Earnings Call: Q3 2015

Oct 29, 2015

Welcome to the Q3 2015 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, ConocoPhillips. Thanks, Christine, and good morning, everybody. Thank you for joining us today. Our speakers this morning are Jeff Sheets, our EVP of Finance and Chief Financial Officer and Matt Fox, our EVP of E and P. Let me take care of a couple of quick administrative matters. First of all, I wanted to make sure that all of you saw the note in this morning's earnings release that we plan to announce our 2016 capital budget on December 10. We also plan to host a conference call in conjunction with that release, And the reason is to provide some additional details about our operating and financial plans that will include some specifics on our CapEx, our operating costs, our volumes, and also a brief region and program overview. That's a bit of a departure for us, but we think a very good and early opportunity to share our plans for next year, particularly given the ongoing market uncertainty. We will provide the details for that call very shortly. Now if you turn to Page 2, you'll see our safe harbor language. We will make some forward looking statements this morning and the risks and uncertainties in our future performance are described on this slide, and also with our periodic filings with the SEC. And then finally, once again during Q and A, we'll limit questions to 1 plus a follow-up. That way, we can hope to get everybody through the queue within our planned hour. And now, I'll turn the call over to Jeff. Thank you, Ellen, and thanks, everyone, for joining our call today. Before reviewing the quarter, I'll make a few brief comments about how we're addressing the current low commodity price environment, which is clearly impacting financial performance across the sector. This down cycle poses significant challenges and we're taking aggressive actions across our business to position for lower for low and more volatile oil prices in the future. These actions plus our unique portfolio characteristics are the key to delivering on our value proposition through the cycles. Over the past few years, we've high graded the portfolio, organically grown a world class position in North American unconventional plays and are nearing completion on several major projects. We are increasing our capital flexibility, lowering the underlying cost structure of the business and continuing to reduce exposures to assets that won't compete for capital in our portfolio, including deepwater exploration and North American natural gas. As we go through the call today, you should be listening for a few key messages. The underlying operational performance of the business is very strong. We continue to exercise capital flexibility and are further reducing our planned 2015 CapEx spending. We are accelerating reductions in our operating costs and we're on track to exceed our cost reduction target in half the time we expected. We're in strong shape financially. And finally, we're closing the gap on cash flow neutrality. These actions set us up well for 2016 and beyond. As Ellen mentioned, we look forward to providing more details about our 2016 operating plan in December. So while the current environment continues to test the sector, we are focused on the things we can control and moving decisively to position ourselves for a market with greater price uncertainty. So with that said, let's dive into the quarterly results starting on Slide 4. The key theme for the quarter is the underlying business continues to perform very well. We produced 1,554,000 BOE per day, which is 4% growth year over year. Matt will cover operations in more detail, but let me hit the high points. We achieved first oil from our Surmont 2 mega project, which should continue ramping up through 2017. We also brought on our drill site 2S and CD5 projects online in Alaska during October. We brought 6 major projects online so far this year and we expect to deliver cargoes from the 7th, our APLNG project, before year end. Clearly, earnings were challenged given weak commodity prices. Our adjusted loss of $0.38 per share was in line with consensus. Cash flow from operations was $1,300,000,000 This looks low and it excludes impacts of working capital changes. When you adjust for special items, including the rig termination, restructuring costs and pension settlement expense in the quarter, that $1,300,000,000 is more like 1,600,000,000 dollars So about what you'd expect in this price environment given the impact of higher costs and lower production related to turnaround activity this quarter in our Alaska, UK and Malaysia business units. These three business units had 40,000 barrels per day of lower production in the 3rd quarter compared to Q2. These turnarounds are now complete and the high margin oil weighted production from these business units will return in the 4th quarter. Operating costs were down 18% when adjusted for special items and we'll talk about that more in a minute. And we ended the quarter with $2,400,000,000 of cash. On the strategic front, we modestly increased our quarterly dividend in July. This was an important signal to the market that our dividend continues to be a top priority. We also announced our plan to further reduce deepwater exploration spending and began implementing a phased exit. As previously announced, we booked the rig termination fee this quarter. Finally, we are progressing several non core asset dispositions across the portfolio that provide additional sources of cash. We'll provide an update on these activities in December. So now let's look at our financial performance on Slide 5. The story for earnings is weak commodity prices. $6,000,000 or the $0.38 a share. The lower commodity prices were partially offset by higher volumes and lower operating costs after adjusting for special items. 3rd quarter adjusted earnings by segment are shown in the lower right side of the slide. Segment adjusted earnings are roughly in line with our sensitivities and the financial details for each segment can be found in the supplemental data on our website. So it's a tough quarter financially, but the underlying business performance remains strong. Moving to Slide 6, I'll cover our production results. Our Q3 production from continuing operations excluding Libya averaged 1,554,000 BOE per day compared to 1.473 per day in the same quarter last year. Adjusting out 25,000 BOE per day due to lower third quarter downtime and dispositions, we achieved growth of 4% or 56,000 BOE per day. Our growth continues to come primarily from North American liquids and APLNG ramp gas, which will soon become liquids priced LNG. On a price normalized basis, this should help drive margins and returns. Now if you'll turn to the next slide, I'll cover our year to date cash flow waterfall. This chart summarizes our year to date sources and uses of cash. Starting at the left, we began the year with 5 $100,000,000 of cash. Through September, we generated $5,800,000,000 from operating activities excluding working capital. Working capital over this period was a $600,000,000 use of cash. Through 3 quarters, we received $600,000,000 in disposition proceeds. As we mentioned, we