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

Paul Cheng – Barclays James Sullivan – Alembic Global Advisors Doug Terreson – ISI Group Paul Sankey – Wolfe Research Ed Westlake – Credit Suisse Blake Fernandez – Howard Weil Doug Leggate – Bank of America Merrill Lynch Faisel Khan – Citigroup Inc. Roger Reid – Wells Fargo Pavel Molchanov – Raymond James Asik Sen – Cowen and Company

Welcome to the Q1 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 good morning to everybody. With me here today are Jeff Sheets, our EVP of Finance and our Chief Financial Officer and Matt Fox, our EVP of Exploration and Production. Jeff will cover the quarter’s financial highlights and then Matt will take us through the quarter’s operational highlights and provide some color on what to watch out for what’s to pay attention to for the remainder of the year. Then we’ll have Q&A in the last. During Q&A, if you can limit your questions to two. Of course, jump back into the queue if necessary. We will make some forward-looking statements this morning. And the risks and uncertainties in our future performance are described on page 2 of this morning’s presentation material and also in our periodic filings with the SEC. This information as well as our GAAP to non-GAAP reconciliations and additional supplemental information can be found on our website. Now we’ll turn the call over to Jeff.

Thank you, Ellen. Hello everyone and thank you for joining us today. As you know, we just recently held our 2014 analyst meeting in New York where we reaffirmed our plans to deliver double digit returns annually to our shareholders. We outlined our production in margin growth plans for the next few years and hopefully gave you increased confidence on our ability to deliver on those plans. We have an exciting year ahead and as we reported this morning, are off to a strong start. So Slide 4 lists our key highlights for the first quarter. Operationally, we have a very good quarter. We produced 1.53 million BOE per day from continuing operations excluding Libya. Adjusted for dispositions and downtimes, this is up about 3% compared last year’s first quarter, so we’re seeing growth. We also made progress on key activities that will continue to drive organic growth. We delivered on key milestones around our major projects and continued our strong performance on the unconventionals. Exploration and appraisal activities continued during the quarter in the North American unconventional across Mexico deep water, Australia and elsewhere. These activities are key to our reserve and production growth beyond 2017. Financially, this was also a very strong quarter. We achieved adjusted earnings of $2.3 billion or $1.81 per diluted share. This was quite higher than expectations and I’ll address some of the drivers of this stronger than expected performance on the next slide. During the recent quarter, we generated $4.4 billion in cash from our operating activities alone. We also had positive working capital change of about $600 million in a distribution of $1.3 billion from FCCL, so a total cash from operations of $6.3 billion. And our balance sheet remains very healthy with over $7.7 billion in cash and short-term investment fund on hand as of the end of the quarter. Strategically, we delivered on both production and margin growth this quarter. We continue to expand our inventory organic growth opportunities to support our growth to support our growth goals. And importantly, we remain committed to deliver in double digit returns to our shareholders annually including a compelling dividend. So all in all, the first quarter was very strong operationally, financially and strategically. So now I’m going to turn to Slide 5 for a discussion on earnings. First quarter adjusted earnings of $2.3 billion were up 29% compared to last year’s first quarter and up 30% sequentially. Adjusted EPS of $1.81 was higher than consensus, about a dime of the difference of roughly $100 million was due to North American natural gas price realizations that were stronger than the realizations indicated by changes in market prices. Another dime or about another $100 million was due to gains from marketing of third party natural gas during the quarter. As a reminder, we have a strong commercial gas marketing organization that markets both equity and third party gas in North America. Given the high volatility in the first quarter gas prices, our commercial team was able to capture some benefit by supplying both equity and third party gas into premium markets. This benefit from our third party activities is not necessarily repeatable, but it speaks to our strong marketing capability. First quarter segment earnings are shown in the lower right side of this chart. So the financial details for each segment can be found in the supplemental data that accompany this morning’s release. But then we address a couple of items about the segments. Lower 48 earnings included the marketing gain. I just talked about it as well as strong realizations for natural gas. Canada segment earnings were very strong and again reflecting stronger business prices and the gas realizations. Gas realizations for the quarter were $5.81 reflecting both strong acre pricing and the placement of some volumes in the premium markets during the quarter. Canada segment earnings also included approximately $60 million benefit from foreign exchange which was offset mostly by foreign exchange losses across other parts of the portfolio. The last was pretty straightforward with nothing unusual to highlight in the quarter. Europe operations performed well in the quarter with growth coming from several major projects. And if you look over the past several quarters, we’re starting to see the benefit of volume growth in this segment. Our Asia-Pacific and Middle East segment was impacted by lift timing differences in China and Western Australia but otherwise was in line with expectations. And finally, our corporate segment was in line with our previous guidance. So if you’ll turn to Slide 6, I’ll cover our production results for the quarter. As you know our convention for production is continuing operations less Libya. On this basis, our first quarter averaged 1.53 billion BOE per day. Normalized for disposition and this is compared to 1.495 million per day in the first quarter of 2013. The waterfall shows that over the period, we had 6,000 BOE per day more plan and unplanned downtimes and in the first quarter of 2013 and net growth of 41,000 BOE per day. That represents a 3% increase compared to a year ago. The box on this stage illustrates the composition of this 41,000 BOE per day of growth. As we discussed at our recently analyst meeting we are growing in the highest marks and portions of our portfolio and this growth of higher margin production is driving growth in the company’s cash margins. And we’ll discuss that margin growth on the next slide which is Slide 7. This slide show changes in our cash margins from the first quarter of 2013 to the first quarter of 2014. And also, on a sequential basis. On the left side of the chart are the margins on as report basis which were up over 20% year-over-year on strong natural gas prices. And on the right are the margins on a price normalized basis. So on a price normalized basis, margins increased 13% year-over-year. Over this improvement, over a third or 5% is due to our underlying liquids growth especially in areas with more favorable fiscals. The remaining 8% margin improvement was due to the benefits related to equity and third party gas marketing activities that we’ve just discussed as well as Libya being down. So we are delivering on our commitment to improve margins as we grow, not just generating growth for growth’s sake. I’ll conclude my prepared remarks with our cash flow waterfall which is another good story. So I’ll move that now to Slide 8. This shows our cash flow performance for the first quarter. We began the first quarter with $6.5 billion of cash in short-term investment from the balance sheet. You can see we generated $4.4 billion of cash from operating activities. Had a $1.3 billion FCCL distribution and a working capital benefit of $600 million. We had capital expenditures and investments of $3.9 billion. And after paying our dividends and returning debt of $500 million, we ended the quarter with $7.7 billion of cash in short-term investment from the balance sheet. We’ve reduced our debt to cap ratio to 28% from 29% the beginning of the year. So we’re in great financial shape and well-positioned to execute our investment programs for the company. That concludes the review of our financial performance. Now, I’ll turn the call over to Matt for an update on our operations.

