forward look is based on the average.
So throughout this year, just like we did last year, we expect continued improvement in both cost and well productivity.
So, I think there's upside to that production plot, both from a pace standpoint, number of wells you drill per rig line, and productivity.
At $60 or $70 oil, things change fairly significantly based on what ---+ the numbers we gave you on our sensitivity around oil prices obviously.
But keep in mind that what we said was that there's a lot of flexibility in the capital program, as <UNK> pointed out.
We will sort of see how things go in terms of commodity prices through the year.
Obviously, we would be more encouraged to maybe spend a little bit more money at the higher end of the range, better prices.
So we will just sort of see how things go.
We gave you all sorts of points in terms of cash flow changes and deltas from the different business segments, so I think I have a high degree of confidence in your modeling ability, so you should probably be able to come to some sense of what's going on.
The Permian business as a whole, as I mentioned, generated quite a bit of free cash flow, and Permian EOR is sort of there largely to harvest the free cash flow to redeploy into Permian Resources.
So, on the cash neutrality, it could sort of be whatever you want it to be.
We were under $50 WTI in the fourth quarter.
We are spending ---+ so you're almost there now if you wanted to spend lower amounts of capital and to sort of keep production flat, but it's largely dependent on how much you would like to grow.
And we think we have a lot of opportunities, as <UNK> pointed out, 11,650 places to park the money so ---+ at good returns.
So I think that is the best way to frame it.
As I said previously, we are continuing to look at our opportunities to monetize things where it makes sense, where we think that would increase the net present value for our shareholders.
While we are not prepared to talk about specific assets today, we will continue that process.
And as we make decisions, certainly we will share that with you, but it's something that we think about and evaluate pretty much on an ongoing basis.
So, the operated versus nonoperated in that kind of core 300,000, you can kind of think 75% to 80% operating kind of position there.
With regard to the longer laterals, that's been a great effort by our business unit and our land organization to continue to core up, so doing swaps, doing trades, picking up pieces of acreage to drive that lateral length longer.
So, I expect us to continue to do that.
The majority of our wells will be longer laterals.
That's just an average of the whole inventory.
Technically, there's not a problem.
10,000 early on in horizontal development was a bit of a challenge.
10,000 is no longer a challenge.
We are looking at even the option of 15,000 now.
The bulk of the development this year will be 7,500 foot or 10,000 foot laterals.
If we have to drill a 4,500 foot lateral, it's because we've already developed or started developing a section that way, and we really can't change.
So most of our wells will be the longer version.
On the 350,000 acres we are delineating, it's really multiple things.
We are drilling appraisal wells on our own acreage.
We are evaluating 3D seismic.
Again, those two equivalent nonoperated rigs really are six to eight actual rigs in any day of the year.
So we get a lot of information from that nonoperated position that helps derisk, plus just watching what other competitors do offset of this acreage.
So, with regard to acquisition, it's going to be a function of what we think about that acreage, what the current position is, what trade opportunities there are to core up before you go down the acquisition path.
No, we provided the delta of the free cash flow that we expect in some of the pieces of the business based on prior investments that we've made that are now completed, so there's, to some extent, that, specifically around chemicals.
The Permian, a lot of that is driven by the production growth and the volume improvements that we've seen at good returns.
And part of it obviously in oil and gas is some view around a little bit better price, but not much.
And going forward, I would tell you that not sort of ---+ we started the year with $2.2 billion of cash, and the capital program remains quite flexible, so we will sort of see how it goes as far as the spending.
But again, the number one priority, as <UNK> said, right after maintenance, is really to continue to be able to fund and grow the dividend over time based on our ability to grow volumes.
So, we do believe there will be inflation pressure.
And you mentioned pumping service.
That's probably one of the areas where you will see it the strongest.
But to counter that, we are really working two approaches.
One is to continue to get better technically, some innovations that are happening in the drilling space and in the completion.
We can drill our wells faster and better over time.
That will help offset that inflation pressure.
But on the commercial side, we are working very closely with a group of suppliers to create the ability for them to have greater margins without just price increase ---+ more efficiency, better utilization, better logistics management.
And so we think the combination of those two things can hold our overall well cost flat or continue to improve it.
We will have to see how conditions look in the second half of the year, but, currently, our plan would be not to increase our capital for this year but to go with the plan that we have in place and to look at what our program next year would look like.
But it really is going to depend on how we feel about oil prices.
