Earnings Call: Q4 2016

Jan 31, 2017

Good day, everyone, and welcome to this ExxonMobil Corporation 4th Quarter and Full Year 2016 Earnings Call. Today's call is being recorded. At this time, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir. Thank you. Ladies and gentlemen, good morning, and welcome to ExxonMobil's 4th quarter and full year 2016 earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. So before we go further, I'd like to draw your attention to our cautionary statement shown on Slide 2. Turning now to Slide 3, let me begin by summarizing the key headlines of our performance. ExxonMobil generated full year earnings of $7,800,000,000 and 4th quarter earnings of 1,700,000,000 dollars Corporation continues to generate cash flow through the business cycle to meet our commitment to shareholders and support investments across the value chain. In the Q4, cash flow from operations and asset sales exceeded dividends and net investments by a healthy margin. We're realizing the benefit of strengthening prices in the 4th quarter in our upstream financial results. However, these results included a $2,000,000,000 impairment charge in the U. S. Segment, largely related to dry gas operations with undeveloped acreage in the Rocky Mountain region. The impairment charge was the result of an asset recoverability study completed during the quarter and is consistent with the approach we took in 2015. Continued solid performance in our Downstream and Chemical segments underscores the resilience of our integrated business throughout the commodity price cycle. Corporation continued to progress strategic investments across the Upstream, Downstream and Chemical segments during the year, including execution of major projects, value accretive acquisitions and pursuit of high affecting our results. Global economic growth remained modest during the Q4. In the United States, the pace of economic expansion slowed relative to a stronger 3rd quarter. Growth stabilized in China and remained tepid in Europe and Japan despite some improvement in the quarter. Crude oil and natural gas prices strengthened during the quarter on anticipation of an improved supply balance as well as colder weather. Refining margins improved in Europe and Asia, while seasonal margins in the United States weakened. And finally, chemical margins decreased due to higher feed and energy costs, driven largely by commodity products. Turning now to the financial results shown on Slide 5. As indicated, 4th quarter earnings were $1,700,000,000 or $0.41 per share. In the quarter, the corporation distributed dividends of $3,100,000,000 to our shareholders. CapEx was $4,800,000,000 down 35% from the Q4 of 2015, reflecting ongoing capital discipline and strong project execution. Cash flow from operations and asset sales was $9,500,000,000 and at the end of the quarter, cash totaled $3,700,000,000 and debt was $42,800,000,000 The next slide provides more detail on sources and uses of cash. So over the quarter, cash decreased from $5,100,000,000 to $3,700,000,000 Earnings, adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program yielded $9,500,000,000 of cash flow from operations and asset sales. The negative adjustment for working capital and other items reflects changes in deferred tax balances. Uses of cash included shareholder distributions of 3 $100,000,000 and net investments in the business of $3,800,000,000 Debt and other financing items decreased cash by $4,000,000,000 primarily due to a reduction in short term debt. Cash flow from operations and asset sales covered dividends and net investments in the quarter by more than $2,000,000,000 Moving now to Slide 7 for a review of our segmented results. ExxonMobil's 4th quarter earnings decreased $1,100,000,000 from a year ago quarter as a result of the impairment charge taken in the U. S. Upstream segment. This was partly offset by stronger upstream results and an earnings benefit in the corporate and financing segment as a result of favorable non U. S. One time tax items. On average, we expect that near term corporate and financing expenses will be in the range of $400,000,000 to $600,000,000 per quarter, which does represent a reduction relative to our previous guidance. Similarly, in the sequential comparison shown on Slide 8, earnings decreased $970,000,000 Turning now to the upstream financial and operating results starting on Slide 9. 4th quarter upstream earnings decreased $1,500,000,000 from a year ago quarter, resulting in a loss of $642,000,000 Higher realizations improved earnings by $510,000,000 driven by our liquids prices. Crude realizations increased more than $8 per barrel, whereas natural gas realizations decreased $0.32 per 1,000 cubic feet. Volume and mix effects decreased earnings by $50,000,000 and other items added $70,000,000 driven by lower operating expenses, partly offset by the absence of favorable tax items. Excluding the impairment charge, 4th quarter 2016 upstream earnings totaled $1,400,000,000 up $528,000,000 from the prior year quarter. Moving to Slide 10. Oil equivalent production decreased 3% compared to the Q4 of last year to 4,100,000 barrels per day. Liquids production decreased 97,000 barrels per day as new project growth and work program volumes were more than offset by field decline, entitlement impacts and downtime in Nigeria. Natural gas production decreased to 179,000,000 cubic feet per day as higher demand and project growth were more than offset by decline, regulatory impacts in the Netherlands, entitlement effects and divestments. Turning now to the sequential comparison, starting on Slide 11. Upstream earnings decreased $1,300,000,000 for the Q3 of 2016 from the Q3 of 2016. Improved realizations increased earnings by $450,000,000 Crude prices were $4 per barrel higher and natural gas prices were up $0.41 per 1,000 cubic feet. Favorable volume and mix effects contributed $230,000,000 driven by higher seasonal demand, lower downtime and project growth. Other items increased earnings by $90,000,000 driven by favorable foreign exchange effects. Moving to Slide 12. Sequentially, volumes increased more than 8% or 310,000 oil equivalent barrels per day. Liquids production was up 173,000 barrels per day, mainly the result of lower downtime and growth from new projects and more programs. Natural gas production was 823,000,000 cubic feet per day higher than the previous quarter. Stronger seasonal demand in Europe and entitlement effects were partly offset by regulatory impacts in the Netherlands and field decline. Moving now to the Downstream financial and operating results starting on Slide 13. Downstream earnings for the quarter were $1,200,000,000 a decrease of $110,000,000 compared to the Q4 of 2015. Weaker margins reduced earnings by $570,000,000 Favorable volume mix effects, mainly from increased operational efficiency and production optimization improved earnings by $200,000,000 All other items added $260,000,000 mostly from asset management activities, partly offset by increased maintenance costs and unfavorable foreign exchange effects. In the quarter, Imperial Oil completed the sale of its retail network. The sites have been converted to the branded wholesale distributor model, resulting in an earnings benefit of $522,000,000 Turning to Slide 14. Downstream earnings were flat sequentially. Stronger refining margins outside the United States and improved volume mix increased earnings by $160,000,000 $100,000,000 respectively. All other items reduced earnings by $250,000,000 driven by increased maintenance costs and unfavorable inventory and foreign exchange effects, partially offset by asset management gains. Moving now to the chemical financial and operating results starting on Slide 15. 