Ellen R. DeSanctis - ConocoPhillips Donald Evert Wallette - ConocoPhillips Alan J. Hirshberg - ConocoPhillips.

Doug Leggate - Bank of America / Merrill Lynch Neil Mehta - Goldman Sachs & Co. Scott Hanold - RBC Capital Markets LLC Philip M. Gresh - JPMorgan Securities LLC Edward George Westlake - Credit Suisse Securities (USA) LLC (Broker) Ryan Todd - Deutsche Bank Securities, Inc. Roger D. Read - Wells Fargo Securities LLC Paul Cheng - Barclays Capital, Inc.

Blake Fernandez - Scotia Howard Weil Paul Sankey - Wolfe Research LLC Jason Gammel - Jefferies International Ltd. Doug Terreson - Evercore ISI Guy Allen Baber - Simmons & Company International Pavel S. Molchanov - Raymond James & Associates, Inc..

Welcome to the Third Quarter 2016 ConocoPhillips Earnings Conference Call. My name is Christine and I will be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question and answer session. 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 two 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 four 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 cost 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 cost, we continued to drive cost down and achieved an 18% reduction in adjusted operating cost compared to the third quarter of 2015. Most of these reductions are structural and continued 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 five. 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 six. 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 seven, 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 nine. 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. So 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's more to come.

We've revised full-year production guidance to a range of $1,560 MBOED 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 MBOED 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 cost across the business are also succeeding. We're 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, very quick recap of the third quarter. We look toward 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..

Thank you. And our first question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead..

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, Al, this year I think you talked about major capital spending being around $1.5 billion.

I'm just curious, 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 roll off amount. About $1 billion of that was from some mega projects finishing up and about $0.5 billion was deepwater related.

And some of that I've said in the past will roll into some other mid-cycle 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 us kind of starting now.

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. And 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 have 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, and 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, you did hit cash breakeven in the third quarter.

You were pretty close in the second, but you're 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 or us?.

Yeah, Doug, I mean, if you look back to the third quarter and our reported CFO was about $1.2 billion, then I mentioned the special items.

So when we look at sort of the underlying performance of the business, ex recurring items and adjusted for timing effects, reclassifications of liabilities and things like that, we kind of look at it as about $1.5 billion.

So that's what we are 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 about a $6.5 billion type of run rate at a $50 Brent marker..

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 – what's the gross up to $50 all about.

I don't understand why that is coming into the picture when you're up $1.5 billion in the second and third quarter?.

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

I'll take it offline. We'll get into it in a couple weeks. Thanks a lot, guys, appreciate it..

Okay..

Thanks, Doug..

Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead..

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, I mean, 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.

And 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 kind of set sort of a status quo, business as usual goal of maybe $1 billion to $2 billion, in a really weak market, maybe more towards the $1 billion, which is sort of 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. And 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..

Yeah. Appreciate that. And 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 has been 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 kind of comment on the underlying drivers of it and how much of this is related to more 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 problem 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. And so it started strongest in the U.S.

and the lower 48 unconventionals but as we progressed through the year and as that has kind of asymptoted a bit, we're getting bigger savings in the later parts of the year in Alaska, Europe and the Far East, the of the world outside the U.S..

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

Thank you. Our next question is from Scott Hanold of RBC Capital Markets. Please go ahead..

Hey, thanks for taking my question here. Just a couple of quick ones in the quarter. And 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 turnarounds? 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're not allowed to ask Paul's question. 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 a 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 it's been – 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 that 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 MBOED in the second quarter. Third quarter came in at 259 MBOED, so down 3,000 (sic) 3 million barrels a day.

The three big pieces of that, just because we got to get Paul Cheng's fell question in here, Eagle Ford was 171 MBOED in second quarter, it was down 8 MBOED to 163 MBOED. The Bakken went from 64 MBOED in the second quarter to 61 MBOED in the third quarter, down 3 MBOED and then the Permian was an offsetter, it was plus 8 MBOED.

The Permian shale went from 13 MBOED to 21 MBOED for a plus 8 MBOED. So that – and everything else was flat, our other unconventional lower 48, so that's why the total added up to minus 3 MBOED. Minus 8 MBOED in the Eagle Ford offset by a plus 8 MBOED in Permian and a minus 3 MBOED in Bakken..

That's great color. The Permian jump is a bit of 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 and when some of the volumes have come on into the third quarter..

Okay, okay. Thanks for that color. And then a follow-up question. APLNG, Train 2 is now online, is Train 1 still outperforming, are you seeing similar indications with Train 2 in early days and I'm assuming you're still selling those excess cargoes at spot.

Is that correct?.

Yes. So Train 2 actually started making LNG in late September, had a very smooth startup as we were able to get to 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're 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..

Thank you. Our next question is from Phil Gresh of JPMorgan. Please go ahead..

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?.

Yeah. 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 where we're – we are 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 rigs in the Bakken and two rigs in the Eagle Ford, so that we'll be four rigs and four rigs. So that eight rigs that I mentioned earlier we expected to be at at the end of the year will be four rigs in the Bakken, four rigs 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 on our progress in terms of recoveries and cost, but recently we've put a new completion design into place that we're going to talk more about at our Investor Day.