previously we currently have several assets on the market. We expect several of them to close this year and we'll provide an update in December. As we said before, you should expect us to generate $1,000,000,000 to $2,000,000,000 per year as part of our routine high grading process. We increased debt by $2,400,000,000 during the 2nd quarter, but added no debt in the Q3. Through the Q3, we spent $7,900,000,000 in capital, paid our dividend and ended with $2,400,000,000 of cash on the balance We believe we're in strong shape financially. Between cash on hand, debt capacity within inspected asset sales proceeds, we have the means to manage through the current period of low prices. As a pretty quick recap of the financial results for the quarter, now I'll turn the call over to Matt, who will go through the operational performance and close with a 2015 guidance update. What you're going to hear is driving positive momentum in the business. All things equal, these steps should take we're taking should drive improved 2016 earnings and cash flow. So I'll turn it over to Matt. Thanks, Jeff. As Jeff mentioned, we performed very well this quarter operationally. We successfully completed several major turnarounds, continued to bring major projects online and exceeded our production targets. I'll now quickly run through the segment results and then we'll move on to your questions. So let's start with Slide 9. The Lower forty eight, 3rd quarter production averaged 551,000 BOE per day. That's a 1% increase from the same period last year and a 1% decrease sequentially. Importantly though, this represents a 12% increase in our crude oil year over year. We're currently running 13 rigs in the Lower 48, 6 in the Eagle Ford, 4 in the Permian and 4 in the Bakken and 3 in the Permian, one of which is in the unconventionals. And we're delivering more for less across our programs. In fact, we've seen 20% to 30% lower drilling and completion costs compared to a year ago, about half of that is driven by program efficiencies and about half is from deflation capture. Production from these 3 unconventional plays was 249,000 BOE per day this quarter. That's an increase of 28,000 barrels versus the Q3 last year, but a decrease of 6,000 barrels a day sequentially. As we forecasted, given our current level of rig activity from production from these plays plateaued in the Q3 and we'd expect to see modest decline in the Q4. Clearly, 2016 production will depend on the level of capital flexibility we choose to exercise. However, you should not expect us to increase capital in these plays at current prices. Despite our stated plans to reduce deepwater exploration spending over time, we are continuing to fund activity based on existing commitments, but we also progress possible monetization options. This is important for protecting the value we've created from our existing program. In the Gulf of Mexico, we had encouraging results from the recent Shenandoah appraisal well. We're currently drilling the Vernachie and Gibson exploration wells and we to spud the Melmar prospect this quarter. In Canada, we produced 315,000 BOE per day, a 14% increase year over year. This growth came mostly from strong well performance, ramp up at Foster Creek Phase F and lower planned downtime. We achieved a major milestone during the quarter with first oil at our Sherman II oil sands project. This project will continue ramping up through 2017 and at full production, we expect to increase Surmont's total gross capacity to 150 1,000 BOE per day. We spotted the Cheshire exploration well offshore Nova Scotia this month and that's the first of 2 exploration well commitments. Next, let's review our Alaska and Europe segments on Slide 10. Alaska's average production was 160,000 BOE per day, an increase of 3% compared to last year's Q3 due to lower planned downtime. We successfully completed several major project turnarounds during the quarter of Trudeau and Coparac. We recently achieved 2 key project milestones with 1st oil from CD5 and Drill Site 2S in October. At peak production, we expect these projects to contribute about 15,000 barrels a day of crude. So, we are seeing the benefits of project activity that will help to keep our Alaska production relatively flat the next several years. We completed our 6 cargo export program from Kenai in 2015 with the last cargo delivered in October and we applied for a license from the BOE to continue our export program in 2016. Moving to Europe, 3rd quarter production averaged 192,000 BOE per day. We had several major turnarounds across the UK that were all completed successfully and we're continuing development drilling at EcoFisk South and Eildfisk 2 in Norway. Now I'll cover the Asia Pacific and Middle East and other international segments on Slide 11. In the APME segment, we produced 332,000 BOE per day in the third quarter. This is a 10% increase from the same period last year driven by Gamusut and increased ramp gas from APLNG. In Malaysia, Gamusut underwent its 1st major turnaround, which was completed ahead of schedule. In Australia, we expect APLNG Train 1 to deliver its 1st cargo in the 4th In the downstream project, all the mechanical runs are complete and in the upstream project, 14 of the 15 gas processing facilities are now fully commissioned. In other international, the Athena rig from Angola has arrived in Senegal where we expect to conduct a 6 well exploration and appraisal program starting now and extending into next year. In Libya, production remains shutting as a result of the ongoing regional instability. So let me close on the next slide by giving you some updated guidance for 2015 and summarizing the key takeaways from our call. The title of this slide says it all. We are reducing our 2015 CapEx, reducing our 2015 operating cost and delivering strong underlying business performance. Like Jeff mentioned, this will help drive solid momentum into 2016. On the production front, we now expect to exceed our full year 2015 production guidance. That's in large part due to delivering our 7 major project start ups this year. We expect to achieve 4th quarter production of 1.585 to 1.625 1,000,000 BOE per day and that puts our full year 2015 guidance range at 1.585 1,000,000 BOE per day. And as the chart shows, this represents 3% to 4% growth from continuing operations excluding Libya, up from the 2% to 3% we expected at the start of the year. The table captures several other key guidance items and shows the progress we've made since 2014 and through 2015. The far right column is our current 2015 guidance and all of these numbers exclude special items. We now expect our 2015 capital spending to come in at 10,200,000,000 dollars That's a 40% decrease from 2014 and 11% decrease from our initial outlook for 2015. About half of the reduction was related to market factors like FX and deflation and about half is due to discretionary deferrals and program efficiencies. On operating costs, we're now guiding to $8,200,000,000 for 2015 and that's a 15% reduction compared to 2014. You remember in April, we set a target to reduce operating costs in 2016 by $1,000,000,000 compared to 2014 and what our revised 2015 operating cost guidance represents