Earnings Call: Q1 2015

Apr 30, 2015

Welcome to the ConocoPhillips First Quarter 2015 Earnings Conference Call. My name is Adrienne and I'll be your operator for today's call. At this time, all participants are in a listen only mode. Later, we'll conduct a question and answer session. Please note this conference is being recorded. I'll now turn the call over to Ellen DeSantis, VP, Investor Relations and Communications, ConocoPhillips. Please go ahead. Thanks, Adrienne, and welcome to all of our call 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 and Production. On this morning's call, Jeff will cover the Q1 financial results 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 upcoming. During Q and A, please would ask that you limit your questions to 1 plus a follow-up. Page 2 contains our Safe Harbor statement. We'll make some forward looking statements this morning. And as always, we'd ask you to refer to our periodic filings with the SEC for a description of the risks and uncertainties in our future performance. Again, thank you for participating. And now I'll turn the call over to Jeff. Thanks, Alan. Hello, everyone, and thanks for joining us today. As you know, we our large low cost of supply resource base. We outlined our capital and production plans for the next few years and how we would achieve cash flow neutrality in 20 17 in a range of commodity prices. We also reaffirmed our commitment to a compelling dividend. In the Q1 results we will discuss this morning, we're going to describe a quarter with strong production growth and good cost control, but one where weak commodity prices overshadowed strong operational performance. If you'll turn to slide 4, I'll cover our key highlights for the Q1. We produced 1.6 1,000,000 BOE per day, which is growth of 5% compared to the same period last year, adjusted for Libya dispositions and downtime. We achieved 1st production at Elphist II by Nandan Phase III in the Vrodgar H3 Subsea tieback. We also advanced 5 major projects towards startup by the end of the year. And that includes our 2 mega projects at Surmont II and ATLNG. Financially, our earnings were materially impacted by low prices. We had a $222,000,000 loss or $0.18 a share after adjusting out special items. We generated $2,100,000,000 in cash from operations excluding impacts from working capital and ended the quarter with $2,700,000,000 in cash. Costs are a big focus this year. At our Analyst and Investor Meeting, we announced the goal to reduce operating costs by $1,000,000,000 in 2016 versus 14 and we're already moving the needle. We've made significant progress on capturing deflationary capital benefits in our capital program, which we also outlined at our Analyst Meeting. Strategically, we announced our new 3 year operating plan that provides predictable growth for about $11,500,000,000 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 at this CapEx level. And in 2015, we plan to deliver production growth continuing operations without Libya about 2% to 3% compared to 2014. Now I'll turn to slide 5 for more of a discussion on our earnings. Production came in at the high end of guidance. We also saw improvement in our operating costs, which as we discussed at the Analyst Meeting includes production and operating costs, SG and A and exploration expenses excluding dry holes and leasehold impairment. Those costs improved 7% compared to the Q1 last year. When you adjust out the restructuring charges, which were a special item for the quarter, you see a 12% improvement in our costs. Driver's sharply lower prices overwhelmed that performance. Realized prices were down 30% compared to last quarter and down 48% compared to the Q1 of 2014. That contributed to the Q1 adjusted loss of $222,000,000 or the $0.18 a share. 1st quarter segment adjusted earnings are shown on the lower right side of this chart. The financial details for each segment can be found in the supplemental data on our website. And segment earnings are roughly in line with our sensitivities except for the lower $48,000,000 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 40 segment adjusted earnings were driven by the Amosi 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 Q1 production averaged 1,610,000 BOE per day compared to 1,530,000 BOE per day in the Q1 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 $82,000,000 $61,000,000 of the improvement comes from liquids. That's mostly from oil sands in Canada, unconventionals in the Lower 48 in Gamusset in Malaysia. Gas is up 21% and some of that's from domestic gas sales at APLNG that will turn to LNG over time. Now if you turn to the next slide, I'll review our cash flow waterfall. We started the year with $5,100,000,000 in cash. During the quarter, we generated $2,100,000,000 from operating activities. And this reflects an environment where Brent was at $54 WTI was at $48.50 And as you know, current prices in the strip are higher than these numbers. Moving through the chart, we saw a negative impact of about $300,000,000 from working capital. For the quarter, we spent $3,300,000,000 capital expenditures and investments. As you would expect, 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 $2,700,000,000 of cash on 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 a $555,000,000 benefit to earnings