Welcome to the third quarter 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. 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&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 10th. We also plan to host a conference call in conjunction with that release. 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. 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. If you turn to page two, you'll see our safe harbor language. We will make some forward-looking statements this morning. The risks and uncertainties in our future performance are described on this slide, and also with our periodic filings with the SEC. Finally, once again, during Q&A, we'll limit questions to one plus a follow-up. That way, we can hope to get everybody through the queue within our planned hour. Now I'll turn the call over to Jeff.
Thank you, Ellen. 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. We're taking aggressive actions across our business to position for low and more volatile oil prices in the future. These actions, plus our unique portfolio characteristics, are the keys 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. 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. 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.
With that said, let's dive into the quarterly results, starting on slide four. The key theme for the quarter is the underlying business continues to perform very well. We produced 1.554 million 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've brought six major projects online so far this year, and we expect to deliver cargoes from the seventh, 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 $1.3 billion. 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 $1.3 billion is more like $1.6 billion. 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, U.K., and Malaysia business units. These three business units had 40,000 barrels per day of lower production in the third quarter compared to the second quarter. These turnarounds are now complete, and the high margin oil-weighted production from these business units will return in the fourth quarter. Operating costs were down 18% when adjusted for special items, and we'll talk about that more in a minute.
We ended the quarter with $2.4 billion 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. Now let's look at our financial performance on slide five. The story for earnings is weak commodity prices. Realized prices were down 16% sequentially and 49% on a year-over-year basis. As a result, we reported an adjusted loss of $466 million or $0.38 a share.
The lower commodity prices were partially offset by higher volumes and lower operating costs after adjusting for special items. Third quarter adjusted earnings by segment are shown in the lower right side of this 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. It was a tough quarter financially, but the underlying business performance remains strong. Moving to slide six, I'll cover our production results. Our third quarter production from continuing operations including Libya averaged 1.554 million 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. 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 $5.1 billion of cash. Through September, we generated $5.8 billion from operating activities excluding working capital. Working capital over this period was a $600 million use of cash. Through three quarters, we received $600 million in disposition proceeds. As we mentioned, 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.
We said before, you should expect us to generate $1 billion to $2 billion per year as part of our routine high grading process. We increased debt by $2.4 billion during the second quarter but added no debt in the third quarter. Through the third quarter, we've spent $7.9 billion in capital, paid our dividend, and ended with $2.4 billion of cash on the balance sheet. We believe we're in strong shape financially. Between cash on hand, debt capacity within a single A credit rating, and expected asset sales proceeds, we have the means to manage through the current period of low prices. That's a pretty quick recap of the financial results for the quarter. I'll turn the call over to Matt, who'll go through the operational performance and close with a 2015 guidance update. What you're going to hear is we're driving positive momentum in the business.
All things equal, these steps we're taking should drive improved 2016 earnings and cash flow. 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 will now quickly run through the segment results, then we will move on to your questions. Let us start with slide nine. In the Lower 48, third quarter production averaged 551,000 BOE per day. That is 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 are currently running 13 rigs in the Lower 48, six in the Eagle Ford, four in the Bakken, and three in the Permian, one of which is in the unconventionals. We are delivering more for less across our programs. In fact, we are seeing 20%-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 three unconventional plays was 249,000 BOE per day this quarter. That is an increase of 28,000 barrels versus the third quarter last year, but a decrease of 6,000 barrels a day sequentially. As we forecasted, given our current level of rig activity, production from these plays plateaued in the third quarter, and we would expect to see a modest decline in the fourth quarter. 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, while we also progress possible monetization options. This is important for protecting the value we have created from our existing program.
