Ellen DeSanctis - IR Jeff Sheets - CFO Matt Fox - EVP, Exploration & Production.

Douglas Terreson - Evercore ISI Doug Leggate - Bank of America Paul Sankey - Wolfe Research Paul Cheng - Barclays Ryan Todd - Deutsche Bank Evan Calio - Morgan Stanley Ed Westlake - Credit Suisse John Herrlin - Societe Generale Blake Fernandez - Howard Weil Neil Mehta - Goldman Sachs Roger Read - Wells Fargo Pavel Molchanov - Raymond James Asit Sen - Cowen and Company

Welcome to the ConocoPhillips First Quarter 2015 Earnings Conference Call. My name is Adrian, and I will be your operator for today’s call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Ellen DeSanctis, VP Investor Relations and Communications in ConocoPhilips. Please go ahead.

Thanks Adrian and welcome to all of at calls participants today. I'm joined this morning by Jeff Sheets, our EVP of Finance and our Chief Financial Officer; and Matt Fox, our EVP of Exploration & Production. On this morning's call, Jeff will cover the first quarter financial result as well as our guidance items for the rest of the year and Matt will review the operational highlights for both the quarter and the rest of the year out coming. During Q&A please we would ask that you would limit your questions to one, plus a follow-up. Our page 2 contains our SAFE HARBOR statement, we'll make some forward-looking statements this morning and as always we would ask you to refer our periodic filings with the SEC for description of the risk and uncertainties in our future performance, again thank you for participating and now I'll turn the call over to Jeff.

