Welcome to the Fourth Quarter 2014 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, Vice President, Investor Relations and Communications. You may begin.

Thanks, Christine, and greetings to everybody. Joining me in the room today are Ryan Lance, our Chairman and CEO; Jeff Sheets, our EVP of Finance and Chief Financial Officer; and Matt Fox, our EVP of E&P. Really three quick very administrative points before we launch into our remarks here, we will make some forward-looking statements this morning. The risks and uncertainties in our future performance are covered on page two of today’s deck and in our periodic filings with the SEC. This information can also found on our website. Next, if you haven’t done so, save the date for our 2015 Analyst Meeting on April 8th in New York City. We will be providing some additional logistical details on that event soon. And then, finally, during Q&A this morning, we are going to limit questions to one with a follow-up, so we can accommodate the call queue, we appreciate your support there. So, now let me turn the call over to Ryan.

Thank you, Ellen, and thanks to all our call participants this morning. So I will start by making few quick comments about 2014. Then I will jump into our view of 2015 and the actions we are taking to manage through this current period of very low prices. Of course, we are also spending a lot of time thinking about the future beyond 2015. It’s bit early to talk about -- that today, but as Ellen mentioned, we will speak to that at our April Analyst Meeting, where we will be ready to address our longer term view of the sector and how we are positioned to succeed. So if you turn to slide four, this is our company level set in chart that we show during every quarterly call. Certainly, ’14 seems like old news, but I think it’s important to spend a minute recapping our results for the year. Operationally, we hit our volume targets and achieved 4% year-on-year growth and I think that’s pretty big accomplishment for a company our size. The growth came from the startup of five major projects, ongoing ramp up in the Eagle Ford and Bakken, and a successful turnaround season across our operations and we also discovered two new oil plays in Offshore Senegal. Financially, we generated $6.6 billion of adjusted earnings or $5.30 per share for the year. This includes fourth quarter adjusted earnings of $742 million or $0.60 a share. Obviously, reflecting weak fourth quarter prices. We ended the year with $5.1 billion of cash on the balance sheet and also exceeded our price normalized cash margin growth target with more than an 8% improvement. On the strategic front, we achieved a strong organic reserve replacement ratio of 124%. By the way the three-year average organic reserve replacement ratio is…

Thanks, Ryan. As Ryan mentioned, our full year 2014 adjusted earnings were $6.6 billion, our full year earnings slide is in the appendix, but I will quickly cover fourth quarter earnings. Fourth quarter 2014 adjusted earnings were $742 million or $0.60 a share. Our operational performance was overshadowed by a roughly 20% drop in realized prices compared to prior periods and a previously announced dry hole in Angola. Our segment breakdown of earnings is shown in the lower right with more detail provided in the supplemental data on our website. There is one special item to note, in the fourth quarter, an agreement to terminate our long-term obligations at the Freeport LNG terminal took effect. The ins and outs for the income statement and cash flow are shown in the appendix, but as a result of the transaction, the company anticipate saving about $50 million per annually over the next 18 years, so this was a good long-term economic decision. On slide eight, I will cover our 2014 production from continuing operations. We achieved two important milestones in 2014, namely, hitting our growth targets for production and margin growth. Our production growth for the year excluding Libya was 4% from 1,472 to 1,532 BOE per day. The impact from downtime and dispositions was small and compared to last year our net growth was over 60,000 BOE per day, primarily from liquids in area with favorable fiscals. We also achieved our cash margin growth target and that’s shown on slide nine. For 2014, we achieved an 8% cash margin improvement when normalized on 2013 prices. Despite lower prices, we are not going to lose our focus on cash margins and in fact, it’s as important as ever. Next, I will review our 2014 cash flow waterfall on slide 10. We started…