In the Gulf of Mexico, we had encouraging results from the recent Shenandoah appraisal well. We are currently drilling the Vernaccia and Gibson exploration wells, and we expect 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 Surmont 2 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 150,000 BOE per day. We spudded the Cheshire exploration well offshore Nova Scotia this month, and that is the first of two exploration well commitments. Let us 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 third quarter due to lower planned downtime. We successfully completed several major project turnarounds during the quarter at Prudhoe and Kuparuk. We recently achieved two key project milestones with first 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. We are seeing the benefits of project activity that will help to keep our Alaska production relatively flat for the next several years. We completed our sixth cargo export program from Kenai in 2015 with the last cargo delivered in October, and we applied for a license from the DOE to continue our export program in 2016. Moving to Europe, third quarter production averaged 192,000 BOE per day.
We had several major turnarounds across the U.K. that were all completed successfully, and we're continuing development drilling at Ekofisk South and Eldfisk II in Norway. 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. It's a 10% increase from the same period last year, driven by Gumusut and increased ramp gas from APLNG. In Malaysia, Gumusut underwent its first major turnaround, which was completed ahead of schedule. In Australia, we expect APLNG Train 1 to deliver its first cargo in the fourth quarter. 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 six-well exploration and appraisal program starting now and extending into next year. In Libya, production remains shut in as a result of the ongoing regional instability. 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're 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 seven major project startups this year.
We expect to achieve fourth quarter production of 1.585 million-1.625 million BOE per day, and that puts our full year 2015 guidance range at 1.585 million-1.595 million BOE per day. As the chart shows, this represents 3%-4% growth from continuing operations excluding Libya, up from the 2%-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 $10.2 billion. That's a 40% decrease from 2014, an 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 $8.2 billion for 2015, and that's a 15% reduction compared to 2014. You'll remember in April, we set a target to reduce operating costs in 2016 by a billion dollars compared to 2014. What our revised 2015 operating cost guidance represents is an acceleration of this effort. In fact, we've now exceeded our $1 billion target and 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&A reductions, new operating philosophies, and supply chain efficiencies. We're not done yet.
We're also changing our full year corporate segment guidance to a net expense of $800 million. 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. We're further reducing our planned 2015 capital spending. We're accelerating reductions in our operating costs and are on track to exceed our cost reduction target in half the time we expected. Finally, we're in very strong shape financially. 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 operating plan for 2016 in December.
Now I'll turn the call back over to you for Q&A.
Thank you. Ladies and gentlemen, if you have a question, please press star then one on your touchtone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star one on your phone now. 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, 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. While this could be a blip in the data, it could also be that technological limits are being reached by some, and that science might play a greater role in recovery rate capture in the future. 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. Also, based on your experience and with your credentials, where do you think we are in understanding of the shale resource overall?
Doug, I think from our perspective, the sweet spots really matter. You're going to get the best performance out of the sweet spots, and you're probably right that people are focusing there just now with a limited number of rigs running. I wouldn't say that our perspective is that we've reached any sort of technological limit. We're continuing to see encouraging results from our pilot tests on different well spacings. We're continuing to run our stimulated rock 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. Even in the Bakken, we're moving from open hole slide and sleeve completions to cemented liner and plug and perf, and we're seeing improvements there from our pilot tests. From our perspective, we're not seeing ourselves hitting any technology limit yet.
Okay, Matt. Don't disagree with that, but it seems like the industry may be slowing down somewhat. 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?
Yeah, we see that in other people's individual well performance.
I'm not quite sure what to attribute that to, Doug.
Okay. Thanks a lot.
Thank you. Our next question is from John Hirjee of Societe Generale. Please go ahead.
Yeah. Hi. I know you're going to announce your CapEx budget for next year on the 10th of December. From a portfolio management perspective, is it safe to say that you're focusing more on short- and intermediate-term type projects, and deferring kind of the longer term type business?
Well, really what's going to happen for us, John, is that as we move from 2015 into 2016, we're seeing about $2 billion of major project spend roll off as we complete, in particular, Surmont and APLNG. We have a choice as to what to do with that, 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. 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 in concept du jour is to accumulate uncompleted wells. Is that part of your MO?