4th quarter chemical earnings were 872,000,000 down $91,000,000 compared to the prior year quarter. Weaker margins, primarily for specialty products, decreased earnings by $10,000,000 while unfavorable volumes and mix effects further reduced earnings by 30,000,000 dollars All other items decreased earnings by $50,000,000 largely due to unfavorable inventory and foreign exchange effects. Moving to Slide 16. Chemical earnings were down almost $300,000,000 sequentially. Weaker margins driven by higher feed and energy costs reduced earnings by $200,000,000 Higher volumes added $50,000,000 and all other items decreased earnings $150,000,000 including seasonally higher operating expenses and unfavorable inventory and foreign exchange effects. Turning now to the full year financial results starting on Slide 17. As I mentioned, 2016 earnings totaled $7,800,000,000 and represents $1.88 per share. Corporation distributed $12,500,000,000 in dividends to our shareholders. CapEx totaled $19,300,000,000 for the year, a reduction of $11,700,000,000 versus 20.15. Throughout the year, we maintained a relentless focus on costs, capturing both structural efficiencies and market savings, while maintaining operational integrity. These efforts resulted in further reduction in total CapEx and OpEx of $16,000,000,000 in the year versus 2015 when excluding the effect of the upstream impairment charge. As a result, cash flow from operations and asset sales was $26,400,000,000 Turning to Slide 18. Cash balances were flat to year end 2015 at $3,700,000,000 Earnings, adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program resulted in the $26,400,000,000 of cash flow from operations and asset sales. The negative working capital and other impacts for the year were driven by lower upstream payables, deferred tax impacts and cash contributions to the U. S. Pension plan. Uses included shareholder distributions of $12,500,000,000 and net investments of 16,700,000,000 dollars Debt and other financing items provided $2,800,000,000 in the year. Moving to Slide 19. This graphic illustrates the corporation's sources and uses of cash during the year and highlights our ability to meet our financial objectives. In a difficult business environment, the corporation continued to generate strong cash flow from We maintain financial flexibility to continue to invest through the cycle in attractive opportunities. As indicated, shareholder distributions totaled $12,500,000,000 annual per share dividends were up 3.5% compared to 2015 and this marks the 34th consecutive year of per share dividend growth. In the Q4 of 2017, ExxonMobil will limit share purchases to amounts needed to offset dilution related to our benefits plans and programs. During the year, ExxonMobil generated $9,700,000,000 of free cash flow, up $3,200,000,000 from 2015, reflecting the resilience of our integrated businesses and our focus on the fundamentals. Looking ahead, we anticipate our 2017 capital and exploration expenditures to be about $22,000,000,000 We know there will be a lot of interest in our investment plans and we will share additional details in a few weeks at our Analyst Meeting. Moving now to Slide 20 and a review of our full year segmented results. 2016 earnings fell $8,300,000,000 as the impact of lower realizations and margins on our upstream and downstream segments was partially offset by stronger chemical results and lower corporate costs associated with several one time tax items. As a result, the full year effective tax rate was 13%. Now assuming current commodity prices and the existing portfolio mix, we do anticipate that the effective tax rate will be between 20 35%, excluding the impact of any large one time items. On this basis, our full year 2016 effective tax rate was within the new guidance range. Turning now to the full year comparison of upstream results starting on Slide 21. Upstream earnings of $196,000,000 were $6,900,000,000 lower than 2015. Realizations reduced earnings by $5,300,000,000 as crude oil prices decreased over $7 per barrel and natural gas prices declined by $1.40 per 1,000 cubic feet. Favorable volume and mix effects increased earnings by $130,000,000 driven by new project growth. All other items added 310,000,000 dollars due to lower operating expenses, partly offset by the absence of favorable tax items. Excluding the impairment charge, 2016 upstream earnings totaled $2,200,000,000 Moving to Slide 22. As indicated, volumes ended the year at 4,100,000 oil equivalent barrels per day, down about 1% compared to last year, but within our full year guidance of 4,000,000 to 4,200,000 oil equivalent barrels per day. Liquids production increased 20,000 barrels per day as project and work program growth was partly offset by field decline and higher unplanned downtime, most notably from 3rd party impacts in Nigeria and wildfires in Canada. Natural gas production, however, decreased 388,000,000 cubic feet per day. Growth from projects and work programs was more than offset by field decline, regulatory restrictions in the Netherlands and divestments. The full year comparison for downstream results is shown on Slide 23. Earnings were $4,200,000,000 a decrease of $2,400,000,000 from 20.15. Weaker margins decreased earnings by $3,800,000,000 Favorable volumes, mix effects increased earnings by $560,000,000 dollars and all other items, primarily asset management gains, increased earnings by $920,000,000 On Slide 24, we show the full year comparison for chemical results. 2016 earnings were $4,600,000,000 up $197,000,000 from 2015. Stronger commodity margins driven by advantage liquids cracking increased earnings $440,000,000 while higher volumes added 100,000,000 dollars Other items reduced earnings by $340,000,000 reflecting the absence of asset management gains. Moving next to an update on our upstream project activities. So we continue to deliver on our investment plans with an unwavering focus on long term value. 5 major projects started up in 2016, adding 250,000 oil crude barrels per day of working interest production capacity. In the Q4, Kashagan and Gorgon Train 2 started up and like other 2016 projects continue to ramp up to plateau production levels. Looking forward, construction activities continue to progress on another five major projects that will come online over the next 2 years. These projects will together another 340,000 oil equivalent barrels per day of working interest production capacity. Moving now to Slide 26. Our focused exploration program continues to enhance our resource portfolio as demonstrated in the Q4. In Guyana, ExxonMobil submitted a development plan for the initial phase of the Liza field. We continue to progress broader development planning activities based on a phased development approach. As part of these activities, contracts were awarded to perform front end engineering and design. We expect to reach the final investment decision for the project later this year. Additionally, as I mentioned in the Q3 earnings call, the Liza III appraisal well successfully encountered an additional deeper reservoir, which was being evaluated at the time. This reservoir is now estimated to contain 100,000,000 to 150,000,000 oil equivalent barrels beneath the Liza field. Also, offshore Guyana, the Payara exploration well discovered hydrocarbons marking the 2nd discovery on the Stabroek Block. The well encountered more than 95 feet of high quality oil bearing sandstone reservoirs. 