Thanks Ellen, hello everyone and thanks for joining us today. As you know, we recently held our 2015 Analyst and Investor meeting in New York, where we launched our new three year operating plan and provided details on our long term growth opportunities from our large low cost to supply resource base. We outlined our capital and production plans for next year and how we will achieve cash flow neutrality in 2017 in a arranged to commodity prices. We also reaffirmed our commitment to compelling dividend. In the first quarter results we will discuss this morning, we are going to describe a quarter with strong production growth and good cost control, the one where weak commodity prices over shadowed strong operational performance. If you'll turn to Slide 4, I'll cover our key highlights for the first quarter. We produced 1.61 million BOE per day which is growth of 5% compared to the same period last year. Adjusted for Libya dispositions and downtime. We achieved first production at Eldfisk II by an indent Phase 3 and then Brodgar H3 subsea tie-back. We also advanced five major projects toward startup by the end of the year. And that includes our two major projects with Surmont II and APLNG. Financially our earnings were materially impacted by low prices. We had a $222 million loss or $0.18 per share after adjusting out special items. We generated 2.1 billion in cash from operation excluding impacts from working capital and ended the quarter with 2.7 billion in cash. Costs are our big focus this year. At our analyst and investor meeting we announced the goal to reduce operating cost by $1 billion in 2016 versus 2014 and we are already moving to needle. We’ve made significant progress on capturing deflation capital benefits on our capital program which we also outlined at our analyst meeting. Strategically announced our new three year operating plan that provides predictable growth for about 11.5 billion of capital per year. We’re making good progress on implementing that plan this year, as we ramp down activity across the portfolio. We still grow high margin volumes in this CapEx level and in 2015 we plan to deliver production growth from continuing operations without Libya of 2% to 3% compared to 2014. Now I'll turn the Slide 5 for our more of discussion on earnings. Production came in the high end of guidance we also saw improvement in our cost which as we discussed in the analyst meeting includes production and operating cost, SG&A and exploration expenses, but excluding dry holes and leasehold impairment. Those costs improved 7% compared to the first quarter of last year. When you adjust out the restructuring charges which were a special item for the quarter, you see a 12% improvement in our cost. However sharply lower prices overwhelmed that performance. We realized prices were down 30% compared to last quarter and down 48% compared to the first quarter of 2014. That contributed to the first quarter adjusted loss of $222 million or the $0.18 per share. First quarter segment adjusted earnings were showing a lower right part of this chart. The financial details for each segment can be found on the supplemental date on our website and segment earnings are roughly in line with our sensitivities, except for the lower 48 where adjusted earnings were differentially impacted by lower realizations, both in absolute terms and relative to markers. This impact wasn’t just from crude but also from NGLs and natural gas. Lower 48 earnings also reflected the previously announced dry hole expense from Harrier. And the other international segment adjusted earnings were driven by the MOC 1 dry hole in Angola. If you’ll turn to Slide 6, I’ll summarize our production results for the quarter. Our projections slide follows our usual convention and continuing operations excluding Libya. Our first quarter production averaged 1.61 million BOE per day compared to 1.53 million BOE per day in the first quarter of 2014. The waterfall shows downtime and dispositions were essentially flat year-over-year that leaves net growth of 82,000 BOE per day or 5% growth compared to last year. And of the 82, 61 of the improvements comes from liquids, that’s mostly from oil pants in Canada and conventional in the Lower 48 and Gumusut, Malaysia. Gas was up 21 and some from that’s from domestic gas sales at APLNG that will turn to LNG over time. Now if you turn to the next Slide, I will review our cash flow waterfall. We started the year with 5.1 billion in cash. During the quarter we generated 2.1 billion from operating activities. And this reflects an environment where Brent was at $54 and WTI was at 48.50 and as you know current prices in the strip are higher than these numbers. Moving to the chart we saw a negative impact of about $300 million from working capital. For the quarter we spent 3.3 billion in capital expenditures in investments. As you would expect the capital is front end loaded and tapers off through the year as we complete our major projects and ramp down our activity in unconventionals, so that number is not ratable. After paying our dividend we ended the quarter with 2.7 billion of cash from the balance sheet. Before I leave this slide, let me mention an item that you’ll notice on the cash flow statement in our supplemental information regarding deferred taxes. In the quarter we had -- $555 million benefit to earnings as results of change in tax laws in the UK. This was a special item and not included in our adjusted earnings. This income benefit did not create an immediate cash flow benefit so on the cash flow statement the income benefit is reversed out on the deferred tax line which is why the deferred tax line on cash flow shows a large negative this quarter. Without this tax law change, deferred taxes would have been about an $85 million use of cash in the quarter. I’ll wrap up my comments on the next slide with some guidance for the rest of the year. We provided guidance at our Analyst and Investor Meeting earlier this month. We’re not making any changes to the guidance, but I do want to walk through some of the trends and profiles as we go through the year since most of our first quarter metrics aren’t ratable. We remain on track to achieve our 2% to 3% production growth this year. Our second quarter projection guidance is 1.555 to 1.595 million BOE per day. This reduction from our first quarter mostly reflects the start of our seasonal major turnaround activity. As I just mentioned we expect capital to decrease throughout the year and we remain on track for 11.5 billion of capital this year. Our operating cost guidance of 9.2 billion remains unchanged we did better on a run rate basis in the first quarter and as we continue to work on lowering cost. We could see further improvement in our cost guidance for the year especially if the U.S. dollar stays strong but we’re holding to the current guideline for now. We expect cost to be higher in the second and third quarters as we go into turnaround season. We’ll also see some higher costs in the fourth quarter associated with our major project start up. There is no change to our exploration dry hole and impairment guidance of 800 million for the year. We were higher than that rate in this quarter and we’ll keep you updated throughout the year. DD&A look a little low on run rate but we expect to end the year at about 9 billion. This reflects mix shift changes and major projects coming online through the year. Finally, our corporate segment is in line with the guidance. That concludes the review of our financial performance and guidance. The theme you should be hearing is that we’re focused on executing a prudent plan and we’re delivering on our operational commitments. Now I’ll turn the call over to Matt for an update on our operations.

