Earnings Call: Q1 2017

May 2, 2017

Welcome to the First Quarter 2017 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 I will now turn the call over to Ellen DeSanctis, VP, Investor Relations and Communications. You may begin. Thanks, Christine. Hello, everybody, and welcome to our Q1 earnings call. Our speakers for today will be Don Wallett, our EVP of Finance and Commercial and our Chief Financial Officer and Al Hirschberg, our EVP of Production, Drilling and Projects. Our cautionary statement is on Page 2 of the presentation materials we've provided. We will make some forward looking statements during today's call that refer to estimates or plans. Actual results could differ due to the factors described on this slide and also described in our periodic SEC filings. We will also refer to some non GAAP financial measures today to facilitate comparisons across periods and with our peers. Reconciliations to non GAAP measures to the nearest corresponding GAAP measure can be found in this morning's press release and also on our website. Finally, during this morning's Q and A, we will limit questions to 1 and a follow-up. And now I will turn the call over to Don. Thank you, Ellen. I'll start by covering a few highlights from the Q1 and Al will close with more on our operational results and what to watch for the remainder of the year. I'll begin on Slide 4 with a summary of the Q1. 2017 is off to a good start for the company. We continue to deliver strong underlying performance, both operationally and financially. But the biggest news of this quarter was the progress we made strategically. So let me start there with the left side of the chart. Consistent with our cash allocation priorities, we grew the dividend 6%, we paid off $800,000,000 of debt and we repurchased 2,200,000 shares. In total, we've announced over $16,000,000,000 of dispositions, along with our intent to use a significant portion of the cash proceeds for debt reduction and share buybacks. These strategic actions mean we've not only accelerated the 3 year plan we laid out in November into less than 1 year, but greatly exceeded it. We were on track to close the Canada transaction this quarter and the San Juan Basin transaction in the Q3. So we are making rapid progress on our transformation. Moving to the middle column. Financially, we had an adjusted loss of $19,000,000 Our first quarter results included dry hole expense of 101,000,000 dollars which accounts for the slight variance to consensus. This quarter, we generated $1,800,000,000 in cash from operations excluding working capital. This exceeded capital and dividends by over $500,000,000 Our adjusted operating costs were 6% improved compared to the Q1 of 2016. Finally, both S and P and Moody's improved their rating outlooks on the company after our announced dispositions. In terms of day to day execution, our operations are running well. We exceeded the high end of our Q1 production guidance, delivering 2% underlying production growth year over year. In the Lower forty eight, we are executing our drilling program in line with our plans, and we expect to average 11 to 12 rigs for the year. Bottom line, we remain on track to meet our 2017 operational targets, which Al will cover in a few minutes. If you turn to Slide 5, I'll review the quarter financials in more detail. This quarter, Brent averaged about $54 a barrel and Henry Hub averaged about $3.30 in Mcf. This resulted in an average overall realized price of about $36 a barrel. We reported an adjusted loss of $19,000,000 or $0.02 a share. Year over year, adjusted earnings improved nearly $1,200,000,000 The biggest driver was a 58% improvement in realized prices, but we also benefited from the actions we've been taking to improve our cost structure. Sequentially, adjusted earnings improved about $300,000,000 The benefit came primarily from improved realizations and lower costs. One way to think about this quarter is that with $54 Brent on an adjusted basis, we were very close to being profitable. A year or so ago, we would have needed oil prices in the mid-60s. That's how much improvement we've made and those improvements also drive cash flow. 1st quarter adjusted earnings by segment are shown on the lower right. 3 of the 5 producing segments were again profitable this quarter. Both Canada and Lower 40 8 showed significant improvement on the path to profitability. The supplemental data on our website provides additional segment financial detail. If you turn to Slide 6, I'll cover our cash flow waterfall for the Q1. Here's our typical cash flow waterfall, which you are familiar with, so I won't go through each element. But I do want to add some color to a couple of items. While we generated $1,800,000,000 of operational cash flow ex working capital, we had 2 items in the quarter that I would not expect to factor into future quarters. First, we had a hedged cross currency swap contract from British pounds to Canadian dollars that was put in place pre Brexit, but matured this March. So at the termination of the contract, we realized about a $200,000,000 currency loss due to the sterling devaluation over that period, which adversely impacted cash flow. 2nd, our cash flows in the quarter benefited from the recapture of tax loss carryforwards in Libya when crude oil exports resumed in late 2016. We had 4 liftings during the Q1 and cash flow benefited by about $100,000,000 due to the tax recoupment. So those items netted to an overall adverse impact on operating cash flow ex working capital of about 100,000,000 dollars Also of note, we paid down $800,000,000 of debt and made distribution to shareholders of $400,000,000 between dividends and share repurchases. I should point out that we suspended our buyback program during the quarter as we work to progress the transaction with Cenovus. Shortly after the public announcement of the deal, we resumed repurchasing shares. And as we previously announced, we plan to complete the $3,000,000,000 of buybacks this year. As you see, we ended the quarter with $3,400,000,000 in cash and