is an acceleration of this effort. In fact, we've now exceeded our $1,000,000,000 target in half the time. These savings came from market factors like deflation and FX impacts, but the rest came from steps we've taken to lower the cost structure of the business through G and A reductions, new operating philosophies and supply chain efficiencies and we're not done yet. We're also changing our full year corporate segment guidance to a net expense of 800,000,000 dollars and that's a 20% reduction from initial 2015 guidance. I'll close by repeating the key messages you should take from this call. The underlying operational performance of the business is very strong. We continue to exercise capital flexibility and we are further reducing our planned 2015 capital spending. We are accelerating reductions in our operating costs and are on track to exceed our cost reduction target in half the time we expected. And finally, we're in very strong shape financially. So we are all focused on safely and successfully executing our operations, while positioning the company to be more flexible and resilient to deliver on our long term commitments to shareholders. We look forward to providing more details of our plan for 2016 in December. So now I'll turn the call over to you for Q and A. Thank And our first question is from Doug Terreson of Evercore ISI. Please go ahead. Good morning, everybody. Hello, Doug. In U. S. Unconventional, in that arena, industry productivity gains were pretty significant in recent years, but more recent data indicates that we've had a slowdown even though companies seem to be drilling their best resources and using optimal technology and personnel too. So while this could be a blip in the data, it could also be that logical limits are being reached by some and that science might play a greater role in recovery rate capture in the future. So I just wanted to get your insights into this paradigm or maybe into this transition that's underway, that is if you think that there is one. And also, based on your experience and with your credentials, where do you think we are in understanding of the shale resource overall? So, Doug, I think the from our perspective, the sweet spots really matter. So you're going to get the best performance out of the sweet spots and you're probably right that people are focusing. They're just not with a limited number of rigs running. But I wouldn't say that our perspective is that we've reached any sort of technological limit. And we are continuing to see encouraging results from our pilot tests on different well spacings. We're continuing to run our stimulated drop volume pilot in the Eagle Ford and learning a lot that's going to allow us to optimize well spacing and completions in the future. And even in the Bakken, we're moving from open hole slide and sleeve completions to cemented liner and plug and pair. But we're going to see and we're seeing improvements there from our pilot tests. So I don't from our perspective, we're not seeing ourselves set in any technology limit yet. Okay, Matt. So don't disagree with that, but it seems like the industry may be slowing down somewhat. And so I recognize it's hard for you to maybe attribute that to other factors because it's not your company, but do you have any insight as to what may be those drivers? Yes, we see that in other people's individual well performance, but I'm not quite sure what to attribute that to. Okay. Okay, thanks a lot. Thank you. Our next question is from John Herrlin of Societe Generale. Please go ahead. Yes. Hi. I know you're going to announce your CapEx budget for next year on the 10th December. But from a portfolio management perspective, is it safe to say that you're focusing more on short and intermediate term type projects or and deferring kind of a longer term type business? Well, really what's going to happen for us, John, is that we're as we move from 'fifteen and 'sixteen, we are seeing about $2,000,000,000 of major project spend roll off as we complete, in particular, Surmont and APLNG. So we have a choice as to what to do with that and the additional capital flexibility that's appearing. And we could redirect it to shorter cycle or we could just hold on to those opportunities for another time. And that's exactly the sort of detail we're going to provide in the December call. Okay. Next one for me is a quickie. DUCs, you're hearing a lot of companies now say the concept is to accumulate uncompleted wells. Is that part of your MO? No, it's not. I mean, our view is that they if you don't want to complete the wells, don't drill them. So we are we are not we don't have a strategy to drill wells and intentionally not complete them. We are reducing the number of uncompleted wells as we've gone through this year. We started the year with about 135 wells that were uncompleted and we'll end the year with about 95 wells. But that's just the sort of natural course of executing our program. So it's not a deliberate choice to drill wells and not complete them. Thanks, Matt. Thanks, Matt. Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thank you. Good afternoon, everybody. Hi, Doug. I got a couple of questions also, if I may. First of all, on the I guess there's a curious statement in the release about disposals, Matt. And I'm just kind of thinking out loud about headcount reduction, large capital projects coming online. You've got a very large tail of non operated relatively small assets, particularly in light of a potential exit in the Gulf of Mexico. So I'm just wondering order of magnitude, you've got 80,000 barrels a day of gas equivalent in the U. S. That my understanding is you're marketing. What do you think the scale of the non core disposals, if you want to call it that, stands out once you get those big projects online and what's the likely timeline to see some movement on the asset sales? Doug, we're I mean, it's no secret there will be several non core assets on the market, including the North American gas assets. But we're not ready to give details of those at this time. We are going to give some more detail in December. But what you should expect is something of the order of $1,000,000,000 to $2,000,000,000 annually, but we are going to give you more detail in December, but it's not appropriate for us to go into detail just now. Annually needs a number of years on it, Matt. What are we talking about, 1 year or 5 years or what? I would say that on average over any period of time, we should be cleaning the portfolio and that could be $1,000,000,000 to $2,000,000,000 a year, so annually, yes. Okay. My follow-up is on Jeff, maybe on cash flow. It looks like cash flow was operating cash flow is a little weak this quarter. And I'm trying to decipher what was going on at the affiliate level. Thinking about your $60 sort of cash breakeven by 2017 and obviously the cost reductions announced today. So can you just kind of help reconcile what was going on with the cash flow this quarter and where do you think that cash breakeven now stands after your latest run to cost reductions? And I'll leave it there. Thanks. So on the affiliate level, we really have 3 major equity affiliates. You have the Foster