Thanks, Jeff. Good morning everyone. To begin I’ll quickly go through our segment results for the quarter and then conclude with the preview of some key activities to look out for in 2015. As Jeff mentioned we had a strong operationally, achieving high end of our production guidance and we did that while reducing capital and operating cost and maintaining our relentless focus on safety. So let’s jump into review of the segment performance starting with the Lower 48 in Canada on Slide 10. In the Lower 48 first quarter production averaged 542,000 BOE per day, that’s a 7% overall increase from the first quarter of last year and represents a 16% increase in crude oil production. Production drill in the conventionals but as we’ve previously announced grew to begin to slow as we see the impact of reducing the number of rigs in operation. Overall in Lower 48 we had 15 operated rigs running at the end of April which is more than a 50% reduction from the end of 2014. As a result of fewer rigs we expect production growth to slow in the second quarter and begin a slight decline in the same half of year. In our recent Analyst and Investor Meeting we gave you a lot of details on pilot tests and were continuing to run those test across the segment. In addition to our unconventional activities in a Lower 48 exploration and appraisal activity continues in deepwater Gulf for Mexico. We currently have appraisal wells drilling at Gila and Tiber and unfortunately Harrier was a dry hole. Next we’ll cover Canada. We saw a strong growth from our Canadian business segment during the quarter. We produce 318,000 BOE per day, a 14% year-over-year increase. This growth came primarily from our oil sands assets with Bitumen productions increasing 26% compared to the first quarter of 2014. In Western Canada we successfully completed our winter drilling program with activity focused primarily in the Clearwater, [Blair] and Montney areas. This activity will reduce as we ramp down our rigs from a high of 10 in the quarter to 2 for the remainder of the year. And the oil sands were seeing strong performance from Christina Lake and Foster Creek, the production continuing to ramp up at Foster Creek Phase F and at Sermont II construction is more than 93% complete and final preparations are underway and anticipation of first theme by the middle of the year. Next I will cover off our Alaska and Europe segments from Slide 11. Alaska's average production was an 186,000 BOE per day and activity this quarter was focused on several major projects. CD5 and new development on the west side of [Alpine] is more than 75% complete, drilling is already commenced and were moving ahead with pipeline and module instillation. At drill site 2S facility construction is on schedule and driven will commenced in the second quarter. Both CD5 and 2S or on schedule for startup in the fourth quarter of this year. And we sanctioned the first phase of the north east-west act development, the 1H NEWS project in March and we expect to see first production in 2017. In addition to progress on these projects we resumed operations of the Kenai LNG plan with exports expected to recommence in May. Moving on to Europe first quarter production averaged 209,000 BOE per day. We saw two startups this quarter at the Eldfisk II and Brodgar. Eldfisk II production will continue to ramp through the year as we bring additional wells online and the Brodgar H3 subsea tie-back well achieved first gas in March. Enochdhu is also progressing on schedule and should start in the third quarter. Now let's review Asia specific and Middle East segments and other international segments on Slide 12. In APME we produced 351,000 BOE per day in the first quarter, this is 10% increase compared to the first quarter of last year. Primarily as a result of new production from major projects starts up at Gumusut and S&P in Malaysia. The Gumusut 2014 production system in continuing to ramp up, with full fuel production currently exceeding a 150,000 BOE per day on a gross basis. At KBB production remains constrained awaiting third party pipeline repairs. We achieve first gas from Bayu Undan Phase III program in March and production is continuing to ramp up. The APLNG project was more than 90% complete at the end of March, we achieve first fire from one of our gas turbine generate as in April and we’re progressing towards startup in the third quarter. In our other international segment we’re continuing to focus on our exploration and the appraisal programs, in Angola we spotted the Vali well this month and we’ll update you on a progress there next quarter. We announced the dry hole at Omosi where we encountered the gas column and subsequently plugged the well. In Senegal planning continues for an appraisal program in the fourth quarter. Finally, in Libya our production remains shut in due to ongoing unrest and it remains out of our production guidance for the year. I'll wrap up my prepared remarks on Slide 13 with some key activities to watch in 2015. As Jeff mentioned we’re on track to deliver 2% to 3% production growth this year. For the second quarter we expect to produce 1.555 to 1.595 million BOE per day. The key driver is a typical turn around activity which you see in the upper right chat. Our major turnaround activity for the year is schedule in Alaska, Europe and APNE, in the second quarter and third quarter. These large turnarounds staring June, so we’ll see an impact on production in the second quarter with a more significant impact in the third quarter. In the Lower 48 we expect production to begin to decline in the second half of the year reflecting our reduce rate count. As I just mentioned we ended April with 15 rigs and we expect to run 12 rigs through the second half of the year. Moving to major projects, there are 5 startups expected before the end of the year Surmont 2, APLNG, Enochdhu, CD5 and Drill Site 2S. Production from these five projects were minimal in 2015 but will provide momentum going into 2016. We also have exploration and appraisal activity underway, as I said earlier we spotted the Vali well in Angola this month. We plan to start drilling the Vernaccia and Melmar wells in the Gulf of Mexico and the second and fourth quarters respectively. And we expect to spud the Cheshire well and Nova Scotia in the fourth quarter. In Senegal we plan to start appraisal work before the end of the year and we’ll continue to appraise our existing discoveries in the Gulf of Mexico. So that’s a quick review of the segments. We gave you a lot of information at the recent Analyst and Investor Meeting, so there is not a lot and new to add. We are playing close attention to the things we can control by safely executing our operating plan, capturing capital and operating cost improvements and creating value for shareholders. So this ends our prepared remarks. Now I’ll turn the call back to the operator for Q&A.

Thank you. We’ll now begin the question-and-answer session [Operator Instructions]. And we have Douglas Terreson from Evercore ISI on line with the question. Please go ahead.