Thanks, Jeff, and good morning everyone. So to begin, I’ll provide a first quarter operations update for each of our business segments. Then I’ll go over our production outlet for the remainder of the year. And I’ll conclude with a preview of some key activities to watch over for the rest of 2014. As we talked about each segment, you’ll hear a comment spread through the presentation and that’s true. As we progress through 2014 and then to 2015, we expect to see growth in almost every segment of our business. And we’re not just growing volumes. We’re growing margins. Virtually, all of our growing production will be at margins higher than our average margins to be. So let’s go to Slide 10, our Lower 48 in Latin America segment, which continues to lead the way on strong growth of the company. First quarter production averaged 507,000 BOE per day for this segment which is 7% increase from the first quarter of 2013. But more importantly, our crude production increased 16% over the same period. The biggest contributor to this growth with the Eagle Ford with just an average of 147,000 BOE per day during the quarter. Our daily peak rate for the quarter was 163,000 barrels a day. So we achieved good momentum after the weather problems early in the quarter. But currently our trail [ph] of operated rigs running in the Eagle Ford, I mean we brought 48 wells on line in the first quarter. We’re transitioning to the 80-acre high low developments, spacing to outline our analyst meeting a few minutes ago. And we have additional pilots and progress that are testing other than spacing. In the Bakken, we average 43,000 BOE per day and achieved a peak daily rate of off 54,000 barrels a day in the first quarter. We’re also performing pilot test in the Bakken to optimize our drilling and development programs. Unconventional drilling and testing continues in the Delaware and Midland basins in the Permian as well as in the Niobrara. It’s still early days, but as we said in the analyst meeting, we remain optimistic about these amazing place [ph]. In addition to our unconventional activities are appraisal drilling in the deep water goal for Mexico continues at Tiber and Coronado, and exploration drilling continues at Deep Nansen. In Slide 11, we’ll give you some highlights from our Canada segment. Operationally, our Canada business performed very well in the first quarter. We produced 280,000 BOE per day which includes a 9% increase in liquids production from the first quarter o 2013. Surmont 1 deep automating [ph] is progressing and the major project in Surmont 2 remains on schedule for first team in the middle of next year. At the end of the quarter, the project was 68% complete. Christina Lake Phase E is approaching full capacity and Foster Creek Phase F remains on track across production and the third quarter of this year. As part of our Western Canada winter drilling program, we successfully drilled 25 horizontal wells in the liquid rich plains across our acreage position. This program continues to deliver good returns and also a lot of drilling inventory. And we achieved a big milestone on the first quarter by drilling the longest horizontals onto well effort [ph] drill in Canada over 13,000 feet. There’s an impressive operation on technological accomplishment. And it shows we’re working 10-year [ph] to optimize the programs. We also continue to explore and appraise our own conventional place in the Duverny and Montney where we’re encouraging early results. I’ll now cover the Alaska segment on the next slide, Slide 12. Alaska production was about flat sequentially at 200,000 BOE per day. We remain encouraged by the improved –fiscal ‘10 [ph] was brought why the passage of the More Alaska Production Act last year. And no, we plan to spend more capital in Alaska in 2014 than we’ve spent over the past three decades. This increased investment will mitigate the claims and legacy fields and provides growth from new satellite fuels into the future. We’re making good progress at Drill Site 2S and Kuparuk. The Greater Moose Tooth [ph] is one project in the west from slope. And the one inch [ph], north east west side project. That one inch [ph] news project is a third new project that have been initiated by the company since the passage of the More Alaska Production Act last spring. We’ve had a good one to construction season ad at CD 5 and remain on track for stock up in [ph] late 2015. We drove two exploration wells in the western north slope. This one’s and flat top one. And we’re in the process of evaluating those results. [Indiscernible] but the contract is saying to deliver six cargos in 2014 with first shipment this month. In April, enabling legislation was passed by the state legislation to allow the State of Alaska’s equity participation in the AK LNG project. That is a positive step forward for the project, but there’s still a lot of feasibility of what to do. And we hope to move into [indiscernible] in the near future. Alaska has become an attractive area for investment. We’ve got a lot of activity underway. But we expect to provide additional growth opportunities for this segment in the future. I’ll next cover our Europe segment on Slide 13. Like the Lower 48, this segment recovered well from very challenging weather conditions late last year and early in the quarter. Production for the quarter averaged 220,000 barrels a day which is about 12% higher sequentially. On our last quarterly call, we discussed the startup of Ekofisk South and Jasmine. Eko South were ramping up volumes in conjunction with drilling activity. At Jasmine, we recovered from some minor startup delays and averaged 25,000 BOE per day for the quarter. And we brought [indiscernible] Jasmine in March. We also commissioned and started up a new San Juan Gas Plant at this Irish Sea. On to our construction activities and nearing completion, the Eldfisk II for early 2015 startup. And also a commissioning is ramping up for the Britannia Long-Term Compression project for startup and the third quarter of this year. In Poland, we