Creek, Christina Lake Oil Sands joint venture, the APLNG project in Australia and the QG3 III project in Cairnscutter. Of those 3, 2 of them are still in a fairly heavy investment phase. So for the APLNG, we don't get any cash distributions out of there. The FCCL this year. It's the same kind of story that all the cash flow is being retained to fund capital there. And we do get some distributions out of QG3. As we move forward in 2016 2017 with the start up of APLNG and as additional phases and we would assume some price recovery happens for Frost Creek and Christina Lake, we expect that we would see distributions coming out of all three of those joint ventures. And as we've talked previously, that's a pretty significant source of cash flow to bring us closer to cash flow neutrality. As we've also talked before, we as we think about cash flow neutrality in 2017, we have increasing levels of capital flexibility, increasing production levels to where we feel like we're going to be able to get there at a pretty broad range of commodity prices. So there's not really just kind of one commodity price number that we point out is what it takes for us to get to cash flow neutrality in 2017. So nothing specific this quarter is because the cash flow is a lag? Well, I mean, we had some unique effects this quarter. If you look at the $1,300,000,000 of cash from operations before working capital and the 1.9 $1,900,000,000 of after working. We had 600,000,000 dollars of working capital impacts. We had the rig termination fee, which we took against earnings, but didn't hit cash, but ended up hitting cash before working capital because it caused a shift in working capital. A similar effect happened on our restructuring costs. So when we made the comment in the as we went through the slides that you should think about that $1,300,000 being more like $1,600,000 It's taking account of the impact of just those special items. And then as we also pointed out, this is a the Q3 is always a weak cash flow quarter for us because it tends to be the quarter where we get the most turnaround activity. In this quarter, we had we lost about 40,000 business units business units because they're the ones who went through turnaround. And that is pretty heavily weighted to oil production. And when you think about what happens in a turnaround, you're losing the revenue, but you're still keeping all your normal costs and then you're having the costs associated with the turnaround itself. So the net margin you're losing when you have a turnaround is pretty high on those barrels. That's helpful. Thanks, Jeff. Thanks, Jeff. Thank you. Our next question is from Scott Hanold of RBC Capital Markets. Please go ahead. Thanks, guys. Just a couple of questions for me as well. A little more specific on some of the unconventional U. S. Resource plays, the Eagle Ford and Bakken, it sounds like the current activity levels, the expectation production is probably going to slide a little bit. Is that true if we remain in this somewhat $45, $50 environment and kind of more direct, what price would allocate more capital to those areas? Yes. If we stay at our current level of rigs in the Eagle Ford and Bakken, We would expect to see some modest decline. So for example, if we go from this year into next year and we don't increase rigs, we'll see 3% to 5% decline on our production in the unconventionals. We're going through the process of setting our operating plan and budget for 2016 and we'll give you a lot more detail on what we actually decide to do with that rig count at that time. But just as a sort of reference, so if we stay at the current rig rate, it will be 3% to 5% decline in our unconventional production. Okay, appreciate that. That's good color. And one other thing on the sales goals. Jeff, rather than trying to be too specific as far as what you're selling and timing on it, But just specifically, can you give us a broad sense of what really are the goals of these asset sales? Is it cleaning up the portfolio? Is it help bridging cash flow deficit to keep strong dividend? And I guess my point is if commodity prices do eventually improve, does that become less important to Conoco? It's a combination of those factors. These are predominantly going to be asset sales that we would be doing regardless of a commodity price environment. You think about a portfolio of our size, we're always going to be in the process of trying to find the assets with some other someone else wouldn't value more highly than we do. So as we've talked about, it's things like some parts of our North American natural gas portfolio might fit in that category. The other thing that we think about in terms of asset sales are what assets are just not going to make the cut for us to fund capital for them. And when someone who might be more willing to fund that capital, would they have a different value perspective on those. So it's always a bit of a combination, but predominantly these are assets that are going to be part of any of a rationalization process in most commodity price environments. Understood. Appreciate it. Thanks. Thanks, Scott. Thank you. Our next question is from Guy Baber of Simmons. Please go ahead. Good afternoon, everybody. Hey, Guy. Hello, Guy. I wanted to dive into the production a little bit, but hoping you could just address the major project performance, how those projects are ramping up relative to expectations? And specifically, if you could just remind us of the incremental production from those projects latest view, in 2016 2017? Just trying to understand that base level of growth that's coming on as the CapEx begins to decline? Yes. So the major projects are ramping up and Gamuso is coming in now that expectations have had the turnaround there that I mentioned, which has allowed us to get the gas injection established and we're so it's ramping up and getting close to full capacity. APLNG is ramping up gas in anticipation of having the LNG plant full and for the first train. Cermont is really just literally just started producing oil in September and that's going to gradually ramp up over the next 12 months to 15 months. So if you just look to those 3 projects alone and aggregate by 2017, we're probably looking at 150 or so 1,000 barrels a day of incremental production from those 3 projects, maybe 120 because Gamuso is already there. That's helpful. Thanks, Matt. And then I wanted to dive into thoughts around capital allocation and the deepwater portfolio a little bit more, specifically on development capital towards deepwater and offshore. But do you have flexibility to slow your offshore development CapEx next year, the year after? And is that something that you would consider in this environment at this point in time? Well, I mean, we have announced that we are going to be exiting deepwater exploration, although we do have quite a significant program that we are executing next year. Development of the discoveries that we have in deepwater is quite some way off and we may choose to stay with those developments, but we may choose to exit before development happens. So really what we're in just now is in the ramping down our exploration commitments and continuing appraisal on the