A key element of the path to cash flow neutrality that you guys talked about at the Analyst Meeting for the next few years is the shift in spending away from the capital intensive projects in the oil sands and also in LNG and towards unconventionals. And on this point, I wanted to see if we could get an update on when you expect Surmont and APLNG to commence operations and therefore for spending to be significantly curtailed? And second is a $2 billion reduction in spending which is about 20% of the budget kind of a reasonable order of magnitude type reduction for these two projects or is that too high? So if we just get the color on what to expect on capital spending declines.

So Doug, on Surmont II we expect to have first steam sometimes relatively soon certainly by the middle of the year. APLNG we expect to start up there in the third quarter. So it’s pretty much in line with still with what we discussed at Analyst Day and what we’ve been expecting for some time. And as we move from 2015 into 2016 we’ll see a about $2 billion reduction in capital associated with those projects but that won’t be seen from stack up immediately because we still got capital being spent in both of those projects and through the end of the year. Between ’15 and ’16 it’s about $2 billion reduction.

And the next question comes from Doug Leggate from Bank of America. Please go ahead.

Matt one of the things that has changed since the Analyst Day is unfortunately you had a couple of dry holes from a sizeable write-off and I guess I’m mindful that you had a lot of obligations on drilling this year in exploration. When you consider a 1.5 billion in exploration relative to let’s say M&A and opportunity so there’d be both from working interest on their onshore or something like that. How does your exploration appetite look post 2015 once those obligations are rolled off? And I’ve got a follow up.

Clearly we’re disappointed in the results we’ve had from Angola so far we and the whole industry in fact expected that that pre-salt clay in the Kwanza Basin showed a similar characteristic as the pre-salt clay in Brazil, but it’s not planning out that way so far. On the other hand we’re really pleased with the results that we had in Senegal which on the face of it was a more risky play and there as we saved prudent 2 different clay types in the basin, we’re looking forward to getting back there. Of course as you know that’s the nature of exploration. In terms of sort of long term role for exploration, I mean we see explorations role to supplement the resource portfolio with additional opportunities to sustain long term growth and with exploring in plays where we think we can do that at a competitive cost of supply. And over the last five years or so exploration has delivered a lot of success remember the Eagle Ford was an exploration success for us. And during that time we’ve been building the deep-water portfolio and focused initially in the Gulf of Mexico and we already have significant discoveries there too, 3 discoveries in the Gulf of Mexico, additional to Senegal. So we’re continuing to test the portfolio, but clearly exploration has to compete for capital in what is a very competitive investment portfolio. And as we outlined when we describe the resource base and the cost of supply of our resource base a few weeks ago, but we see that as good discipline there, to make sure that we’re only committing to exploration opportunities that we think we can compete against our resource base.

I guess like kind of a related question, I was going to have another follow up but I don’t want to take up too much time so maybe I’ll stick with this one. But I’m thinking really more about the scale of the discretionary capital because 1.5 billion is still a descent chunk of your spending this year, so where would you expect that to move towards let’s say in a lowered oil price environment should this continue? I’ll leave it there. Thanks.

Thanks Doug. Well in the operating plan that we laid out a few weeks ago, we’re anticipating a level of about 1.5 billion this year, next year and in 2017. We can revisit that to some extent, but that sort of expectation as of sort of planned average over the next few years.

And the next question comes from Paul Sankey from Wolfe Research. Please go ahead.

Good afternoon everybody. A couple of quickies. You mentioned on Libya that you are shut in, is that full-shore shut in or can someone else be producing those volumes and the follow up which is also a fairly quick and clean, could you talk a little bit more about the Kenia sales, I'm not sure who is buying that, Ohio is selling it and then I have a longer term follow up.

So Libya yes that productions shut in and we are confident of that shut in in the Waha concession, so nobody else is producing it. The Kenia and we started operations up this month, will sell their cargos starting next month, we have growing our sales five or six cargos and they are going to Japan.

Is that kind of spot sales. Matt?

Yes.

Got it. Matt, one of the things that people have been talking about since your analyst meeting is your comments on the pilot that you ran and pilots that you're continuing to run in the Eagle Ford. Could you just expand and talk about what could be the next catalyst in terms of news flow on those pilots? Thanks.