No, it's not. Our view is that if you don't want to complete the wells, don't drill them. 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. That's just the sort of natural course of executing a program. It's not a deliberate choice to drill wells and not complete them.
Thanks, Matt.
Thanks.
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, I guess there's a curious statement in the release about disposals, Matt. 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. 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 at once you get those big projects online, and what's the likely timeline to see some movement on the asset sales?
Yeah, Doug, it's no secret that we've got several non-core assets on the market, including the North American gas assets. We're not ready to give details of those at this time. We are going to give some more detail in December. What you should expect is something of the order of $1 billion-$2 billion annually. We are going to give you more detail in December. 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? One year or five 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 billion-$2 billion a year. Annually, yeah.
My follow-up, Jeff, maybe on cash flow. It looks like 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. Can you just 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 round of cost reductions? I'll leave it there. Thanks.
On the affiliate level, we really have three major equity affiliates. You have the Foster Creek/Christina Lake oil sands joint venture, the APLNG project in Australia, and the QG3 project in Qatar. Of those three, two of them are still in a fairly heavy investment phase. For APLNG, we don't get any cash distributions out of there. It's all retained to cover capital. In FCCL this year, it's the same kind of story. 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 and 2017 with the startup of APLNG and as additional phases, and we would assume some price recovery happens for Foster Creek and Christina Lake, we expect that we would see distributions coming out of all three of those joint ventures.
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, 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. There's not really just one commodity price number that we point out as what it takes for us to get to cash flow neutrality in 2017.
Nothing specific this quarter has caused the cash flow to lag?
Well, we had some unique effects this quarter. If you look at the $1.3 billion of cash from operations before working capital and the $1.9 after working capital. The $1.9 of after working, we had $600 million 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. When we made the comment as we went through the slides, that you should think about that $1.3 being more like $1.6, it's taking account of the impact of just those special items. As we also pointed out, the third quarter is always a weak cash flow quarter for us because it tends to be the quarter when we have the most turnaround activity.
In this quarter, we lost about 40,000 barrels a day roughly in our Malaysia, our U.K., and our Alaska business units because they're the ones who went through turnaround. That is pretty heavily weighted to oil production. 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. 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 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 at the current activity levels, the expectations production is starting to slide a little bit. Is that true if we remain in this somewhat $45, $50 environment? More direct, what price would allocate more capital to those areas?
If we stay at our current level of rigs in the Eagle Ford and Bakken, we would expect to see some modest decline. For example, if we go from this year into next year and we don't increase rigs, we'll see 3%-5% decline on our production in the unconventionals. We're going through the process of setting our operating plan and budget for 2016. We'll give you a lot more detail on what we actually decide to do with that rig count at that time. Just as a sort of reference, if we stay at the current rig rate, it'll be a 3%-5% decline in our unconventional production.
Okay, appreciate that. That's good color. One other thing on, I guess, the sales goals. Jeff, rather than trying to be too specific as far as what you're selling and timing on it, 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 a cash flow deficit to keep a strong dividend? 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 which someone else would value more highly than we do. 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. When someone who might be more willing to fund that capital, would they have a different value perspective on those? 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.
Hoping you could just address the major project performance how those projects are ramping up relative to expectations. Specifically, if you could just remind us of the incremental production from those projects' latest view in 2016 and 2017. Just trying to understand that base level of growth that's coming on as the CapEx begins to decline.
The major projects are ramping up. Gumusut-Kakap is coming in now at expectations. We've had the turnaround there that I mentioned, which has allowed us to get the gas injection established. It's ramping up. It's getting close to full capacity. APLNG is ramping up gas in anticipation of having the LNG plant full for the first train. Surmont is literally just started producing oil in September, that's going to gradually ramp up over the next 12 to 15 months. If you just looked at those three projects alone in aggregate by 2017, we're probably looking at 150 or so thousand barrels a day of incremental production from those three projects. Maybe 120 because Gumusut-Kakap is already there.
That's helpful. Thanks, Matt. 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. Do you have flexibility to slow your offshore development CapEx next year, the year after? Is that something that you would consider in this environment at this point in time?
We have announced that we're going to be exiting deepwater exploration, although we do have quite a significant program that we're executing next year. Development of the discoveries that we have in deepwater is quite some way off. We may choose to stay with those developments, we may choose to exit before development happens. Really what we're in just now is in a ramping down our exploration commitments and continuing appraisal on the existing discoveries. We're not at a development stage yet.
Thanks for that.
Okay. Thanks, Guy.
Thanks, Guy.
Thank you. Our next question is from Phil Gresh of JP Morgan. 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 million in CapEx on the base level spend. If this happens, the equity affiliate source of cash for you guys will be lower. 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 Surmont to the extent your partner wants to move forward on this.
We obviously engage in the budgeting process with our partner there, and that's a pretty collaborative process. 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 rather than taking distributions out. Those are good projects at Foster and Christina. We'll have a good discussion at the management committee on what the right pace is to develop those. 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. Yeah, 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.
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. We've been at a period where we've had low commodity prices and pretty wide differentials. The net result has been some pretty weak realizations. There's quite a bit of leverage to increases in prices that can happen there as well. You've got 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. My follow-up is just on 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. It's not really associated with major project acceleration. It's more an indication of the performance of our base and the managing our base decline and the performance that we're getting from our new development wells across the portfolio as a whole.
Sure. Okay. Thank you.
They're on the turnarounds.
Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead.
Hi, guys.
Hello, Paul.
Hello, Paul.
You've done a tremendous amount this year, as shown on the slides. When we look at it at, let's say, $50 oil this year, you've made about, it looks like, a run rate of about $8 billion 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? 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, they're not going to be largely different than what you've seen currently. We're also going to, in December, be giving 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.
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, and 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 in the 2017 timeframe within the capacity that we have on our balance sheet.
Yeah, 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, yes
since you last updated. I'll go with a follow-up, which is kind of related. 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 billion-$2 billion a year. I would assume that that's a phased exit, which will sort of be a one-way street. Once you've left, you'll be gone. 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 heading in the right direction here in terms of how you're looking at this? Thanks.
Yes, that's right, Paul.
Can you just remind us how big your position is in the Gulf of Mexico? I know it's top three.
In the Gulf, we've got about 2.2 million acres in the Gulf and three existing discoveries. Our intention is to not be doing deepwater exploration by 2017. Those acreage positions that we hold that we don't intend to drill, we'll be marketing those positions.
Yeah, understood. That becomes then, as I said, you sort of agreed, I hope I didn't trap you, that that becomes a one-way street. Effectively, over time, you're simply leaving the deepwater and won't come back.
No, 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.
Hello.
Hello, Paul.
Jeff, I think maybe several months ago that you and Matt talking about to sustain your operation is about $8 billion, which was down from $9 billion, say maybe from last year. Are we still talking about $8 billion, given that you actually accelerate your cost reduction and everything, or that this number is now $7 billion or $7.5 billion?
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 billion, but it's in that same kind of range.
Okay. That maybe this is for Matt, that you're currently running about 13 rigs, and you're saying that the fourth quarter production will be modestly down. My guess is that what is the number of rigs that you think you need in order to hold the production flat? And what kind of CapEx required to have that kind of progress?
To keep Eagle Ford production flat probably requires between seven and eight rigs. Currently, we're running six. The Bakken requires closer to five rigs. We're currently running four. You'd be looking at maybe three additional rigs to maintain production flat. If you look at sort of all-in cost, drill complete, hook up, and so on, you can use an order of magnitude of $150 million.
Per rig line.
Additional $150 million.
Great.
No, per rig line per year. Maybe $400 million. 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.