2 sidetracks have been drilled to rapidly evaluate the discovery and a well test is about to get underway. The data will be analyzed in the coming months to better understand the full resource potential and development options. Now after the Priaro well test, distenna Caron drillship will next move to the Snook prospect just south of the Liza discovery. ExxonMobil also made 2 additional discoveries in the 4th quarter, including the Nigeria Owo-three oil discovery announced in the Q3 earnings call and the Maruk discovery in Papua New Guinea. Both Aloha and Maruk are near currently producing fields, which will enable capital efficient development. We also continue to capture new prospective exploration acreage. In Mexico's offshore bid round 1, ExxonMobil and Total jointly submitted the apparent high bid for Block 2 located in the Perdido area near the U. S. Border. In Cyprus, ExxonMobil and our partner Cutter Petroleum have been selected as the winners of Offshore Block 10 in the recent tender round and we look forward to negotiating the production sharing contract for this high potential block. ExxonMobil has also been awarded an offshore prospecting license for exploration activities in the Gulf of Papua in Papua New Guinea. Initial scope of work on this block is expected to include seismic acquisition. Turning now to Slide 27 and an update on ExxonMobil's U. S. Unconventional portfolio. As a leading oil and gas producer in the United States, we have a strong acreage position and proven operational expertise in unconventional plays. XTO's daily production is currently more than 700,000 oil equivalent barrels per day of which 38% is liquids. Our ownership and operating position enable flexible development and allow us to maximize learning curve benefits through the cycle. For instance, in the Permian Basin, where we operate 2 thirds of our production, our average drilling footage per day has increased about 85% since 2014 because of continuous learning and application of ExxonMobil's proprietary fast drill process. We continue to focus on liquids growth through development activities and strategic farm ins and acquisitions. Since 2010, XTO has grown liquids production at a compounded annual growth rate of about 11% and which currently represents about 12% of the corporation's global liquids production. Moving now to Slide 28. Our most recent acquisition in the Permian further strengthens our unconventional portfolio, adding high quality acreage in the Delaware Basin and more than doubling our resources in the Permian to greater than 6,000,000,000 oil equivalent barrels. ExxonMobil agreed to acquire privately owned companies whose holdings include 250,000 net acres of leasehold in the Permian. The acquisition includes an upfront payment of $5,600,000,000 a specified timeframe. Map on the left shows our heritage acreage in yellow, acreage acquired in transactions in 2014 2015 in blue and the acreage associated with the most recent transactions in red. As you can see, the new leasehold represents a significant position in the heart of the Delaware Basin. Less than 5% of the acquired resource has been developed to date, providing substantial opportunity for future growth. As a result of our proven capabilities, we are well positioned to maximize the value of this resource. This acquisition will add an estimated 3,400,000,000 oil current barrels in multiple stacked pays place, 75% of which is liquids. The highly contiguous nature of the acreage will also provide significant cost advantages by combining XTO's low cost execution capabilities with proprietary technology from upstream research company. We plan to drill the longest laterals within the play, which will maximize per well recoveries and help generate market leading development costs. More than 85% of the wells are expected to have lateral lengths 2 miles or longer because the acreage is not constrained by traditional land lease issues. This transaction increases ExxonMobil's inventory of Permian drill wells that yield at least a 10% rate of return at $40 per barrel to more than 4,500 wells. We currently produce more than 140,000 net oil equivalent barrels per day in the Permian and are operating 10 rigs. This is expected to move higher in 2017 as we begin activity on the newly acquired acreage. Moving now to Slide 29. We continue to strengthen our Downstream and Chemical business through selected integrated investments in our facilities and operations. We recently completed investments in lubricants in chemical facilities in Louisiana that support our aviation lubricants business, commissioning a new state of the art jet oil manufacturing facility in October of last year. The new plant will use Group 5 synthetic based stocks sourced from facilities that started up last year at our adjacent Baton Rouge chemical plant. Across the fuels, lubricants chemical value chains, we continue to high grade our portfolio and reduce complexity to efficiently capture market value while reducing operational risk and capital expenditures. In the quarter, we reached agreements to divest several downstream affiliates in Africa and South America. Additionally, as I mentioned earlier, Imperial Oil completed the conversion of its retail business to a branded wholesaler model. This model benefits from significantly lower capital requirements, while continuing to grow retail sales. We also continue to enhance our logistics capabilities by focusing on strategic midstream assets. We recently announced the formation of a joint venture with Sunoco Logistics that will expand access to domestic crude oils by improving transportation options from the Permian and Ardmore basins to the U. S. Gulf Coast refineries. In Baytown and Mount Bellevue, Texas, the construction of our new 1,500,000 ton per annum ethane steam cracker and associated metallocene polyethylene facilities is progressing well with phase startup commencing in the second half of this year. Finally, ExxonMobil recently announced a new project at our Beaumont, Texas facility to expand polyethylene capacity by 650,000 tons per year. This expansion amounts to a 65% increase in polyethylene capacity at the site. Together, the projects at Beaumont and Mount Bellevue represent multibillion dollar investments that will increase ExxonMobil's U. S. Polyethylene production by nearly 2,000,000 tons per year or 40%, making Texas our largest polyethylene supply point. The new facilities will process advantaged ethane feedstock to meet growing global chemical demand. Moving to the final chart on Slide 30. I'd like to conclude today's comments with a brief summary of our 2016 performance, which is really underpinned by our sustained focus on value. ExxonMobil earned $7,800,000,000 in the year, while managing through a challenging business environment. Corporation delivered on its plan to produce 4,100,000 oil crude barrels per day and maintain focus on business fundamentals. Volume contributions from our portfolio of new developments underscore our project execution excellence and reputation as a reliable operator. Total CapEx was $19,300,000,000 down 38% from 2015 as we exercised capital discipline and investment selectivity and continue to pursue market and execution efficiencies. Solid operating performance combined with continued investment and cost discipline generated cash flow from operations and asset sales of 20 $6,400,000,000 and positive free cash flow of $9,700,000,000 As I mentioned in the Q4, cash flow from operations and asset sales more than covered the dividend and net investments in the business. Our commitment to shareholders remains strong as demonstrated by our reliable and growing dividend. We are confident in ExxonMobil's integrated business model and our ability to continue to grow long term value in any business environment. Now we'll discuss our forward plans in more detail at the upcoming analyst meeting, which will take place at the New York Stock Exchange on Wednesday, March 1. That concludes my prepared remarks on a very busy year. And now I would be happy to take your questions. Thank you, Mr. Woodberry. The question and answer session will be conducted electronically. We'll take our first question from Neil Mehta with Goldman Sachs. Jeff, I appreciate the incremental disclosure here on the Delaware transaction. That's where I want to start. As you think about that deal, is it indicative the view that Exxon has that you see more value in, let's say, the private market than the public market? And can you just talk a bit more about the opportunity you see in U. S. Unconventional to do deals? Yes, Neal. That's a good question. I would tell you that I would not view it as being exclusive to one type of transaction. As we have talked in the past, we keep a full view on what may be out there that could be competitive with our existing resource base and accretive to overall long term financial performance. These things don't happen overnight. Several of these take many, many months to go ahead and put in place and not all of them transpire into an executed deal. But what's important is that it is a key aspect of our overall asset management program in order to high grade our portfolio with the view of our underlying mission of growing shareholder value. Appreciate that. And then my follow-up, Jeff, is on CapEx. I imagine we're going to get a little bit more color on this at the Analyst Day in a couple of weeks. But the $22,000,000,000 that you outlined is in line with what you talked about earlier this year, but up from 20 16. Can you at least speak high level to what's driving the growth in 2017 versus 2016 in terms of CapEx? Is that cost inflation or that higher growth? And then bigger picture, can you talk about what you're seeing in terms of cost inflation across your portfolio? Yes. Well, Neil, as you indicated, we do plan on giving a lot more detail around our investment plans in the analyst presentation that will be just a little bit more a month from now. As you indicated, the $22,000,000,000 that I mentioned is fairly consistent with our forward looking plan that we provided a year ago. I would tell you that it does not reflect a year on year increase associated with the cost inflation. And in fact, the inverse is true is that the organization continues to look for high impact capital efficiencies to drive the cost down. And it is by and large a function of activity level. Certainly, as activity continues to build, we will all experience some market pressures, but that doesn't relieve us of our fundamental objective of maximizing the value proposition. And rest assured that the organization will continue to be keep focused on what new solutions are there for us to get to a lower cost outcome. And the organization is very committed to make sure that we're capturing those and really leading the cost curve. Our next question comes from Phil Gresh with JPMorgan. Hey, Jeff. Good morning. Good morning, Phil. Hey, I want to start on the working capital and other headwind, dollars 2 400,000,000 in the quarter, dollars 8,000,000,000 for the year. It's a pretty big number. I guess I was just wondering if you could maybe elaborate or break that down a little more between deferred taxes and some of the other items. And moving forward, how you think about the ability to lessen that headwind in 2017? Well, I mean, obviously, there's really 2 large components that are driving it. Obviously, the working the changes in the working capital. By and large, adjustments in receivables and payables due to activity and changes in commodity prices. And then the second part are other balance sheet items, some of that associated with deferred taxes. As I said, it also includes cash contributions that we made to the pension plan. So a lot of moving parts pieces is understandable and I understand the interest. But that's about all the color I have for you at this point. Okay. And then in terms of kind of priorities for with cash from here, I mean to the extent you have excess free cash flow above the dividend in 2017, is the first priority with your ending debt balances where they are, would it be debt pay down? Or do you feel like you have flexibility to other things? I think it's a function of the business climate and the opportunities that we have for ourselves. As you've heard us say before, if you think about our capital allocation approach, it's a commitment to provide a reliable and growing dividend to our shareholders and business with opportunities we believe are going to enhance the long term return of the corporation. The excess cash by and large, we don't want to hold large cash balances. If we don't have an immediate need for it, we will think about either paying down debt or buying back shares and that is done primarily on a quarterly basis. The corporation will step back and look at a number of factors like our current financial position, our potential opportunities to put capital to work as well as what we see in the near term in terms of the business outlook. Okay. Thanks. We'll take our next question from Doug Leggate with Bank of America. Thanks. Good morning, everybody. Good morning, Jeff. Good morning, Doug. Geoff, I wonder if I could kick off with your capital guidance. I guess, it's kind of a follow-up, but ask you if you could move it on to talk a little bit about the production capacity that you see that goes along with that capital. I'm assuming the Permian is part of it. What I'm really driving at is you've got a number of projects still ramping up. So could you give us some idea as to what the remaining capacity is for those ramp ups? In other words, what would the delta be if those projects were running full out in 2017? And I've got a follow-up, please. Yes. Doug, I mean, first observation would be is that you're correct that we have projects that started up all the way back to early 2015 that are still well within their development drilling programs are ramping up to plateau production rate. Some of these things could take 12 to 24 months to fully reach the plateau production rate. I don't have a specific number for you as to what is that incremental capacity that's left to ramp up. But I'll also highlight that a number of those projects also are exceeding design expectations due to really strong management by the organization around reliability and reservoir performance. We talked about Papua New Guinea in the past, design at about 6.9. It's now produced above 8,000,000 tons per annum. You've heard in the news about Banyu Europe, which the development base is about 165,000 barrels a day. We've been producing about 185,000 barrels a day. And it is now under review to take it all the way up to 200,000 barrels a day. Again, very, very strong operational reliability and very good reservoir performance. So the point I'm making is above the additional ramp up that's anticipated from the major project startups, there's also another layer of capacity that we're building on based on the organization's focus on the operational capabilities of our assets. Okay. Just to be clear, Jeff, on the Permian piece of that, I think at the time of the acquisition, you talked about moving to a 15 rig program. Is that what's the starting point for that? What are you running right now? So you're talking about the recent acquisition, I believe. Right. Yes. So let me back up and first say that if you look at the overall development of the new acreage, we see that over the long term, it would support a multi decade production plateau of about 350,000 oil equivalent barrels per day. So a very substantial addition to liquids production as well. And in fact, if I can put it in scale for you, if you remember the in my prepared comments, I said that our current liquids production from XTO represents about 12% of the corporation's global liquids production. If you were just to add on the expectation from the Delaware acreage, that would take us up somewhere between 20% to 25% of our global liquids production. So the point being is it's a very material part of the