Yes, thanks Paul. So, we are running several different pilots in the Eagle Ford in particular, in the upper Eagle Ford we are running I think 7 different pilots and across the over -- across different parts of Eagle Ford to test the triple stack concept that we talked about and just to understand, what parts of our geographic extent of the Eagle Ford is going to be meaningful to the triple stock development. So, those pilots are going to be drilled, as we go through this year and we’ll start to see results, as we head into next year, so they I don't expected it to drill any definitive conclusions on just how much of the aerial extend will be developed that way until maybe the later part or next year frankly because a lot this is understanding till the wells began to interfere with each other and you don't see that early in the wells life. And off course we're still running this stimulated growth volume pilot that we talked about and we're going to get lot of new information from this year that from a longer term basis in terms of optimizing the Eagle Ford as a whole and other unconventional plays that we have in the portfolio.

Yes, Matt, just remind us what the uplift is in terms of performance that you I think we're anticipating, if I'm not wrong. I can't remember if you've seen initial results or whether you anticipate.

Yes. The initial results from single well pilots in the upper Eagle Ford basically showed the production was the same as to Lower Eagle Ford and of what we haven’t test yet is windows are drilled in the context of a pattern of wells, do we see interference. And that's what we’re testing with these days seven pilots that were running now.

So, there was actually a number I think associated with what you might get in terms of improved performance?

No, I don’t think we went into that yet Paul, because we really need to understand the nature of this pilots, how they perform when they’re confined with other wells, we didn’t actually make any view prediction about what we expect to find. We’d rather do that after we're seen the pilot test results.

Okay and as you said this something that's going to take a bit of time to really -- maybe by next analyst meeting I guess?

Yes it's possible but then it may take you to longer than that, we don't want jump the gun and I wouldn’t, we’re definitely encouraged as we said a few weeks ago, but we want to make sure that we’re calibrating properly before we make any claims with that what there incremental reserves will be for example.

And the next question comes from Paul Cheng from Barclays. Please go ahead.

Hi, Guys. Two quick question. Matt can you share what EPLNG the cash operating cost and the tax regime?

We’re not in the operating phase yet for EPLNG, so the -- I don’t have the operating cost number of the top of my head. The tax regime is a tax and royalty and regime with royalties at the Queensland level and taxes at the federal level.

So it’s typical like 10% on the royalty and 30% PPT or TIP?

Yes. This is actually not fully resolved yet, there is some discussion still under way with the Princeton government on the nature of how their oil could be calculated, so I can’t really give you a definitive answer on that yet. Paul.

I'll add a little bit to what Matt said on the tax side, the taxes are actually paid down at the ATLNT at kind of corporate level and there is going to be as you can imagine with a big capital investment project like that from a cash flow perspective, a fair business tax Shale from depreciation on the investment particularly in the early years of the project.

So, Jeff, does that mean that during the first five years that we should assume there's not really had the tax that APLNG need to pay?

I don’t know but I can give you that precisely in the number that depends on price levels as well. But if we had current kind of prices, that's probably not a bad assumption.

Okay. And then, Matt, can you -- maybe I missed it; can you tell me what is the Eagle Ford, Bakken and Permian production in the first quarter? And if you have any number you can share in terms of the exit rate for this year?

Yes the Eagle Ford was around the 175,000 about first quarter, and the Bakken was around 55,000 barrels a day in the first quarter. Permian was less than 10, on the unconventional side we also have significant conventional production but in the Shale’s side it was less than 10. So what we expect to happen forward is we the aggregate production from the unconventionals is going to grow a little bit into the second quarter and then it’s going to gradually decline as we exit the year so the fourth quarter exit rate is going to be quite similar to the first quarter rate in aggregate for the Shale plays.

And you start increasing the rig count next year again? I think that’s the current trend so we should assume that they will resume the growth or that the increase in rig count for next year will be only sufficient that to hold it flat?

It depends a bit on the pace of the build of the rigs back up you should really assume that it’s going to hold it flat because by the time we get the wells back and running again through the drilling and completion and hook up and bringing them on production. We’re actually going to see the decline in production from those plays continue into the early part of 2016 and then start to increase towards the end of 2016 and based on our current assessment of how we’ll put rigs back to work, they’re probably relatively flat from the average of 15 to the average of 6.

And our next question comes from Ryan Todd from Deutsche Bank. Please go ahead.

So a couple of questions on the -- there have been several recent news stories around some of your M&A efforts of potential assets that you might consider selling, any additional commentary that you might have regarding potential M&A programs, are these bringing the people approaching you or are these assets that you are marketing, are we still looking at kind of smaller 500 to $1 billion sized deals. Any thoughts around that?

