Earnings Call: Q3 2016

Oct 27, 2016

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 Q3 call. With me today are Don Wallet, our EVP of Finance, Commercial and our Chief Financial Officer and Al Hirschberg, 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'll provide a reconciliation 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 and A, if you would, please limit your questions to 1 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 Q3, 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 3rd quarter. We had a strong operational quarter and again exceeded the high end of our production guidance range, 4% underlying growth production growth year over year. We safely completed an active turnaround season and achieved a major milestone with the start up of Train 2 at APLNG. Financially, we had an adjusted net loss of $826,000,000 We generated $1,230,000,000 of operating cash flow, excluding working capital. It's notable that during the Q3, operating cash flows covered capital spending and dividends. Cash flow in the quarter was also negatively impacted by about $230,000,000 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 $6,500,000,000 of operating cash flow, which is about what we would expect, again, sufficient to cover sustaining capital and dividends. Looking at operating costs, we continue to drive costs down and achieved an 18% reduction in adjusted operating costs compared to the Q3 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 3 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 $1,250,000,000 of maturing debt and expect to end the year with debt a little over 27,000,000,000 dollars I'll go through our Q3 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 $826,000,000 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. 3rd 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 Q3 volumes were 15.54 MBOE per day or 14.84 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 $15.57 for the 3rd quarter. Al will provide more color on 3rd quarter operating performance. If you turn to Slide 7, I'll cover year to date cash flow. We started the year with $2,400,000,000 in cash. Year to date, we've generated $3,100,000,000 from operating activities, excluding operating working capital. Total working capital has been a use of cash of $600,000,000 Proceeds from asset sales have generated $400,000,000 Debt has increased by 3,800,000,000 decrease for the full year once we include the $1,250,000,000 repayment we made in October. Capital spending year to date has been $3,900,000,000 And after dividend payments of around $900,000,000 we ended September with $4,300,000,000 in cash and short term investments. So financially, we are very well We've made good progress on driving the business to cash flow neutrality and on improving our balance sheet since the Q1. 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 Q3 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. 3rd quarter production averaged 15.57 Mboed, which exceeded the high end of guidance. The beat was driven by better than expected performance in Canada, Norway, Lower forty eight 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 3 rigs for the majority of the year, although we do expect more decline in the Q4. 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 1,000 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 Clear Ridge in the U. K, Aasta Hansteen in Norway, Malachi 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 Q2 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 15.60 to 15.70 Mboed. That's up 10,000 barrels a day from prior guidance at the midpoint, reflecting our strong third quarter performance. 4th quarter production guidance is $15.55 to $15.95 in boed. We're lowering our capital guidance by $300,000,000 from $5,500,000,000 to $5,200,000,000 even though we're beginning to add rigs in the Lower forty eight as I just mentioned. Our efforts to reduce operating costs across the business are also succeeding. We're lowering our adjusted operating cost guidance by $200,000,000 from $6,800,000,000 to $6,600,000,000 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 Q3. 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 and A related to the quarter. Thank 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 $1,500,000,000 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, I Doug, I've nothing's really changed from what I've said about this the last couple of quarters. The $1,500,000,000 was sort of the roll off amount. About $1,000,000,000 of that was from some mega projects finishing up and about $500,000,000 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 unconventional. 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 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 and provided that we still can 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 world 48? 8? Well, right as of right now, we're still at the 3 rigs that we've been running all year. We have contracts now to add 5 more. And so we will I expect that we'll be at 8 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 of weeks' time, but you did hit cash breakeven in the Q3. You're pretty close in the second. But you're talking about a $50 number in your opening remarks as covering dividends and spending when the target is $45,000,000 Can you just close the gap for us? Yes, Doug. I mean, if you look back the Q3 and our reported CFO was about 1.2. 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 $1,500,000,000 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 Q3, Brent, up to about 50 and you annualize all that, then we're looking at about a $6,500,000,000 type of run rate at a $50 Brent marker. Yes. I don't want to labor this point, but I guess why are you the target is 45, right, to cover CapEx and dividends. And ex the adjustments, you just pointed out you were out 1.5. 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% in the second and the third quarter. Yes. I may not be following you fully on that. We were just trying to take the Q3 and adjust it to today's prices, Doug. I'll take it offline. We'll get into it in a couple of 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 larger scale asset sales in the portfolio? And then how does that compare to the $1,000,000,000 to $2,000,000,000 that you talked about previously? Yes. Neal, you've 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 $16,000,000,000 in asset sales. And then with the falling prices in the soft market, we backed off and said we've done most of the strategic things we want to do. And we kind of set a sort of a status quo business as usual goal of maybe $1,000,000,000 to $2,000,000,000 in a really weak market, maybe more toward the $1,000,000,000 which is sort of what we've guided toward this year in a better market, maybe $1,000,000,000 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 of years. Yes. Appreciate that. And then in terms of the capital spending number, you continue to impress us on this point. It's now down to $5,200,000,000 It's 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. Neal, just to recap where we've been, we started out the year with a $6,400,000,000 CapEx projection and flat volumes. And where we are now is down to $5,200,000,000 So down $1,200,000,000 and about a +3 percent on volumes once you adjust for dispositions. So that shows you how much progress we've made as we've gone through the year. And 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. And so it started strongest in the U. S. In the lower 48 unconventionals. But as we progress 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 rest 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 in 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'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 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 a 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 plan our unplanned downtime has been performing better than expected. And 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 U. S. First, if you look at the total Lower 48 unconventional, last quarter we were at 2 62 in the 2nd quarter. 