Morning. Can we come back around on the Gulf of Mexico or just deep water in general? You mentioned earlier on the call you'd had the further appraisal on Shenandoah. Should we think of the exit of exploration also including the exit of not yet developed, but partially explored?
Possibly, only if we get full value for it. We're willing to stay in our discoveries if that's what maximizes the value. We haven't made a commitment to exit deep water per se, deep water exploration. If we saw full value for those assets, then we'd certainly consider that.
Okay. Can you give us an idea of what the capital flexibility is once you're away from deep water exploration or any other type of exploration you're not planning to do by 2017? 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. As we look at the total CapEx number, sort of as a starting point for when you talk about it in December, where we can see that CapEx flexibility that could come back into the shale plays in future years?
To give you a bit of a preview of the 2016 budget, we expect to spend about $800 million in 2016 in the deep water exploration and appraisal space. That's the order of magnitude on the capital side that we wouldn't be spending if we weren't doing deep water exploration and appraisal for one year. There's the G&G and G&A associated with that as well.
That number Matt noted is a fairly consistent number with what we're spending there in 2015 as well.
Yeah.
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 high level, more philosophic question on the 2016 capital plan ahead of getting the details. One is simple. What sort of price deck 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. 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. 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?
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 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 and the dividend, we'll be looking to increase debt. It's just the mechanic of what's going to end up happening for us.
Yep.
As we said, as we look at the amount of debt that we might need to raise even in some continuations 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 Fernandez of Howard Weil. Please go ahead.
Folks, good morning. I had two questions, if I could first just confirm, Ellen, the December 10th capital 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 until April to see the details of what our current year plan is. 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. Seeing how those are two 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 or earnings per share?
I don't have that.
Yeah, I don't have that off the top of my head. We could
That's fine. That's fine. Maybe I can follow up with the
We can come back to you.
Yeah, we can come back to you on that.
No, not a problem. I'll get back with Sid on that. The last one is just more of a broader picture question, I guess. 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 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&A opportunities instead of a pure dividend payout?
We've been pretty consistent since we started ConocoPhillips as an independent E&P, that we thought the way to create value in the business was a combination of moderate growth and 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. The key to dividend is to have it be consistent and to grow it over time. 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. 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 proposition.
Okay. Thanks a lot, Jeff.
Thanks, Blake.
Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead.
Good afternoon.
Hello, Neil.
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. Any thoughts on the LNG markets broadly? There has been some investor concern around Sinopec and the APLNG contracts. Just any updated thoughts there? Anything you could say that can help investors get comfort around that risk?
Yeah. Clearly the short-term LNG market is pretty weak. 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, APLNG, that's a take-or-pay contract. Sinopec have the right to divert cargoes within China. We've also given them the right to divert cargoes outside China. It is a take-or-pay contract, and with a price formula that's tied to oil. We've got no reason to believe that there's any issue with that contract. Sinopec, in fact, is a 25% shareholder in APLNG on the upstream project. We don't have any concerns, if that's what you're indicating about the sanctity of that contract.
All right. Terrific. 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 $8.9 billion to $8.2 billion? On the CapEx side, from $11 billion to $10.2 billion, what are all the cats and dogs there?
We just put it in 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'd 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. 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 took the first increment of our guidance down.
That's great. One last question from 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. People are adjusting their capital programs where they have the flexibility to do that. That will be things like infill drilling where they have rig contract flexibility. People are exercising operating cost flexibility, too, which means less workovers, less spinning spares and so on. Over time, that's going to materialize in the non-OPEC, non-U.S. production. Exactly when and to what magnitude is hard to tell. It's 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 billion-$2 billion. Probably there were some disposals in your prior plan to get to 1.7 million barrels a day. Can you just give us a sort of maybe an endpoint kind of impact that it might make as you reshape the outlook?
The 1.7 million barrels a day in 2017 that we talked about in April, there was no assumption of dispositions in that.
Okay.