short term investments. In summary, our focus on free cash flow generation and the lowering of our breakeven price is showing up in our financial performance for the 3rd straight quarter. We're delivering on our cash allocation priorities and the business continues to run well. I'll hand over now to Al to review the quarter's operations in more detail. Thanks, Don. Well, we've had another good operational quarter with strong performance on production, capital and operating costs. If you'll turn to slide 8, I'll cover some operational highlights from our Lower 48 and Alaska segments. For the quarter, production excluding Libya increased to 1,580,000 oil equivalent barrels per day. That exceeded the high end of guidance and beat the midpoint by 24,000 barrels per day. As Don said, once you adjust for 2016 asset sales and downtime, it was an underlying increase of 2% compared to our Q1 production last year. We accomplished this production increase while maintaining our discipline on capital and operating costs throughout the company. Lower 48 unconventional production averaged 221,000 barrels per day for the quarter with the Eagle Ford at 133, the Bakken at 59, and the Permian at 17,000 barrels per day, with the balance in Barnett and Niobrara. This result is a 2% decline versus the same period last year. On the last call, I mentioned the low point for unconventional production was expected to be in the Q2 this year. We now see the inflection point behind us in the Q1. In April, we reached 12 rigs in the Lower forty eight as planned. We're currently running 5 in the Eagle Ford, 4 in the Bakken and 3 in the Permian. Increased 3% compared to the Q1 of 2016 when adjusted for asset sales. Through the winter construction season, the Greater Musa's Tooth 1 ice roads and associated key infrastructure components of the project were completed. This keeps us on track for 1st oil by the end of 2018 at GMT-1. The 1H News drill site facilities are complete and 1st oil is expected by the end of this year. Following our 2016 exploration discoveries and success at the December lease sales, we completed shooting 3 d seismic in the GMT unit, which includes our Willow discovery. If you turn to Slide 9, I'll cover some operational highlights from the remainder of the portfolio. At our Surmont operations in Canada, we reached a record production rate of 128,000 barrels per day gross just before a disruption of 3rd party diluent supply forced curtailment of the field. We're currently operating at about 2 thirds of pre disruption volumes, but we expect to return to our planned ramp this month. At this time, we do not anticipate this disruption to have a material impact on full year Canada volumes, although it negatively impacted 1st quarter volumes by around 5,000 barrels per day. In the U. K, commissioning began for the Clare Ridge production platform. This is another important step for this project as we move toward 1st production in early 2018. In April, the Alstahanstein spar left port in Korea en route to Norway. The project is on track and first production is expected by the end of 2018. Moving to Australia, APLNG continues to operate well and the first turnaround at Train 1 was successfully completed in April. 27 LNG cargoes were loaded in the Q1. We're continuing to hone in on the range of resource for the promising Barossa development to backfill the Darwin LNG plant. The successful Barossa 5 appraisal well increased the estimate of gas in place and significantly reduced the downside uncertainty. The Barossa-six well is currently drilling. And finally, in Malaysia, after full commissioning of both gas trains, the Malachi development continues to deliver better than expected production rates. The project will continue to ramp after the planned KBB Malachi turnaround currently underway. So those were just a few operational highlights from the quarter. Now let's move to Slide 10 to discuss the remainder of the year. As we move forward in 2017, we're on track to deliver on continued strong operational performance. In the Lower forty eight, we expect our unconventional production to increase throughout the year with an exit rate of around 250,000 barrels per day, while maintaining the average of rigs at around 11 to 12. In the next two quarters, we have planned turnarounds in Alaska, Europe and the APME segments that will impact production. The table on the left provides some perspective on how key operational metrics will be affected for our 2 announced asset sales. Given that we don't know the exact dates of closing for the sales transactions, the table shows the metrics both with and without these sales. On the left are the numbers excluding any impact from dispositions. The numbers on the right are pro form a guidance numbers, assuming both the Canadian and the San Juan dispositions had closed on January 1, 2017. As Don said, we expect Canada to close sometime in the second quarter and San Juan in the third quarter. We will update guidance during the year as those transactions close. In the appendix, we provide additional guidance on each of the 2 dispositions. But the bottom line is this, underlying performance is on track to meet or exceed our budgeted plans. And finally, please save the date for our 2017 Analyst and Investor Meeting. This year's meeting will be held on November 8 in New York. We're on a fast track to transform ConocoPhillips into a company that thrives at today's oil prices. We look forward to updating you on strategic progress and providing a deep dive into our unique portfolio. Now I'll turn the call over for Q and A. Thank And our first question is from Phil Gresh of JPMorgan. Please go ahead. Hey, good afternoon. Hey, Bill. My first question is just on the 2nd quarter production guidance. I just want to make sure I understood it on an apples to apples basis. I understand that you don't have the asset sales in there that have been announced. But I just wanted to go back to the 2Q 2016 and make sure I understood those numbers because you did have some asset sales in 2016 as well that you're talking about when you discussed the 1Q performance. So is the right base from 2Q 2016, 1546, so the midpoint would be down 2% year over year? Or am I looking at that the wrong way? Phil, we're looking here. Yes, $15.46 is the actual from Q2 last year. So because 1Q you were up 2% year over year. So I was just trying to tie that to the midpoint being about down 2%. I think you mentioned that there's some maintenance in the Q2 of this year. I just hoping to understand a little bit better some of the moving pieces there? Yes. The $15.46 though does not have adjustments in it for sales that have happened since then. Like me. Yes. So I don't think it's right to take that number and then compare it directly to 2Q this you would that would be missing the adjustments for sales since then? We can take that offline Phil. Sure. No problem. And the Q1 this quarter does include the delta between its dispositions and it does include the delta on planned downtime as well. Yes. In the Q number, there is a significant turnaround downtime built in, but that's not so different from last year either. Okay. And then second question, maybe just to follow-up on the buyback commentary. So you obviously were blacked out for a period of time there. But it sounds like you're committed to the $3,000,000,000 number for the full year, which imply you're going to go from like $100,000,000 run rate in the Q1 or something closer to $1,000,000,000 for the next three quarters. Is that the right way to think about that? Yes, Phil. I think that's a reasonable assumption. Our philosophy is to dollar cost average mostly. So it will be pretty consistent over the quarters. Okay. Thank you. Thank you. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead. Great. Thanks. Maybe to start out with one on CapEx. The CapEx run rate in the quarter was certainly well below kind of the full year guidance on a quarterly basis. Can you talk about what was driving that and some of the moving pieces that will drive the trajectory of quarterly CapEx throughout the year? Sure. Yes, the quarterly came in at about $950,000,000 So if you take the run rate times 4, you get like a $3,800,000,000 kind of number. We do still expect to spend $5,000,000,000 on the year. It's interesting though that we were able to continue to grow volumes even at that lower CapEx rate. I think so partly it does reflect our continuing capital discipline and our success in resisting some of the inflationary forces that are out there. But we did have in the quarter some more roll off in project activity, particularly in our APME region, Malaysia, Indonesia, some lower project activity. Our exploration CapEx was lower, a bit of a timing thing in the Q1. Our CapEx in places where we are ramping projects like Alaska and places like L48, where we were coming up on rigs was increased. But just to give you perspective around the Lower forty eight where we have our biggest ramp going on, we came into the quarter at 8 rigs and we exited the quarter at 11 rigs. We're now at 12. And of course, the majority of the cost associated with that rig is associated with the completions and the completion work comes along behind that. And so that's still ramping. And so I think that will be a key driver that will push our quarterly CapEx numbers up going forward through the rest of the year. And I expect that we will spend that $5,000,000,000 even though you don't see it in the Q1 pace. Okay. Thanks. That's helpful. And then maybe just one follow-up on your on the U. S. Onshore. Can you talk a little bit, I mean, you the comments that you had previously that you expected to trough in 2Q, it looks like you're going to trough in 1Q now. You were able to hold production relatively flat quarter on quarter versus 4Q 2016. Can you talk about some of the things that drove the better than expected production? The exit rate looks like it's a little bit above the 5% to 10% exit rate increase that you had talked about on a previous call. So can you run through some of the things maybe Is it earlier activity? Is it better well performance? What's driving the better than expected production out of the Lower 48? Yes. No, Ryan, yes, I think you're right. We are continuing to see better than expected numbers there. Our first quarter production out of this piece of our business was up 2%, 3% over what we were predicting say a quarter ago. And it's the continuing drumbeat of improvements from technology and other efficiency drivers, things like data analytics that are helping us continue to get more and more efficient in the results that we get there. So I think that last quarter I said I thought that on a full year basis that 2017 would be 5% to 10%, somewhere in that range lower than 2016. I think it's clear just from the progress we've already made so far this year that we'll be at the low end of that decline range, if you will. So we'll do better. Instead of declining 5% to 10%, we'll be closer to the 5%. If you look at it 4Q to 4Q, I said on the last call, I thought we would be up 5% to 10%, 4Q of 'sixteen to 4Q of 'seventeen. And I think you're right, it's already clear that we're at the very high end of that guidance now that we'll be at the top end just based on what we see so far. And it's consistent with this idea that 11 rigs to 12 rigs, we said we would grow 10% to 15% based on that chart we showed you back at the analyst meeting. And I think it's clear from the progress we've made so far that we're on the upper end of that kind of range, if not beating it also. And is it safe to assume that your estimates here are based on the fact that in the current environment that you pause here at 12 rigs and the rig ramp doesn't go any farther beyond that? Yes, that's right. In 2017, as we've said before, we don't plan to go above this kind of 11 to 12 rigs for 2017. And so all of those numbers are based on continuing with that same scope that we've laid out in the past, no increase. Great. Thank you. Thank you. Our next question is from Paul Sankey of Wolfe Research. Please go ahead. Good