We’re always in with a portfolio of our size looking at what going to we do in the way of portfolio optimization. As we go forward we’re not going to be pre-announcing that we’re marketing particular assets. You will hear stories probably on the marketplace that we’re testing values on that and that’s what we’ll always be doing as part of a prudent optimization of the portfolio. As we’ve said I think it’s prudent to think in terms of a company our size will do something with its asset portfolio every year and we talked about it, whether that’s a $1 billion so a year there is probably a good go by. It really just depends on whether we’re getting full value for the assets. It’s always about whether we can sell the assets or at least what we think we could receive from in-value if we kept them in our portfolio. And we don’t know what that number is going to be but there will be some level of asset sale.

And maybe shifting gears a little bit, in Alaska at the Analyst Meeting you guys had given guidance on Alaska production and you have a couple of projects turning up later this year. I guess can you talk a little about your production expectation in Alaska and maybe that of the industry with these differentials had kind of bounce around quite a bit. Maybe if you look out one or two years, what’s the direction that you would expect in terms of crude realizations and activity levels in general in Alaska?

We expect with the major projects that we’re doing and the development drilling that we’re doing in Alaska that we’re likely to hold production relatively flat for the next three years and beyond that actually. And we had a reasonably good representation of the overall Alaska production because we get the big production areas we look to drill Kuparuk and Alpine so I think if you at us our macro view of Alaska about wouldn’t be about basis to think about that. In terms of realizations I think currently realizations are -- for the E&S, crude are both $2 or $3 below Brent and we have taken one cargo this year to Asia and one last year and we always have that option if that’s what we chose to do.

And the next question is from Evan Calio from Morgan Stanley. Please go ahead.

I know Conoco remains focused on your yield bridging the cash flow neutrality; how would you respond to the commodity recovery, meaning when you seek to increase cash cushion, balance sheet repair just some level which might dictate or delay any potential reacceleration?

I think our first reaction to an increase in prices is going to be to reduce the amount of cash we use and the amount of debt we might borrow, particularly as we think about the activity levels in 2015 and 2016.

Any idea in terms of kind of levels or price signal that you need to see to reaccelerate?

I think in the near term I am not sure we see a price level that would cause us to reaccelerate and we are going to want to see what that if there is some acceleration in prices and it's got a more lasting effect as well. I mean we are taking anything about, what's going on with our capital program as Matt mentioned earlier we have a couple of billion dollars rolling off on from certain amount of APLNG and we are -- our plans already accelerating capital spending in places like North American and un-conventional, as we go into 2016.

Right, right, no, I understood that. Maybe to the other side could you quantify or provide a range of how much more you could borrow and still maintain you’re A rating?

It’s a bit of a -- I don’t think I can actually quantify that because the rating agencies won't tell you exactly what number that is. As I think we would characterize the same way we characterized it on our call last time, we think the amount that we do borrow is going to be -- it could be enough that would cause us to see a one notch downgrade from what's currently A1 at Moody's and A the middle single A with the Standard & Poor’s and with Fitch. And what their have you seen all the agencies do have our credit rating outlook on a negative, so that that's they are going to be anticipating that. But once if that were to happen that were moves into a range, what we are comfortable that there is plenty of space there to meet, whatever borrowing needs we might have in 2015 and 2016 as we head towards cash flow neutrality in 2017.

And our next question comes from Ed Westlake from Credit Suisse. Please go ahead.

I just wanted to dive a little bit into shale again. I've seen some very strong performance from you guys this year, even stronger in the Bakken. Is there anything you are doing differently this year?

And we were continuing to work through our optimizations, Ed that we discuss a little bit few weeks ago, optimizing the completion design and the well length and the well placement and so on. I wouldn’t say there is anything fundamentally different going on there, but we are and we are moving towards more pad drilling, 90% of the wells have become pad drilling, but there is not a fundamental change there, the guys are just executing well.

And then on the shale program and obviously a massive cut in rigs, and obviously you do modeling on volumes probably to a far greater degree than we do from the outside. But are there any risk that you undershoot on volumes or you feel pretty comfortable about the trajectory you just outlined?

I feel pretty comfortable, although for obvious -- the answer I gave earlier on what we expect of our Eagle Ford and Permian and Bakken production to do this year and into next year. Assuming that we do increase our rigs in the way that we intend to next year.

And then coming back to Doug's question on -- you know obviously people are going to focus a lot on cash flow margins and you got these big projects coming up. When do you reckon that APLNG Surmont will sort of hit what you think is sort of a peak operational cash flow? Obviously, whatever the macro gives at that point is a separate discussion.