We would make an adjustment when we know exactly what assets are moving out of the portfolio. We're not ready, Ed, to give you a number yet because we don't know exactly which of the mix of assets that we have on the market are actually going to achieve an acceptable price. We will give you some more indication of where that's heading, hopefully by in December, but it's too early for us to do that now. That's one of the reasons we really don't talk about the dispositions until they close. You can't know exactly which of the assets that are being considered for sale are actually achieving the price that they need to make it acceptable for us to sell them.
Okay. 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. 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 billion 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.
We have this 44 billion barrel resource base that we've described in some length in April. The 18 billion of that has less than a $60 cost of supply. 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?
Sure. Okay.
The point is that 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.
Hey, thanks. Good afternoon, everybody. Maybe if I could talk a little bit about CapEx. The run rate in the third quarter of $2.2 billion, annualized at an $8.8 billion run rate. How should we think about, maybe this is too much preview, how should we think about moving pieces into 2016? 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'll be cycled in the short cycle, much of that rolling off by this point? 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. I think the easiest way to think about it, Ryan, is the $2 billion 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. I wouldn't get too hung up on the run rate in the third quarter, more think about it as that sort of amount of major project capital rolling off from 2015 to 2016.
Okay. Thanks. I guess a follow-up on a couple questions ago in terms of the operating cost reductions. You've been well ahead of schedule with the $1 billion respectively in one year. If you think of that $1.5 billion, how much of that is kind of structural versus cyclical? As you look forward into 2016, I guess on the cyclical portion, do you have any thoughts on which way it cycles, 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. To answer your question, you kind of have to answer that in context of a price level. 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, it may also mean that we continue to have a fairly strong US dollar. I don't know where you draw the line between cyclical and structural, 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.
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 as things that we're doing within the way we operate the business, which are kind of more structural in nature.
Do you think there's more to I guess on the non-cyclical side, do you view there as being more to go still in 2016, or have you pulled forward the lion's share of what you thought you'd be able to achieve?
We've 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.
Great. Thanks a lot, gentlemen.
All right. Thank you.
Thanks, Ryan. Thank you. Our next question is from Evan Calio of Morgan Stanley. Please go ahead.
Hi, good afternoon, guys. Thanks for squeezing me in here at the top of the hour. It's a philosophical question more on total returns. I know you guys have made significant CapEx cuts and outpacing deflation. Yet 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? 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.
Yeah, I'm not sure if I followed your question, Evan. If you think about it 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. 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.
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. 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. What's the cost as it relates to those sales in regard to the longer-term outlook of either growth or asset value? I'll leave it at that.
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. 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. 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, 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. Thanks.
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 was being sold as LNG under your contracts?
Chris, do you like the quick?
Yeah, I don't have that off the top of my head. James, you're right. The ramp gas, as we're building up to fill Train 1, is getting sold at domestic prices, essentially.
Yeah.
The net back 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. I don't have that number off the top of my head.
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 sell into the North American gas market. There's a pretty significant uplift, even in the current oil price market, to move that to LNG.
Right. Yeah, because I was just trying to see whether it was a lot lower or if there was a contractually lower rate or anything like that. 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-A drilling. Can you guys give a little update there? I know Greater Moose's Tooth, some of these are longer dated projects, but what the timeframe and potential impact of some of those projects are, and I'll take offline after that.
Yeah. We announced the first production from the NPR-A from the CD5 project. It started just a week or so ago, less than a week ago. We did get approval from the government for the permits that we need to develop the GMT1 prospect, so the first prospect inside the Greater Moose's Tooth unit. We're working through the process of deciding the sanction of that project. 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. 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 ConocoPhillips, we're focusing on what we can control, and that's our production, our capital, and our operating cost. As we outlined today, we're moving all of those quickly in the right direction. We're 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 a 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 project, so it can add to the 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. 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. We think that you need to prioritize return of capital to the shareholders to give them a real return and to instill capital discipline, and that's what we are doing.
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. 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. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.