day. Hi, Paul. Hi. You said that you'd bottom sooner than expected in the lower 48. Is the rig count that you've got there, the 12, what's the progression now anticipated if it's changed at all? And could you break that down by between Eagle Ford, Bakken and Permian, please? Thanks. Well, like we said a minute ago, the rigs are 5 in the Eagle Ford, 4 in the Bakken, 3 in the Permian. The Permian, there's 2 of those are in the unconventional and one is in the Permian conventional. I apologize if I didn't completely miss the go ahead. Yes. And so we do plan to do some work in the Niobrara this year. And so some of these rigs may bounce up and down a little bit, but I expect to be in the 11% to 12% kind of range all year. Where would you think that goes next year, Al? Well, it's that's a 2018 CapEx question. It's just too early to say. We'll obviously be watching the macro environment as we go through the year and that includes where the cost and inflationary environment is going as well to sort of see how we judge that, but it's just too early to say. I imagine we'll be talking about that at our Analyst Meeting come November about what our plans are for 2018. Great. Just a follow-up and apologies if that previous question was somewhat already asked. When you look at the proceeds that you've got from these big disposals, and I'm also thinking back to conversations you and I've had about cash again in the past, You're getting really outstanding valuations relative to where your stock trades. Is there not a strong temptation to re up the disposal program up? Thanks. To re up, I mean, I guess, I mean, that we talked at the Analyst Day just not too long ago last November about $5,000,000,000 to $8,000,000,000 over 2 years, 2017 2018, and we've already announced, what is it, dollars 16,000,000,000 Over. Over $16,000,000,000 and have said we still we're still going to continue with the rest of our program and get probably another $1,000,000,000 to $2,000,000 as we Yes, I guess it's the upside to the 1% to 2% is what I'm driving at. Couldn't you add another leg when the valuations are still attractive to you? We don't have any plans to do that right now. I mean that we identified from a strategic standpoint the kind of assets that we wanted to sell and part of the consideration there was which types of assets did we think we could get good value for in today's market. And so that's how we put that list together. And I haven't seen any fundamental change in the market that would make me want to change that right now. I understand. That's you answered the question. Thanks. Thank you. Our next question is from Paul Cheng of Barclays. Sorry, we preempted you on your question by answering it. So I don't have to waste my one question or two questions. I think the first question is for maybe both for Don and Elle. Have you guys received any dividend payment from the ATRNG at $54 brand? And also that Al, can you talk about Queensland LNG export quota? What kind of time line and decision making process we should be able to monitor to understand that how that process? Okay. I can comment on both of those. I guess the I mean we're in the we have not received any distributions so far this year from APLNG. Of course, that cash sort of builds inside the joint venture and then the joint venture decides when to make distributions. But we are in that kind of range where we're as we move in the kind of 50s that ramp up and as we ramp up our volumes that you would expect to start getting some distributions. With regard to the export licensing, the government of Australia has announced some key principles around that just here recently and have said they'd like to put it into effect by July 1. With regard to that, we're of course very engaged with the government and the details around how we're going to how this regulatory how these regulations are going to roll out. And we can see that APLNG is very well positioned relative to what the government is trying to do here. Their focus is on wanting the LNG export projects to be net domestic gas contributors is what they call it, which just simply means that of all the production that we control and that's and a portion of which goes through our LNG plant that we also are a net provider to the domestic market. So we may be buying gas in the domestic market, selling gas, but we need to net provide gas. And APLNG has always done that and has a firm plan to continue to do that. In fact, APLNG provides about 20% of the domestic gas on the East Coast market in Australia. So because of that and the way they've laid the rules out, we don't expect that there will be any impact on APLNG exports from these new rules as they come into detailed regulations. Okay. Thank you. Second question I think is for Dawn and maybe also for Al. Don, how much is the debt you may be able to buy back or pay down without any penalty over the next 2 years? And in terms of the dry hole, do we still see a lot of exposure for the remainder of the year? Or that those are behind us by now after the Q1 dry hole? Well, maybe the second question first, Paul, as far as dry holes, we had about $100,000,000 dry hole expense in the Q1 and I think our guidance on that for the year was 200 So we've taken a look at that. We haven't changed our guidance. We're pretty comfortable that we'll be somewhere around the 200,000,000 dollars range when we look at the program and the way that the risk is distributed across the quarter. So no change to the $200,000,000 guidance. As far as debt repayment, we've said that we want to reduce our balance sheet debt down to $20,000,000,000 this year, which is nearly 7,500,000,000 dollars of reduction. Your question was around how much can you reduce without a penalty. What we're doing in this first phase, if you will, to get down to $20,000,000,000 is basically focused on near term maturities and the term loan that we have out there in 2019. The term loan has no penalties associated with it. The balance of these of the debt that's going to be retired this year will be retired through make whole