as a result of change in tax laws in the U. K. This is 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 the cash flow statement shows a large negative this quarter. Without this tax law change deferred taxes would have been about an $85,000,000 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 Q1 metrics aren't ratable. We remain on track to achieve our 2% to 3% production growth this year. Our 2nd quarter production guidance is 1 point 555,000,000 to 1,595,000 BOE per day. This reduction from our Q1 mostly reflects the start of our major turnaround activity. As I just mentioned, we expect capital to decrease throughout the year and we remain on track for $11,500,000,000 of capital this year. Our operating cost guidance of $9,200,000,000 remains unchanged. We did better on a run rate basis in the Q1 and as we continue to work on lowering costs. 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 heavy turnaround season. We'll also see some higher cost in the 4th quarter associated with our major project start ups. There's no change to our exploration dry hole and year. DD and A looked a little low on run rate, but we expect to end the year at about 9,000,000,000 dollars This reflects mix shift changes and major projects coming online through the year. Finally, our corporate segment is in line with 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 commitment. 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 a preview of some key activities to look out for in 2015. As Jeff mentioned, we had a strong quarter operationally, achieving the high end of our production guidance and we did that while reducing capital and operating costs and maintaining a relentless focus on safety. So let's jump into a review of the segment performance starting with the Lower 48 in Canada on slide 10. In the Lower 48, 1st quarter production averaged 542,000 BOE day. That's a 7% overall increase from the Q1 of last year and represents a 16% increase in crude oil production. Production drew in the unconventionals, but as we have previously announced, growth will begin to slow as we see the impact of reducing the number of rigs in operation. Overall, in Lower forty eight, 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 again a slight decline in the second half of the year. Our recent analyst and investor meeting, we gave you a lot of detail on pilot tests and we're continuing to run those tests across the segment. In addition to our unconventional activities in the Lower forty eight, exploration and appraisal activity continues in the Deepwater Gulf of Mexico. We currently have appraisal wells drilling at Gila and Tiber. 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 produced 318 1,000 BOE per day, a 14% year over year increase. This growth came primarily from our oil sands assets with bitumen increasing 26% compared to the Q1 of 2014. In Western Canada, we successfully completed our winter drilling program with activity focused primarily in the Clearwater, Clear and Modern areas. This activity will reduce as we ramp our rigs from a high of 10 in the quarter to 2 for the remainder of the year. In the oil sands, we're seeing strong performance from Christina Lake and Foster Creek with production continuing to ramp up at Foster Creek Phase F. And at Sermon 2, construction is more than 93% complete and final preparations are underway in anticipation of first steam by the middle of the year. Next, I'll cover off our Alaska and Europe segments on slide 11. Alaska's average production was 186,000 BOE per day and activity this quarter was focused on several major projects. CD5, a new development on the west side of Alpine is more than 75% complete. Drilling has already commenced and we're moving ahead with pipeline and module installation. At Copartic Drill Site 2S facility construction is on schedule and drilling will commence in the Q2. Both CD5 and IIS are on schedule for start up in the Q4 of this year. And we sanctioned the first phase of the Northeast West Act development, the 1H news project in Coparac in March and we expect to see production in 2017. In addition to progress on these projects, we've resumed operations at the Kenai LNG plant with exports expected to recommence in May. Moving on to Europe. 1st quarter production averaged 209,000 BOE per day. We saw 2 start ups this quarter at Elfress II and Brodgar. Elfress II production will continue to ramp through the year as we bring additional wells online. And the Brodgar H3 Subsea tieback well achieved 1st gas in March. Enoch Kedou is also progressing on schedule and should start in the second in the Q3. Now let's review our Asia Pacific and Middle East segments and other international segment on Slide 12. In APME, we produced 351,000 BOE per day in the Q1. This is a 10% increase compared to the Q1 of last year, primarily as a result of new production from major projects start ups at Gamusut and SMP in Malaysia. The Gamusut floating production system is continuing to ramp up with full fuel production currently exceeding 150,000 BOE per day on a gross basis. At HBB at KVB, sorry, production remains constrained awaiting third party pipeline repairs. We achieved first gas from our Bayou Undan Phase 3 program in March and production is continuing to ramp up. The APLNG project was more than 90% complete at the end of March. We achieved first fire from 1 of our gas turbine generators in April and we're progressing towards start up in the Q3. In our other international segment, we're continuing to focus on our exploration and appraisal programs. In Angola, we spudded the valley well this month and we'll update you on our progress there next quarter. We announced the dry hole at Amose where we encountered a gas column and subsequently plugged the well. In Senegal, planning continues for an appraisal program in the Q4. 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 Q2, we expect to produce 1.555000000 to 1.595000000 BOE per day. The key driver is a typical turnaround activity that you see on the upper right chart. Our major turnaround activity for the year is scheduled in Alaska, Europe and APME in the 2nd and third quarters. These large turnarounds start in June, so we'll see an impact on production in the second quarter with a more significant impact in the Q3. In the Lower forty eight, we expect production to begin to decline in the second half of the year, reflecting our reduced rig 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. We have 5 start ups expected before the end of the year at Surmont 2, APLNG, Enokdu, CD5 and Drill Site 2S. Production from these five projects will be minimal in 2015, but will provide momentum going into 2016. We also have exploration and appraisal activity underway. As I said earlier, we studied the Vale well in Angola this month. We plan to start drilling the Vernachan and Melmar wells in the Gulf of Mexico in the second and fourth quarters respectively. And we expect to spud the Cheshire well and Nova Scotia in the Q4. 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 segments. We gave you a lot of information at the recent analyst and investor meetings. So there's not a lot new to add. We are paying 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 and A. Thank you. We'll now begin the question and answer And we have Douglas Terreson from Evercore ISI on line with the question. Please go ahead. Good morning, everybody. Good morning, Doug. 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 $2,000,000,000 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 some color what to expect on capital spending declines? Yes. So on Doug on Surmont 2, we expect to have first steam sometime relatively soon, certainly by the middle of the year. APLNG, we expect to start up there in the Q3. 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. As we move from 2015 into 2016, we'll see about a $2,000,000,000 reduction in capital associated with those projects. But that won't be seen from start up immediately because we still have very capital being spent on both of those projects through the end of the year. But between 2015 and 2016, it's about a $2,000,000,000 reduction. Okay. Great. Thanks a lot. Thank you, Doug. Our next question comes from Doug Leggate from Bank of America. Please go ahead. Thanks. Good morning, everybody. Matt, one of the things that has changed since Ciano's days, unfortunately, you had a couple of dry holes with a sizable write off. And I guess, I'm mindful that you had a lot of obligations on drilling this year and exploration. But when you consider $1,500,000,000 on exploration relative to let's say M and A and opportunities whether it be bolt on working interest on the onshore or something like that, how does your exploration appetite look post 2015 once those obligations have rolled off? And I've got a follow-up please. We know clearly we're disappointed in the results we've had from Angola so far. We and the whole industry in fact expected that pre salt play in the Kwanzaa Basin should have similar characteristics to the pre salt play in Brazil, but it's not panning out that way so far. On the other hand, we were 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 said, we've proven 2 different play 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 the sort of longer term role for exploration, I mean, we see exploration's role to supplement the resource portfolio with additional opportunities to sustain long term growth. And we're exploring in place where we think we can do that at competitive cost of supply. And over the last 5 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 deepwater portfolio and focused initially in the Gulf of Mexico. And we already have significant discoveries there too, 3 discoveries in the Gulf of Mexico in addition to Senegal. So we're continuing to test the portfolio. But clearly exploration has to compete for capital and what is a very competitive investment portfolio. And as we outlined when we described the resource base and the cost of supply of that resource base a few weeks ago. But we see that as good discipline to make sure that we're only committing to exploration opportunities that we think we can compete against that resource base. I guess 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, Matt, about the scale of the discretionary capital because $1,500,000,000 is still a decent chunk of your spending this year. So where would you expect that to move towards let's say in a lower oil price environment should continue? I will leave it there. Thanks. Okay. Thanks, Doug. Well, in the operating plan that we laid out a few weeks ago, we're anticipating a level of about $1,500,000,000 this year, next year and in 2017. We can revisit that to some extent, but that's our expectation as a sort of an average over the next 3 years. All right. Thanks very much. Thank you. 