And 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 supply, single well cost supply in the mid-teens, and so who wouldn't want to go run more rigs there in the Eagle Ford? And so that's where we've got those extra rigs allocated, in those two places right now..

Got it.

Okay, and any and thoughts on the impact this could have on production for next year 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..

Thank you. Our next question is from Ed Westlake of Credit Suisse. Please go ahead..

Yes, good morning. And congrats on cash and 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's still projects in the international side but costs are sort of still coming down as you said in the international area.

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

We, if we look just that deflation now, not talking about some of our other efforts to drive down cost, 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 has 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 year, there's just been some shifting in geography..

And then as you think about allocating rigs to North America, as everyone else is starting to do, I mean, 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 that's part of what's driven us to move ahead. I think we have a ways 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, and everybody is busy flogging the Permian.

And so that actually makes it easier to continue to get good logistics and infrastructure costs and net backs 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..

Thank you. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead..

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 kind of 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, and 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. And then maybe one follow-up on the quarter. Any color on the resilient performance of the U.S.

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?.

Yeah. 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..

Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead..

Hi, good morning..

Good morning..

Well, I'll do you the favor of sticking to kind of 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 sort of 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 depend on prices. And between – if you think about prices 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 position.

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 the guidance we've given on trying to estimate cash flow is probably legitimate, still within that range, and that is to take the earnings 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 U.S.

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.

And 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, $1.75 billion here in the third quarter going up and adding the rigs, but does – 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 kind of apologize for saying I'm not going to ask about 2017, but I'm just generally trying understand as we think about $5.2 billion this year and next, kind of 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 unconventional.

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 roll off..

All right. Thank you..

Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead..

Hey, guys. Good afternoon....

Morning, Paul.

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.

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

Yeah. 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 years to three years.

If – most of the suppliers we were – all the suppliers we were talking with, if you wanted a 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 much higher rate....

Right..

...because of their perception that prices will be that much higher over that timeframe. So we weren't able to get those kind of locks. We were able to lock for shorter periods..

And with the five additional rigs, you're at eight. I think in the past you guys are talking about to keep production flat you need about somewhere in the six rigs to seven rigs.

Is that still the kind of number or that I got 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 rigs to 16 rigs range. Earlier this year we talked about 12 rigs to 13 rigs. And, yeah, the eight rigs number you're thinking of may have been just for Eagle Ford alone.

I'm really talking about for the L 48 unconventional..

Yes, so....

We are going to show you a graph on that at the Analyst Day that really lays out what kind of – for our total L 48 unconventional how many rigs it will 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 kind of 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 rigs will not keep you flat, yeah?.

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

Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead..

Hey, folks. Good morning..

Hey, Blake..

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 kind of 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. I mean, you just hit it 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. And 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 the 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. Beyond $60, I think that would be right, Blake..

Okay. Great. All right. Thank you..

Thanks..

Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead..

Good afternoon. Al, I think it's come -.

Hey, Paul..

Hey how are you doing? 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 in to firstly your lower guidance for this year but also the idea that you're going to hold flat for next year?.

Yeah. 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, yeah, 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're coming on fairly late in the year, it's not a – it's $100 million to $150 million of additional CapEx from those five rigs coming in late in the year for 2016. But we've got....

Yeah..

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..

Yeah.

And 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?.

Yeah. You said something about holding CapEx flat..

No. No..

I wasn't necessarily agreeing with that..

Thank you. Our next question is from Jason Gammel of Jefferies. Please go ahead..

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 could address what type of cash margin that you're actually generating from those businesses in the current price environment?.

Yes. I mean, at 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 kind of positive territory at these kind of prices..

Okay. Great. And 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 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 – I mean, there might be some amount of non-operated, but it is dominated by operated. And all I was saying, 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 MBOED quarter-to-quarter..

Great. That's helpful. That squares it..

Okay..

Thank you. Our next question is from Doug Terreson of Evercore ISI. Please go ahead..

Hi, everybody..

Hey, Doug..

Hi, Doug..

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 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.

And 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.

And then, second, do you think that the cyclical/structural cost decline ratio is kind of 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..

Yeah, so, 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 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.

And 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. And so it really remains to be seen just how that ratio is going to turn out.

We're all trying to model in 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 costs would work. We'll be learning on the upside as well some new ground there.

But I know everybody's 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..

So, Al, just to be clear, so 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...?.

Yeah, it's about two-thirds – our model and our tracking says two-thirds structural, one-third cyclical. And all I'm saying is that it's – 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..

Okay..

Thanks, Doug..

Thank you. Our next question is from Guy Baber of Simmons. Please go ahead..

Thank you. You've obviously highlighted that accelerating investment into the U.S. lower 48 by adding rigs is a priority here. Is the higher investment into next year almost entirely going to be a lower 48 U.S.

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 got to tell you, that is the perfect question for our Analyst Day in a couple of weeks.

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 U.S. and Canada.

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

Understood. So 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? And 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..

Yeah, 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 acres, 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 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 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 it. And so, we're approaching the Permian in that same way.

And 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 ullage of all kinds and people offering us good deals. And with the exports coming out of Corpus Christi, we're getting good net backs 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..

Thank you. And our last question is from Pavel Molchanov of Raymond James. Please go ahead..

Yeah. 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 and significant challenges repairing infrastructure pipelines, and out in the wellfield. 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, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect..