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#Yes, thanks, <UNK>.
So we are running several different pilots in the Eagle Ford, in particular in the Upper Eagle Ford we are running I think it is seven different pilots across different parts of the Eagle Ford to test the triple stack concept that we talked about.
And just to understand what parts of our geographic extent of the Eagle Ford is going to be amenable to the triple stack development.
So those pilots are going to be drilled as we go through this year.
And we will start to see results as we head into next year.
So I don't expect it to draw any definitive conclusions on just how much of our aerial extent will be developed that way until maybe the later part of next year, frankly.
Because a lot of this is understanding do the wells begin to interfere with each other and you don't see that early in the well's life.
And of course we are still running the stimulated rock volume pilot that we talked about.
And we're going to get a lot of new information from that this year that will be important from a longer-term basis in terms of optimizing the Eagle Ford as a whole and other unconventional plays that we have in the portfolio.
Yes, the initial results from single well pilots in the Upper Eagle Ford basically showed the production was the same as the Lower Eagle Ford.
And but we haven't tested yet is when those are drilled in the context of a pattern of wells do we see interference.
And that is what we are testing with these seven pilots that we are running now.
No, I don't think we went into that yet, <UNK>, because we really need to understand the nature of these pilots, how they perform when they are confined with other wells.
We didn't actually make any real prediction about what we expect to find.
We would rather do that after we have seen the pilot test results.
Yes, it is possible but it may take even longer than that.
We don't want to jump the gun on it.
We are definitely encouraged, as we said a few weeks ago.
But we want to make sure that we are calibrating properly before we make any claims about what the incremental reserves will be, for example.
We are not in the operating phase yet for APLNG, so I don't have the operating cost number off the top of my head.
The tax regime is a tax and royalty regime with the royalties at the Queensland level and taxes at the federal level.
This is actually not fully resolved yet.
There are some discussions still underway with the Queensland government on the nature of how the royalty will be calculated.
So I can't really give you a definitive answer on that yet, <UNK>.
(Multiple speakers) I will add a little bit to what <UNK> said on the tax side.
The taxes are actually paid down at the APLNG kind of corporate level.
And there is going to be, as you can imagine with a big capital investment project like that from a cash flow perspective, a fair bit of tax shield from depreciation on the investment particularly in the early years of the project.
I don't know that I could give you precisely of a number, that depends upon price levels as well.
But if we had current kind of prices that is probably not a bad assumption.
Yes, the Eagle Ford was around 175,000 barrels a day in the first quarter and the Bakken was around 55,000 barrels a day in the first quarter.
The Permian was less than 10 on the unconventional side.
We also have significant conventional production, but on the shale side it was less than 10.
So what we expect to happen, <UNK>, is we ---+ the aggregate production from the unconventionals is going to grow a little bit into the second quarter.
And then it's going to gradually decline as we exit the year.
So the fourth-quarter exit rate is going to be quite similar to the first-quarter rate on aggregate for the shale plays.
It depends a bit on the pace of the build of the rigs back up.
But you should really assume that it is going to hold it flat.
Because by the time we get the wells back and running again we're through the drilling and completion and hook up and bringing them onto production.
We're actually going to see the declining production from those plays continue into the early part of 2016 and then start to increase towards the end of 2016.
And based on our current assessment of how we will put rigs back to work there, we'll probably be relatively flat from the average of 15 to the average of 16.
Yes, we are always with a portfolio of our size looking at what can we do in the way of portfolio optimization.
As we go forward we are not going to be pre-announcing that we are marketing particular assets.
You will hear stories probably out in the marketplace that we are testing values on that and that is what we will always be doing as part of a prudent optimization of the portfolio.
As we have said, I think it is prudent to think in terms of a company our size will do something with its asset portfolio every year.
And we talked about it, whether that is $1 billion or so a year is probably a good go by.
It really just depends on whether we are getting full value for the assets.