continue exploring in the Baltic Basin just to the west of Gdansk. We completed two vertical wells in sidetracked one of them horizontal during the first quarter. We’re currently completing the horizontal section with an Eagle Ford style frack. And we intend to conduct an extended floor test later this year. As you can see at the bottom left of the chart, there’s a heavy turnaround activity planned in the UK during the second and third quarter, which I’ll discuss in a bit more detail in a later slide. So our Europe segment is positioned for growth from high margin production this year. And finally, let’s look at our Asia-Pacific and Middle East segment on Slide 14. In this segment, we produced 319,000 BOE a day, 9% higher than the fourth quarter. And over this period, we also saw a 20% increase in high margin and liquids for this segment. Our 1Q plan turnaround at Train 7 in Qatar was completely ahead of schedule. In Indonesia, we achieved first gas in the South Belut Project in April which is the fifth phase of block B [ph] oil and gas development. We also achieved first oil in February at Siakap North-Petai and our non operated commissioned project is progressing towards that to open the third quarter of this year. At Kebabangan, our topsides are schedule for sail away in the second quarter. And we’re on track for first reduction by the end of this year. And exploration, we drilled a successful appraisal well in Malaysia at Limbayong-2. And we remain encouraged by our findings there. So there’s clearly a more growth potential in the Malaysia business. APLNG also remains on track for our mid-2015 startup. From a combined downstream and upstream basis, we were 67% complete by the end of the first quarter. Our appraisal programs continue in Australia and the Browse Basin and at the Barossa field for well start [ph] in March and April respectively. Both of these wells should TD [ph] later in the second quarter. We expect this segment to provide significant production growth over the next couple of years. Before I move to the next slide, let me briefly touch on other international segment. The key activity in this segment is exploration related. In Senegal, we spudded the first well two weeks ago. In Angola, a rig is now on transit to block 36 and we expect this to spud the Kamush [ph] well late this quarter or early in the third quarter. I’ll cover the production outlet now on Slide 15. We showed this slide in our analyst meeting last month. We slightly exceeded our guidance for first quarter volumes, but otherwise our expectations are unchanged. As you can see, we expect production to drop during the second or third quarter due to seasonal maintenance activities across our operations. And on the left side of the chart is a list of the key turnarounds and tying up entities [ph] for the next two quarters. This activity will start late in the second quarter beginning in the UK, but the majority of our turnaround activity will occur in the third quarter. And these turnarounds impact almost all of our segments. The key activities in the third quarter will be in Alaska, Canada, the UK, and the Bayu-Undan field in the Asia Pacific region. Bayu-Undan is particularly noteworthy as this is a 36-day shutdown that includes brown field activity for the tie-in at two new subsea wells. By the fourth quarter, our seasonal maintenance should be complete and additional projects should be coming on line. I’m going to expect to exit the year at or above 1.6 million BOE a day. Full year production guidance for continued operations is 1.51 to 1.55 million BOE a day excluding Libya. And this is unchanged from a prior guidance and in line with our 3% to 5% production growth target. At this point, the biggest uncertainty in the ranges is startup of our non-operated commissioned project in Malaysia. I’m going to wrap up my comments with what to watch for in 2014. There are several activities underway to drive growth. Major projects, startups are expected at Gumusut, Foster Creek Phase F, Kebabangan and the Britannia long-term compression project. These are important activities that should impact the 2014 exit ways [ph] and drive 2015 performance. We also expect to continue growth both in the Eagle Ford and the Bakken relate as some development program, details of the recent analyst meeting. And these are the expectations with this place over the next few years. We’ll continue our North American unconventional exploration and appraisal programs with the focus on the Permian and Niobrara. We’ll also test that unconventional plea in Poland which the extended production test that I spoke about. The company also found and to see additional blocks in Colombia last year with explorational commands in the second half of 2014 to test the prospectivity of the La Luna Shale. Gulf of Mexico would be – more drilling continues in Tiber, Coronado and Deep Nansen. And we’re also preparing to begin and operate the drilling program late this year or early next year. Finally, as I mentioned earlier, we’ll begin explorations drilling in Senegal and Angola this year. And if successful, these programs would be catalysts for growth into the next decade. So here’s what I hope you’ll hear from our comments today. 2014 is off to a good start. We still will recover from some weather and startup delays early in the first quarter and exited the quarter in a strong position to deliver on our volume expectations for the year. Our unconventional programs are performing very well and our major projects are ramping up or progressing towards that top. We have another year of significant second and third quarter turnaround activity. But we’re optimistic about achieving our 3% to 5% production growth in the momentum we built to continue that growth into 2015 and beyond. Our exploration activity is focused on drilling and testing a high quality set of conventional and unconventional prospects. And there’s sort of a lot to update you on the coming months. So this ends our prepared remarks and we’ll turn over for questions. Thank you.

Thank you. We will now begin the question-and-answer session. (Operator instructions). And our first question is from Paul Cheng of Barclays, please go ahead. Paul Cheng – Barclays: Hey guys, good morning.

Good morning, Paul.

Good morning, Paul. Paul Cheng – Barclays: Matt, on Foster Creek, it seems like you [ph] have been facing some operating issue [indiscernible] has been up and the cost has been pretty high. Can you give us an update, what is the game plan and how confident you are that you can return that operation into say a couple of years ago tie off operating cost structure.

Yeah, these are short-term measures that we anticipate it would happen. As these steam chamber [indiscernible] and you expect to see steam oil ratios and [indiscernible] under those circumstances. But they operate, there’s a good plan in place to regain the steam oil ratios that the Foster Creek exhales [ph]. And as we add Foster Creek this [indiscernible] and move the steam from some of the more well developed steam chambers that can use steams. So we feel pretty confident across the creek that it will return to the high performance that we’ve seen on the past. Paul Cheng – Barclays: Jeff, can you give us an update, any update at all related to the other sales plan in Canada or for their oil sand.

We’ve said on several occasions that we’ll continue to look for opportunities to liken our position on oil sands. But that is something that we’re going to watch or some of us state on that process, Paul. And there’s nothing that in our plans for 2014 in that regard. Paul Cheng – Barclays: Can I just sneak a really quick one for Matt.

Okay, go ahead. Paul Cheng – Barclays: Man, from an M&A point of view, looking at your portfolio in the upstream, is there any particular location that you think you may want to be more aggressive in acquiring additional acres?

You know, Paul, of course, we’re always looking ahead the [indiscernible] to add opportunities to our portfolio. We’re focused on doing that organically. And the exploration and teams are out there – all the team looking for a high quality acreage that we can add early in life cycle. So yeah, of course we will. We always want to take opportunities to strengthen the portfolio. But it’s all about organic live growth for us. Paul Cheng – Barclays: So there’s no really any particular region or area that you think that you really have a hold and you want to be – substantially step up the land acquisitions strategic.

There’s no region where we [indiscernible] that really we have a particular hole, and I wouldn’t want to go in. And if we have any specifics [indiscernible] looking at. It wouldn’t be wise to do that. Paul Cheng – Barclays: Okay, thank you.

Thanks, Paul.

Thank you. Our next question is from James Sullivan of Alembic Global Advisors. Please go ahead. James Sullivan – Alembic Global Advisors: Hey, good morning guys.

Hi, James. James Sullivan – Alembic Global Advisors: Oh, afternoon actually. I just wanted to hear if you guys have had any plans on reporting results. I know during the analyst day, you talked about ongoing spacing test into Bakken, testing I think down to maybe four middle Bakken wells for spacing unit out there. Is that an ongoing test? And give a timeframe where you might have results on that.

Yes, James, we have I think it’s about it operated different pilot, operated pilot tests going on in the Bakken in particular. And we have some partner operated areas in the Bakken are testing different well spacings and different horizons. And the timeframe, it takes a lot of time to really get results that you can feel confident about. So I would say, over the next year or more before we get really definitive results that would drive conclusions on the well density. James Sullivan – Alembic Global Advisors: Okay, that’s great. And then I just have two kind of the housekeeping types ones on your cost. Obviously, you guys had a pretty good performance this quarter on production and other areas. But to really jump out in the [ph] SG&A and the net interest numbers, I was looking for these on interest, now [indiscernible] pay down a bit of debt, but I’ve been on to the impression that the capital interest – capitalized interest number is going to come down with cash again out of the portfolio. Yet the net number was pretty low. And then just the SG&A numbers. Is there anything driving those and are those sustainable running rates?

James, we’re looking at a couple things here. Hang on a second. James Sullivan – Alembic Global Advisors: Sure.

What the net is – the net interest number is higher than it was – I’m not sure what really your question is. And we do expect interest expense to be higher because in effect we’re no longer capitalizing interest and you see that in the first quarter. James Sullivan – Alembic Global Advisors: Sure.

So I’m not sure I’m following your question there James. James Sullivan – Alembic Global Advisors: I think I was just looking at the kind of sequentially at the numbers. I mean, I was – yes, it was up over Q1 ‘13 –

Yes. I think in Q4 it’s roughly the same number. And you can just have slight variations during the quarter, so. James Sullivan – Alembic Global Advisors: Okay, great. Then on the G&A number?

G&A can also be a little bit lumpy as well quarter-over-quarter. I think we don’t try to give any guidance separate for production and operating cost and for G&A. What we said back at our analyst presentation as you recall is that we’ve see the combination of those to being $8.5 billion for this year which is a little bit higher than last year, but last year ramping up [ph] with growth. James Sullivan – Alembic Global Advisors: Okay, great. Thanks guys.

Thanks, Jim.

Thank you. Our next question is from Doug Terreson of ISI. Please go ahead. Doug Terreson – ISI Group: Good morning everybody.

Hey, Doug.

Good morning, Doug. Doug Terreson – ISI Group: Profitability and margins were very high in the quarter and maybe even that a [ph] record level even after normalizing for price as I think Jeff demonstrated. And on this point I wanted to see if you could comment on couple things, first, if the trend in cost across the global portfolio, what you do think there [ph]? Two, your leaping [ph] status in the most recent period, and three whether there any other regional profitability mix factors either on the gas side outside just comments [ph] on Lower 48 that stood out in the period?

I would say – well, we made some – we made some comments about the obvious things. Price is of course as you point out were big drivers this quarter and in particular natural gas prices. But underlying the margin growth is still the same thing we’ve been talking about, the movement of our portfolio, the more liquids into more production in areas where tax rates are generally lower. And that’s the underlying effect, what we said, it was still around 5% this quarter. We’re not having linear volumes [ph] in the portfolio does make a 2% or 3% difference in cash margin see there every year [ph] for us this year. And of course the fact that we are able to sell gas at strong prices and have bargaining games that help this time as well. In terms of other impacts, we mention that there were some minor impacts on lift timing this year, this quarter. Overall, lift timing was a negative on earnings mostly in the Asia Pacific area, and it probably impacted Asia Pacific earnings by the order of $40 million to $45 million on – in terms of lift timing, and with relatively smaller impacts across the other segments. But other than those things, there wasn’t really anything very anomalous in the – in the numbers. You asked about kind of trends on cost, kind of like on the previous question, what we are seeing is cost are going up as production is going up. But all that is covered by the fact that we’re producing higher value product. So overall, cash margins are going up like we’ve been talking about. Doug Terreson – ISI Group: Sure. And then Matt, you talked about Alaska where you guys are obviously one of the leaders up in the state. And while it might be only – my question is whether or not the improvement in your opportunity set appears likely to be significant enough to be able to stabilize your output up there maybe [ph]. What I’m trying to gauge is whether or not Alaska can end up being significant enough to reps in another way of [ph] growth for the company over a reasonable period of time.

Yes. I mean, we are the biggest producer up there as you know Doug. And this change in the fiscal regime has opened up opportunities there to stabilize with the claim [ph] from our overall asset-based. Our asset-base up there declines of about 7.5% a year. So the development activity that we have going on just – and field development drilling and in the major projects that we are – that we’re kicking off, the engineering firm [ph] moving towards sanction, we’re hopeful that we should be – that we could stabilize Alaska production. And dependent on the – how the things basically as we [ph] put these development plans together, there’s a possibility that we could see growth in Alaska, but even just stabilizing production in an assay of [ph] that size and that maturity would be a pretty good accomplishment. And I think that’s achievable over the long run. Doug Terreson – ISI Group: Okay, great. Thanks a lot.

Thanks, Doug. Doug Terreson – ISI Group: Yes.

Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead. Paul Sankey – Wolfe Research: Hi, good morning, good afternoon everyone. Matt, thanks to your comments. I had a kind of high level question about your acceleration the Eagle Ford and maybe the Bakken too. How representative do you [ph] think you are at the wider competition that you have in those areas? I guess what I’m driving at is to an extent you were slower to ramp up than some of your competitors, but have – at the analyst meeting put through a significant increase in your outlook for these areas. Do you feel like that’s represents what everyone is seeing or that you’re going to be acting and [ph] moving much faster than your competition? And I guess I was also thinking of any geologic implications you think about where you located them [ph], what you’re seeing against what would be the wider trend in the play. Thanks.

Yes. That’s a good question, Paul. As you know that’s quite a lot geologic [ph]. But even though all these things are essentially in Shale [ph] there’s quite a lot of variability geologically as you move across the Bakken and as you move across the Eagle Ford. We think that the acreage that we have in the Eagle Ford and the Bakken is right in the sweet spot [indiscernible] in the Bakken is pretty clearly the sweet spot. The area where we have [indiscernible] maturity and sickness and pressure and geologic characteristics of our Eagle Ford position is strong. So I wouldn’t expect our results to be the same as everyone else else’s. I would expect the – over the – as we continue this development our returns will be higher than the average returns because of the position in the sweet spot. So you’re right, we didn’t pick – we didn’t ramp up the paces last to some other instead [ph]. We did that very intentionally. We try to do it right and do it fast and we will focus on maximizing value. And I think that the strategy that we’ve adopted in both of those places has gone a – has gone prove that to be the best long-term strategy. Paul Sankey – Wolfe Research: Which I guess would imply that you’re volume growth in this place will outpace the volume growth in the wider play?

I mean, it is very dependent on how many rigs people choose to run. So I couldn’t see if that’s going to be the case for sure. But the – but we are going to see significant continued growth in both of those places as we showed a couple weeks ago. Paul Sankey – Wolfe Research: I understand contextual what’s [ph] you’re feeling about how others are – others are behaving as regard – in competition with you?

You know, it’s really hard to say, Paul, because – I mean, it depends on how quickly we’ve been growing so far and then what we tend to intend to do in the rig counts and I don’t even stay into [ph] that. But the – we are in the middle of the sweet spot in both places [ph] and we are really clear to our consistent strategy on how everyone execute that. And we’re continuing to see upside in both of those places that we’ll exploit over the next few years. Paul Sankey – Wolfe Research: That’s great. And then just to close off, the follow up is how our cost in particularly in the Eagle Ford but also at the Bakken as regards to the activity that you’re undertaking [ph]? How do we look at that? Thanks a lot.

So is that operating cost or capital cost, Paul? Paul Sankey – Wolfe Research: Both please, but really I was thinking more operating, but –

Yes. So our operating cost in both place are really low. I mean, we’re below $5 a barrel in operating cost. So it’s a very low operating cost. That’s one other thing that contributes to the high margins, of course along with the high liquids yield in both places. On our capital cost spaces, I mean, for this – the sort of wells that [ph] we have driven the cost. So we are seeing a pretty much in line with what the rest of the industry are seeing up there. So obviously that competitive on operating – I mean, capital [ph] cost in both place. Paul Sankey – Wolfe Research: Great, [Indiscernible]. Thanks, Matt.

Thank you.

Thanks, Paul.

Thank you. Our next question is from Ed Westlake of Credit Suisse. Please go ahead. Ed Westlake – Credit Suisse: Yes. Two questions probably for Matt. Firstly on the Bakken, you said a couple more years before you get [indiscernible] to think about well done is going [ph] to appreciate. And that’s not too fractures [ph] in probably some of this area is maybe slight off piece [ph] of that. Just on – what is it that you’re trying to see? Is it the sort of the year two and the year three declines to try and get a sense of the economics of some of these wells? And then also we have data from some of these wells for about year so far?

Yes. That’s right, Ed. When you tighten up the well spacing, it’s you saw we would expect [ph] the early period of production to look similar on wells tighter spacing and wider spacing. So it’s not until the – until you’ve got a sense of the decline characteristics that you can really get full understanding if the wells are interfering with each other and competing for the same oil or if not. And so, that – you’re right, you need – you need a few years to get – to get confidence in the – in the overall type of characteristics as you tighten up. You got to be careful not to load [ph] the pilot test to flatter to deceive because in the early days you do expect to see similar performance from wells on tighter spacing. So you do – that’s why obviously and then [ph] we need some time to make sure that we are – that we’re actually developing incremental reserves and having incremental values of tighten well spacing up. Ed Westlake – Credit Suisse: So a little bit premature to have your wells where we can [ph] have confidence in?

