Ellen DeSanctis - VP-IR and Communications Jeff Sheets - EVP, Finance & CFO Matt Fox - EVP, Exploration and Production

Doug Terreson - ISI Group John Herrlin - Societe Generale Doug Leggate - Bank of America Merrill Lynch Scott Hanold - RBC Capital Markets Guy Baber - Simmons Phil Gresh - JPMorgan Paul Sankey - Wolfe Research Paul Cheng - Barclays Capital Roger Read - Wells Fargo Securities Bob Brackett - Sanford Bernstein Blake Fernandez - Howard Weil Incorporated Neil Mehta - Goldman Sachs Edward Westlake - Credit Suisse Ryan Todd - Deutsche Bank Evan Calio - Morgan Stanley James Sullivan - Alembic Global Advisors

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, 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&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 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 will 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&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. And now I will turn the call over to Jeff.

Thank you, Ellen, and thanks everyone for joining our call today. Before reviewing the quarter, I will make a few brief comments about how we're addressing the current low commodity prices 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 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 plans 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 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 megaproject, 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 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 is $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. So about what you'd expect in this price environment given the impact of higher cost and lower production related to turn-around 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 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. And 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. So now let's look at our financial performance on Slide 5. 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 the $0.38 share. The lower commodity prices were partially offset by higher volumes and lower operating cost after adjusting for special items. Third quarter adjusted earnings by segment are shown on 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 Web site. So it was a tough quarter financially. But the underlying business performance remains strong. Moving to Slide 6 I'll cover our production results. Our third quarter production from continuing operations excluding 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. Now if you will turn to the next slide I will 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 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 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 was 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 we're driving positive momentum in the business. All things equal these steps we're taking should drive improved 2016 earnings and cash flow. So I will turn it over to Matt.

Thanks, Jeff. As Jeff mentioned we performed very well this quarter operationally. We successfully completed several major turnarounds, continue to bring major projects online and exceeded our production targets. I will now quickly run through the segment results and then we will move on to your questions. So let's start with Slide 9. In the lower 48 third 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, six in the Eagle Ford, four in the Permian, four in the Bakken and three in the Permian, one of which is in the unconventionals. And we're delivering more for less across our programs. In fact, we have seen 20% to 30% lower drilling and completion costs compared to a year ago. About half of that’s 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's 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 from production from these plays plateaued in the third quarter and we'd 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're continuing to fund activity based on existing commitments while 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 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's the first of two 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 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 keep 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. So we're seeing the benefits of project activity that will help to keep our Alaska production relatively flat for the next several years. We completed our six 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 UK that were all completed successfully. And we're continuing development drilling at Ekofisk South and Eldfisk II in Norway. Now I'll cover the Asia-Pacific and Middle East and other international segments on Slide 11. In the AP&ME 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 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. On the downstream project, all the mechanical runs are complete. And on 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. And in Libya, production remains shut-in 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'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 to 1.625 million BOE per day. And that puts our full year 2015 guidance range at 1.585 million to 1.595 million 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 $10.2 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 remember in April, we set a target to reduce operating costs in 2016 by $1 billion 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 billion target in half the time. About half of 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. And we're not done yet. We're also changing our full year corporate segment guidance to a net expense of $800 million 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'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. And finally, we're in very strong shape financially. So we're 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. So now I will turn the call over to you for Q&A.

Thank you. [Operator Instructions] And our first question is from Doug Terreson of Evercore ISI. Please go ahead.

Good morning, everybody. In U.S. unconventional in that arena industry productivity gains were pretty significant in recent years but more recent data indicates that we have had a slowdown even though company 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 technological 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 the shale resource overall?

So Doug I think 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 are just now 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. 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. And even in the Bakken we're moving from open hole slide and sleeve completions to cemented liner and plug-n-perf. We're seeing improvements there from our pilot tests. So from our perspective we're not seeing ourselves in any technology limit yet.

Okay, Matt. So I don't disagree with that but it seems like the industry may be slowing down somewhat. 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?

We see that in other people's individual well performance. But I'm not quite sure what to attribute that to.

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 of December but from a portfolio management perspective is it safe to say that you're focusing more on short and intermediate term time projects or and deferring kind of a longer-term type business?

Really what's going to happen for us John is as we move from ‘15 into ‘16 we're seeing about $2 billion 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 and hold onto 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. Ducks you're hearing a lot of companies now say the 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 well don't drill them. So we don't have a strategy to drill wells and then 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. It's not a deliberate choice to drill wells and not complete them.

Thank you. Our next question is from Doug Leggate of Bank of America/Merrill Lynch. Please go ahead.

Thank you. Good afternoon everybody. I've got a couple of questions also if I may. First of all, on I guess there was a curious statement in the release about disposals, Matt. And 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 at once you get those big projects online and what's the likely timeline to see some movement on the asset sales?

Doug, I mean it's no secret that we've got 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 to $2 billion 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 means 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 to $2 billion a year. So annually, yes.