Thanks, Jeff. I want to begin my comments with a brief recap of 2014, beginning with the review of our reserve performance. These are preliminary numbers, but we don’t expect any material changes when the final reserves are published in our 10-K. We started the year with 8.9 billion BOE of reserves, repurchased 598 million and added 742 million organically. These additions came primarily from our Lower 48, APME and Canada assets. This resulted in an organic reserve replacement ratio of 124%. We also sold 159 million BOE, mostly from Nigeria and ended the year with 8.9 billion barrels of reserves. That represents a total reserve replacement ratio of 97%. Over the past three years, our total reserve replacement has averaged 129% and that’s after selling assets, which generated about $14 billion of proceeds. So let me put that all in perspective. We were launched as an E&P three years ago with 8.4 billion barrels of reserves on the books. Over that time, we’ve produced more than 1.5 billion barrels and sold over 400 million barrels and yet, we will exit 2014 with 8.9 billion barrels of high-quality reserves on the books. That’s pretty impressive for a company of our size. Now, I want to recap the 2014 operational highlights that contributed to our reserve performance and a 4% production growth. As Ryan and Jeff mentioned, we achieved our production growth target, both for the fourth quarter and for the year. Our base assets continued to perform well, with strong safety performance and successfully completed several major turnarounds across the portfolio. We achieved another strong year in the unconventionals, with 35% annual growth in the Eagle Ford and Bakken. We also conducted multiple pilot tests and progressed exploration and appraisal activities across our whole unconventional portfolio. And as a result…

Thank you, Matt. So let me recap what you’ve heard today. I think we delivered again in 2014. But certainly that was then and now it’s all about 2015 and it’s all about flexibility in Brazilians which we believe we have both. Our priorities are clear, dividend and cash flow neutrality. And we’re taking immediate actions to defend them. We’re cutting CapEx, capturing cost improvements and exercising our balance sheet if needed. And we’re also thinking about the timeframe beyond 2015. We’re asking ourselves what's changed in our industry, if anything for the longer term. We’re testing our portfolio under different scenarios and again we’ll see what -- we’ll see that we have a resilient portfolio with flexibility to adapt if circumstances warrant. Now some things might change, but here’s what’s not going to change. We’re going to allocate capital prudently. We’ll continue to migrate our portfolio to a lower cost of supply. We’ll maintain capital and financial flexibility and we’ll pay our shareholders first. That’s our formula for creating long-term shareholder value. And I look forward to seeing you and describing that in more detail in April in New York. So with that, now let me turn the call back over to the operator and we’ll take some Q&A.

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

Good morning, everybody. Thanks for taking my questions. Folks, I wonder if I could dig into the cash flow neutrality question a little bit because obviously the dividend is still a big commitment for you guys. When you separated Phillips, you -- I think Jim at that time had talked about maintenance capital level of around $10 billion to hold production flat. I guess what I'm trying to understand is to Matt's comments, obviously that was $100 oil. So one assumes that costs are going to drop at some point, but also had a slightly different portfolio and you've had a bunch of new projects come online a longer life or will come online rather. So what is that number today assuming -- as it stands today, and maybe assuming some cost reductions over time? And I've got a follow-up, please.

So I think the Doug, a number of $9 to $10 billion to keep production flat is a good go-by from that. It I mean, it clearly is going to be a function of how much deflation we see, this sustained deflation across the industry. And -- but the -- a number of that sort of magnitude is good go-by for the time being.

So, when you talk about cash flow neutrality, I don't know if this is either Jeff or Matt, but what commodity deck are you assuming when you think about that for 2017?

That might be a comment that Matt made about capital. That also depends on what kind of cost deflation we see in both capital cost and operating cost. We don’t expect that prices are going to maintain at current levels for that period of time. So we would be at cash flow neutrality at some improvement over current price levels but not at a level as high as what we’ve experienced recently.

So Doug, what I would say is that we see modestly rising price that go over the course of the next few years but certainly not back to a level that we see in the last two or three years.

Got it. My follow-up, if I may, Ryan is probably one for you. It's really more of a high-level strategy question because we could debate over the years what the market looks for out of Conoco. Your unique offering obviously is the dividend, but top line for a company of your size is always going to be relatively modest at best. So when you think about the trade-off between portfolio high grading, bringing new projects on and perhaps monetizing or exiting other areas, with the potential to buy back shares when you do get a windfall of oil prices as we may have just had the last several years. How do you see the strategic rationale of continuing to pursue top line growth in a volatile oil price environment as opposed to continuous high grading with a very strong yield and the option to buy back stock? I'm just kind of curious as to how this oil price environment changes your thinking.