I think so. Ed Westlake – Credit Suisse: And then on the Permian, I mean, one of the debates in obviously in the refining space is there’s super light [ph] crudes that are coming out of the Shales. Obviously you have some of that in the Eagle Ford with condensates. You’re doing that test in the Delaware basin and also in the Midland basin. So I’m just wondering if there’s any differences in terms of the – I mean, obviously people quote crude, NGLs and gas but they probably don’t speak enough about the quality of the crudes that are coming out. Can you give us some color on what you’re seeing in terms of those tests [ph] because obviously it will affect the infrastructure that’s required and also the pricing of the molecules?

Yes. Yes. The – you know, this may not a very satisfactory answer Ed, because as you go through this 500 feet of sort of stack opportunity that exists in the Delaware basin in particular, you get a very significant variation from some – in some areas let’s say, gas with a high liquid yield and some areas let’s say is a relatively low API oil, in other areas you got a strong condensate yield. It’s going to be very variable. But it’s clear that over the long run, there’s going to be quite a bit of gas, NGLs condensate and this is going to grow in production in the Permian business as a whole. And as our understanding and the industry’s understanding will matures, that implications will what sort of [ph] off peak and the infrastructure requirements that are [indiscernible] fully evacuate all of these products from the Permian area. Ed Westlake – Credit Suisse: And let more in the Delaware than the Permian?

The – Ed Westlake – Credit Suisse: [Indiscernible].

– but even in the Midland basin too, there’s going to be – there’s going to be some significant variation there. But I think – my sense there’s a wider variation in the Permian than the Delaware but time will tell. Ed Westlake – Credit Suisse: Thank you.

Thanks.

Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead. Blake Fernandez – Howard Weil: Hi, folks. Thanks for taking the question. Back at the Analyst Day, you kind of outlined the production profile where the US unconventionals were increasing and it seems like you were declining Europe and Western Canada, if I’m not mistaken to kind of accommodate to where overall things remained pretty much in lined with your previous guidance. My question I guess is what happens to those European and Western Canadian project? Is that simply being differed? And I guess where I’m wondering is do we have potential into ‘15 for there to be an opportunity to maybe getting [ph] toward the upper end of the 35% range on production?

Yes. We’re very careful that if we are going to be just skeptical in an area [ph] that is deferring, we’re not going to lose opportunities. So the Western Canada, we’ve got huge infantry of opportunities there with a high liquid yields. And the European projects that we spoke about those are the deferrals [ph]. So both of those would give those areas for example are retaining opportunities to add growth in the later part of the – in 2017 and beyond. So I think that we’re making – we’re making pretty judicious capital allocation decisions that balance the short and long-term growth potential in the portfolio. Blake Fernandez – Howard Weil: Okay. So that’s outer year not necessarily next year then, it sounds like?

Yes, probably. But every year we saw – we look at the – we look at the portfolio. One of the beauties of that portfolio is the level of flexibility that we have and the level of optionality that exists. But the – but in general, the ones that we’re talking about are probably more of that than [ph] opportunities to continue growth beyond 2017, but time – but we’ll see, yes. Blake Fernandez – Howard Weil: Okay. Thanks for that Matt. The second one, I apologize if this is a little bit detailed, but I just want to make sure we have steep [ph] from a modeling stand point. The K&I Alaska [ph] LNG, from a reporting stand point, I’m assuming obviously the earnings from that will simply drop into Alaska. But are there corresponding volumes associated with that? I guess I’m just trying to understand if this is just going to be simply margin expansion or if there will be both production and earnings increases.

So there will be both but the production growth is relatively small. So each of those LNG tankers that we will load in K&I [ph] are about – contain about 2.7 high BCF of gas. And our expectation is that about 40% of that are soon will be [ph] equity gas, ConocoPhillips equity gas, and then there will be third party gas that we’re moving for those tankers as well. So there will be some production growth but annualized over the years relatively modest full [ph] [indiscernible] something like that over the year. But the – but we do get – we do get very good margins, good value from that business. Blake Fernandez – Howard Weil: Okay. Thank you.

Thanks, Blake.

Thank you. Our next question is from Doug Leggate of Bank of America. Please go ahead. Doug Leggate – Bank of America Merrill Lynch: Hey, guys. Thanks for getting me on. Jeff, can I start with the DD&A guidance for the year, is that really going to be Bakken loaded compared to what you’ve done in Q1? I think in your analyst that you said [indiscernible] and one or two others might be responsible for that. What should we think of that as a unit DD&A [indiscernible] let’s say at the end of the year when the production is online?

So we give guidance Doug, of $8.5 billion per DD&A for the year. And what you’ve seen we came in like one, nine or so [ph] in the first quarter. It can be back in load and really a few things drive that. One is, I guess we’re starting up whether it was [ph] ramping up in the first quarter, that’s one of the thought things [ph] causing increases in DD&A. We’re going to continue to see increases in unconventional production in our Lower 48 as we go through the year. That will cause DD&A to increase. But probably the largest single item is the when it moves to start up [ph] which is more of a third quarter item for us which causes that DD&A to be back and loaded. In terms of unit rates it’s – you’ll see that go a little bit higher. I don’t have those just right at the top of my head here. But we still think the 8.5 number is the right number for the year. And then you’ll see that – you’ll see that back and loaded a little bit higher numbers in the fourth quarter than in the second and third quarter. Doug Leggate – Bank of America Merrill Lynch: [Indiscernible] now Jeff. So Q1 was about 13 in change [ph]. And the average would be about 15 in change [ph]. So should we think something like $16, $17 kind of number in Q4 or that might be Jeff?