portfolio. As I indicated, we've got 10 rigs running right now. We are planning on ramping up that activity over the near future. But we're going to do it commensurate with the leasehold development requirements. We're very positive about this obviously given the acquisition and we want to get to it right away. Jeff, I appreciate that answer. My follow-up is very hopefully a quick one. Payara, I think, in Guyana, the limited disclosure you've given so far, I guess, has raised some questions about potential scale. Is there anything you can tell us about relative scale or absolute scale of both Louisa and Payara reserve expectations ultimately, but also a likely development plan both beyond the early production And I'll leave it there. Thanks. Yes, Doug. So as we indicated in the Q3, given the Liza III appraisal well, that really built confidence in a view that we've got at least 1,000,000,000 barrels of recoverable reserve. Since then, we've drilled the deeper zone that added additional volume as I indicated in the prepared comments. Pallara, we're very pleased with the outcome. We moved very quickly to drill 2 additional sidetracks in order to better define the reservoir. And as I said, I think the next critical piece of information will be this well Pagliara. Now obviously, as we move along in each operational activity, that data is feeding our real time development planning effort to assess the full development scope of the block. And remember, we've got 2 other blocks that we'll have to integrate as well. But right now, we're moving forward with the initial phase development. As we've said previously, it's 100,000 barrel a day FPSO. We do feel like that's a prudent step, very good strong returns. And right now, we view that as just the initial phase. Okay. I'll wait till the Analyst Day. Thanks, Jeff. Thank you, Doug. We'll go next to John Herrlin with Societe Generale. Yes. Hi. Two quick ones for me, Jeff. Regarding your CapEx, is that just strictly E and D or are you including the acquisition cost for BaaS? Well, John, the on the Permian acquisition, remember, we're purchasing that via shares. So it excludes that share purchase. Okay. Well, it'll still be part of incurred at the end of the day, but that's fine. Next one on payerin. Is that age correlative with the upper lease of pay or the lower lease of pay? Or can you not say anything on that? Yes. I really don't have anything to share on that at this point. Okay. That's it. Thank you. Thank you. We'll go next to Doug Thorson with Evercore ISI. Good morning, Jeff. Good morning, Doug. Just for clarification, is it correct that the $2,100,000,000 in asset sale gains were after tax and included in the $1,700,000,000 earnings figure? And either way, could you provide some guidance as to which operating segments that these gains came from? Yes. So the proceeds of $2,100,000,000 you're asking about the proceeds that we had in the press release? Correct. Yes. Those are before tax proceeds. Okay. And then those proceeds are primarily within our downstream portfolio. I'd say about over 85% of it is in the downstream. Okay. And the largest part of that is in the Canada retail sales. Jeff, can you give guidance on after tax? On the proceeds? Yes. No, I don't have any numbers to share with you on that. Okay. And then also, 3 of your competitors have taken steps to enhance their pay for performance linkage by changing the metrics that they're using for their business units to ones which tie to intrinsic value on the stock market and probably CEO pay too. And while your stock has outperformed some of these companies in the equity market over the years, my question is, how is the company thinking about P4P this year and specifically whether there's need for change given its rising profile as a corporate governance issue with investors? Well, if you remember, our you're talking about our executive compensation program. I am. Yes. As you and I talked in the past, remember that a large part of our compensation program is based on a long term payment schedule. And it is intended in order to make sure that our executives are being held to the decisions that we're making over the long term. And our long term incentive is paid over a 10 year period, 50% about 5 years, the remaining 50% after 10 years. Really, it's the later of 10 years or retirement. So some of us go even beyond 10 years. But it's really designed to ensure that our executives feel the same performance that our investors feel because when it does pay out, it's paid out at the current stock price. Now I'll tell you that the compensation committee does step back and look at the program periodically to make sure that it's ensuring, it's encouraging the right type of behaviors and it's recognizing the success of the corporation. For those that are listening about it, we've got a what we call an executive compensation overview disclosure that we send out annually that provide a lot of good detail about the structure of the program. Okay. Okay. Thanks a lot, Jeff. Doug, just a follow-up on your question regarding the Canadian Retail. I said in my prepared comments, it was $522,000,000 after tax. Great. Thanks a lot. We'll go next to Sam Margolin with Cowen and Company. Good morning, Jeff. How are you? Good morning, Sam. So late in the quarter, you finally got FERC approval for Golden Pass. I guess I'd add that to the bucket in one of the later slides about kind of de lengthening your U. S. Natgas position maybe. So I was wondering, I'm sure you've made comments on this before, but how do you think now in the new environment or how things are played out currently how U. S. LNG competes with some of your other world scale LNG potential assets around the world? And how do you think about that sort of moving forward as you want to develop additional U. S. Gas assets in the context of that? Yes. It's a good question, Sam. If you could, the best place to start is really thinking about it from our overall energy outlook and our supply demand balances. Over the long term, we expect that LNG capacity or demand will continue to grow, in fact, almost something like 2 50 percent of today's LNG capacity. A large part of that growth is primarily driven by Asia. Now like most commodities, you're going to have periods in which there's oversupply and periods where there's insufficient supply. And we do expect that with a number of projects coming on that there are some projects that where there is a period in which we'll see LNG oversupply. Now if I step back from that, that's the if you will the value proposition. And I step back, we've got a very extensive portfolio. And I would tell you that Brownfield Developments that is incremental investments to existing operations like Papua New Guinea or even Golden Pass provide us an economic advantage by lowering the cost by leveraging the installed investment. At Golden Pass, as you noted, we did get FERC approval. The one key step we're still waiting for after many years is final DOA Department of Energy approval of non FTA export authorization and we're hoping that that will come shortly. But each one of these projects will be evaluated on their own merit. As you've heard us say previously, as it relates to LNG projects, we want to lock in a large part of that capacity on long term contracts. And going past within the whole portfolio of investment opportunities that we have, we're pursuing long term sales contracts. But they'll all be evaluated on their own merits. Okay. I guess my follow-up then is sort of on the same topic. It might be a similar answer on sort of an individual project analysis basis. But as you look within your 30 year outlook and a lot of energy demand globally is driven by gas and against the backdrop of early this year, the de booking of some natural gas reserves