Yeah. I think as I look out, we probably should expect with some of the modest growth that we’re seeing in demand and really the resiliency that we see and the unconventionals having an impact on the supply, we’re going to be in a more volatile world as we go ahead. So as I think about that strategically for the company, we’re trying to build the company that has a solid base of legacy assets, low production decline, the things that you can underpin the dividend with overtime. So as we bring on the oil sands, our legacy assets in Alaska, what we’re doing in Europe in the North Sea, what we’re building in Asia-Pacific. And then on top of that, we’re moving to lower cost of supply in the portfolio through the addition of the unconventional portfolio that we’re developing here in North America. And that provides us a lot of resilience and flexibility to the capital. So we’ll see what you commodity price gives us, we’ll protect the dividend first and then with what’s left over in the cash flow, we’ll fund a capital program that will set the growth that we see coming out of that because we know the growth is directly related to that capital program. When it comes to share buyback, we will just assess what we have in terms of capital opportunities in the portfolio, if they are good, strong returns which we think they're going to be with the unconventional inventory that we have. We will judge that against the opportunity for share buyback down the road.

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

Good morning, everybody.

Good morning, Doug.

Ryan, one of your competitors indicated today that service costs have not declined as much as might be expected given the decline in oil and gas prices. And while there is always going to be lag effects and different contract durations and other things, I want to see if you would elaborate further on what ConocoPhillips has seen in the market, and whether service costs lag effects were an important factor in today’s reduction in spending, or there is lower prices? And then also some of the specific initiatives that you guys were undertaking that led to the $500 million benefit that you talked about a few minutes ago.

Yeah, sure, Doug, I can chime in and Matt is even closer to it than I am, so I can let him add some color to it if he would like. But we’ve -- so as he said, we are seeing reductions as we -- as rigs start rolling off onshore, rig rates will be coming down. We are seeing pumping services and some of the commodities, and we are tracking each of those. We have 20 different categories that we track on the supply chain side, and we are looking at them pretty closely. So a lot of those are coming to the capital side, some go to the OpEx side. What we said is we’ve got pretty clear line of sight to the $500 million of reductions that we factored in, but those are going to continue as this commodity price environment continues into 2015 and depending on the recovery that we see coming into 2016. We are all over it. We are looking to try to capture as much of that as we can. The interesting sort of piece that you get, although reductions and the flexibility that we’re exercising is in North America and that’s where we expect to see a lot of the first reductions from capturing the deflation. So I don’t know, Matt -- I think that’s where we are all over Doug and here is as much as we can out of it and as quickly as we can.

Okay. Well, thanks a lot, guys.

Thank you, Doug.

Thanks, Doug.

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

Thanks. I would like to dig into I guess CapEx and flexibility or just a little bit more. And you cite your maintenance CapEx is around $9 billion to $10 billion. But when you sit back and look at kind of major project spend, as I think you cited, you’re seeing a reduction in 2016, 2017. Can you give us a sense of what the size of that might be and how much you guys think you need to spend annually on those longer-dated projects, whether you have them today or you need to build them for kind of long-term growth opportunities?

Well, as we move from 2015 and 2016, we will see about $2 billion coming out of our major capital projects, CapEx requirements just from Surmont and APLNG. So that’s why we’re referring to have significant increase and flexibility from '15 to '16 and that trend continues, the several hundred millions, not billions of barrels as we go from '16 -- billions of dollars as we go from '16 to '17, but that trend of reducing capital going to major projects and increasing capital going to the flexible low cost to supply development program. That’s an underlying part of the strategy that we’ve been executing for the past few years. And we are in the middle of that and adjustments to overall investment portfolio right now and for the next couple of years.

Okay. So if I can kind of clarify, if I look at that $11.5 billion 2015 budget, call it you will take out $2.5 billion for some of these major projects and that gets you to somewhat that maintenance capital level?