Kind of order of magnitude. I think the way I tend to think about it more is that the DD&A doesn’t – it doesn’t apply to all of our production since you get equity barrels as well. So you got in our portfolio about 200,000 barrels a day of equity accounting barrels which don’t have DD&A associated with them. So I would say our DD&A is probably more like 15, 15.5 right now. And that you may see that drift up a little bit as you go into the third and fourth quarters. Doug Leggate – Bank of America Merrill Lynch: Okay. Thanks.

[Indiscernible] significant volumes in the fourth quarter in particular. Doug Leggate – Bank of America Merrill Lynch: Got it. Second one, my follow up if I may, and just a quick one for Matt. Matt over the years it has been a debate between operators in the Eagle Ford on how you choke your wells. We’ve seen obviously [indiscernible] with some very, very strong rates and there obviously in our well pressure part the reservoir [ph]. There is others like pioneer I guess which are a little bit sort of view [ph] and not [indiscernible] as you guys are, big advocate of kind of choking back to routine reservoir [ph] quality. So I’m just wondering if you could show us how are you approaching that in terms of how you think about the well race that [ph] you’re getting at? Are you choking Bakken or you’re trying to manage towards out longer term recovery or how do you think about it, and I’ll leave it there [ph] there? Thanks.

Yes. So we’re more than – in the latter camp of [ph] managing the early rates. And that’s driven by a few different things. The – we don’t build our single well facilities so that they can handle a very peak rate [ph]. So you’re going to only going to have [ph] a few weeks or a few months even. And so, that’s a reason for doing it. We want to make sure that we keep all the propane in the whole [ph]. We don’t want to be having such a high draw than that were [ph] damage in our completions. And so, we do choke that way significantly. I mean, in the early month, we can have tube and head pressures over 7,000 psi, choke back. And then – and so, we manage it to make sure that we’re not oversizing the facilities and to make sure that we’re damaging the completion. And there are some evidence that that’s the right long-term thing to do as well. You’re not only start operating [ph] from an operation’s perspective so that’s the approach that we take. Doug Leggate – Bank of America Merrill Lynch: Is that significant in terms of the upfront [indiscernible] does that slow you down quite a bit for a meaningful period or is it not really that material and you’re just trying to get a feel for what your decline terms might look like on as well?

So we can – on some of our wells we’ll only be maintaining essentially flat production for several months and so over those months, you’re choking the reservoir back. So it has implications for the first year average rate. And then so there does have implications for the observed decline rate. I think that’s where you’re getting at. Doug Leggate – Bank of America Merrill Lynch: Yeah, [indiscernible] right. Okay, that’s helpful. Thanks a lot.

Thank you.

Thanks, Doug.

Thank you. Our next question is from Faisel Khan of Citigroup. Please go ahead. Faisel Khan – Citigroup Inc.: Thanks. Good afternoon.

Good afternoon, Faisel.

Good afternoon, Faisel. Faisel Khan – Citigroup Inc.: Hi. Just going back to your comments on the Alaska LNG project, you talked about sort of enabling legislation passed in April. Is there any change from the comments in those major analyst meeting in terms of sort of the type of spend pattern you would see for this project over the next few years with this enabling legislation haven’t been passed?

No, we were anticipating that the legislature would support the governor’s approach to this. So our view of the spend profile for APLNG hasn’t really changed. We were hopeful that we’ll get to move in to pre-feed [ph]. And we’ve already selected a high-level concept and I think I’ve discussed in previous calls. But we need to get in to pre-feed [ph] hopefully in the second quarter here and that will last for over 18 months. And then we’ll move in to the feed program which will take two or three years. So really the sanction of the project, we’re probably looking out to 2017 or 2018 before we would actually sanction the full scale project. It takes about a time to [indiscernible] the engineering of something of that sort of scale as you can imagine. Faisel Khan – Citigroup Inc.: Okay, go it. And then just wanted to see if there’s any sort of re-through [ph] for guys drilling program and go low [ph] with the sort of recent results by the Cobalt on this Orca DST, is there anything that changes? So is there anything in that data that changes sort of your outlook for the prospects you have at the end of this year?

Not really. I mean, the way we’ve been encouraged, I mean, by the results for the other operators we’ve had in the area. We picked up acreage before the play had been tested. The results we’ve had sort of seeing other operators and then sort of giving us encouragement that we’re in the right part of the play and we’ll know that before we get to the end of this. We’ll have the first well done hopefully by before the end of the year. But no, no change in our views really as to what the materiality and prospect of [indiscernible] in our Angola position. Faisel Khan – Citigroup Inc.: Okay, just last question from me. On APLNG, you’d given some detail on that at the analyst meeting, but in terms of the progress on that facility, is it still – are all the major sort of components for that facility sort of coming online and are the producing wells sort of also ramping up the way you anticipate? I just want to make sure that there’s sort of no risk here that this – the projects or the slips that we’ve seen with a few others in that part of the world.

No, we’re still pretty confident we’re hitting our milestones. The actual LNG plant itself on Curtis Island, I’m not sure if we’ve shipped all of the modules already but if we haven’t it’s pretty much all of the modules so we’re on track. We’ve built these plants before so we feel pretty confident that we’re on schedule there. And the upstream part of the project, we still have a lot of work to do there. Remember, we’ve got a lot of rigs running. We’re commissioning our gas plants, our handling facilities. But we’re still confident that the middle of 2015, we should be – have the LNG plant itself, the first train [ph] maybe and we should have the gas that we need to get that fully commissioned. So I would say that we feel that the project is on track. Faisel Khan – Citigroup Inc.: Understood. Thank you for the time, appreciate it.

Thanks, Faisel.

Thank you. Our next question is from Roger Reid of Wells Fargo. Please go ahead. Roger Reid – Wells Fargo: Good morning or good afternoon as the case may be.