domestically and an imperative to maybe get those rebooked over time. What do you think is more preferable between uses of that gas for you investing in kind of shipping it to these Asian demand centers via LNG or keeping it onshore and consuming it within your chemical business? That's a good question. It really highlights and talks to the issue of optionality. We are the largest gas producer in the U. S. Where do we see that gas going in the future? Again, stepping back from the energy outlook, we expect gas is going to grow about 1.5% per year. That's primarily driven by 2 things: 1, power generation and the second thing, petrochemicals. As you know, we've got a very integrated value chain. The utilization of that into our value chain in the Chemicals business as well as when we started this discussion around LNG export. So optionality gives us tremendous amount of flexibility to make sure that we're maximizing the value proposition. All right. Thanks, Jeff. You bet. We'll go next to Evan Kallio with Morgan Stanley. Hey, good morning, Jeff. Good morning. I have a question. Any outlook on future project returns, conventional versus your acquired Permian? I asked the question in the context that you make a significant acquisition in one of the tighter energy asset markets in the world, the Permian. You discuss a relatively healthy plateau, future plateau level of production, while there's distress in asset markets globally in regions in which Exxon operates. So I mean, I don't know, I guess given the assets and these laterals, this longer laterals you discussed, Any can you talk about how you think the future returns compete within your portfolio and how advantaged they may be? Well, It really goes back to the It really goes back to the fundamental objective that we're trying to achieve through acquisitions or through exploration or our investment program that is to make sure that we're going to maintain a focus on value accretive performance. So we're looking for investments that are going to continue to maintain our industry leading return on capital employed. So certainly very attractive. We've given you a sense from the for the economics where I think back in the second quarter, we showed you some of the progress we've made in unit development cost, operating cost. We gave you a sense for the portfolio then which with the Bakken and Permian together, we had over 2,000 wells that achieved greater than a 10% return. Money forward economics, full in, fully loaded on a $40 per barrel price. You add these this acquisition into this, it takes us up to about 4,500 wells. So a very robust inventory. The long term objective thinking about the short cycle versus long cycle is 1 and making sure that the pace maximizes the learnings that we're integrating and captures the technology application that we want to apply in order to achieve these outcomes like the length of the lab goals. But I'd say that this acquisition and the investments that we plan under it are going to be very competitive to our existing inventory of opportunities. I mean can you even mention how much of your expected CapEx, dollars 20 $2,000,000,000 CapEx is in shorter cycle, however you define that whether offshore or onshore? And related, I mean, how do you consider the value of capital flexibility or cycle times in your gating process, either as a plus or a minus for a longer cycle project? Yes. On the first question, I'd tell you that we are going to provide some more color in about a month's time at the Analyst Meeting. So if I ask you just to hold that thought, we'll give you a little bit more perspective at that time. On the second one, the balance, the overall balance of short cycle versus long cycle, obviously, we've got a very large resource inventory with over 90,000,000,000 barrels. We're trying to move that resource inventory at the same time maintaining a robust level of short cycle investments. Now of course that short cycle inventory continues to grow with all these acquisitions that we've been picking up. So that's done through our annual planning process. We look at the execution capability of the organization, the service sector and then we look at the fundamental cash management objectives to make sure that we've got that flexibility. And a key element of when we share a CapEx objective, we've got we've built in flexibility to the upside as well as flexibility to the downside. We know how to flex that program depending on what commodity prices do. Appreciate it. We'll go next to Jason Gammel with Jefferies. Thanks. Hi, Jeff. Jeff, I know that in the Q3 press release, you talked about the potential for needing to take some negative revisions to proved reserves in the oil sands. And clearly, at least in the quarter, you haven't taken any financial impairments to those assets. Can you talk about whether you would still view those proved reserves as potentially needing to be written down or whether the price recovery into the end of the year was sufficient to allow those to remain on the books? Yes. It's a good question. Again, I want to make sure that everybody is very clear that there is a separation between proved reserves reporting under the SEC rules and then the whole issue of asset impairments. And really what you're asking Jason is clear I think clearly the question about proved reserves. In the Q3, we indicated because we thought it was prudent at the time given where crude prices were that we indicated that we were likely going to take as much as 4,600,000,000 barrels out approved and put them in our resource base. And I'll remind you that I emphasized at that time that even though we make that transfer, there is no change to our operations or how we manage the business, those assets going forward. We'll be announcing our final year end reserves here in the next couple of weeks as we typically do. In short, we do expect to reflect most of the SEC pricing impact that we discussed in the Q3. But I will also note that we anticipate that there will be some partial offsets to those numbers. So stay tuned. We'll be finalizing that shortly and be releasing that information here in the next 2 weeks. Appreciate that, Jeff. And then just as a follow-up, the acquisition that you've announced this year, I'm afraid a little bit lost on the process for actually completing the Intra Oil transaction. Can you talk about what is still outstanding there in order to get that deal done? Yes. So we're going back through the process following a decision by Canadian courts. And we put in place a new amended agreement between InterOil and ExxonMobil. And I'll just remind everybody that in the first process through the InterOil Board fully unanimously approved this transaction and shareholders approved it by over 80%. So we're going back through the process. And right now, there is a shareholder vote anticipated in the middle of February. And then as in the last cycle through this, we will need to go back to the Yukon courts to make a final ruling on the offer and then hopefully close thereafter. Great. Thanks, Jeff. Appreciate that. We'll go next to Ryan Todd with Deutsche Bank. Great. Thanks. Maybe if I could have a couple of quick follow ups on capital budget. And I realize you'll give more details next month. But how should we think about capital allocation some extent for the Lower forty eight business with the addition of the Permian acquisition? Does that highlight the growing relative share of the capital budget by the U. S. Onshore? Is it additive to your existing activity? Or should we expect to see the capital diverted away from areas like the Bakken and Oklahoma and be replaced activity in the Permian? Well, I mean, Ryan, we'll certainly provide more color here in a month or so. But I mean, directionally, it's a fairly sizable acquisition