That’s the good way of thinking about it. And that’s close enough.

Okay. I appreciate that. And one follow-up question then on your rig count reductions, obviously it was pretty meaningful in the U.S. onshore. And when you look at plays like the Bakken, Eagle Ford, and Permian, can you give us sense when you are drilling your projects today, when you sit there and look at three, four and six rig counts, you assume that this will be economic at currency spot prices, strip priced or better price? And just to give you some context, I know there is a lot of debate whether or not the Bakken is economic today so why should there be any rigs drilling there today.

Yes. So we are in the sweet spot of the Bakken and we can -- with the rig rates and the rates that we are getting, it’s economic at current conditions, but we are actually taking that all the way down to three rigs this year. We do have some commitments within some of the units and the Bakken where we have to run some rigs in the Bakken. The Eagle Ford is still very economic even at the current prices. But having said, it makes more economic sense to be fair. So what we are dealing with in the Eagle Ford is that a balance of, we have some commitments. We need to run probably three legs to meet commitments on our leasehold and we are also keen to continue to learn on Eagle Ford, because we have a huge inventory to develop over the next couple of decades and we want to make that we are capturing all the learnings. So we’ve chosen to continue with some of our pilot tests as we go through 2015. And our expectation is that some of the capital flexibility appears more into next year, they were likely to increase our rig count and take advantage of what maybe higher prices, but certainly will be deflated costs.

Thank you. Our next question is from John Herrlin of Societe Generale. Please go ahead.

Yes, hi. Addressing the service costs another way, are you getting discounts from book rates, or are you going to be able to get longer-term rates at discount, or is it too early regarding fracking the rigs, etcetera?

So there is a mixture both going on John. I mean, this isn’t a great time to enter into long term commitments. We waited until we see how the deflation works its way through the system, but we are working with the suppliers. We’ve got great relationship with the suppliers and we’re looking at across the spectrum of things influence the capital and operating cost and making judgments everyday on what the most prudent thing to do as in terms of contract duration and commitments against reducing costs that we are seeing.

Okay. Thanks, Matt. One other question. It’s a more volatile world. Given the short cycle nature of shale based activity, would you ever institute a hedging program for the shale or just given your size realistic?

Yeah, I think the latter is the case John. With our size, we are naturally hedged across a lot of commodities and the markers. So given our size of where we are at, we don’t see that is a useful strategy right now.

Great. Thank you.

Thanks, John.

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

Good afternoon, everybody.

Hello, Guy.

I had question on your 2015 production. And I was trying to get a better sense of the general trend as we progress through the year, especially for the US unconventional portfolio. So could you help frame for us perhaps what kind of the 2015 exit rate production expectations might be for Lower 48 on the current capital spending plans and then any early expectations on 2016 with current rig count levels would be much appreciated? And then I have a follow-up.

Well, Guy, I think you are really trying to focus in on unconventionals in that portfolio. So to give you a sense of that, we expect a production from the Eagle Ford and Bakken will grow from about 200,000 barrels a day in 2014 to about 225,000 a day in 2015, so somewhere between the 10% and 15% increase. That production growth is all going to come through the first half of the year. And then if we state the rig counts that we said just now, we’re going again to a slow decline in both the Bakken and the Eagle Ford. Not a rapid decline but a slow decline and that’s going to continue into early 2016. So early 2016 average rate will be -- is going to be a function of the numbers of rigs we decide to run and we -- and as I said earlier, we do expect to increase our rigs in Eagle Ford and Bakken in ‘16, so production maybe flat from ‘15 to ’16, but time will tell. So, growing production on average year-on-year from ‘14 to ‘15, all of that growth is seen in the early part, the first half of the year and then a slow decline through the third and fourth quarter.

