Jeff Woodbury - Vice President of Investor Relations and Secretary

Neil Mehta - Goldman Sachs Phil Gresh - JPMorgan Doug Leggate - Bank of America John Herrlin - Societe Generale Doug Terreson - Evercore ISI Sam Margolin - Cowen and Company Evan Calio - Morgan Stanley Jason Gammel - Jefferies Ryan Todd - Deutsche Bank Paul Sankey - Wolfe Research Asit Sen - CLSA Americas Moses Sutton - Barclays Alastair Syme - Citi Brendan Warren - BMO Capital Markets Ed Westlake - Credit Suisse Theepan Jothilingam - Exane BNP Pavel Molchanov - Raymond James

Good day everyone and welcome to this ExxonMobil Corporation fourth 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 fourth quarter and full year 216 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 would like to draw your attention to our cautionary statements shown on slide two. Turning now to slide three, let me begin by summarizing the key headlines of our performance. ExxonMobil generated full year earnings of $7.8 billion and fourth quarter earnings of $1.7 billion. 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 fourth quarter, cash flow from operations and asset sales exceeded dividends and net investments by a healthy margin. We are realizing the benefit of strengthening prices in the fourth quarter in our upstream financial results. However these results included a $2 billion 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 on our downstream and chemicals 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 potential exploration opportunities. Moving to slide four, we provide an overview of some of the external factors affecting our results. Global economic growth remained modest during the fourth quarter. In the United States, the pace of economic expansion slowed relative to a stronger third quarter. We have stabilized in China and remain 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 five. As indicated, fourth quarter earnings were $1.7 billion or $0.41 per share. In the quarter, the corporation distributed dividends of $3.1 billion to our shareholders. CapEx was $4.8 billion, down 35% from the fourth quarter of 2015 reflecting ongoing capital discipline and strong project execution. Cash flow from operations and asset sales was $9.5 billion and at the end of the quarter cash totaled $3.7 billion and debt was $42.8 billion. The next slide provides more detail on sources and uses of cash. So over the quarter, cash decreased from $5.1 billion to $3.7 billion. Earnings, adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program yielded $9.5 billion 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 $3.1 billion and net investments in the business of $3.8 billion. Debt and other financing items decreased cash by $4 billion, primarily due to a reduction in short-term debt. Cash flow from operations and asset sales cover dividends and net investments in the quarter by more than $2 billion. Moving now to slide seven for a review of our segmented results. ExxonMobil's fourth quarter earnings decreased $1.1 billion 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 in 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 million to $600 million per quarter which does represent a reduction relative to our previous guidance. Similarly in the sequential comparison shown on slide eight, earnings decreased $970 million. Turning now to the upstream financial and operating results starting on slide nine. Fourth quarter upstream earnings decreased $1.5 billion from a year ago quarter resulting in a loss of $642 million. Higher realizations improved earnings by $510 million driven by higher liquids prices. Crude realizations increased more than $8 per barrel whereas natural gas realizations decreased $0.32 per thousand cubic feet. Volume and mix effects decreased earnings by $50 million. And other items added $70 million driven by lower operating expenses partly offset by the absence of favorable tax items. Excluding the impairment charge, fourth quarter 2016 upstream earnings totaled $1.4 billion, up $528 million from the prior year quarter. Moving to slide 10. Oil equivalent production decreased 3% compared to the fourth quarter of last year to 4.1 million barrels per day. Liquids production decreased 97,000 barrels per day as new project growth and more program volumes were more than offset by field decline, entitlement impacts and downtime in Nigeria. Natural gas production decreased to 179 million 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 $1.3 billion from the third quarter of 2016. Improved realizations increased earnings by $450 million. Crude prices were $4 per barrel higher and natural gas prices were up $0.41 per thousand cubic feet. Favorable volume and mix effects contributed $230 million, driven by higher seasonal demand, lower downtime and project growth. Other items increased earnings by $90 million 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 work programs. Natural gas production was 823 million 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 $1.2 billion, a decrease of $110 million compared to the fourth of 2015. Weaker margins reduced earnings by $570 million. Favorable volume mix effects mainly from increased operational efficiency and production optimization improved earnings by $200 million. All other items added $260 million, 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 are then converted to their branded wholesale distributor model resulting in an earnings benefit of $522 million dollars. Turning to slide 14. Downstream earnings were flat sequentially. Stronger refining margins outside the United States and improved volume mix increased earnings by $160 million and $100 million respectively. All other items reduced earnings by $250 million 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. Fourth quarter chemical earnings were $872 million, down $91 million compared to the prior year quarter. Weaker margins primarily for specialty products decreased earnings by $10 million while unfavorable volumes and mix effects further reduced earnings by $30 million. All other items decreased earnings by $50 million largely due to unfavorable inventory and foreign exchange effects. Moving to slide 16. Chemical earnings were down almost $300 million sequentially. Weaker margins driven by higher feed and energy costs reduced earnings by $200 million. Higher volumes added $50 million and all other items decreased earnings $150 million 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 $7.8 billion and represents a $1.88 per share. Corporation distributed $12.5 billion in dividends to our shareholders. CapEx totaled $19.3 billion for the year, a reduction of $11.7 billion versus 2015. 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 billion 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 $26.4 billion. