康菲 (COP) 2016 Q3 法說會逐字稿

Welcome to the third-quarter 2016 ConocoPhillips earnings conference call. My name is Christine and I will be your operator for today's call. (Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Ellen DeSanctis, VP, Investor Relations and Communications. You may begin.

Thanks, Christine. Hello to everyone and welcome to the third-quarter call. With me today are Don Wallette, our EVP of Finance, Commercial, and our Chief Financial Officer; and Al Hirshberg, our EVP of Production, Drilling, and Projects.

Our cautionary statement is shown on page 2 of today's presentation. We will make some forward-looking statements during today's call that refers to estimates and plans. Actual results could differ due to the factors noted on this slide and in our periodic SEC filings.

We may also refer to some non-GAAP financial measures today. These help facilitate comparisons across periods and with our peers. For any non-GAAP measures that we use, we provided a reconciliation to the nearest corresponding GAAP measure; that can also be found on our website.

One final note before we jump in. As most of you know, ConocoPhillips will hold our Analyst and Investor Meeting on November 10; that's just around the corner. At that time, we'll provide an update on our strategy and our 2017 operating plan; so we will not be addressing those topics on today's call.

And then as always, during Q&A, if you would please limit your questions to one and a follow-up. And now I'll turn the call over to Don.

Thanks, Ellen. I'll start by covering a few highlights from the third quarter, and Al will close with more on our operational results and what to watch for through the remainder of the year. I'll begin on slide 4 with a summary of the third quarter.

We had a strong operational quarter and again exceeded the high end of our production guidance range, delivering 4% underlying production growth year-over-year. We safely completed an active turnaround season and achieved a major milestone with the startup of Train 2 at APLNG.

Financially, we had an adjusted net loss of $826 million. We generated $1.23 billion of operating cash flow, excluding working capital.

It's notable that during the third quarter operating cash flows covered capital spending and dividends. Cash flow in the quarter was also negatively impacted by about $230 million from special items related to rig termination costs and severance expenses. So if you take the clean number and adjust it to today's prices of about $50 a barrel, then on an annualized basis that would be about $6.5 billion of operating cash flow, which is about what we would expect -- again, sufficient to cover sustaining capital and dividends.

Looking at operating costs, we continued to drive costs down and achieved an 18% reduction in adjusted operating costs compared to the third quarter of 2015. Most of these reductions are structural and continue to lower the overall breakeven price of our business.

With respect to strategic objectives, in July we entered into an agreement for the sale of our three exploration blocks offshore Senegal, which is part of our ongoing exit from deepwater exploration. We also reached agreement on the sale of our Block B assets in Indonesia. We expect both of these sales to close before the end of the year.

Earlier this month, we retired $1.25 billion of maturing debt and expect to end the year with debt a little over $27 billion.

I'll go through our third-quarter financial results on slide 5. While we operated well this quarter, low commodity prices continued to impact financial results. For the quarter, with an average realized price just under $30 per barrel, we reported an adjusted loss of $826 million or $0.66 per share.

Year-over-year, adjusted earnings decreased as the result of a 9% drop in realized prices and lower equity affiliate earnings. Sequentially, adjusted earnings benefited from a 7% improvement in realized prices, mainly driven by improved North America natural gas prices as well as higher contract LNG prices.

Third-quarter adjusted earnings by segment are shown in the lower-right side of the slide and are roughly in line with expectations. The supplemental data on our website provides additional financial detail.

I'll cover production on slide 6. Last year's third-quarter volumes were 1,554 MBOE per day, or 1,484 MBOE a day when adjusted for dispositions. Adjusting for the impact of less downtime, production increased by 56 MBOE a day, representing 4% year-over-year growth.

That increase came primarily from higher volumes at APLNG and in the Canadian oil sands. Those increases were partially offset by a 28,000 BOE per day decrease in natural gas, primarily in North America, bringing us to the 1,557 MBOED for the third quarter. Al will provide more color on third-quarter operating performance.

If you turn to slide 7, I'll cover year-to-date cash flow. We started the year with $2.4 billion in cash. Year-to-date we've generated $3.1 billion from operating activities excluding operating working capital.

Total working capital has been a use of cash of $600 million. Proceeds from asset sales have generated $400 million.

Debt has increased by $3.8 billion, but this number will decrease for the full year once we include the $1.25 billion repayment we made in October.

Capital spending year-to-date has been $3.9 billion. And after dividend payments of around $900 million, we ended September with $4.3 billion in cash and short-term investments.

So financially, we are very well positioned. We've made good progress on driving the business to cash flow neutrality and on improving our balance sheet since the first quarter. I look forward to providing more detail on our financial plans next month in New York.

Now I'll turn it over to Al to take you through our operational performance.

Thanks, Don. I'll provide a brief overview of our third-quarter operating highlights, starting on slide 9. Then I'll provide some additional thoughts for the rest of the year, including updated guidance for capital and adjusted operating costs.

Third-quarter production averaged 1,557 MBOED, which exceeded the high end of guidance. The beat was driven by better-than-expected performance in Canada, Norway, Lower 48 unconventionals, and Malaysia.

We completed some significant turnaround activities in Alaska and Europe during the quarter, which brings an end to our major turnarounds for the year.

We continue to see some production resiliency in the Lower 48 unconventionals despite the fact that we've been running only three rigs for the majority of the year, although we do expect more decline in the fourth quarter. Now that APLNG Train 2 has started up, the major project capital roll off that we have been experiencing is essentially complete; so we've been working to shift more of our capital spending to the Lower 48 unconventionals.

We've already been able to secure drilling rigs and pressure pumping crews at attractive rates to maintain our low cost of supply, so we expect this incremental drilling work to start ramping in November. This work will have no impact on 2016 volumes, but will give us a head start on our 2017 production.

In Canada, Surmont fully recovered from the impact of the wildfires earlier this year and achieved a milestone of more than 100,000 barrels a day of gross production in mid-October. We're on track to exit this year at over 110,000 barrels a day gross, as we continue to increase toward our 150,000 barrels a day gross capacity.

In Australia, we achieved first production from Train 2 at APLNG in September and have again experienced a very smooth startup, which allowed us to begin delivering cargoes with Train 2 LNG in early October.

We also have several conventional projects underway across the portfolio that are expected to come on production over the next couple of years: Alder and Clair Ridge in the UK, Aasta Hansteen in Norway, Malikai in Malaysia, and additional phases at Bohai in China, as well as GMT1 and 1H NEWS in Alaska.

Moving to slide 10, I'll provide an update of our 2016 full-year guidance. For the second quarter in a row we've hit the trifecta. We increased production guidance based on robust production year-to-date, while at the same time lowering both capital and adjusted operating cost guidance.

We're driving strong execution and are focused on improving every aspect of our business. And we're not done with our improvements; there is more to come.

We've revised full-year production guidance to a range of 1,560 to 1,570 MBOED. That's up 10,000 barrels a day from prior guidance at the midpoint, reflecting our strong third-quarter performance. Fourth-quarter production guidance is 1,555 to 1,595 MBOED.

We're lowering our capital guidance by $300 million from $5.5 billion to $5.2 billion even though we're beginning to add rigs in the Lower 48, as I just mentioned. Our efforts to reduce operating costs across the business are also succeeding. We are lowering our adjusted operating cost guidance by $200 million from $6.8 billion to $6.6 billion.

As you can tell, we're continuing to improve the company's breakeven price and deliver strong momentum going into 2017. So that was a very quick recap of the third quarter; we look forward to giving you a deep dive of our portfolio and providing our 2017 operating plan at our Analyst and Investor Meeting on November 10.

So now I'll turn the call over for Q&A related to the quarter.

(Operator Instructions) Doug Leggate, Bank of America Merrill Lynch.

Hi, good morning, everybody. It's going to be interesting to see how many of us can stay on the quarter, but we'll have a go. Okay.

So this year I think you talked about major capital spending being around $1.5 billion. I'm just curious as, when we look at the maintenance capital -- and obviously that theoretically rolls off next year -- is that the kind of level we should be thinking about in terms of what pivots to unconventional spending, per your comments, in the quarter?

Well, Doug, nothing's really changed from what I've said about this the last couple quarters. The $1.5 billion was sort of the rolloff amount. About $1 billion of that was from some megaprojects finishing up, and about $0.5 billion was deepwater related.

Some of that I've said in the past will roll into some other midcycle-type projects that are coming up. And the rest will tend to roll into Lower 48 unconventionals. So I do expect that a fair chunk of that is going to go into Lower 48 unconventionals in 2017.

And that's what you see is starting now is, as that work has rolled off, we've gotten ourselves ready. First, we went out and checked the market to see what kind of pricing we could get on rigs and frac crews. Provided that we still could get attractive rates similar to what we've been getting all year long, we were interested in getting started with that, and that's what we found, and so we've done that.

How many rigs are you at right now in the Lower 48?

Well, as of right now, we're still at the three rigs that we've been running all year. We have contracts now to add five more. So I expect that we'll be at eight before the end of the year.

That's helpful. My follow-up is for Don, if I may. So, Don, I just want to get clarification on your opening remarks.

I'm sure you'll get into this in a couple weeks' time, but you did take cash breakeven in the third quarter; you were pretty close in the second. But you are talking about a $50 oil number in your opening remarks as covering dividends and spending when the target is $45.

Can you just close the gap for us?

Yes, Doug. I mean if you look back at the third quarter and our reported CFO was about $1.2 billion; then I mentioned the special items. So when we look at the underlying performance of the business, ex-recurring items and adjusted for timing effects -- reclassifications of liabilities and things like that -- we look at it as about a $1.5 billion.

So that's what we're saying that we get to when you adjust it up from $46, which was the marker price for the third-quarter Brent, up to about $50 and you annualize all that, then we're looking at about a 6.5 billion type of run rate at a $50 Brent marker.

Yes. I don't want to labor this point, but I guess why -- the target is $45, right, to cover capex and dividends? And ex- the adjustments you just pointed out, you were at $1.5 billion. Why do you need -- what's the gross up to $50 all about? I don't understand why that's coming into the picture when you were at $1.5 billion in the third quarter.

Yes, I may not be following you fully on that. But we were just trying to take the third quarter and adjust it to today's prices, Doug.

I'll take it off-line. We'll get into it in a couple weeks. Thanks a lot, guys. Appreciate it.

Neil Mehta, Goldman Sachs.

Good morning, guys. Quick question here on asset sales. In the quarter, I don't think there was anything particularly notable.

But how do you think about the potential for larger-scale asset sales in the portfolio? And then how does that compare to the $1 billion to $2 billion that you talked about previously?

Yes, Neil, you're familiar with our history since the spin. We've been pretty active in managing the portfolio. I think up through 2015 we had generated about $16 billion in asset sales.

Then with the falling prices and the soft market we backed off and said we'd done most of the strategic things we wanted to do. And we set a sort of status quo business as usual goal of maybe $1 billion to $2 billion in a really weak market; maybe more toward the $1 billion, which is what we've guided toward this year. In a better market, maybe $2 billion.

I think as prices recover, then we continue to look at the portfolio for opportunities. So we get a little more interested in asset sales in a recovering market than the one that we've been in the last couple years.

Yes, appreciate that. Then in terms of the capital spending number, you continue to impress us on this point. It's now down to $5.2 billion. There's been multiple points, multiple times you've been able to do this while simultaneously raising production.

Just in terms of where you've been able to drive that delta, can you comment on the underlying drivers of it and how much of this is related to more a cyclical type of deflation as opposed to gains that you can hold on a more sustainable basis?

Yes, Neil, just to recap where we've been, we started out the year with a $6.4 billion capex projection and flat volumes. And where we are now is down to $5.2 billion, so down $1.2 billion, and about a plus 3% on volumes once you adjust for dispositions. So that shows you how much progress we've made as we've gone through the year.

It's been a combination, as you know, of both the structural work that we've been doing -- we've had a very rigorous program ongoing with a lot of concrete steps to drive down our costs -- in addition to the more cyclical side of the deflation that we've been able to capture.

So it started strongest in the US, in the Lower 48 unconventionals. But as we progressed through the year and as that has asymptoted a bit, we're getting bigger savings in the later parts of the year in Alaska, Europe, and the Far East -- the rest of the world outside the US.

That's great. Thanks for the color, guys. Thank you.

Scott Hanold, RBC Capital Markets.

Hey, thanks for taking my question here. Just a couple quick ones in the quarter. You all had strong performance in 3Q and everything rolls nice into 4Q.

Can you give us a sense of what some of that production outperformance was really driven by? Was it better-than-anticipated turnaround, or was it better well performance that you've seen in the unconventionals?

And as a sidebar, could you also provide the Eagle Ford, Bakken, and Permian production, if you have that as well.

You are not allowed to ask Paul's question. (laughter) All right, we'll let you take that one over for this quarter.

Well, the first part of your question, the turnarounds were -- we had some pluses and minuses. Overall, quite successful operationally and came about right about on target. So less than 1,000 barrels a day delta from turnaround actuals versus what we had expected.

The increase really has been driven by the Lower 48 unconventional, by Canada, the oil sands side there, by stronger well performance in Norway, and KBB in Malaysia, some better volumes there. Those have been the biggest pieces. A little bit in Alaska as well with the continuing outperformance from CD5.

So if I had to put a headline across all of that, I would say it's been really well performance and uptime beyond not so much the planned downtime, but our unplanned downtime has been performing better than expected. So uptime has given us a little boost, but primarily just well performance.

In terms of the -- let me give you the actual numbers. On the -- first, if you look at the total Lower 48 unconventional, last quarter we were at 262,000 in the second quarter; third quarter came in at 259,000; so down 3,000 barrels a day.

The three big pieces of that -- just because we've got to get Paul Cheng's full question in here -- Eagle Ford was 171,000 in the second quarter; it was down 8,000 to 163,000. The Bakken went from 64,000 in the second quarter to 61,000 in the third quarter, down 3,000.

And then the Permian was an offsetter. It was plus 8,000. The Permian shale went from 13,000 to 21,000 for a plus 8,000. So that -- and everything else was flat, our other unconventional Lower 48.

So that's why the total added up to minus 3,000: minus 8,000 in Eagle Ford offset by a plus 8,000 in Permian and a minus 3,000 in Bakken.

That's great color. The Permian jump is a bit of a surprise.

Is that pretty much non-operated stuff? You all haven't been doing any completions there recently, have you?

Actually, it mainly has been operated, actually. We've had some very nice wells there in both our Red Hills and our China Draw area.

The timing of our completions and our hookups and our gas plant access have driven some shift there in when some of the volumes have come on into the third quarter.

Okay, okay. Thanks for that color. Then a follow-up question. APLNG Train 2 is now online. Is 1 still outperforming? Are you seeing similar indications with 2 in early days?

And I'm assuming you're still selling those excess cargoes at spot. Is that correct?

Yes. Train 2 actually started making LNG in late September. Had a very smooth startup, so we were able to get to a first cargo -- I think October 8 was the official date. Really been ramping up with no issues there.

Train 1 continues to run very well at more than 10% over the nameplate capacity. So where we're headed next there is that we are now -- we're focused on the upstream side, on ramping our gas supply to be able to run both trains at full capacity. We're not at that point yet.

I expect it will be sometime in the second quarter before we have enough gas supply from the upstream side to be able to run both trains at full tilt. And that's when we'll be looking to do our Train 2 lenders' test.

We've completed the lenders' test on Train 1. Train 2 tentatively thinking around May or so that we'd be in a position to run that test.

Just to give you an idea, year-to-date we've now shipped over 50 cargoes from APLNG.

Phil Gresh, JP Morgan.

Hey, good afternoon. Just following up on the Lower 48 commentary, the five additional rigs, where do you expect those to go? And then generally, I guess how are you thinking about the exit rate on production and what the rig additions could mean for 2017?

Yes. I mean, this is -- of course, using this roll off capex to move to Lower 48 unconventional in 2017 is not a change in plan for us. This timing, taking advantage of today's rates to get started a little earlier in 2016 is a little bit of a shift.

But we're adding in the Eagle Ford and in the Bakken, so we have the three rigs; there's been two in Eagle Ford, one in Bakken. We're going to add three in the Bakken and two in the Eagle Ford so that we'll be four and four.

So the eight rigs that I mentioned earlier we expected to be at, at the end of the year, will be four in the Bakken, four in the Eagle Ford. We will be looking to add rigs in our Permian acreage in 2017, but that's not part of this late 2016 effort.

In the Bakken, we've been fairly steady there in our progress in terms of recoveries and costs. But recently we've put a new completion design into place that we're going to talk more about at our Investor Day.

So we're really pretty excited. That's part of why we're eager to get some rigs back to work in the Bakken.

In the Eagle Ford, if you look at our cost of supply there, we've got such a huge segment that's got down in below $25 fully burdened cost of supply, single well cost supply in the mid teens. So who wouldn't want to go run more rigs there in the Eagle Ford? So that's where we've got those extra rigs allocated, in those two places right now.

Got it. Okay. Then any thoughts on the impact this could have on production for next year in terms -- relative to where the exit rate might be?

Well, I mean it's not going to change the exit rate in 2016. We won't get any volumes from these five extra rigs in 2016.

But it just fits in with our plan for 2017. We're going to talk more about that at our Investor Day here in a couple of weeks, and we'll show you quite a bit more detail around how we expect all that to come out. I'll save that for then.

Ed Westlake, Credit Suisse.

Yes, good morning, and congrats on cash neutrality. Just on the capex inflation/deflation debate again, 20% of your capex I think in Q3 was really in the Lower 48; and obviously there are still projects in the international side. But costs are still coming down, as you said, in the international areas.

So maybe just a sense of how much further deflation you think is possible on that chunk of underlying project capex that you guys have.

If we look just at deflation now, not talking about some of our other efforts to drive down costs, but just the -- we have a pretty rigorous tracking system for trying to keep track of the structural and the cyclical, and look at the deflation side. We achieved about $1 billion of savings - that's capex and opex -- from deflation last year versus 2014. And we're on track in 2016 to get almost another $1 billion in 2016 versus 2015 of deflation savings.

And even though there's been some shift geographically, if you look at how we've been capturing that, we look at it every month, it's been fairly ratable across the years. Just been some shifting in geography.

Then as you think about allocating rigs to North America as everyone else is starting to do, what type of inflation assumptions do you think it's prudent for investors to think about?

Yes, I mean, as I hinted at a minute ago, so far we have not seen any increases in cost in these rigs or pressure pumping crews as we've gone back. And then that's part of what's driven us to move ahead.

I think we have a way to go where we'll be in that situation. We're also helped somewhat by the fact that we're, as I said earlier, focused on places like the Eagle Ford, where a lot of the other folks have left and the rigs are down 85% from where they were.

Everybody is busy logging the Permian, and so that actually makes it easier to continue to get good logistics and infrastructure costs and netbacks and contracts in the Eagle Ford.

So, we do assume in our plans that there will be some reflation as we move over the next couple of years, if prices improve. But we haven't seen any of that so far.

Ryan Todd, Deutsche Bank.

Great. Thanks. Good morning. Maybe if I could follow up on one on the capex, your run rate on capex during the second half of 2016 has been impressive, running probably at an annualized rate of around $4.5 billion a year. Certainly below the $5 billion-plus number that you've suggested in the past as sustaining capex.

Has there been any change in your expectations for sustaining capex as we look going forward? Or is this just a sign, as I guess the 4Q budget is a little bit of an indication of acceleration in capital as we head into 2017?

Well, we'll talk about this more at the Analyst Day. But the fact is that our stay-flat run rate has continued to come down. Every time we look at it in detail again we find a lower number.

If you look at our run rate through three quarters of capex this year, it's at $3.9 billion. And the $5.2 billion is exactly ratable with that, that we're projecting.

I just want to be clear about one thing so that nobody gets the wrong impression. When we talk about adding these five rigs back and rotating some of this major project and deepwater capex over to the unconventional, I don't want anyone to get the wrong impression that that hints in any way at an increase in capex for us next year versus this year. That's certainly not what we have in mind.

We're going to -- you'll see a plan at our Investor Day that continues to show strong discipline in the way that we're spending our capital.

Great, thanks. Then maybe one follow-up on the quarter. Any color on the resilient performance of the US onshore volumes? Is that just lower-than-expected declines or have you adjusted completions and that's driving improved productivity? Anything you can share there?

Yes, it really is as we continue to use our latest technology, latest things we've learned from our stimulated rock volume work -- I'm going to show you some of that at the Investor Day -- we continue to get better recoveries and better production for longer from these wells. So it's all about well performance, and better IPs, and slower declines than what we had put into our plans back when we set up the budget a year ago.

Roger Read, Wells Fargo.

Good morning. Well, I'll do you the favor of sticking to Q3/Q4 things and save all the fun for two weeks. Don, I'd like to ask you: as we think about cash flow and the impacts of deferred taxes going against you, at what point, given a flat capex outlook for next year at a minimum it sounds like, should we expect that to come back around and be a favorable tailwind instead of a headwind?

Well, I think it's going to be a while, Roger. I mean it's going to depend on prices.

You know between -- if you think about prices being between $50 and $60 you've got a number of operating areas, tax jurisdictions that are flipping back and forth between tax-paying and not tax-paying positions. So if prices were to stay about where they are or in that $50 to $60 range, I don't think you're going to see a substantial change.

So I think that the guidance we've given on trying to estimate cash flow is probably legitimate still within that range. And that is to take the earning sensitivities that we've given you and gross them up for the effective tax rate, put it on a pre-tax basis.

It's going to be a while, as I mentioned before, I think, in North America and the US and Canada before we move into a tax-paying position. So I would take those earning sensitivities and divide by say 0.65; and that's going to keep you pretty close within that price range that I mentioned.

Okay, thanks. Then I guess the other main thing -- and you've covered this to some degree with adding the rigs. But what should we think about in terms of the Lower 48 capex? Clearly $175 here in the third quarter, going up, and adding the rigs.

But is the number we see in Q4 probably a pretty good run rate? Or as you mentioned, if you do add some rigs in other regions like the Permian, it's more of a steady increase?

And I apologize for saying I'm not going to ask about 2017, but I'm just generally trying to understand, as we think about $5.2 billion this year and next, regionally how we should think about that.

Yes, okay. You did violate your own rule there. But we will get into that, Roger, in a couple weeks.

But as I've already said, we are going to be rolling more into the Lower 48 unconventionals. So without talking about the absolute amount, there is going to be a continued shift beyond what we're just doing here at the end of the year into the Lower 48 unconventional. And there's going to be plenty of room to do that without having to increase capex.

And that follows the plan that we've been really talking about all year with the capex rolloff.

All right, thank you.

Paul Cheng, Barclays.

Hey, guys. Good afternoon.

So now what are you going to do when they've already asked your question for you?

Excellent, so I ask other things. Two questions actually.

When you negotiate the contract of five rigs, have you been able to get, say, a fixed rate for the next two or three years? Is that kind of option available that you can lock in for a longer period of time at this point to take advantage of the low price?

Yes, Paul, we did explore that with a lot of our different business partners that we work with, looking at who might be willing to do that. And we have been able to get some lock in, but nothing like two to three years.

If most of the suppliers -- all of the suppliers we were talking with, if you wanted to lock for that period of time, they wanted a much higher price to start with. So they were willing to lock, but it had to be at a much higher rate because of their perception that prices will be that much higher over that time frame.

So we weren't able to get those kind of locks. We were able to lock for shorter periods.

With the five additional rigs, you're at eight. I think in the past you guys had talked about to keep production flat you need about somewhere in the six to seven rigs. Is that still the kind of number, or did I get it wrong, the number?

Yes, no, I don't think that's the number we've talked about in the past. When we first started quoting that number a few years ago it was in the 15 to 16 range; earlier this year we talked about 12 to 13.

And yes, the eight number you are thinking of may have been just for Eagle Ford alone. I'm really talking about for the L48 unconventional.

We're going to show you a graph on that at the Analyst Day that really lays out what kind of -- for our total L48 unconventional, how many rigs it would take to stay flat, and what kind of growth rates do you get as you add rigs back. So I've got a whole chart to address that coming up here in a few weeks. But suffice it to say that that number has continued to come down.

Right. But eight would not keep you flat yet?

Well, we'll see. I'll let you interpolate that off the graph in a couple weeks.

Blake Fernandez, Howard Weil.

Hey, folks. Good morning. Just using the midpoint of your production guidance, it looks like we're looking for a decent ramp into 4Q. Al, I know you said Lower 48 would probably continue declining, so I just want to make sure regionally we have our model calibrated correctly.

I think you referenced some turnarounds coming off from Alaska and Europe. So is it fair to think that that's really part of the drivers, in addition to your ongoing ramp in, like, Canada and APLNG?

Yes, you just hit all the key pieces really. It's the absence of those turnarounds and the continued ramp on the big projects at APLNG and Surmont, and some FCCL, as well as Malaysia.

Okay, got it. Then if I could, Don, I wanted to go back to Roger's question, back on the deferred tax. If I'm understanding correctly, the numbers you were using, $6.5 billion, it sounds like that does not contemplate any kind of reversal of a deferred tax.

So I guess, is it fair to think that your cash flow sensitivities potentially have upside longer-term as the portfolio moves to more of a breakeven posture?

Yes, up beyond $60, I think that would be right, Blake.

Okay, great. All right. Thank you.

Paul Sankey, Wolfe Research.

Good afternoon. Al, I think it's come across quite clearly that this is a change in rig count that essentially is a sustaining change. That is to say, where you've been growing you're not adding rigs, but you are in the areas where you've been declining. And at the same time, I assume that the cost of these rigs is essentially baked into, firstly, your lower guidance for this year, but also the idea that you're going to hold flat for next year.

Yes, that's right. I mean, I don't know about the whole flat for next year. I think that's a number we'll talk about in a few weeks. I suspect it might even creep down some more.

But yes, that is built in. The additional, the $300 million savings, getting down to $5.2 billion on our capex guidance for this year includes those costs. Although because they are coming on fairly late in the year, it's not a -- it's a $100 million to $150 million, say, of additional capex from those five rigs coming in late in the year for 2016.

But, we've got -- with all the roll off there's plenty of room to increase rigs in the Lower 48 unconventional without any kind of capex increases in 2017. And that leaves us in very good shape to be able to hold our production volumes.

Yes. Just to be clear on what you just said, when you talk about drifting lower, what you mean is capex may yet still drift lower next year?

Yes. You said something about holding capex flat.

No, no.

I wasn't necessarily agreeing with that.

Jason Gammel, Jefferies.

Yes, thanks very much. I just wanted to ask about the Canadian operations. Clearly the production has been holding in very well. But realizations in bitumen prices have been quite low.

So I was hoping you can address what type of cash margin that you're actually generating from those businesses in the current price environment.

Yes, the current environment, in the environment we've been in this year, we've been moving back and forth between negative to positive on the cash margin. So we're just breaking into positive territory at these kind of prices.

Okay, great. Then maybe if I could just clarify on some of the earlier comments on the Permian drilling. I might have misunderstood this, but I thought you said that the improvement that you were seeing in the Permian production was coming from your operated activity. I might have misunderstood that.

But if you don't have any rigs running there right now and you're really not contemplating on adding any, I'm just trying to square where you're getting the production growth.

Yes, it's -- there may be some amount of nonoperated, but it is dominated by operated. And all I was saying was it's just a matter of timing.

There were some wells that were drilled previously that even though you're not running rigs there, you've still got things that are being hooked up. We had issues with a third-party gas plant that was down for a while; so as it came back up we were able to get gas plant access.

So it was that kind of -- it's timing of completions hookup and gas plant access that really allowed those previously drilled wells to come on production and gave us that plus 8,000 quarter-to-quarter

Great, that's helpful. That squares it.

Doug Terreson, Evercore ISI.

Hi, everybody. First, bravo to Al on his disciplined capital allocation point. I like that one.

And then second, I wanted to ask another cost question but from somewhat of a different perspective than we've talked about so far. Specifically, while it seems that well performance and efficiency gains are going to end up being structural benefits, it also seems that high-grading and operational drilling and completion costs are going to be cyclical. So, first, would you agree with these basic cost categories or, Al, do you guys think about them differently? Meaning, am I leaving something out there?

Then second, do you think that the cyclical flat structural cost decline ratio is 60/40, which seems to be an emerging rule of thumb for the industry?

And then finally, how do you think your cost profile is going to change during the next year or so? And the reason I ask is because there are some rumblings out there that service companies are obviously operating at unsustainable margins and something has to give. So three questions on cost, framework, and your expectations.

Yes. Doug, I think that that 60/40 rule, we're largely in agreement with that. We have, as I mentioned earlier, a rigorous tracking system to track all these reductions. And when we turn the crank on, on that system, it says about two-thirds of the savings we've achieved over the last couple years are structural and about one-third cyclical.

Then there's the question about the timing of how those come back. Of course, the industry hasn't been through a cycle like this since the onslaught of the unconventional revolution. So it really remains to be seen just how that ratio is going to turn out.

We're all trying to model it and make some forward projections. But I'm sure we're all -- just as we all learned in our first down-cycle in the unconventional how the lag times were going to work and how the cyclical cost would work, we'll be learning on the upside as well. Some new ground there.

But I know everybody is talking their book about wanting to increase prices, and so we'll see what happens there. But I can tell you that we are going to be cost sensitive. It's part of our cost discipline that we are going to be selective in adding back rigs, pressure pumping crews, adding to that North American unconventional work.

We don't have to do that. And if we get some rapid reflation to where that starts driving up our cost of supply, then we're not going to add those rigs. We're going to stay disciplined in how we do that, maintain our returns focus.

Al, just to be clear, you think that the decline in cost for you guys was 60% structural, 40% cyclical rather than the other way around? I know that we don't know at this point; but is that the way you guys (multiple speakers)?

Yes, it's about two-thirds -- our model and our tracking says two-thirds structural, one-third cyclical. And all I'm saying is that some of that is a bit theoretical because we've never been through this, before so we'll see how it really turns out.

Great. Thanks a lot, guys.

Guy Baber, Simmons.

Thank you. You've obviously highlighted that accelerating investment into the US Lower 48 by adding rigs is a priority here. Is the higher investment into next year almost entirely going to be a Lower 48 US unconventional story?

Or are there some other international brownfield-type investment opportunities that should start to attract capital? And if so, can you discuss those?

And can you maybe address where incremental oil sands capex might stack up for you as you think about next phases for Foster Creek, Christina Lake?

Guy, I've got to tell you, that is the perfect question for our Analyst Day in a couple of weeks, and we're going to address exactly that in some detail, and have a whole -- in my section I've got a whole set of slides to really lay all that out and show you where the capital is going, where the production is coming from. Oil sands, LNG, our conventional projects, conventional drilling, and our unconventional in the US and Canada.

So rather than try to front run all that right now, I'll save it for the meeting.

Understood. My follow-up would be on the topic of the Permian and the growth this quarter. Can you just remind us of the current size of your Permian position as it stands today, the Midland/Delaware split?

Also what's the rationale behind not adding any rigs there this year? Is that just an economics decision? Is it due to the smaller position? Is it infrastructure related? Just trying to understand the thought process there.

Yes, we'll be getting into that at the Analyst Day in quite a bit of detail also. But we have on the order of 100,000, 110,000 acres in the core part of the Permian; that's both in the Delaware and the Midland basins.

And we've done enough appraisal work there to see that we've obviously got very attractive acreage in the heart of those plays that is going to give us excellent economics -- just as you hear from everybody else. But we're not in a hurry to go start drilling that up before we completely understand it.

If you look at the very disciplined process that we've used in the Eagle Ford and in the Bakken, where we make sure we understand it -- everything from the spacing to the completion design to being able to drill with maximum efficiency -- lining all that out before we go out there and just run a whole bunch of rigs drilling is our view of how to develop the asset the most efficiently and create and derive the most value from that.

So we're approaching the Permian in that same way. In fact, this rush to the Permian by everybody else has really left us advantaged in the Eagle Ford and the Bakken, because we don't have nearly as much competition for suppliers there, for midstream.

Everyone in the Permian is worrying now about all the pipes filling up and the plants filling up and not being able to get capacity -- and just the way it used to be in the Eagle Ford. These days in the Eagle Ford, there's [oilage] of all kinds and people offering us good deals.

And with the exports coming out of Corpus Christi, we're getting good netbacks because there's not as much volume flowing out of there. So it's all good in the places where we're at.

That's a great point. Thanks for the comments.

Pavel Molchanov, Raymond James.

Yes, hey guys. Just two quick international ones. You're one of the few overseas operators in Libya. We've heard that Libyan volumes have doubled in roughly the last 100 days. Have you noticed any uplift on your assets?

Yes, I can't say much in any detail about Libya overall, but I can tell you about Waha, our asset there. We are -- Waha is producing about 50,000 barrels a day gross right now, which is about 7,000 barrels a day net to us, from near zero not very long ago. So that's kind of where we are here in mid to later October.

I just should reiterate that none of these Libya volumes are in any of our numbers. We're quoting everything ex-Libya because of all the volatility there.

But if we continue to produce at this 50,000 barrel a day gross from our facilities there, it should lead to a first lifting from Es Sider from the port there sometime in November. But there's a tremendous amount of damage. The significant challenge is repairing infrastructure, pipelines, and out in the well field, also at the port and the tankage facilities there. The pictures from there are just -- look like the battle zone that it's been.

And so I don't expect that that's going to be able to ramp in a huge way overnight. But we are seeing some volumes coming out now and expect some liftings if it keeps up next month.

Thank you. I will now turn the call back over to Ellen DeSanctis, VP, Investor Relations and Communications.

Thanks, Christine, and thanks to all our listeners. Obviously, we look forward to giving you a whole lot more detail in a couple of weeks. And between now and then if you have any additional questions about the quarter, don't hesitate to call. Thanks so much.

Thank you; and thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.

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