That’s very helpful, Matt. And then my follow-up, I wanted to kind of walk through some of the implications of the low rig count. And you partially address this in your prepared comments, Matt. But how do you think about reduced investment levels materially but still retaining the practical ability to quickly flex those activity levels higher if the commodity price improves? And then secondly, can you just address just with the focus on minimizing spending and maximizing efficiencies. Your ability to still continue with some of your experimentation to drive a long-term recourse upside, I mean, are those plans still going to in place in the Eagle Ford and the Bakken as well with the lower rig count? So any comments you can provide there would be great.

Yeah. So we -- the organization that we have in the Lower 48 is flexible enough to bring the rigs down and bring the rigs back up, if we want to do that. So that flexibility exists. And we’re exercising our flexibility now and we done and we will be able to do it on the way back up again. So the organizational flexibility and the relationships with the suppliers and so on, that’s all in hand to go both ways. And in terms of the continued experimentation, yeah, we have to chock back somewhat on the pace of learning. We can’t do all of the pilot tests that we’d like to do, because you need to be drilling wells to do some of those. But the critical pilot tests that really have the biggest implications for our long-term resource and understanding. We’re going to continue with those sort of pilot tests through this downturn because they have implications of the value of our information for the long-term. We think is worth continuing to collect.

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

Hey, folks. Good morning. I have a question on slide seven. It looks like you provide the regional breakout of your adjusted earnings. And it looks, I hate to put a too much emphasis on just one quarter, but it looks like the Lower 48 actually saw a loss compared to the other regions and then, obviously, you’re cutting CapEx in the Lower 48 as well? I guess my view is that that was one of the main drivers of margin expansion going forward? And so could you maybe elaborate a little bit on the economics that you’re seeing there compared to the other investment opportunities that you have?

So, Blake, in the Lower 48 in the fourth quarter, there were around $100 million or so of an impairments that happened between and then also some dry hole cost related to the Shenandoah appraisal well that we wrote out as well, which impacted that loss somewhat. But having said that, it will be a challenging year coming forward for Lower 48 based on the fact that there is still a fairly heavy natural gas weighting in the Lower 48 production. It is, as Matt mentioned, the economics are still there for continued investments that we are making and those are good cash margin investments. But it is going to be a challenging 2015 at current commodity price levels in the Lower 48.

Sure. Understood. Okay. And then the second question is on the commitment to the dividend. I fully appreciate kind of the differentiated strategy and having that as a top priority? But you kind of mentioned debt-to-capita increase and potentially investment grade could go below AA or A? Is there a level that we should kind of think about where you begin to have to rethink that that strategy and emphasis on the dividend whether it would be investment grade rating or certain debt-to-cap level?

As we mentioned in our remarks on call, we look at a lot of different scenarios that might happen over the next couple of years. We think between the capital flexibility that we have, the potential that we could have some level of asset sales in the mix and the cash balance that we’re starting with. So we don’t think, we’re going to be having to face the question of having more borrowings than would take us out of that A credit rating range. With -- and again that’s part of the overall message here is that that’s baking in the dividend is the first priority for how we’re using our cash flow.

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

Hey, guys. A - Ryan Lance Hi, Paul

Good afternoon. And couple quick question if I could. Maybe this is for Matt and Jeff. If you are looking at your supply cost, do you have a rough percentage? How much of that supply cost is currently under contract longer than two years?

Supply cost, you mean like our rigs and so on?

Yeah. Rig or anything that relate to your upstream operation.

And well, in our North America business and certainly in Canada on the Lower 48, there is a very, very little that extends beyond one year. And in terms of rig contracts, most of them are 30 days, if we move to the international business, there is some in U.K. and Alaska there and Norway that are on longer term contracts than that. But it’s typically, it’s not common for us to have a significant amount of our drilling development led portfolio and constrained by long-term contracts.

So should we -- Matt, should we assume that more than 50% of your supply cost base that you could potentially not seeing cost reduction relatively quick timeline?

Say that again. You are looking at the opportunities to get deflation and to ….

That’s correct. But how quickly that [indiscernible], because you have a lot of your surface is under long-term contract and maybe that you can negotiate even though that you are still under contract, but normally that people don’t like to allow that, but -- so that’s what I am trying to understand. How quickly is that the saving will be able to pass-through?