that we're making in the Permian. We feel good about our acreage position in the other unconventional as an indicative guidance, I would tell you that it's likely going to add additional CapEx to our short cycle investments in order to move forward on the acreage that we picked up in the acquisition. Okay. That's helpful. And then maybe just one on 2016 CapEx, which came in quite a bit lower than guidance early in the year. I mean, can you any comments on what were the primary drivers? Is that cost deflation, deferral of activity, change any expected scope and spend? Yes. Thanks for asking the question, Ryan, because I think it does reflect very well on how the corporation responded and particularly our people and their focus on recognizing that we're in a down cycle and we got a great opportunity to take advantage during that down cycle. I'd say that it really is a function of a number of things. One is and it all is underpinned by our very strong focus around capital discipline. When it comes down to capital efficiency, opportunities that we're able to continue to capture regardless of where we're in the commodity price cycle. It includes market capture. We all know that the service sector and the related costs have dropped materially. It also importantly, it has to do with the very strong project execution performance on our operated projects, most of which coming in on budget and on cost. And then there was an element of how we paced our projects for several reasons: 1, recognizing the business climate, wanting to stay within our means and 2, in a low price environment, there's unique value that we're able to capture by going back and recycling through the development planning process on some of these projects to try to do things like reduce the cost structure, add additional resource to increase resource density. But it really is an opportunity in the down cycle to go ahead and add incremental value to those future investment. Thanks, Jeff. Okay. Thank you. We'll go next to Paul Sankey with Wolfe Research. Jeff, with the changes in Washington, I just wondered what Exxon's stance is. Firstly, I assume you guys are pro lifting sanctions on Russia. Secondly, I assume that you would be anti the border adjusted tax. And finally, can you make any comments about the impact on your operations in Iraq from the recent limitations on travel there? I wondered if that was going to I assume that's going to directly impact you. Thanks. Yes. I guess a couple of comments. We will continue to advocate free market principles. When it comes down to the important discussion that's happening in Congress and the current administration around the tax code, we believe the tax code should be globally competitive. Predictable, stable, providing investment certainty and not picking winners and losers. So I mean we will continue to stay principle based in our view on those matters. With respect to Russia, we will continue to fully comply with the existing sanctions. And I'm not going to speculate when or if they are fully satisfied and removed in the future. And then on the Iraq and more broadly speaking, some of the issues associated with decisions taken in the U. S, a key aspect wherever we are around the world including Iraq is the security of our people and our contractors. And we have a very dedicated effort within the organization to ensure that we're trying to stay in front of potential threats that the organization needs to respond to in order to ensure the safety and security of our assets and people. So I'd rather not talk about specifics, but I will tell you that we're monitoring the situation very closely. Understood, Jeff. If I could completely change the subject. The President of Guyana was commenting earlier in the week that we could see production start up in 2019 from Liza. Is that reasonable, do you think? We've also obviously heard from Hess about final investment decision this year. And if we look back to what you did in Angola as an example of your speed with which you can get these things up and running with the idea of getting very early cash flow, I wondered if you could handicap the chances that we do see first production much sooner than the I think you've been talking more 2021. No, it's a good question. Listen, I think 1st and foremost is that we're going to work with our co ventures and the government to move this project along in the most efficient and expedient way. And all stakeholders have a role in deciding how this project moves forward. And we certainly understand the resource owners' interest and I'll tell you, we are very attuned to it. As I indicated in my prepared comments, we think it is reasonable that the initial phase will move forward to an FID decision later this year. The guidance that we have been providing as well as consistent with the regulatory filings is that the initial phase would start up in 2020. Got it, Jeff. Thank you. Welcome. We'll take our next question from Asit Sen with CLSA Americas. Good morning, Jeff. Good morning, Asif. So, thanks for the color on the short cycle versus long cycle. I just wanted to make sure I got the Permian numbers right. So the 140,000 barrels a day production now and your comment on the 350,000 barrels a day of plateau production from the recent Delaware acquisition, what time frame are we looking at? Well, we have yet to share the specifics around the buildup of that. But as I indicated, Dasset, we want to get at it quickly. But the $350,000 potential and that's oil equivalent barrels per day, we believe is a reasonable investment program that can be maintained over multi decades. Got you. Okay. And my quick question on the new project start up. Barzan, is that a 2017 start up? And could you remind us on the working interest that you have there, 7%? That's what I have. Yes. Our working interest is 7% and you really need to talk to the operator, RASGAS, on specifics around the project. Great. Thanks, Jeff. Welcome. We'll go next to Paul Cheng with Barclays. Hi. This is Moses Sutton on for Paul. Quick question on the impairment charges. Have you completed the review of the entire portfolio or are certain assets still under review in 2017? We've completed the review of the entire portfolio. Great. Thank you. That's it from us. You're welcome. We'll go next to Alastair Syme with Citi. Hi, Jeff. I also had a question on the impairment. If we look back at your most recent energy outlook, it looks like you made some quite big changes around the expectation on North American tight oil and gas. Is it possible to relate those changes back to today's impairment decision? It feels like you expect there's going to be a lot of growth in associated gas, for instance. Well, I mean, it's a good question, Alastair. But I'd tell you, the first point I'd make is the reason why we do an annual update on energy outlook is really to make sure that we are most informed about the fundamental building blocks that really underpin that demand projection. The changes that you're asking about is really a function of a number of factors. It's not just the energy outlook. It's our we do this in conjunction with our annual budget and plans process. And it also is a function as part of the energy outlook is looking at the competitiveness of different resources Okay. Thank you. As a follow Okay. As a follow-up, can I ask can you explain what non U? S. Tax effects are on the corporate items? Are these upstream or downstream items? The non U. S. Tax items really across a number of the business segments, but the largest in the Q4 were primarily in the upstream business. Is it possible to give any color what they relate to? We don't have any additional information to share. Okay. Thanks very much, Jeff. You're welcome. We'll go next to Brendan Warren with BMO Capital Markets. Yes. Thanks, Jeff. So