My follow-up is on Jeff maybe on cash flow. It looks like cash flow was operating cash flow was a little weak this quarter and I'm trying to decipher what was going on at the affiliate level. And thinking about your $60 cash breakeven by 2017 and obviously the cost reductions announced today, so 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? And I will 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. So for the 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 a 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. 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, 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 as what it takes for us to get to cash flow neutrality in 2017.

So nothing specific this quarter that's caused the cash flow to lag?

Well, I mean we had a unique effect this quarter if you look at the $1.3 billion in cash from operations before working capital and $1.9 billion after working capital. $1.9 billion of after working we had $600 million of working capital impact. 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 slide -- as we went through the slides you should think about that $1.3 billion being more like $1.6 billion. It's taking account of the impact of just those special items. And as we also pointed out this is, the third quarter always is a weak cash flow quarter for us because it tends to be the quarter where we have the most turnaround activity. In this quarter, we lost about 40,000 barrels a day roughly in our Malaysia, our UK and our Alaska business units because they are 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 are 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.

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

Just a couple of questions for me as well, little more specific on some of the unconventional U.S. resource plays, you know the Eagle Ford and Bakken it sounds like at the current activity levels the expectations is production is starting to slide a little bit. Is that true if we remained in this somewhat $45, $50 environment and 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. 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 little more detail on what we actually decide to do with that rig count at that time. But just as a sort of reference if we stay at the current rig rate it will be 3% to 5% decline in our unconventional production.

Okay, I appreciate that. Good color. And one other thing on I guess the sales goals, Jeff rather than try 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 a cash flow deficit to keep a 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. If you think about it a portfolio of our size we're always going to be in the process of trying to find the assets someone else wouldn't value more highly than we do. So as we've talked about its 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. 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.

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

Good afternoon everybody. I wanted to dive into the production the little bit, but hoping you could just address the major project performance, how those projects a ramping up relative to expectations? And 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.

Yes, so the major projects are ramping up. And Gumusut is coming in. The expectations we've had the turnaround there that I mentioned which has allowed us to get the gas injection established. And so it's ramping up and getting close to full capacity. APLNG is ramping up gas in anticipation of having the LNG plant full for the first train. Surmont has really just literally just started producing oil in September. And that's going to gradually ramp up over the next 12 to 15 months. So if you just looked at those three projects alone in aggregate by 2017 we're probably looking at 150,000 or so barrels a day of incremental production from those three projects, maybe 120 because Gumusut is already there.

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?

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 and we may choose to stay with those developments but we may choose to exit before development happens there. So really what we're in just now is a ramping down of exploration commitments and continuing appraisal on the existing discoveries. We're not at a development stage yet.

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

Good afternoon. First question is just on the equity affiliates again. In the oil sands your partner on FCCL noted that they are contemplating restarting some of the project phases in 2016 that could add up to another 500 million in CapEx on the base level of spend. So as this happens the equity affiliate source of cash for you guys would 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 Surmont 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. 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. And those are good projects at Foster and Christina, so we'll have a good discussion at the management committee on what the right pace is 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. But 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 are 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 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've got what is probably price increases happening both on the differential and the flat price side and increased production that's going to provide more capability to fund increased investment as well.

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?

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 we're getting from our new development wells across the portfolio as a whole.

Sure, okay, thank you.

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

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 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? 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 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 cost 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 cash flow neutrality balance still within the 2017 time frame within the capacity that we have on our balance sheet.

Yes, I guess what I'm driving at is it feels like that price, the price of oil required for that has come down over the course of the last year, since your last update. I will 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 billion to $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 and I would also anticipate 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? Because I know it's top three.

In the Gulf we've got about 2.2 million acres in the Gulf and three existing discoveries and 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. This is a strategic decision to leave -- to exit deepwater exploration. That's exactly right.

Great, that's very clear. Thanks, guys.

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

Just 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. So are we still talking about $8 billion given that you have actually accelerated 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 smaller than $8 billion. But it's in that same kind of range.

And maybe this is for Matt. You are currently running about 13 rigs and you're saying that the third quarter production -- the fourth quarter production will be modestly down. So 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 requires that you have that kind of program?

So to keep Eagle Ford production flat probably requires between seven and eight rigs. Currently we're running six. The Bakken requires about closer to five rigs. We're currently running four. So you'd be looking at maybe three additional rigs to maintain production flat. And if you look at all-in cost, drill complete hook-up and so on you can use an order of magnitude of $150 million.

An additional 150 million?

No, per rig line per year. So maybe $400 million.

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

I guess come back around on the Gulf of Mexico or just deepwater in general you mentioned earlier on the call you had a further appraisal in Shenandoah. Should we think of the exit of exploration also including the exit of not yet developed but partially explored?

Possibly but only if we get full value for it. We're willing to stay in our discoveries if that's what maximizes the value. 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 ‘17? And then if I understood correctly it doesn't sound like the oil sands necessarily gets incremental CapEx and we can presume that there is not another LNG project. So as we look at the total CapEx number sort of as 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 in to 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 million 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 one year. And then there's G&G and G&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.

Thank you. Our next question is from Bob Brackett of Sanford Bernstein. Please go ahead.

Hi, I've got 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 stick would you be looking at in terms of thinking about your cash flow from operations next year?

We don't have one price stick 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 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 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 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.

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

Good morning. I had two questions but if I could first just kind of 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. So at this point you can count on December being a pretty big update on the company's plans and programs for the year.

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 two 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, whether those are actually accretive to net income or earnings per share?

I don't have that off the top of my head.

That's fine. That's fine. Maybe I can follow up with…

Yes, we can come back to you on that

Not a problem. I will get back with side on that. The last one is just kind of 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 call it mid-80s down into the 50s, is there any consideration whatsoever to maybe shift that ratio towards maybe a buyback program or even toward capturing M&A opportunities instead of pure dividend payout?

We've been pretty consistent. Since we started ConocoPhillips as an independent E&P, 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. But the key to a dividend is to have it be consistent and to grow it over time. So we haven't really had significant discussion to talk about trying to adjust the 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 proposition.

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

So I want to start off on the LNG market, 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 can say that can help investors get comfort around that risk?

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. But with respect to the Sinopec contract at APLNG, so 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 but as a take-or-pay contract and with a price formula that's tied to oil. Then we have got no reason to believe that there is any issue with that contract. Sinopec in fact is a 25% shareholder in APLNG on the upstream project. So we don't have any concerns if that's what you're indicating about the sanctity of that contract.

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 $8.9 billion to $8.2 billion and then on the CapEx side from $11 billion to $10.2 billion where are all the cats and dogs there?

We just put it in kind of broad categories. Like 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, 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 in 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. And one last question from me. You guys have the advantage of seeing the world when it comes to oil production. Curious on your views and 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. And the people are adjusting their capital programs where they have the flexibility to do that. So that will be things like infill drilling where they have rig contract flexibility. People are exercising operating cost flexibility, too, which means less work-overs, less spinning spheres and so on. So over time that's going to materialize in the non-OPEC non-U.S. production, but exactly when and what magnitude is hard to tell, that is coming.

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

Couple of quick ones, disposals $1 billion to $2 billion, probably there was some disposals in your prior plan to get to 1.7 million 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?

The 1.7 million barrels a day in 2017 that we talked about in April there was no assumption of dispositions in that. We would make an adjustment there from when we know exactly what assets are moving out of the portfolio. And we're not ready 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 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 are being 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 which 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 billion at the low end as the CapEx drops out what reserve replacement looks like say 2017 onwards or what are the big sources that 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, so there is lots of sources to continue to convert that resource base and the reserves as we go through the next few years. Is that the question you were getting at, Ed? So 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.

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, so annualized at an $8.8 billion run rate. How should we think about, maybe this is too much preview, but how should we think about moving pieces into 2016? Is that 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 into short cycle or is 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 go into next year. So 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. So I wouldn't get too hung up on the run rate in the third quarter but more think about it as that sort of amount of major project capital rolling off from ‘15 to ‘16.

And then I guess a follow-up on a couple of questions ago in terms of the operating cost reductions. You've been well ahead of schedule with the $1 billion over two years turning into $1.5 billion effectively in one year. How much of that I mean if you think of that $1.5 billion, 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, 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've got to answer that in the context of our 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, it may also mean that we continue to have a fairly strong U.S. dollar. So I don't know where you'd 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 is more I guess on the non-cyclical side is there do you view there as being more to go still in 2016? Or have you pulled forward the line 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.

Our next question is from Evan Calio of Morgan Stanley. Please go ahead.

Good afternoon guys. Thanks for squeezing me in here at the top of the hour. It's a philosophical question more on total returns. And I know you guys have made significant CapEx cuts 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, so that I mean I guess the risk is that dividend yield merges with total shareholder return type of metric in the future?

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. 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 will leave it there, so 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 the security of the dividend at most prices but 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 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 nonstrategic assets which we 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. Thanks, guys.

We don't feel like we're 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.

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 notice 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 contracts?

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. 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 at the top of my head.

But 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 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.

Because I guess it was just trying to see whether it was a lot lower or if there was 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 that 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 Mooses Tooth some of these are longer dated projects, but what the timeframe and potential impact for some of those projects are? And I will take it off-line after that.

Yes so we announced that the first production from the NPR-A from the CD5 project 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 Mooses Tooth unit. And we're working through the process of deciding the sanction of that project but that sanction decision hasn't been made yet.

Thank you. I will now turn the call back over to the company for closing comments.

Okay, 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 focused on what we can control and that's our production, our capital and our operating cost. As we outlined today we're moving all those quickly in the right direction. But 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 us stable source of funding to sustain the dividend and we have that. We think you want a large low cost 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 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 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 return of capital to the shareholders to get them a real return and to install 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.