So when me see it most quickly in the onshore and North American business in this and particularly in Canada in Lower 48. We’re not going to see it, for example in the APLNG project. We are now almost a 100% labor cost. We’re not likely to see labor cost in Australia decrease over the next year. And same applies really to the Surmont 2 project in Canada where that’s all labor just now and we don’t anticipate any significant labor cost reductions over the next few months as we complete the project. So the short answer is that the major projects are going to see limited and slower deflationary and forces act on them and the development programs everywhere, but in particular in Canada and Lower 48 are going to see it more quickly.

Okay. Second question, this is for Ryan. Ryan, understand your priority in protecting dividend. What is, as the industry under stress and there’s a great opportunity of rise and you make a choice between making an acquisition, but that has to dramatically cut your dividend subsequently to ensure that you have sufficient cash flow going forward? What that, how that choice will be made from your standpoint? I mean, how you balance that?

Well, Paul, it’s an interesting scenario to try to think about that, but it’s a tough one to anticipate a little bit over because we’re focused on executing the plan that we have. We watch the M&A market. We see the assets that are out there. The issue with M&A in our portfolio is it’s got to compete against the investments that we have in the portfolio already today. And it’s a pretty big hurdle for it to climb over. So, I wouldn’t speculate on where that might go.

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

Hey. Thanks. Good afternoon, gentlemen. Maybe one follow-up on activity levels and balance sheet. I guess as we look forward into 2016 -- you probably implied on reaching the 2017 cash flow neutrality target, even if the current capital, CapEx balance and dividend rate would imply relatively significant ramp in cash flow potentially from commodity prices in the 2017, as is so. What would you need to see -- I guess in the market, either from a cost or from a commodity point of view to actually start adding capital back to the budget as apposed to just letting things play out through 2017?

So what we said is that I mean, that we are going to have a lower capital to be flexible and to manage within our cash flow and maintain the dividend, so the capital is going to flex and we have the portfolio to allow that to happen. So when we say that we are going to get to cash flow neutrality in 2017, there is a bunch of different ways that that could transpire. It could transpire through higher prices with more capital and more production or lower prices with less capital and less production growth. So, we model all of these scenarios and we are planning to talk more about this, Ryan, when we have our Analyst Day in April.

The capital, Ryan, is the flywheel. So, again, we started with dividends being the number one priority. We’ll fund that out of the cash flow. The growth will come from whatever capital level that we set in the commodity price and the cash flows informs that. And then we are setting that level to make sure that we reach cash flow neutrality by 2017. And as Matt said across very scenarios of combination of capital and oil price projections, we are focused on getting there in 2017.

Hey. I appreciate lots of moving pieces in the equation. Just trying to get an idea if there is a level that you would think about that would have to see, at least to actually star -- to star putting some money back into the business incrementally from what you have now?

We won’t let cash flow neutrality move out beyond 2017. So, I think that’s the stakes you can put in the ground, Ryan.

Okay. That’s helpful.

It could move closer depending on the commodity price levels and what the market gives us.

That’s helpful. And then if I could ask on the -- on what you are seeing on the cost environment. I know you talked a little bit -- am I correct in understanding that the vast majority of the $500 million CapEx catch that you’ve implied in the budget today that have come in the U.S. and if -- and either way, can you talk a little bit -- we have a little bit more visibility, I think generally in what we see in the U.S? But can you talk a little bit about what you are seeing globally on cost across deepwater or major capital price and those types of things in the current environment?

Well. I think, Matt’s trying to address that. And we see it will be slower in the major projects and those like APLNG and Surmont that have a large labor component. That’s going to take a long time to work through the system depending on how long the down cycle is .We do see deepwater floater rigs coming off quite a bit. So the market today is quite a bit less than it was just a couple or a year ago maybe this time a year ago. So we do see pieces of that tubular goods, Oil Country Tubular Goods, we see that coming down, and that’s a commodity that we use across the world. So where we have development in drilling programs, and we use workovers and stuff, we see some of that flowing through as well. So it is -- my category, it’s different by each category, and it’s different around the world. And the $500 million that we were talking about is something that we’ve got pretty clear line of sight on to capture this year, and that will continue into ‘16.