provisions. Now I don't know if you consider that a penalty, but we will pay a premium over the par value on the bonds. But since there's such near term maturities, the penalty is fairly modest or the make whole premium is fairly modest. And so what I'm looking at is cash efficiency and we believe we can retire that $7,500,000,000 of debt. We'd spend about $1.04 roughly to retire each dollar of debt. So that's pretty efficient. All right. Thank you. Thank you. Our next question is from Edward Westlake of Credit Suisse. Please go ahead. Yes. A question just on inflation and deflation. I mean, obviously, your program is spread across the Eagle Ford, Bakken and Permian. The Permian is where people think inflation is the most severe, but maybe any comments what you're seeing in the other basins? And then you did touch on it that some of its timing on CapEx, but maybe just some any comments on deflation in the non shale spend of the $5,000,000,000 program that you're seeing? Okay. I would say at a high level, there's really been no big changes in my views about inflation for this year versus the comments I made on the last quarter call. If I look at our spending year to date, where we track this every month, we are still net deflation year to date as a company. So we've certainly experienced more deflation in our costs year after the Q1 in 2017 versus 2016 and there's a mix there. And as you correctly point out, I think the Permian is hotter than some of the other Lower 48 unconventional areas, but all of the Lower 48 unconventional is experiencing some pressure, although actually only in certain business lines. I mean, it is variable. We are experiencing inflation in the lower 48% in pressure pumping, proppant, cement, tubulars, those kind of categories. But we're actually still experiencing deflation on some of our labor costs, oilfield chemical costs, some of our fabrication costs in Lower 48 are lower than they were last year. And so there is some mix there. But overall, because we are still experiencing significant deflation internationally, that plus a little bit of help we're getting for some of our fixed contract pricing in the Lower forty eight is more than offsetting that and allowing us to be net deflating so far this year. That's very helpful. And switching around geographically, I mean Alaska seems to be a real progress area. Obviously, you gave guidance on the production potential out to 2021 at the Analyst Day last year, which included some of these projects that you're starting up. Is there anything that you can do to drive production harder before 2021? I know you on the last call, you mentioned the Willow discovery was maybe 100,000 barrels a day, but that was 2023. I'm just trying to get a sense of the levers to lean into Alaska as you get more confident in the resource base and maybe oil picks up? Yes. I think we have a lot of continuous coiled tubing drilling work there, rotary drilling work there. So we have a fairly continuous program that's a lot of which is driven by different kinds of new technology that allow you to see where to drill. And so you do have some ability to change the pace of that work. And also our as we continue to march out GMT-1, GMT-two, our next projects, you maybe have some control over the pace of those. But and recall on Willow, when I said 2023, I think I said that the most important thing driving timing there was the permitting process and that based on experience from the past, 2023 would be the earliest that would be if we had cooperative federal permitting process. Thanks for that clarification. Thank you. Thank you. Our next question is from Doug Parisian of Evercore. Please go ahead. Good morning, everybody. Hi, Doug. I have a few questions that I think are probably for Don. First, can you provide some specificity on the deferred tax item in the quarter and that it was fairly high and also any insight as to how it may trend in the future? Sure, Doug. Yes, the deferred tax use in the Q1 was very high at $1,200,000,000 It does stand out. So I'm not surprised you're asking about it. But that was mainly driven by that large financial tax benefit that we had on the Canadian transaction that we booked during the Q1. If you remember that was like $1,000,000,000 or so. So when you remove that and a few other special items, non recurring type items, you would we would get down to about 100 $1,000,000 use of cash for the quarter, which is right on line with what we would expect and probably more in line with what you would expect. Okay. Okay. And then second, just to clarify and getting to your debt reduction target of 15 $1,000,000,000 in 2019, it looks like you're assuming Brent prices of only $55,000,000 So number 1, to clarify that figure 2, ask what divestiture proceeds are included in that outcome? And then 3, is it correct to assume that debt to total cap or net debt to total cap in that scenario is less than 10% in your scenario by that point in 2019? Is that about right, Don? Well, as far as the planning scenario, I think what we've shown is around $50 Brent plan over the next few years. That's what we're planning for. And as far as what mix, what the dispositions contribute to the debt reduction, it's all gets pretty fungible pretty quick. I would say based on these two transactions we've announced closing, that's $16,000,000,000 of proceeds. You can look at our current cash balance. If you use current strip going forward, we're going to end the year with a pretty large cash balance. But we still have a bit to do in 2017 2018. We've pretty much earmarked another $5,000,000,000 for debt reduction over those years and another $3,000,000,000 in share buybacks. So that's $8,000,000,000 that's going to have to be funded from the combination of our cash balances, which are the result of the dispositions as well as free cash flow that we're able to generate. I don't know if that answers your question. Doug, on net debt to total cap, I don't have that statistic handy right now, but based on my projections as far as say CFO to net debt, I'm looking at a leverage ratio somewhere around 1.5 closer to 1.5 than the 2 that we've talked about previously. Okay. Okay, Don. Thanks a lot. Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead. Thanks. Good morning, everybody. Good morning, Doug. A lot of the detailed ones have been asked, I guess. But I wonder if I could a little prematurely, I guess, talk about major capital project spending and your thoughts beyond the current year. And what was at the back of my mind is your comment on Barossa, I guess, sorry, and some speculation that ConocoPhillips might consider an expansion of Darwin. So just sort of big picture comments on where you see major capital project commitments and Darwin specifically? And I've got a follow-up, please. Well, I think consistent with what we've said in the past, I expect that we're not eager to get into any inflexible super major projects like things like APLNG and Surmont II anytime soon, but we do have this nice pathway of semi flexible midsize projects that we can modify the timing of that extend well out in time. And so we'll be managing that as we figure out how much of our capital do we want to allocate to things that are flexible on the month and things that are flexible over a period of years. And so we have a lot of optionality there and keep adding new things into the hopper things like Willow up in Alaska. But with regard to Barossa, I mean we have Bayou London supplying the Darwin plant now and it's coming toward the end of its life. And so we know that we need to backfill with some new development and Barossa is what's in our plans. And Barossa fits into the current Darwin plant as it is. We don't need to expand it. There has been interest from many other parties in the area who have there's a lot of discovered gas off the coast there. And so there's been interest from a lot of other parties in whether we would consider expanding the plant. And so they've been willing to put up money to do some engineering study work to see what it might cost to do that. And so we've been supporting that effort, But that's not in our current plans to expand the plant, but that possibility is being studied primarily to see whether you could accommodate some of the other gas that's been discovered in the area. You don't need it for Barossa. Okay. That's very helpful. Thank you. And I guess my follow-up is also for you, Al. It really goes back to an earlier question about the pace of growth in the Lower forty eight. I mean, obviously, given the environment we're in right now and oil kind of struggling to break 50 on a sustainable basis, What's the governor for your growth targets for Lower 48? It's obviously not cash flow or cash, given the amount of cash you're going to have on the balance sheet. But what's the right rate of growth as you think about the 12 rig program looking beyond 2017? And I'll leave it there. Thanks. Well, I think for us, you really have to go back to the priorities, those five priorities that we laid out back at the Analyst Meeting where we've got this high return disciplined growth CapEx that we have available as an option, but it's competing with how we spend our cash on share buybacks and net debt reduction that was Don was talking about a minute ago. We don't plan to chase production growth into the cycle. We're quite pleased with the amount of growth we've been able to get in the unconventional space just with at the rig levels that we're at now. If you look at our if you look at entry to exit in 2017, even as we've been increasing our rig counts and really haven't gotten to steady state till here in April, you'll see on the order of about a 20% entry to exit growth rate for us in our Lower 48 unconventional. So we'll be considering those trade offs between how to use that cash as we work through our plans and establish working with our Board of Directors, what's our 2018 CapEx level going to be and be talking more about that as we move back into the later part of the year and into the November analyst meeting. All right. I will wait until then. Thanks guys. Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead. Sorry, I had to take mute off there. Thanks. Good morning. Good morning, Roger. Hey, I guess coming back to the Eagle Ford Shale and your guidance or your indication that you may perform at the top end of the guidance range. If you're not spending any more money, I presume that means it's the same well count, but the wells themselves are more efficient or they're getting completed more quickly, maybe just a little enlightenment there, please? Yes. Well, Roger, it's some of both. It's this continuing improvement year after year that really hasn't slowed down for us in the Lower forty eight unconventional space where we're getting better production, better recoveries and continuing to drill and complete faster quarter over quarter, year over year. And so that's really what drives it. We build some of that into our forecast when we lay it out, but we've had a pretty good history here quarter after quarter of having it perform even better than the level of improvement that we had forecast. Any particular item you'd single out or call out? Well, I would say we haven't there hasn't been anything involved here that I would call a step change. So it's we're working on some step change items that for the future, but I wouldn't say there's been a particular step change item that's driven this. If I had to call out one thing that's really gained steam over the last couple of years and is paying significant dividends for us now, it would be just generically data analytics, big data where we've been able we've been working hard on that for quite a few years, but we've been able to standardize and drive it through more and more of our operations and have it much more handily helping us make day to day decisions on how to develop as a stronger force. And I think that's probably if I had to pick one thing that threads through all of this, that's probably what I would say is the biggest trend driver. All right. I'm sensing a theme for November 