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're shut in. Is that for sure shut in or could someone else be producing those volumes? And the follow-up which is also fairly quick I think is could you talk a little bit more about the Cannae sales? I'm not sure who's buying that or how you're selling it. And then I have a longer term follow-up. So Libya, yes, the production shut in and we're confident that that shut in the Waha concession. So nobody else is producing it. Kenai, we started operations up this month. We'll sell their cargoes starting next month. We're going to sell 5 or 6 cargoes and they're going to Japan. Is that kind of spot sales, Matt? Yes. Got it. Matt, one of the things 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 next catalyst in terms of new flow on those pilots? Thanks. Yes. Thanks, Bob. So we're running several different pilots in the Eagle Ford and particularly in the Upper Eagle Ford. We're running, I think it's 7 different pilots 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 amenable to the triple stack 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 I don't expect it to draw any definitive conclusions on just how much of our aerial extent will be developed that way until maybe the later part of next year, frankly, because a lot of this is understanding that the wells begin to interfere with each other and you don't see that early in the wells life. And of course, we're still running the stimulated drop volume pilot that we talked about and we're going to get a lot of new information from that this year that will be important in the 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 were anticipating if I'm not wrong. I can't remember if you'd seen initial results or whether you anticipate? Yes. The initial results from single well pilots in the Upper Eagle Ford basically showed that the production was the same as the Lower Eagle Ford. But what we haven't tested yet is when those are drilled in the context of a pattern of wells do we see interference. And that's what we're testing with these 7 pilots that we're running. 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 these pilots, how they perform when they're confined with other wells. We didn't actually make any real prediction about what we expect to about what we expect to find. We'd rather do that after we've seen the pilot test results. Okay. And as you said, this is something that's going to take a bit of time to really maybe by next analyst meeting, I guess. Yes, it's possible, but it may take even longer than that. We just we don't want to jump the gun on it. 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 about what incremental reserves will be for example. Got it. Thanks. Thank you all. Thanks Paul. And the next question comes from Paul Cheng from Barclays. Hey, guys. Two quick questions. Matt, can you share what is APLNG the cash operating cost and the tax regime? We're not in the operating phase yet for APLNG. So I don't have the operating cost number off the top of my head. The tax regime is a tax and royalty regime with the royalties at the Queensland level and taxes at the federal level. So it's a typical like 10% on the royalty and 30% PPT or PIP? Yes. This is actually not fully resolved yet. There's some discussions still underway with the Queensland Government on the nature of how the royalty will be calculated. So I can't really give you a definitive answer on that yet Paul. And that moves up here to I'll add a little bit to what Matt said on the tax side. The taxes are actually paid down at the APLNG kind of corporate level. And there's going to be as you can imagine with a big capital investment project like that from a cash flow perspective a fair bit of tax shield from depreciation on the investment particularly in the early years of the project. So Jeff, does that means that during the 1st 5 years that we should assume there's not really the tax that APLNG need to pay? It's I don't know that I could give you that precisely the number of that depends upon price levels as well. But if we had current kind of prices there that's probably not a bad assumption. Okay. And then Matt can you maybe that 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 175,000 barrels a day in the Q1 and the Bakken was around 55,000 barrels a day in the Q1. And the Permian was less than 10. On the unconventional side, we also have significant conventional production, but in the shale side it was less than 10. So what we expect to happen Paul is we the aggregate production from the unconventionals is going to grow a little bit into the Q2 and then it's going to gradually decline as we exit the year. So the 4th quarter exit rate is going to be quite similar to the 1st quarter rate and aggregate for the shale plays. Okay. And that you will start increasing the rig count next year again. I think that's the current plan. So we should assume that they will be resumed to 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 that we build the rigs back up, but 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 