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

Yes good morning. Good discussions so far and I am going to have to stick with CapEx then ask some smaller questions. Just on the $4.5 billion of major project spend given that you do have APLNG heavy oil and some large projects in Malaysia that are going to finish hopefully at some point in ‘15. It might be a help to us to maybe give us some color as to just on the existing projects. How might that look in 2016, forget cost deflation, but just the timing of the -- CapEx cycle?

So roughly speaking the -- we are going to see -- so let me give you some specifics. So APLNG will grow from something like $1.6 billion this year to 0 next year. Surmont will grow from about $800 million this year to about $250 million next year. So there is a tip that few have been sort of high level. And yes, few of those biggest projects -- so there are few projects that are increasing in capital year-on-year which has been the clear rich projects and as towards closer we’ll see a slight increase in capital there next year. And same with the Malikai project in Malaysia, but overall we are going to see something greater than $2 billion coming off the -- in the mix between those larger, the biggest projects we’re executing, coming to an end, and some smaller projects that are already in execution ramping up a bit.

With the cash flow from those and then that provides more confidence to add back rigs into shell so...

Well that’s right. -- Actually you make a good point there. Because one other things about the projects like APLNG and Surmont for example, is they’ll start producing this year. But it won’t actually got to a peak raise for a full year until 2017. So they are going to be continuing to contribute the growth long after the capital spend even as the Surmont project takes three years to ramp up, APLNG won’t actually get to peak production until some time early in 2016. And the KBB project in Malaysia, we might only get half -- despite the fact of the project is complete, but waiting on this pipeline being appeared, we might only get half a year of production from KBB this year. But we get full year of production in 2015, and so on. I mean so this will be -- and we are happy that these major projects that they are getting to completion, not just because of that to spend the CapEx but because now we are going to reap the reward over the next several years of contributing, growing our base productions through these long life -- many of the long life flat production projects.

Okay.

So little bit more point on Matt said as well. If you go back to our Analyst Presentation last April, we talked some numbers about how much cash, we are going to expect to see coming out APLNG and out of FCCL, once those things are up and running kind of a full rates by 2017. And those are lower numbers of oil commodity prices, but it’s still a pretty significant source of cash for us. And that is an important part of the equation of getting the cash flow neutrality in 2017

And just on APLNG, just as a follow-up, how will you be treating, I guess, the CBM drilling cost? Would that be in CapEx or you put that in the OpEx just more of the modeling question. The maintenance CapEx on that project, which can be quite significant I think?

Yeah. Because the fact that APLNG is done with equity accounting for asset and you don’t end up seeing the capital expenditure for APLNG or the operating costs for you to see contribution in current -- say the contributions going in as capital and we’ll just see the distributions coming back out in the future.

Thank you. Our next question is from Alastair Syme of Citi. Please go ahead.

Hello. I wonder if I could ask to what extent in this environment the OpEx and overhead might be the flywheel in terms of cash neutrality. If you could put some granularity around the comments you’ve made about G&A cost would be useful?

Yes. Alastair, we have talked a lot about the capital but we have -- we are equally focused on the operating cost here, as you would expect. And just like we are focused across the value chain per capital, deflation opportunities in capital, the same things happening in operating cost. First of all, end cost are externally driven by contract, labor, materials, and chemicals, and there are some of that price sensitivity to transportation cost and some of our transportation contracts. But we got to look inside to for sale productions -- looking at internal operating cost and G&A. So we’re ready to take in actions there. We have -- we really have no salary increases in 2014. We got hiring fees in place across most of the company. We are ready for those plans to reduce headcount in Europe. That’s quite significant. And we’re likely to see more headcount reduction in other part of the business as we re-asses the implications of lower prices on a future plans. So we’ve the whole company focused on minimizing our operating cost and we’re not going to leave any stone unturned. We’re not going to take any measures that reduces the safety or integrity of our assets. And that is one of the things, Alastair, that we intend to talk about in more details at the Analyst Day in April, our approach to the operating cost side of the equation.