8. And then switching gears a little bit over to you Don. Production at Olivia and I recognize there are a lot of things moving around, but are there any prospects for cash flow from Libya in 2017? Well, we had some pretty good cash flow from Libya in the Q1, Roger. I tried to explain that that was a lot of that was due to tax loss carry forwards that had been built up during the couple of years that operations had been suspended and when they resumed, that's the first money we get back. So we're getting the lion's share of the cargoes that are or the proceeds of the cargoes that are sold. We sold 4 cargoes, I believe, in the Q1. We're continuing to sell into the 2nd quarter. But the majority of that tax loss carry forward has been exhausted. And we would expect if production continues uninterrupted in Libya that we would fully exhaust that carry forward during the second quarter. So Okay. Sorry, I should have been more specific like after the loss carry forwards. Is there a does the business underlying generate cash flow? Is it simply a recapture of the tax loss carry forward? Yes, I would call it pretty modest cash flow. Okay. Thank you. Thank you. Our next question is from Blake Fernandez of Scotia Howard Weil. Please go ahead. Good morning, folks. Question on the Lower forty eight profitability, it looks like a loss of about 100 $70,000,000 or so this quarter with oil averaging over $50 Al had mentioned the inflationary pressures being experienced there. I know we get some volume growth, but is there anything that you can think of that would meaningfully change the profitability of the business? In other words, at 50% to 55%, should we just think that this is going to continue to be a net income negative business? Or is that a change, also acknowledging, of course, the gas sales may impact some things? Well, I'll try that one, Blake. Of course, some of the things that we're doing on the portfolio, we expect to be accretive to income going forward and profitability. Obviously, we've taken a lot of measures over the last 2 years to reduce our cost structure. Those efforts continue in the Lower 48 commensurate with the dispositions and other programs that we have underway. So yes, in the Q1 pre tax, I think that loss was around $260,000,000 What if you look back over the last, say, 5 quarters, at the pretax losses versus different prices, you'll see that it's about $500,000,000 of profit improvement for every $10 increase in oil price. Course, there's a lot of gas price improvement going along with that. So we're getting pretty close on the commodity side, but we still got a ways to go. I would say one other area of improvement like in that arena is our DD and A rates. We have been seeing larger bookings across the unconventional as we get more time with that, and that has been driving down some very high DD and A rates. And I expect that to continue as we get more experience and are able to book more proved reserves. We really have pretty small bookings relative to what we know is there. And so that should continue to help our earnings. I guess there's also the dry hole money that's built into those numbers as well. Okay. Yes, over the last few years, of course, we had been active in the deepwater in the Gulf of Mexico and we did incurred quite a few dry hole expenses in this quarter. We saw some dry hole costs there as well. So we would expect that, that trend would abate with time that will improve our earnings. That's helpful. Thank you. The only other question I had and you may not have these numbers at your fingertips, but on your kind of post transaction guidance of $1,145,000,000 to $1,175,000,000 of production, do you happen to have a comparable number of what that what those numbers were in 2016? Blake, I don't have those numbers. We don't have those handy. Can we come back to you on that? Yes, absolutely. No worries. Yes. It won't be hard to do. I don't have it handy. Thank you. Thank you. Our next question is from Guy Baber of Simmons and Company. Please go ahead. Thank you very much for taking the question. Al, on the topic of big data and data analytics and the impact that has had on operational performance, it seemed as if your comments primarily applied to your U. S. Unconventional operations. Is that an accurate observation? And then the question would be, to what extent can those learnings and processes be applied globally across the broader portfolio? Where might you be in that process or assessing that? Yes. No, that's actually not an accurate way to think about it. Our data analytics work actually started outside the U. S. It's one of the things that we actually first started doing that work in the North Sea and it made its way around the world from there. And so it's been a powerful force for us. I would say where the U. S. Has led that effort is the early days of data analytics for us were really focused on operational efficiency, operating your rotating equipment better, that sort of thing. And in the Lower 48 unconventional, where you're drilling so many wells all the time, then data analytics was very helpful at helping to drive up our EURs, make our completions more efficient, our drilling more efficient and you get a lot of opportunities to practice and so it has a quicker impact on your results. And we also use it in the U. S. For to drive our uptime efficiency to manage our equipment and to help our multi skilled operators in the field to be the most efficient they can be in terms of what well do I work on next and those sorts of things. So, it's really got universal use across the company globally and has moved from being an above ground kind of thing that we use on equipment to being something that helps drive the work we're doing below ground as well. That's helpful, Al. Thanks. And then I wanted to talk a little bit more about the key major project ramp ups this year, the longer cycle projects. You mentioned that Malachi was exceeding expectations. Can you speak to that a little bit? What might be driving that? Where we are in terms of production versus