Yes. So, peak on both them really for a different reasons, peak operational cash flows in 2017, and for someone to do this because it takes a while as you know to build the steam chambers and ramp up production in the site B project, and in the case of APLNG, we’ll bring the first train on this year, it will be next year before we bring the second train on, so the first year that will have both trains running will be in 2017. So in both cases it will be 2017 before they fully contribute at their plateau rate and off course that rate will continue in both projects for a decades.

And our next question comes from John Herrlin from Societe Generale. Please go ahead.

Two quick ones. You cut your Lower 48 rigs by over half. How many frac spreads are you running, Matt?

Let’s see, I would say overall we’re probably running three or four, it varies a little bit, but I think three full time and fore if we -- occasionally, so that's our total spread to support to those rigs.

Okay, great. And at Global you had a passing comment about you being disappointed with the geology. Can you elaborate a little bit more on that? That is it for me.

Okay. So we've had two dry holes there in the campaign, the first at Kamoxi was basically the reservoir wasn't developed, as you know better than most these cabinet reservoirs are quite difficult to predict across the development and in the case of porosity just wasn't developed there. For Omosi porosity was developed, we did see good reservoir faces, but it was gas filled. So the fetch area was feeding into Omosi was overcooked. So two different reasons for the failures on those wells and that basin as a whole is a bit less predictable and then we are talking going in. There is a valley well that we’re drilling is actually testing a different play than the Omosi and Kamoxi wells were, so will see how that goes.

And our next question comes from Blake Fernandez from Howard Weil. Please go ahead.

Hi, folks. Good morning. Jeff, back on the balance sheet discussion previously, I am just curious, can you remind me if Libya?

No we've not impaired Libya. For us we would have to see if there is some kind of view that there was a permanent loss of that concession before we really need to do an impairment.

Okay. Offhand do you remember what kind of capital employed or anything on that asset?

You know, I don’t know that number off the top of my head it’s on the order of a $0.5 billion, but I wouldn’t -- I am not sure exactly what that number is.

No worries, that's fine. The second question, there has been a lot of discussion with the recent rise in commodity prices here with some of the E&Ps potentially layering in hedges. I know historically that has not been something that Conoco has enacted. But I didn't know if there was any new internal debate as to the potential benefits of doing that specifically for your Lower 48 activity?

No, we take the portfolio approach to thinking about our cash flows. So we wouldn’t really think about doing it for one particular part of our portfolio. Generally our philosophy that we’ve talked about before hasn’t changed, we feel like hedging is by definition kind of zero sum game in terms of value and it’s one of the reasons we keep a strong balance sheet is to be able to handle the fluctuations in commodity price.

And our next question comes from Neil Mehta from Goldman Sachs. Please go ahead.

So there has been a lot of talk, sticking with the Lower 48, at what price signal does U.S. shale production start reaccelerating? And as a major U.S. player, not speaking specific to your portfolio, just wanted to get your perspective at what level that might occur, whether it's $60 WTI or $65 WTI or the range of outcomes. And how quickly can the industry bring back that production and what potential bottlenecks to bring that supply back online are?

I can’t speak for the industry as to what price signal they might be looking for, it would certainly be a cash flow of a big impact on that as well. But in our plans we are planning the increases within 2016 modestly, but we’re going to increase as we move into 2016 and that’s in the anticipation of some continued recovery in prices. And in terms of the capacity clearly we’ve laid down quite a bit of rig and the completion and capacity. And that can be brought back relatively quickly. There is a flexible industry that we have in the Lower 48, so exactly how quickly people bring these back on will be a function of the cash that we wanted to back in and the what they see us be an efficient and see if we are could bring the rigs and the completion crews back to work. So I don’t think I answered your question very satisfactorily, but that’s the best I’ve got.

You got me there philosophically. And then, Matt, I should've asked you this question at the Analyst Day. But the $1 billion of the cost reduction program, that operating cost reduction target, how sensitive is that to the commodity price? Or do you think that is commodity agnostic?

Our intention is to make that commodity agnostic, for the most part we’re looking to get them a sustainable cost reductions through this effort. Now we’re going to get some fluctuations associated with exchange rates and with the changes in the deflationary environment but our focus is on getting structural cost reductions that we can sustain through the cycles.

And your next question comes from Roger Read from Wells Fargo. Please go ahead.

I guess I would like to ask about the price realization. It seemed a little bit -- well, at least relative to our expectations -- a little weak in the first quarter both on oil and gas. And I was wondering how much of that may just be a function of timing, how much of that is maybe some of the differentials we have seen or a mix of production kind of oil condensate, NGLs, et cetera, working its way through. And the final part of the question, as prices have been recovering does that help on realizations as we think about Q2 and Q3 potentially?