hookup and bring them on to production, we're actually going to see the declining 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 there, we'll probably be relatively flat from the average of 2015 to the average of 16. Thank you. Thanks, Paul. And our next question comes from Ryan Tanal from Deutsche Bank. Please go ahead. Great. Thanks. Good morning, everybody. Good morning, Ryan. Sorry. Can you hear me better? Yes. Sorry. So a couple of questions on the there's been several recent news stories around some of your M and A efforts of potential assets you might consider selling. Any additional commentary that you might add regarding potential M and A programs? Are these programs that people are approaching you? Are these assets that you're marketing? Are we still looking at kind of smaller $500,000,000 to $1,000,000,000 size deals? Any thoughts around that? Yes. We're always in with a portfolio of our size looking at what can 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'll hear stories probably out in the marketplace that we're testing values on that. And that's what we'll always be doing as part of a kind 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've talked about it whether that's $1,000,000,000 or so a year 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 the we can sell the assets for at least what we think we could receive form and value if we kept them in our portfolio. And we don't know what that number is going to be, but there'll be some level of asset sale. Okay. Thanks. And maybe shifting gears a little bit. In Alaska, I know at the Analyst Meeting you guys have given guidance on Alaska production and you have a couple of projects starting up later later this year. I guess can you talk a little bit about your production expectation in Alaska and maybe that of the industry, we've seen differentials kind of bounce around quite a bit. Maybe as you look out 1 or 2 years, what's the direction that you would expect in terms of kind of crude realizations and activity levels in general in Alaska? So 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 3 years and beyond that actually. And we are reasonably good representation of the overall Alaska production because we are in the big production areas there at Frodo, Coparac and Alpine. So I think if you're looking at sort of macro view of Alaska that wouldn't be a bad basis to think about that. In terms of realizations, I think currently realizations are preferred to ANS crude or about $2 or $3 below Brent. We have taken one cargo this year to Asia and one last year and we always have that option if that's what we choose to do. And our next question is from Evan Kalia from Morgan Stanley. Please go ahead. Hey, good afternoon guys. I know Conoco remains focused on your yield bridging to cash flow neutrality. Yet how would you respond to a commodity recovery? Meaning will you seek to increase cash cushion balance sheet repair to some level, which might kind of 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 activity levels in 2015 2016. I mean, I need an idea in terms of kind of levels or price signal that you need to see to reaccelerate? I think in the near term, I'm not sure we see a price level that would cause us to reaccelerate. And we're going to want to see what that if there is some acceleration in prices that it's got a more lasting effect as well. I mean we are taking thinking about what's going on with our capital program. As Matt mentioned earlier, we have a couple of $1,000,000,000 rolling off from Surmont and APLNG. And we are in our plans already accelerating capital spending in places like North American unconventionals as we go into 2016. Right, right. I understood that. Maybe to the other side, I mean, can you kind of could you quantify or provide a range of how much more you could borrow and still maintain your 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. I think we would characterize it the same way we characterized it on our call last time that we think the amount that we do borrow is going to be it could be enough that would cause us to see a 1 notch downgrade from what's currently A1 at Moody's and A, the middle single A with the Standard and Poor's and with Fitch. And as you've seen all the agencies do have our credit rating outlook on a negative. They're anticipating that. But once if that were to happen, that would move us into a range where we're comfortable that there's plenty of space there to meet whatever borrowing needs we might have in 2015 2016 as we head towards cash flow neutrality in 2017. Great. Fair enough. Thanks guys. Thanks Evan. And our next question comes from Ed Westlake from Credit Suisse. Please go ahead. Yes. 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. I mean is there anything you're doing differently this year? I mean we're continuing to work through our optimizations, Ed, that we discussed a little bit a few weeks ago, optimizing the completion design and the well length, the well placement and so on. I wouldn't say that there's anything fundamentally different going on there, but we are moving towards more pad drilling. 