peak capacity? And then can you give us an update on the KBB gas project in Malaysia, how that ramp might be progressing towards full capacity? Yes. The Malachi project, we just we've had better well performance, better reservoir performance than we expected. We're still ramping there. So we're going to continue to get more benefits from that. KBB has continued to be constrained by 3rd party pipelines downstream of it. And so there's been a lot of progress made on that. During there's some additional work being done on those facilities while we are in shutdown right now. We have an extended shutdown that we are on, on KBB right now that and since Malachi gas flows through KBB also, it's got both of those shut in while we complete this turnaround. And as we come up from that, we'll be doing some testing downstream of KBB to try and verify what gas capacity we have now through these 3rd party facilities. And that should allow us to ramp KBB some more as we move back through the back part of the year. And of course, Malachi will be ramping as well. Thank you very much. Thank you. Our next question is from Pavel Molchanov of Raymond James. Please go ahead. Thanks for taking the question guys. You've spelled out 5 Eagle Ford, 4 Bakken and 3 Permian rigs. And recognizing that you do not have any near term plans to add rigs, if you had the choice to add 1 additional or 2 additional ones, which of those 3 plays would be your first call on capital? It's pretty clear that the next place we would add a rig would be the Eagle Ford. The Eagle Ford is mature enough. It has the infrastructure capacity that you could add a rig there and wouldn't have to spend any additional money on takeaway etcetera. And with all the pressure in other places like the Permian, the Eagle Ford has been a good place to operate with less pressure on inflation and better netbacks for the barrels that you're sending out. So for us all of the and we still have a lot of very, very high quality acreage to be drilled, great drilling locations in the Eagle Ford. So it's a pretty straightforward answer for us. Okay. And then just a quick follow-up on Alaska. You've mentioned that you are in the process of trying to sell the Cunai LNG plant. Do you have any involvement at the moment in the Alaska LNG project? Yes. The Kenai LNG plant started up in the late 60s and really there's just the area has sort of run out of gas to feed it. And so it we've been marketing it thinking it might have more value to others and have had some interest in it. So that's something that's in progress. The Alaska LNG project is a mega project that's been that we've had a lot of engineering work going to trying to find the most economic way to develop all the gas that's being recycled right now up at Prudhoe Bay. The current environment of that project is that the state has taken over the engineering commercial work to drive that project forward hoping to do it in a more tax efficient way. And we're supporting the state in those efforts. All right. Appreciate it, guys. Thanks, Kyle. Thank you. And our last question is from Michael Hall of Heikkinen Energy. Please go ahead. Thanks. Appreciate the time. Maybe kind of one in the weeds and one higher up, higher level question. I guess first the detailed one. You just mentioned a difference in netbacks for your crude in the Eagle Ford relative to the Permian. Are you seeing any differences in the way in the sort of pricing you're getting for your crude in the Delaware relative to the Eagle Ford as it relates to gravity discounts or anything along those lines at this point? I don't know about gravity discounts, but the Eagle Ford market has improved significantly over the last several years. It's become a lot more competitive. I guess a couple things probably contributing to that. One is the decline of supply in the Eagle Ford. The other is the crude oil exports last year, which opened up new markets for the Eagle Ford. So we are seeing netback improvements year on year at equivalent pricing of several dollars. So it's become very competitive there. So it sounds like maybe less about the Permian degrading, more about the Eagle Ford improving. Is that fair way to think about it? Yes, that's probably fair. Okay. And then I guess the big picture question, we've kind of hit on it a little bit, but I'm just trying to think about the non shale or let's say non U. S. Business. You guys have a pretty unique perspective as it relates to kind of the deflationary impacts of improving productivity and efficiency in outside of the U. S. I'm just curious if you could kind of compare and contrast how meaningful, how impactful that's been in terms of reducing stay flat capital now versus expectations a year ago and how you think that might continue to progress in the years ahead, it's a big picture. Well, I think it's been a not insignificant factor in driving down our particularly our capital, but also somewhat on our operating costs as a company overall. And we're in the Q1, we continued to see some pretty strong deflation outside the U. S. As we were rolling to new contracts and maybe even a little more deflationary than we would have predicted in the Q1. And so that's been a continuation of a trend over the last couple of years. It's certainly not the key thing that's been driving down our costs and driving down that sort of breakeven CapEx that we've talked about. That's been driven more by other factors, but inflation has been one of the significant piece deflation has been one of the significant pieces. Our model predicts that we will continue to see deflationary forces throughout this year outside the U. S. Internationally, but that they'll be becoming smaller and smaller and that by the time you get to next year that you would stop seeing significant deflation even outside the U. S. And that would start to even up. And so if we continue to see inflation in the lower forty eight, I would expect as we go from 2017 to 2018 that we'll start to have a net inflationary environment. Great. Appreciate it. Helpful color. Thanks,