Hello, Roger.

Hello, Roger. Roger Reid – Wells Fargo: Jeff, a question for you. I look at Q1 results and obviously we can strip out the payment from Canada. We can strip out the working capital advantage here in the quarter yet even after you do that free cash flow is essentially breakeven which given how you structured the company for the next several years, that’s a real positive sign. As you look at the projects that are coming on line kind of the midnight of the 3% to 5% volume growth and 3% to 5% margin, does a quarter like this indicate any sort of maybe you get there sooner in terms of the free cash flow matching or free cash flow – cash flow out matching cash flow in and getting to sort of a neutral or slightly positive free cash flow situation?

Yes, in that we had a quarter with very strong pricing. We had Brent near 110 still and WTI above 100 and very strong North American natural gas prices, of course, which helps our cash flow numbers. I think the way we like to think about it though is we’ve got the growth and production and margins happening which are going to get us to that neutrality point across a wide range of prices and how quickly we get there can be influenced by prices. But by – as we talked about it in the analyst presentation, by 2017, we’ve added considerable production at high margins and we’re going to have the size of cash flows that are going – across a pretty wide range of commodity prices are going to get us to that neutrality point. Yeah, that could back up to 16 if prices were higher. But we don’t count on having prices like we saw on the first quarter long term in order to – as the basis for our plans. Roger Reid – Wells Fargo: Okay. That’s helpful. And then from a strictly operational standpoint, heavy turnarounds last year in the summer and North Sea again this year, maybe, Matt, the question is for you is, is that going to be typical for your North Sea production over the next year, couple of years or are you getting pass sort of a pig in the python moment here, two big years of maintenance in the North Sea in the summer time?

It’s more of the pig in the python thing for the North Sea. We had a huge turnaround last year in Norway, the biggest we’ve ever had. Yeah, there’s no significant turnaround going on in Norway this year or next year because we have [indiscernible] we have Norway in a three-year cycle. But with some short downtime at Eldfisk to tie in for the new Eldfisk II project, but it’s a handful of days from that. This year’s turnaround, it’s a little bit less than last year. I think it’s about 3% less in overall turnaround activity. But you’re right, these have been two relatively big years in turnarounds and that’s somewhat anomalous from that perspective. Roger Reid – Wells Fargo: Okay, that’s helpful. Thank you.

Thank you.

Thanks, Roger.

Thank you. Our next question is from Pavel Molchanov of Raymond James. Please go ahead. Pavel Molchanov – Raymond James: Hi. Thanks for taking the question. In your exploration section, you have a pretty extensive set of upcoming catalyst and I know that historically you’ve talked about kind of shifting away from high-impact wildcatting. Is 2014 somewhat of an exception or do you think you’ll continue this exploration run rate especially Deepwater going forward?

No, I think we’ll continue it. I mean, there are some really interesting wells that we’re drilling this year. But no, our – we’ve built an exploration portfolio that has a good mix of unconventional and conventional opportunities with the – as a portfolio that allows us to do this. So a significant testing this year but continuing that over the next several years in the Gulf of Mexico and elsewhere. I mean, we’re continuing to add to the exploration portfolio. So I’m hopeful that we’ll have the 2015 and the years beyond that we’ll still have an exciting exploration and appraisal program to exploit. Pavel Molchanov – Raymond James: So in the context of kind of flattish CapEx in total, do you anticipate that your offshore spending or just globally will be up year over year in 2014 or –?

No, well, on average I will say that it’s about 15% of our overall capital, about 2.5 billion a year. And some years a bit higher. This year, it will be about 2.1 billion for example. So it’ll be – it’ll fluctuate from year to year but it’s going to average, I think, around that 2.5 billion for the E&A [ph] program overall. And, of course, the split between conventional, unconventional Deepwater and shallower [ph] water, that’s clearly going to fluctuate as the best prospects mature and we get to the drilling phase of the lifecycle. But on average about 2.5 billion a year. Pavel Molchanov – Raymond James: Okay. Thanks very much.

Thank you.

Thanks, Pavel. We’ll take one more question if there is one and then cut it off here.

Our last question is Asik Sen [ph] of Cowen and Company. Please go ahead. Asik Sen – Cowen and Company: Thanks. Good afternoon, guys.

Good afternoon.

Good afternoon. Asik Sen – Cowen and Company: And so I have a question on Malaysia. And Malaysia is a decent part of the growth equation over the next 12 to 18 months driven by Gumusut and KBB. How much Malaysian volume is embedded in the 2014 production guidance and could you provide – what is the incremental contribution from Malaysia expected in 2015?

Off the top of my head, I’m not 100% sure for the component of 2014. I would say it’s around 20,000 barrels a year [ph] for 2014 and that would be higher but I can’t remember how much higher in 2015, maybe another 20 by the time we get to 2015. So as, I mean, that’s a significant part of the growth and a high margin growth is – but how much we’ve produced this year in Malaysia is very dependent upon when Gumusut starts up the – but it is a significant part of the growth and it’s good high-margin growth. And so we have S&P [ph] on production. We have the Gumusut LA [ph] production system [indiscernible] now. We’ll bring on the fuel and flow production system for Gumusut and hopefully in the third quarter here, we’ll bring on Kebabangan and late in the fourth quarter we still have the Malakai project in execution just now. And we’ve got four or five other discoveries in the area that we’re moving forward through the appraisal and engineering stage. So it’s a good piece of business for us and it’s going to contribute to both our production and margin growths over the next few years. Asik Sen – Cowen and Company: Thanks.

Thanks, Asik [ph], appreciate it. And why don’t we call it good day. By all means, call IR if you have any follow-up questions. Thank you so much for joining us everybody and thank you, Christine.

Thank you. And thank you, ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.