90% of our wells will be from pad drilling. But there's not a fundamental change there. The guys are just executing well. And then on the shale program and obviously a massive cut in rigs. I mean and obviously you do modeling on volumes probably to a far greater degree than we do from the outside. But is there any risk that you undershoot on volumes or you feel pretty comfortable about the trajectory you just outlined? I feel pretty comfortable about the I was 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 the way that we intend to next year. And then coming back to Doug's question on, obviously, people are going to focus a lot on cash flow margins and you've got these big projects coming up. When do you reckon that APLNG Sermon will sort of hit what you think is sort of peak operational cash flow? Obviously, whatever the macro gives at that point is a separate discussion. Yes. So peak on both of them really for different reasons peak operational cash flows in 2017. So for Surmod too is because it takes a while as you know to build the steam chambers and ramp up production in the SAGD projects. And in the case of AP LNG, we'll bring the 1st train on this year. It will be next year before we bring the 2nd train on. So the 1st year that we'll have both trains running will be 2017. So in both cases, it will be 2017 before they fully contribute in the plateau rate. And of course, that rate will continue in both projects for decades. Yes. Very clear. Thanks very much. Thanks. Thanks, Graeme. And our next question comes from John Herrlin from Societe Generale. Please go ahead. Yes. Hi. Two quick ones. You cut your Lower 48 rigs by over half. How many frac spreads are you running at? Let's see. I would say we're probably overall we're probably running 3 or 4. They it varies a little bit, but I think 3 full time and 4 if we had occasionally. So that's our total spread to support those rigs. Okay. Great. In Angola, you had a passing comment about you being disappointed with the geology. Can you elaborate a little bit more on that? That's it for me. Okay. Yes, I agree. So we've had 2 dry holes there in the campaign. The first the Camoche was basically the reservoir wasn't developed there. As you know better than most, these carbonate reservoirs are quite difficult to predict today. The porosity development and in the case of Chemosh, the porosity just wasn't developed there. For Amose, the porosity was developed. We did see good reservoir phases, but it was gas filled. So the fetch area that was feeding into El Mose was overcooked. So they so two different reasons for the failures on those wells. And that basin as a whole is a bit less predictable than we had hoped going in. The Valley well that we're drilling is actually testing a different play than the Amos and Amos and Camoche wells were. So we'll see how that goes. Thanks. Thanks, Amit. And our next question comes from Blake Fernandez from Howard Weil. Please go ahead. Hey, folks. Good morning. Jeff back on the balance sheet discussion previously. I'm just curious can you remind me if Libya No, we've not impaired Libya. For us, we would have to see that there was 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? I don't know that number off the top of my head. It's on the order of $500,000,000 But it's I wouldn't I'm not sure exactly what that number is. No worries. That's fine. The second question, there's been a lot of discussion with the recent rise in commodity prices here with some of the E and Ps potentially layering in hedges. I know historically that's 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 forty eight activity? No. We take a portfolio approach to thinking about our cash flows. 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 that we feel like hedging is by definition a kind of 0 sum game in terms of value. And if you one of the reasons we keep a strong balance sheet is to be able to handle the fluctuations in commodity prices. Fair enough. Thank you. Thanks, Clay. And our next question comes from Neil Mehta from Goldman Sachs. Please go ahead. Good morning. Good afternoon. Good morning, Neil. So there's 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 specifically with your portfolio, I 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? Neil, I can't speak for the industry as to what price signal they might be looking for and we'll certainly be cash flow of a big impact on that as well. But in our plans, we are planning the increases moving to 2016 modestly, but we're going to increase as we move into 2016. And that's in anticipation that there'll be some continued recovery in prices. In terms of the capacity, clearly, we've laid down quite a bit of rig and completion 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 they want to put back in and what they see as being an efficient and safe way to bring the rigs and the completion crews back to work. So I don't think I answered your question very satisfactorily, but that's about the best I've got. Now you got me there philosophically. And then that I should have asked you this question at the Analyst Day, but the $1,000,000,000 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? No, our intention is to make that commodity agnostic for the most part. We're looking to get a sustainable cost reductions through this effort. Now we're going to get some fluctuations associated with exchange rates and with changes in the deflationary environment. But our focus is on getting structural