just first question, just on those 5 major project startups. You flagged 2017 to 2018, particular I guess with Hebron and Sakhalin that you do operate. Are they still in 2017 recognizing Hebron you most recently said it was on track to end 2017? I have a follow-up as well. Thanks. Yes. That's correct. They are currently on plan to achieve those objectives. Okay. So they're both in before end 2017. Then my follow-up refers and it's probably you'll probably say defer this to the Capital Markets Day. But if I refer back to Slide 33 from the Capital Markets Day, you'd sort of given guidance of cash flow from operations and asset sales for 2016 with a range of sort of at $40 a barrel to $80 a barrel. It looks like $45 average for this year, you've just come in at where the $40 a barrel line should be. I'm trying to reconcile you had a weaker cash flow number for 2016 and whether that changes your view for 2017 in terms of cash flow from operations? Yes, Brendan, a good question and an important dialogue that we think is something that we should be talking to. And we will update that chart you're referring to in the upcoming Analyst Day here within a month and be ready to talk more about it with our current views. Okay. Thanks, Jeff. Welcome. We'll go next to Ed Westlake with Credit Suisse. Yes, good morning. It's up to you here. Two questions, I guess. Firstly, decline rate. I mean, you guys have done very well on the development on the production side to minimize base decline. You've got these long duration assets in a number of geographies. Maybe just a quick update as far out as you can go on the expected decline rate on the base business. Yes. So Ed, our we assess our long term decline rate over every year. And in fact, it's in our 10 ks. And what we've had in terms of a decline rate here in the last recent past, last couple of years has been 3%. And let me just qualify that 3% as being that does not include project activity. So if we were to stop our investment program, that's It would be high. Yes. Okay. And then, we haven't really had a conversation around OpEx and margins, maybe deferred tax, maybe to the prior question on cash flow as you go forward. But maybe just a word on how much more savings you can get on OpEx, the new projects, are they accretive to margins? And then what you expect to happen to deferred taxes as prices bump up a little here? Yes. Yes. Really good question on in terms of OpEx and how we're managing that. I would tell you that we are never satisfied. I mean, we clearly understand there's been a lot of progress over the last 2 years, but I can tell you that the organization doesn't believe status quo is sufficient. As I alluded to previously, we'll continue to look for structural opportunities. We'll continue to be very focused on organizational effectiveness. And importantly, we'll continue to work with the service sector to come up with lower cost, higher quality opportunities. And sure, if activity continues to build, there's going to be market pressures. But we're going to continue to work against those market pressures to capture incremental value. On deferred income taxes in the future, there's really nothing more I can share with you. You can appreciate some of this has to do with the current low price environment they've been through here the last couple of years. And margin should also improve with the new projects coming on presumably? Well, that's the objective of the investment program. Yes. Thanks, Ed. We'll go next to Tien Tsakmehian with Exane BNP. Yes. Hi, good morning, Jeff. Thanks for taking my questions. I had 2 actually. Firstly, could you just talk about, I know you're intending to issue equity for the recent Permian transaction. Is there any thoughts about buying back to offset that dilution? And my second question just in terms of exploration for 2017. I know the focus is on Guyana. But could you talk about any other high impact plays for 2017 and the spend associated? Thank you. Yes. So, Thipan, on the fundamental question, to me, I interpreted it as whether we're going to buy back any stock. And I'll go back to our earlier discussion around it. It's really a quarterly decision that management makes based on a number of variables that I've already described. And as I said in the prepared comments, we don't anticipate doing any type of buybacks other than to address antidilutive impacts associated with the programs and benefits programs and plans. On other exploration focus, we expect for the near term, flat spend out to the next several years. But I've shared a number of key areas that we're focusing our attention. Cypress, the high quality block we got there on Block 10 that we've got to enter into negotiations on the production sharing contract, but we're very encouraged by it. Mexico, the Block 1 that we picked up, which is right along the U. S. Border, adjacent to some U. S. Acreage that we've got, Again, very encouraged by it, put plans in place. I indicated that we continue to expand to our exploration acreage position in Papua New Guinea. You think about some of the big high potential areas for us, Papua New Guinea is very important to us. Guyana, that area has been very important to us. And then as we've been talking about off and on today is the unconventional business with a very strong focus on the liquids potential. So I think it really does make a very strong statement around the value proposition that we're trying to deliver to our shareholders. Okay. Thanks, Jeff. I was just wondering, I mean, when you think about potential acquisition between equity and adding debt, I mean, could you just talk about how the market should think about that? Should we see if there are opportunities Exxon uses paper rather than debt? Yes. Well, it's going to be case specific. I mean, the important message for you to understand is that we have the flexibility to do either. The final structure of a given transaction is really a function of the between the parties with focus of what the seller wants from the transaction. But I wouldn't read any more into it relating to our capital structure. Great. Thank you. And our final question comes from Pavel Molchanov with Raymond James. Thanks Just two quick ones. You mentioned that almost all of the increase towards the $22,000,000,000 CapEx budget reflects higher activity. Can you be a little more specific on what service cost inflation you are assuming, particularly in your North American CapEx? Pavel, as I indicated earlier, we're going to provide more color around our investment plans about a month's time in the analyst meeting. I just ask you to hold that until we get to that point. Okay. And as far as the InterOil closing process, you're currently doing the rerun of the shareholder vote. Should the Yukon Court block the second attempt as they block the first one? Is there any other alternative in your mind to getting shareholder approval? Yes. Well, I mean, let me not speculate as to how this will progress. Very strong support from the shareholders of InterOil. This is a process that InterOil is running. And we think that we have addressed some of the comments that were made in the first process. So let's let that go through and then we'll decide how we move forward from there. All right. Appreciate it. Thank you. And we have no further questions in the queue at this time. Well, I want to thank everybody for their participation today and I really do appreciate your time and the questions. We appreciate your continued interest in ExxonMobil and we really do look forward to visiting with you next month at the analyst meeting. So until then, we'll keep very focused on our fundamental mission of growing long term shareholder value. Thank you. And that concludes today's conference. We thank you for your participation.