It is always about whether we can sell the assets for at least what we think we could receive for them in value if we kept them in our portfolio.
And we don't know what that number is going to be.
But there will be some level of asset sale.
So we expect with the major projects that we are doing and the development drilling that we are doing in Alaska that we are likely to hold production relatively flat for the next three years and beyond that actually.
And we have a reasonably good representation of the overall Alaska production because we are in all three of the big production areas there, Prudhoe, Kuparuk and Alpine.
So I think if you are looking at sort of a macro view of Alaska that wouldn't be a bad basis to think about that.
In terms of realizations, I think currently realizations for ANS crude are about $2 or $3 below Brent.
We have taken one cargo this year to Asia and one last year.
We always have that option if that is what we choose to do.
I think our first reaction to an increase in prices is going to be to reduce the amount of cash we use and the amount of debt we might borrow.
Particularly as we think about activity levels in 2015 and 2016.
I think in the near term I am not sure we see a price level that would cause us to reaccelerate.
We are going to want to see what ---+ that if there is some acceleration of prices that it has got a more lasting effect as well.
I mean we are taking ---+ as you think about what is going on with our capital program, as <UNK> mentioned earlier, we have a couple billion dollars rolling off from Surmont and APLNG and we are in our plans already accelerating capital spending in places like North AmericaN unconventionals as we go into 2016.
It is a bit of a ---+ I don't think I can actually quantify that because the rating agencies won't tell you exactly what number that is.
I think we would characterize it the same way we characterized it on our call last time.
We think the amount that we do borrow is going to be ---+ it could be enough that it would cause us to see a one notch downgrade from what is currently A1 at Moody's and A ---+ the middle single A with Standard & Poor's and with Fitch.
And as you have seen, all the agencies do have our credit rating outlook on a negative so they are anticipating that.
But once ---+ if that were to happen that would move us into a range where we are comfortable that there is plenty of space there to meet whatever borrowing needs we might have in 2015 and 2016 as we head towards cash flow neutrality in 2017.
We are continuing to work through our optimizations, <UNK>, that we discussed a little bit a few weeks ago, optimizing the completion design and the well end, the well placement and so on.
I wouldn't say there is anything fundamentally different going on there.
But we are moving towards more pad drilling, 90% of our wells will be from pad drilling.
But there is not a fundamental change there, the guys are just executing well.
I feel pretty comfortable about the ---+ the answer I gave earlier on what we expect of our Eagle Ford and Permian and Bakken production to do this year and into next year, assuming that we do increase our rigs the way that we intend to next year.
So peak ---+ on both of them really for different reasons, peak operational cash flows in 2017.
For Surmont 2 it is because it takes a while, as you know, to build the steam chambers and ramp up production in the SAGD project.
And in the case of APLNG we will bring the first train on this year; it will be next year before we bring the second train on.
So the first year that will have both trains running will be 2017.
So in both cases it will be 2017 before they are fully contribute in their plateau rate and of course that rate will continue in both projects for decades.
Let's see, I would say we are probably ---+ overall we are probably running three or four.
It varies a little bit, but I think three full-time and four if we ---+ occasionally.
So that is our total spread to support those rigs.
The Vali well that we are drilling is actually testing a different play than the Omosi and Kamoxi wells were, so we will see how that goes.
No, we have not impaired Libya.
For us we would have to see that there was some kind of view that there was a permanent loss of that concession before we would really need to do an impairment.
I don't know that I know that number off the top of my head.
It is on the order of $0.5 billion.
But I wouldn't ---+ I am not sure exactly what that number is.
No, we take a portfolio approach to thinking about our cash flows.
So we wouldn't really think about doing it for one particular part of our portfolio.
Generally our philosophy that we have talked about before hasn't changed.
But we feel like hedging is by definition a kind of zero sum game in terms of value and one of the reasons we keep a strong balance sheet is being able to handle the fluctuations in commodity prices.