So what we saw in the first quarter was that realizations were probably weaker than what people were expecting primarily in the Lower 48. For example I think our Lower 48 crude oil realization was closer to $40 where WTI was like 48.5 or so for the quarter. What we’re seeing is just a tough quarter for realizations a lost supply in the marketplace. The differentials that we’re seeing are not that different -- that we saw in the first quarter and not that different when we were in a $50 price environment and they were when we were at much higher price environment, but still kind of that same level differentials. I think we would expect to see kind of differentials improve in terms of kind of percent of marker realized and maybe some slight improvement in any kind of absolute levels of differentials as well. The differentials were tough because they were kind of tough across all commodities for us in the Lower 48 as well, just it’s tough on NGLs, oil and natural gas.

Yes, I was just wondering was there any -- I don't remember all the exact moving parts right here, but I am just saying was that a function of any more either a lighter crew that you are selling or a condensate barrel or just it just is what it is? I am just trying to understand.

It's just little bit -- that’s just what the market was in the first quarter, is something really that fundamentally changed in our product mix or the quality of any of the products that were selling that would lead to that kind of differential.

Okay, thanks. And then on related follow-up. The changes in taxes in the UK, give us an idea of maybe how you characterize that. Is it that really helped? It's a nice first step but we need to see more? Does it change anything in terms of how you think about investing over the next say two years, which seems pretty well locked down in terms of expectations on the CapEx side, but it could help on a post 2017 environment?

Yes. Roger, it helps, the U.K. sector needs as much help as it can get, so the help on the tax rate, it was welcomed. The simplification and broadening of the and uplift on capital is going to help us realize about 12% uplift now in capital when you go through the math and so this -- we’ll build only if we’re thinking as a thinking about overall investment portfolio over the next few years, but it’s certainly was a move in the right direction by the UK government.

And our next comes from Pavel Molchanov from Raymond James. Please go ahead.

Your guidance for exploration in dry hole $800 million for the year, you said it is unchanged. But it looked like Q1 was well above your annual run rate. So, does that imply that there is going to be a significant reduction in that expense line item as the year progresses?

Yes, it does and by its nature dry hole cost is going to be pretty lumpy and we happen to have both the Harrier well and the Omosi well in Enochdhu hit in the first quarter. You could have quarters where the numbers really low, no well actually gets to TD during that quarter and it could be lumpy again later in the year. But as we look at the overall kind of balance of the year, we think the guidance that we gave at the Analyst Presentation still make sense.

Okay. And then you've talked about some of the areas, where you are seeing cost savings that look pretty encouraging. Are there any operating areas where on the other hand costs have been surprisingly sticky, where you are not seeing the savings that perhaps you would have anticipated by this point?

Are you talking about operating cost, Pavel or capital cost?

I guess more on the CapEx side.

What we're seeing in this in more rapid response in the Lower 48 and other parts of the company and we expect to see some deflation kicking in and we’re already asking some in our international business, but there is a this coming more slowly I mean it's what we've anticipate is coming more slowly from the international business, but it's come very rapidly in the Lower 48 and but we've build in build that sort of the trend, as we anticipated into our expectations of the deflation and we do expect to see those reductions coming in the international over the next several months.

And we have a question from Asit Sen from Cowen and Company. Please go ahead.

Thanks. Good morning. Matt, just wanted to get your views on the recent industry debate on refracking in the unconventional. And if I could ask two questions on that. First, from Conoco's vantage point what is new in the technology offering that you are seeing? And second, within your portfolio where do you see the most relevance? And if you could frame that on a risk reward context, please?

Yes. So, we have been running some refracs in our portfolio and some using the diverter sort of technology some just basically straight that pumping the new fracs with existing pairs and somewhat new paths so we’ll be testing a few and the area that we’re seeing the best uplift is as you would expect are our older wells where we pumped smaller jobs with wider spacing so they -- we see some potential there and it’s particularly in wells that were drilled a few years ago and more recently drilled well, so we are continuing to evaluate that, but there is some -- certainly some upside potential.

I was just turning the call around to managements for final comments.

That's terrific. Really we appreciate everybody's questions and comments obviously feel free to come back to us if you didn't get your questions answered. But we're going to give you back a little bit of time here again. Thank you for participating and we look forward to staying in touch with all of you. Thank you.

Thank you. Ladies and gentlemen. This concludes today’s conference. Thank you for participating. You may now disconnect.