3rd quarter came in at 2 59, so down 3,000 barrels a day. The 3 big pieces of that, just because we got to get Paul Chang's full question in here, Eagle Ford was 171 in the 2nd quarter, it was down 8 to 163. The Bakken went from 64 in the 2nd quarter to 61 in the 3rd quarter down 3. And then the Permian was an offset or it was +8. The Permian Shale went from 13 to 21 for a +-8. So that and everything else was flat, our other unconventional Lower 48%. So that's why the total added up to minus 3%. Minus 8% in Eagle Ford offset by a +8% in Permian and a minus 3% 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 was 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 Q3. Okay. Okay. Thanks for that color. And 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. So Train 2 actually started making LNG in late September, had a very smooth start up. So we're able to get to the 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 on 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 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 forty eight commentary, the 5 additional rigs, where do you expect those to go? And then generally, I guess, how are you thinking about kind of 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 3 rigs has been 2 in Eagle Ford, 1 in Bakken. We're going to add 3 in the Bakken and 2 in the Eagle Ford, so that will be 4 and 4. So that 8 rigs that I mentioned earlier, we expect it to be at the end of the year, will be 4 in the Bakken and 4 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, had we've put a new completion design in a 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 of supply, single well cost of 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 then any thoughts on the impact this could have on production for next year in terms and relative to where the exit rate might be? Well, I mean, it's not going to change the exit rate in 2016. 16. We won't get any volumes from these 5 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. Just and congrats on cash and transfer. 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 projects sort of CapEx that you guys have? We're 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 $1,000,000,000 of savings, that's CapEx and OpEx from deflation last year versus 2014. And we're on track in 2016 to be to get almost another $1,000,000,000 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 year. It'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 to think about? Yes. I mean, as I hinted out 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 that 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 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 it we do assume in our plans that there will be some reflation as we move over to the next couple of years if prices is improved, 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 1 on CapEx. Your run rate on CapEx during the second half of twenty sixteen has been impressive, running probably at an annualized rate of around $4,500,000,000 a year, certainly below the kind of the $5,000,000,000 plus number that you've suggested in the past is sustaining CapEx. Has there been any change on 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 had 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 3 quarters of CapEx this year, it's at $3,900,000,000 and the $5,200,000,000 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 5 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? Yes. It really is. As we continue to use our latest technology, the 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 2 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 to depend on prices. And between if you think about prices being between $50,000,000 $60,000 you 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 U. S. And Canada before we move into a tax paying position. So I would take those earnings 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, 175 here in the Q3 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 to understand as we think about $5,200,000,000 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 of weeks. But it we as I've already said, we are going to be rolling more into the Lower 40 and the conventional. So there 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 48,000,000 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. Hey, Collyn. So now what are you going to do when they've already asked your question for you? Excellent. So I asked other things. Two questions actually. When you negotiate the contract, the 5 rigs, have you been able to get, say, a fixed rate for the next 2 or 3 years? Is that kind of option is 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 2 to 3 years. If most of the suppliers we were all of the suppliers we were talking with, if you wanted a lot for that period of time, they wanted a much higher price to start with. So they were willing a lot, 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. And with the 5 additional rig you're at 8, I think in the past you guys are talking about to keep production flat, you need about somewhere in the 6 to 7 rigs. Is that still the kind of number or that I got you 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 8 number you're 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 we've got a 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 ag will not keep you flat yet? Well, we'll see. Well, I'll let you interpolate that off the graph in a couple of weeks. Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead. Hey folks, good morning. Just using the midpoint of your production guidance, it looks like we're looking for a decent ramp into 4Q. Alan, 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 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 $6,500,000,000 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. Thanks. Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead. 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 flat for next year? Yes. That's right. I mean, I don't know about the hold 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 $300,000,000 savings getting down to $5,200,000 on our CapEx guidance for this year includes those costs, although because they're coming off fairly late in the year, it's not a it's a bit it's $100,000,000 to $150,000,000 say, of additional CapEx from those 5 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 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. 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? Yes. Yes. 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, 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 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 I mean there may be some amount of non operated, but it is dominated by operated. And it's and all I was saying is just a matter of timing. There were some wells that were drilled previously that even though you're not running rigs there, you still got things that are being hooked up. We had issues with a 3rd 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 +8 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. 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 how do you guys think about them differently? Meaning, am I leaving something out there? And then second, do you think that the cyclical slash structural cost decline ratio is kind of sixty-forty, 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's some rumblings out there that service companies are obviously operating in unsustainable margins and something has to give. So three questions on cost framework and your expectations. Yes. So, Doug, I think that that sixty-forty 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 2 thirds of the savings we've achieved over the last couple of years are structural and about 1 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 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 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 Yes. It's about 2 thirds our model and our tracking says 2 thirds structural, 1 third cyclical. And all I'm saying is that it's some of that's 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. 4 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. 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 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 will 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 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 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 all 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. Thank you. And our last question And our last question is from Pavel Molchanov of Raymond James. 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 mean, 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 a barrel a net to us from near 0 not very long ago. So that's kind of a 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 right 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 Sider from the port there sometime in November. But there's a tremendous amount of damage, significant challenges repairing infrastructure pipelines and out in the well field also at the port and the tankage facilities, 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.