<UNK>, I can't speak for the industry as to what price signal they might be looking for and the same would be cash flow will have a big impact on that as well.
But in our plans we are planning the increases in 2016 modestly but we are going to increase as we move into 2016.
And that is in the anticipation that there will be some continued recovery in prices.
In terms of the capacity, clearly we have laid down quite a bit of rig and completion capacity.
And that can be brought ---+ that can be brought back relatively quickly as a flexible industry that we had in the Lower 48.
So exactly how quickly people bring these back on will be a function of the cash that they want to put back in and what they see as being an efficient and safe way to bring the rigs and the completion crews back to work.
So I don't think I answered your question very satisfactorily, but that is about the best I have got.
No, our intention is to make that commodity agnostic for the most part where we are looking to get sustainable cost reductions through this effort.
We are going to get some fluctuations associated with exchange rates and with changes in the deflationary environment.
But our focus is on getting structural cost reductions that we can sustain through the cycles.
So, what we saw in the first quarter was that realizations were probably weaker than what people were expecting primarily in the Lower 48.
For example, I think our Lower 48 crude oil realization was closer to $40 where WTI was like at $48.50 or so for the quarter.
What we are seeing is just a tough quarter for realizations, a lot of supply in the marketplace.
Kind of the differentials that we are seeing are not that different ---+ that we saw in the first quarter are not that different when we were in a $50 price environment than they were when we were a much higher price environment, it is still kind of that same level of differentials.
I think we would expect to see kind of differentials improve in terms of kind of percent of marker realized and maybe some slight improvement in kind of absolute levels of differentials as well.
The differentials were tough because they were kind of tough across all commodities for us in the Lower 48 as well.
It was tough on NGLs, oil and natural gas.
Yes, it is a little bit just that is just what the market was in the first quarter.
There is nothing really that fundamentally changed in our product mix or the quality of any of the products that we are selling that would lead to that kind of differential.
Yes, <UNK>, I mean it helps, the UK sector needs as much help as it can get.
So the help on the tax rates was welcome.
The simplification and broadening of the uplift on capital is going to help us as well.
It is about a 12% uplift now on capital when you go through the math.
So we will build that into our thinking as we are thinking about our overall investment portfolio over the next few years.
But it certainly was a move in the right direction by the UK government.
Yes, it does.
By its nature the dry hole cost is going to be pretty lumpy.
And we happen to have both the Harrier well and the Omosi well in Angola hit in the first quarter.
You could have quarters where the number is really low if no well actually gets to TD during that quarter and it could be lumpy again later in the year.
But as we look at the overall kind of balance of the year we think the guidance that we gave at the analyst presentation still makes sense.
Are you talking about operating cost, <UNK>, or capital costs.
Yes, so what we are seeing is a more rapid response in the Lower 48 than in other parts of the company.
We expect to see some deflation kicking in and we already actually have seen some in our international business, but it is coming more slowly, which is what we would anticipate.
It's coming more slowly from the International business, but it has come very rapidly in the Lower 48.
But we are building ---+ we've built that sort of trend as we anticipated into our expectations of deflation.
And we do expect to see those reductions coming in the international over the next several months.
So we have been running some re-fracs in our portfolio, some using the (inaudible) technology, some just basically straight pump and new fracs with existing perfs and some with new perfs.
So we've been testing a few.
The area that we are seeing the best uplift is, as you would expect, are older wells where we pumped smaller jobs with wider spacing.
So we see some potential there in this, particularly in wells that were drilled a few years ago.
Not in more recently drilled wells.
So we are continuing to evaluate that.
But there is some ---+ there is certainly some upside potential.
That is terrific.
Really we appreciate everybody's questions and comments.
Obviously feel free to come back to us if you didn't get your questions answered.
But we are going to give you back a little bit of time here.
Again, thank you for participating and we look forward to staying in touch with all of you.
Thank you.