Could you say how much of your operating cost of supply given versus in terms of what percentage roughly?

It’s about, let’s say, that it’s roughly 30% as internal and a company labor. And then the rest is a mixture of transportation cost, contract labor, material, parts, about 30% is a ConocoPhillips internal employee labor.

Thank you very much.

Thanks Alastair.

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

Good morning.

Hello, Roger.

I guess coming at the OpEx question slightly different way, we talked a lot about CapEx flexibility. As you think about the cash margin potential here, and I think about the share play certainly where they were probably a little more on the higher cash cost side, certainly looking across the industry. So as you pull back a little bit on your drilling there as we look at some of the projects and probably more of a '16 than a '15 impact from APLNG and Surmont. But what do you think about cash margins as you look into the latter part of '15 and '16?

We expect the absolute level of cash margin will come down with the commodity prices obviously. But as we look at across the portfolio, most of the portfolio is quite resilient to -- on a cash breakeven basis it’s pretty resilient to these prices. So we are going -- as Matt said, we’re going to continue to drive operating cost reductions as well as the capital reductions. And while the absolute level of margin will probably come down, we’re still going to try to drive to see those margin improvements over the course of the next couple years.

Okay. Thanks. And then maybe a better question, April. But as you think about the exploration program here as part of the overall CapEx discipline and keeping the dividend in mind, flexibility obviously on the growth projects. What is the flexibility of exploration and what is the maybe incentive here as you mentioned with lower rig rates to shift things out another 6 or 12 months where you can?

Okay. So on the short-term aspect of that question in terms of the flexibility in our exploration spend, there is relatively limited flexibility in the short term on the conventional exploration activity. And we have rigs under contracts. We have agreements in place with the governments and the partners. So over the next year through 2015, that’s why we haven’t taken as much as you may expect, the exploration will really have to go to the possible exploration portfolio that is flexible. So we are going to think the 2015 is actually a pretty big year for exploration in Angola, Senegal, Gulf of Mexico, Nova Scotia, for example, and Australia. And so we -- then as a longer-term question about the role of exploration and the growth of the company, and that’s one of the thing, we’re going to talk about more in the Analyst Day in a couple of months.

Thank you.

Sorry, Christine, I'm seeing it's the top of the hour, we will take one more question if you don’t mind, okay.

Okay. Our last question is from Phil Gresh of JPMorgan. Please go ahead.

Thanks for sneaking me in. Two quick ones. One is just, the budget for this year, is it fair to say that the 11.5 is kind of set in stone at this point absent further deflation given that you have $2 billion rolling out for the next year and the 9.5 is kind of the core required spend? So if you got anymore this year, you would be kind of cutting into the data so to speak.

Yeah. We’ve got a set the scope that we want to execute with the $11.5 billion. There is some uncertainty as to how much deflation we will capture this year. We’ve added some in, could be more than that. We’re certainly trying to drive to more than that. Yes, we’ve set the scope associated with what we want to execute on the $11.5 billion.

Got it. And then just a follow-up. Just on the asset sales started, maybe any additional color you could provide around how you might approach the process like that? What parts of the portfolio might be something you would want to monetize in this type of environment?

Well, we continue to look. I’ve said, we won’t have another large announced asset disposition program, but you should expect us every year to be pruning the bottom part of the portfolio. Obviously, it gets tougher in this kind of commodity price environment. But we set our new base case. We know that the assets are worth to us internally. And if there is interest out there in certain assets, we’ll entertain those and look at them. So I think you should expect some modest amount. It will be tougher over the next couple of years, but of course there will be some pieces of our portfolio that we will be taking a hard look at.

So you think you can get $500 million to $1 billion in cash a year out of assets sales. Are any kind of target you are thinking about?

No, I don’t really have a target in mind. We’ll do what makes sense.

Okay. Fair enough. Thanks.

Okay. Christine, why don’t you wrap it up here? And thanks everybody for your time. And by all means call IR if you have any other additional questions.