existing discoveries, we're not at development stage yet. Thanks for that. Okay. Thanks, guys. Thanks, guys. Thank you. Our next question is from Phil Gresh of JPMorgan. Please go ahead. Yes. Hi. Good afternoon. First question is just on the equity affiliates again. In the oil sands, your partner on FCCL noted that they're contemplating restarting some of the project phases in 2016 that could add up to another $500,000,000 in CapEx on the base level of spend. So if this happens, the equity affiliate source of cash for you guys will be lower. And I assume that's not what you're contemplating at this stage, but maybe you could just talk about where oil sands projects rank in terms of your relative priorities of cash post Surma to the extent your partner wants to move forward on this? Yes. So we obviously engage in the budgeting process with our partner there and that's a pretty collaborative process. I mean historically what we've done here is we've funded the additional growth in FCCL from within the joint venture, from cash that's generated within the joint venture and rather than taking distributions out. And those are good projects at Foster and Christina. So we'll be we'll have a good discussion at the management committee on going for the right pieces to develop those. But it won't influence distributions per se, because we really haven't been taking distributions out of FCCL. We've been intending to reinvest in the sort of gradual increase in production as we add more phases there. Okay. Yes, I was referring more to just the expectation moving forward that you will be taking distributions. I didn't know if more growth would hinder that. Jeff, I don't know if you have a comment on that. Yes. Well, at the same time that they're talking about these investments, you have to also keep in mind that production levels from both Foster Creek and Christina Lake continue to increase. And we've been at a period where we've had low commodity prices and pretty wide differentials, so which the net result has been some pretty weak realizations. So there's quite a bit of leverage to increases in prices that can happen there as well. So you get what is probably price increases happening both on the differential and the flat price side and increased production is going to provide more capability to fund increased investment as well. Okay. And my follow-up is just on the production, the increase in the production target for this year. Would you say that's more of a pull forward on just executing on major capital projects faster or is it something that would indicate a sustainably higher growth rate that we should be thinking about for 2016? No, this is not really associated with major project acceleration. It's more an indication of the performance of our base and the managing of base decline and the performance that we're getting from our new development wells across the portfolio as a whole. Sure. Okay. Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead. Hi, guys. Hi, Paul. You've done a tremendous amount this year, as shown on the slides. But when we look at it, let's say $50 oil this year, you've made about it looks like a run rate of about $8,000,000,000 cash flow. I guess that's obviously not a fair number. Can you guide us towards what the real run rate will be given what you've achieved? And secondly, perhaps update us given all the movements on the sensitivities of cash flows or earnings to dollar changes in the oil price, I'm assuming that they've gone up? Thanks. The sensitivities that we've provided are still pretty close. We'll give you some updated sensitivities to that in December that will reflect the latest view, but they're not going to be largely different than what you've seen currently. We're also in December, we'll be giving you a better picture of what 2016 will be looking like in terms of how to think about costs relative to this year and how to think about capital costs relative to this year. But just overall, the picture like we said, when we look at the balance of cash flow and the proceeds that we're likely to get from asset sales when we compare that to what we think capital is going to be and the dividend, we see a picture that is very manageable for us from a balance sheet perspective in order to get to the point where we get to a cash flow neutrality balance still kind of in the 2017 timeframe within the capacity that we have on our balance sheet. Yes. I guess what I'm driving at is that it feels like the price of oil required for that has come down over the course of the last year. It has. Since you last update. I'll go with a follow-up, which is kind of related, but you said here that you're in a phased exit of deepwater exploration. I assume that means that you'll be selling out of positions and that will form part of the disposal program that you've talked about, which is very significant. I think $1,000,000,000 to $2,000,000,000 a year. I would assume that that's a phased exit, which will sort of be a one way street. I mean, once you've left, you'll be gone. And I would also anticipate that that would involve selling leases. I know you've got a major position, for example, in the Gulf of Mexico. Am I kind of heading in the right direction here in terms of how you're looking at this? Yes, that's right, Paul. Can you just remind us how big your position is in the Gulf of Mexico because I know it's Yes, so in the Gulf we've got about 2,200,000 acres in the Gulf and 3 existing discoveries and the there is yes, our intention is to not be doing deepwater exploration by 2017. And those acreage positions that we hold that we don't intend to drill, we will be marketing those positions. Yes, understood. And that becomes then, as I said, and you sort of agreed, I hope I didn't trap you that, that becomes a one way street. I mean, effectively, over time, you're simply leaving the deepwater and won't come back. That's right. No, that's a strategic decision to leave to exit deepwater exploration. That's exactly right. Great. That's very clear. Thanks, guys. Thanks Paul. Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead. Hey guys. Good afternoon. Hey Paul. Hello Hello Paul. Jeff, I think maybe several months ago that you and Matt talking about to sustain your operation is about $8,000,000,000 which was down from $9,000,000,000 say maybe from last year. So are we still talking about $8,000,000,000 given that you actually accelerate your cost reduction and everything or that this number is now $7,000,000 or $7,500,000 It's hard to talk about that number without some context around what kind of environment we think we're in. If we had a continuation of the type of environment we've seen today, we do think we'd be talking about a number that was lower than $8,000,000,000 but it's in that same kind of a range. Okay. And maybe this is for Matt that you're currently wondering about 13 rate and you're saying that the 3rd quarter production the 4th quarter production will be modestly down. So my guess is that what is the number of rig that you think you need in order to hold the production flat and what kind of CapEx required that you have that kind of progress? So to keep Eagle Ford production flat probably requires between 7 8 rigs. Currently we're running 6. The Bakken requires closer to 5 rigs, we're currently running 4. So you'd be looking at maybe 3 additional rigs to maintain production flat. And if you look at sort of all in cost, drill complete, hook and hook up and so on, you can use an order of magnitude of $150,000,000 Per rig line Per rig line Per rig line Per $50,000,000 No, per rig line per year. So you maybe $400,000,000 Okay, perfect. Thank you. Thanks, Paul. Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead. Hi, good morning. Hello, Roger. Hello, Roger. Good morning. I guess, we come back around on the Gulf of Mexico or just deepwater in general. You mentioned earlier on the call you'd had further appraisal on Shenandoah. Should we think of the exit of exploration also including the exit of not yet developed, but partially explored? Possibly, but the only if we get full value for it, we're willing to stay in our discoveries if that's what maximizes the value. And but the so we haven't made a commitment to exit deepwater per se, but it's the deepwater exploration. But if we saw full value for those assets, then we'd certainly consider that. Okay. And can you give us an idea of what the capital flexibility is once you're away from deepwater exploration or any other type of exploration you're not planning to do by 2017? And then if I understood correctly, it doesn't sound like the oil sands necessarily gets incremental CapEx and we're going to presume that there's not another LNG project. So as we look at the total CapEx number sort of as a, I guess, a starting point for when you talk about it in December, kind of where we can see that CapEx flexibility that could come back into the shale plays in future years? Well, I guess to give you a bit of a preview of the 2016 budget, we expect to spend about $800,000,000 in 2016 in the deepwater exploration and appraisal space. And so that's the order of magnitude on the capital side that we wouldn't be spending if we weren't doing deepwater exploration and appraisal for 1 year and then there's a G and G and G and A associated with that as well. And that number, Matt noted, is a fairly consistent number with what we're spending there in 2015 as well. Yes. Okay. Thank you. Thanks, Roger. Thank you. Our next question is from Bob Brackett of Sanford Bernstein. Please go ahead. Hi. I've got a kind of a high level more philosophic question on the 2016 capital plan ahead of getting the details. One is simple. What sort of price tag would you be looking at in terms of thinking about your cash flow from operations next year? We don't have one price deck that we use. As we talk about, we are preparing the company to deal with low and volatile prices. So we're going to be ready to handle whether we get a continuation of current prices, whether we get some recovery. That's not really going to be a determining factor in exactly where we set our capital program. Okay. And then how do you prioritize the sources of cash for that program and the sort of the sinks or the uses of cash? What's the pecking order? So we're going to use cash flow from operations to fund the capital and the dividend. We're going to have some amount of asset sales proceeds that come in from things that we're currently marketing and other things that we might market. We're going to we will first use the cash that's on our balance sheet. And then to the extent that cash from operations and asset sales don't fully fund capital in the dividend, we'll be looking to increase debt. I mean that's the I mean it's just a mechanic of what's going to end up happening for us. And as we said, as we look at the amount of debt that we might need to raise, even in some continuation of some pretty tough price environments, we feel comfortable that that capacity exists on our balance sheet and it really exists within a single A credit rating as well. Great. Thanks. Thanks, Bob. Thank you. Our next question is from Blake update, is that in lieu of the typical Analyst Day we would have in April? We're still thinking about all that, but, our big concern here is not asking the market to wait till April to see the details of what our current year plan is. So at this point, you can count on December being a pretty big update on the company's plans and programs for the year. Okay, thanks. In the past, I believe you've provided some kind of rate of return or breakeven levels for the major projects, including Surmont and APLNG and seeing how those are 2 kind of major contributors near term. I'm just wondering, could you provide us with an update as far as what you think a breakeven price is for oil when those are actually accretive to net income earnings per share? I don't have that off the top of my head. That's fine. Maybe I can follow-up with that. Yes, we can come back to you. Not a problem. I'll get back with Sid on that. The last one is just kind of more of a broader picture question, I guess. With the I'm just curious if the Board ever has a discussion about the shareholder payout. I know you're very committed to the dividend and you're trying to maintain that shareholder base. But when you look at the stock trading from the, call it, mid-80s down into the 50s, is there any consideration whatsoever to maybe shift that ratio toward maybe a buyback program or even toward capturing M and A opportunities instead of pure dividend payout? We've been pretty consistent since we started ConocoPhillips as an independent E and P that we thought the way to create value in strong payouts back to our shareholders in the form of a dividend. We think of a dividend as something that really should only go one direction and there can be some variability in the rate at which dividend increases. But the Keto dividend is that have it be consistent and then to grow it over time. So we haven't really had significant discussion to talk about trying to adjust that dividend. It's an important part of our value proposition. It puts a lot of discipline into the system to have that dividend. So you've heard us talk about it pretty consistently. You're going to continue to hear us talk about that as a key component of our value question is from Neil Mehta of Goldman Sachs. Please go ahead. Good afternoon. Hi, Neil. So, I want to start off on the LNG markets, been a lot of debate and discussion around that. We've got APLNG coming in here in the next couple of weeks. So any thoughts on the LNG markets broadly? And then there has been some investor concern around Sinopec and the APLNG contracts. Just any updated thoughts there and anything you could say that can help investors get comfort around that risk? Yes. Clearly, the short term LNG market is pretty weak. The whether you're tied to oil prices or you're in the spot market, it's a pretty weak price that we're getting for LNG going forward. And there's not a lot that we can do about that. With respect to the Sinopec contract to APLNG, so that's a take or pay contract. Sinopec have the right to divert cargoes within China. And we've also given them the right to divert cargoes outside China. But as a take or pay contract and with a price formula that's tied to oil, And we've been no reason to believe that there's any issue with that contract. The Sinopec in fact is a 25% and shareholder in APLNG on the upstream projects. So we don't have any concerns if that's what you're indicating about the sanctity of that contract. All right, terrific. And then, Jeff, on the operating and CapEx reductions that were announced relative to the July guidance, can you just help bridge the gap from what are the drivers that get you from $8,900,000,000 to $8,200,000,000 And then on the CapEx side from $11,000,000,000 to $10,200,000,000 What are all the cats and dogs there? Well, it's we just put it in kind of broad categories. We talked about before, it's really the same things that have brought it down the first increment. It's a mix of what we call macro factors, just continued deflation out there in the industry and also continued strength of the U. S. Dollar, lowering both our capital and operating costs in Canada and Norway and Australia. But it's also it's about half that and it's about half things that we're doing, efficiencies that we're forcing through the system, changes that we're making to how we run the company, lower employee headcount numbers. It's really more of the same compared to the reductions that we took the first increment of our guidance down. That's great. One last question for me. You guys have the advantage of seeing the world when it comes to oil production. Curious on your views on when we're going to see non OPEC ex U. S. Production really start to fall off and the decline rates start to materialize, which is going to be central to rebalancing these markets? I'm not sure when we're going to see it, but it's going to come, Neil. I mean, the people are adjusting their capital programs where they have the flexibility to do that. So that will be things like infill drilling and where they have rig contract flexibility. People are exercising operating cost flexibility too, which means less workovers, less spinning spares and so on. So the over time that's going to materialize in the non OPEC, non U. S. Production, but exactly when and to what magnitude is hard to tell that is coming. All right. Thank you very much, guys. Thanks, Neil. Thank you. Our next question is from Edward Westlake of Credit Suisse. Please go ahead. Hey, couple of quick ones. Disposals $1,000,000,000 to $2,000,000,000 probably there were some disposals in your prior plan to get to 1,700,000 barrels a day. But can you just give us a sort of maybe an endpoint kind of impact that it might make as you reshape the outlook? No, we went in the 1,700,000 barrels a day in 2017 that we talked about in April. There was no assumption of dispositions in that. We would make an adjustment when we know exactly what assets are moving out of the portfolio. And we're not ready to add to give you a number yet because we don't know exactly which of the mix of assets that we have in the market are actually going to achieve an acceptable price. We will give you some more indication of where that's heading hopefully in December, but it's too early for us to do that now. And that's one of the reasons we really don't talk about the dispositions until they close, because you can't know exactly which of the assets that have been considered for sale are actually achieving the price that they need to make it acceptable for us to sell them. Okay. And then, so I can see how the production and cash flow moving parts move around with these sort of long lived assets coming in with lower decline rates, plus obviously some short cycle production, which you can attack both in conventional and also in shale. But obviously reserve replacement is also something that people focus. I don't know if you've done any long range work as to if you're spending $8,000,000,000 at the low end as the CapEx drops out, what reserve replacement looks like, say 2017 onwards? Or what are the big sources whether you can actually replace reserves at that point? Well, I mean, we have this 44,000,000,000 barrel resource base we've described in some length in April, the $18,000,000,000 of that has less than a $60 cost of supply. So there's lots of sources to continue to convert that resource base into reserves as we go through the next few years. Is that the question you were getting at, Ed? Okay. So the point is that the converting that resource base over time as we execute our capital programs is what's going to result in growth in the reserve base. Thank you. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead. Thanks. Good afternoon, everybody. Maybe if I could talk a little bit about CapEx. The run rate in the Q3 of $2,200,000,000 so annualized at an $8,800,000,000 run rate. How should we think about and maybe this is too much preview, but how should we think about moving pieces into 2016? Is that a I mean, it's meaningfully down from the first half of the year. Is that a reasonable run rate going forward? Is there still meaningful long cycle roll off out of that number that will be cycled in the short cycle? Or is much of that rolling off by this point? I guess anything on kind of the puts and takes as we look forward to the 3Q run rate? We still have capital going into major projects that will reduce significantly as we get into next year. So I think the easiest way to think about it, Ryan, is that the $2,000,000,000 sort of number that we've been talking about in terms of the average capital going into major projects this year that's rolling off next year. So I wouldn't get to the hung up on the run rate in the Q3, but more think about it as that sort of amount of major project capital rolling off from 15 to 16. Okay. And then, I guess, a follow-up on a couple of questions ago in terms of the operating cost reductions. I mean, you've been well ahead of schedule with the $1,000,000,000 over effectively in 1 year. How much of that I mean, if you think of that $1,500,000,000 I mean, how much of that is kind of structural versus cyclical? And as you look forward into 2016, I guess, on the cyclical portion, which do you have any thoughts on which way it cycles? And is there more downside to that number going forward? Well, the cyclical part of it is driven primarily by foreign exchange and just deflation that we've seen in the industry. So to answer your question, you kind of have to answer that in context of a price level. So if we continue to have weak prices, that's not going to cycle up in a period of weak prices. We probably have a period of weak prices and they also mean that we continue to have a fairly strong U. S. Dollar. So I don't know where you draw the line between cyclical and structural, but if you're thinking about near term, if you think in terms of a continued weak price environment, we don't really expect those to cycle back. But just in the overall general context, like we've talked before, we see about half of what's happened is kind of macro factors like deflation and FX and generally half has things that we're doing within the way we operate the business, which are kind of more structural in nature. And do you think there's more to I guess on the non cyclical side, is there I mean, do you view there as being more to go still in 2016? Or have you just have you pulled