cost reductions that we can sustain through the cycles. Thank you very much. Thanks, Neil. And your next question comes from Roger Read from Wells Fargo. Please go ahead. Yes. Thank you. Good morning or afternoon as the case may be. I guess I'd like to ask about the price realization seemed a little bit well, at least relative to our expectations, a little weak in the Q1 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've seen for a mix of production kind of oil condensate NGLs etcetera working its way through? And the final part of that question, as prices have been recovering, does that help on realizations as we think about Q2 and Q3 essentially? So what we saw in the Q1 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 at 48.5 or so for the quarter. What we're seeing is just a tough quarter for realizations a lot of supply in the marketplace. Kind of the differentials that we're seeing are not that different that we saw in the Q1 are not that different when we were in a $50 price environment than they were when we were in a much higher price environment. It's still kind of that same level of differentials. I think we would expect to see differentials improve in terms of percent of marker realized and maybe some slight improvement in absolute levels of differentials as well. Okay. The differentials were tough because they were kind of tough across all commodities for us in the Lower 48 as well. 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'm just saying was that a function of any more either a lighter crude that you're selling or a condensate barrel or just it just gives you what it is. I'm just trying to Yes. It's a little bit just that's just what the market was in the Q1. There's nothing really that fundamentally changed in our product mix or the quality of any of the products that we're selling that would lead to that kind of differential. Okay. Thanks. And then unrelated follow-up. The change in taxes in the U. K, can you give us an idea of maybe how you'd characterize that? Is it a 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 2 years, which seems pretty well locked down in terms of expectations on the CapEx side, but it could help in a post-twenty 17 environment? Yes, Roger. I mean it helps. The U. K. Sector needs as much help as it can get. So the help on the tax rates was welcomed. The simplification and broadening of the uplift on capital is going to help as well. It's about a 12% uplift now on capital when you go through the math. So we will build down our thinking as we're thinking about our about our overall investment portfolio over the next few years. But it's certainly was a move in the right direction by the U. K. Government. Okay. Thank you. Thanks, Roger. Thanks, Roger. And our next question comes from Pavel Molchanov from Raymond James. Please go ahead. Thanks for taking the question. Your guidance for exploration and dry hole $800,000,000 for the year you said 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. By its nature dry hole cost is going to be pretty lumpy. And we happen to have both the Harrier well and the Mosey well in Angola hit in the Q1. I mean, you could have quarters where the number is really low if 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 to the analyst presentation still makes sense. Okay. And then you've talked about some of the areas where you're seeing cost savings that looked pretty encouraging. Are there any operating areas where on the other hand costs have been surprisingly sticky, where you're not seeing the savings that perhaps you would have anticipated by this point? Are you talking about operating costs Pavel or capital costs? I guess, yes, more on the CapEx side. Yes. So we're seeing is a more rapid response in the Lower 48 than in other parts of the company. We expect to see some deflation kicking in and we already are seeing some in our international business, but it's coming more slowly, which is what we would anticipate. It's coming more slowly from the international business, but it's come very rapidly in the Lower 48. But we've built that sort of trend as we anticipated into our expectations of deflation. And we are and we do expect to see those reductions coming in the international over the next several months. Okay. I appreciate it. Thank you. Thanks, Kavail. 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 reef fracking in the unconventional. And if I could ask 2 questions on that. First, from Conoco's vantage point, what is new in the technology offering that you're seeing? And second within your portfolio where 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. Some using the diverter technology, some just basically straight pumping new fracs with an existing tariffs and some with new tariffs. So we've been testing a few. The area that we're seeing the best uplift is as you'd expect our older wells where we pumped smaller jobs with wider spacing. So we see some potential there and this particularly in wells that were drilled a few years ago and more recently drilled wells. So we're continuing to evaluate that, but there is some there is certainly some upside potential. Okay. Thank you. Thank you. Sorry, go ahead operator. I'll just turn the call around to Dennis' 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 and you may now