forward the lion's share of what you thought you'd be able to achieve? We pulled forward a lot of it, but there's still more to come and we're going to give you the details in December on that. Okay. Thanks a lot gentlemen. Thanks, Manny. Thank you. Our next question is from Evan Kallio of Morgan Stanley. Please go ahead. Hi, good afternoon guys. Thanks for squeezing me in here at the top of the hour. As a philosophical question more on total returns, I know you guys have made significant CapEx cuts and outpacing deflation. If combined with asset sales, do you view a risk or how do you balance a risk to a negative medium or longer term production growth? So that I mean, I guess the risk is that dividend yield merges with a total shareholder return type of metric in the future? Cash flow growth? Yes. I'm not sure if I followed your question, Evan. If you think about in the near term, we are going to benefit from capital that we've been investing over the last several years so that we are going to continue to have production growth from these major projects that will provide cash flow growth as well. I mean, if you do think about a longer term lower price environment, then you're in the realm of trying to anticipate what might happen with overall operating costs in the industry. And then from the asset sales perspective, we're not intending to sell assets that have growing production and cash flow. I guess the question and I'll leave it this. It relates to you're making significant cuts and the cuts are driven partially with the commitment to the dividend and at what point are you cutting muscle? I know you run a lot of different scenarios and I believe in the security of the dividend at most prices. But what's the cost as it relates to those sales and rigor to the longer term outlook of either growth or asset value. I'll leave it at that. No, I think it gets back to a comment that we had earlier about what motivates a lot of the asset sales. A lot of the asset sales are driven by kind of normal portfolio rationalization. Of course, we generate asset sales proceeds from that. But if you look back if you look at what we're selling now, if you look back at what we've historically sold, I think you can understand why we would think of those as non strategic assets, which we've got better value for by selling them than we would have had by keeping them inside the portfolio and that's the main driver for asset sales. As you think about things like the Deepwater decision, that's driven as much by the opportunity that we see in the rest of our portfolio as it is by thinking about just deepwater on its own. The resource base that we feel like we have and what are we going to want to prioritize in terms of funding capital is what's been a big driver for that decision. Great. I'll leave it there, Chris. We don't feel like we are doing things in this environment, which are going to not be beneficial to the long term ability to grow production and grow cash flows and grow the dividend. Got it. Thank you. Thanks, Evan. Thank you. Our next question is from James Sullivan of Alembic Global Advisors. Please go ahead. Hey, good afternoon, guys. Thanks again for sneaking me in. Just a quick one here. Obviously, going back to APLNG, I see that the ramp gas is coming up nicely. I also noticed that the equity gas realizations in Asia Pacific are dropping. I'm assuming that's because the ramp gas is getting sold at domestic gas prices. Can you quantify at all, if possible, and you could just maybe use a Q3 constant pricing for this, but what the uplift would be if that ramp gas is being sold as LNG under your contract? I don't have that off the top of my head. James, you're right, the ramp gas is as we're building up to fill the train 1 is getting sold as the domestic prices essentially. And then the netback once we get to LNG will clearly be a function of what the oil price is really at that time because these are linked to JCC, but I don't have that number off the top of my head. But just generally, you can think that the price we're receiving for Australian gas in the domestic gas market is not any stronger than what we get for the what we sell into the North American gas market. So there's a pretty significant uplift even in the current market in the current oil price market to move that to LNG. Right, right. Yes, I guess I was just trying to see whether it was a lot lower or if there is a contractually lower rate or anything like that. But it sounds like it's maybe just about what you'd expect for domestic. One just quick last one there. Obviously, I saw you guys got the go ahead up in Alaska for some of the NPR drilling. Can you guys give a little update there? I know Greater Moose is due some of these are longer dated projects, but what the timeframe and potential impact for some of those projects are? And I'll take offline after that. Yes. So we announced the first production from the NPR rate from the CD5 project and it started just a week or so ago, less than a week ago. And we did get approval from the government for the impairments that we need to develop the GMT-one prospect. So the first prospect inside the Creighton Mercy's Tuf unit and we'll we're working through the process of deciding the sanction of that project, but that sanction decision hasn't been made yet. Okay, great. Thanks guys. Thanks James. Thank you. I will now turn the call back over to the company for closing comments. Good job. I'd just like to make a couple of closing comments because we all know this is a difficult time for the industry, but we at the ConocoPhillips were focused on what we can control and that's our production, our capital and our operating cost and as we outlined here we're moving all of those quickly in the right direction. But we are really not just focused on the short term. When we look at what it's going to take to win in a more cyclical and volatile future, We think it's a diverse low decline production base that gives us stable source of funding to sustain the dividend and we have that. We think you want a large low cost of supply resource base that provides a balance of flexible short cycle investment options, so you can scale your growth to higher or lower prices, but also has a lower risk long term projects that can add to a low decline base and we have that in our portfolio. We also think you need a sustainable low cost structure to make sure your margins are resilient to lower prices And you saw today, we're taking a lot of action to get there. We think you need a strong balance sheet so that you can withstand the low phases of the cycle and we have that. And then we think that you need to prioritize returns of capital to the shareholders to get them a real return and to instill capital discipline and that's what we are doing. So, I think that we have the portfolio, the strategy and the commitment to deliver all of the things that are required for a company in our industry to win in this more cyclical and volatile future. So, thanks for your interest and your questions. Thank you, everybody, and feel free to call back if you have any follow-up. Thank you. Thank you, Christine. Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.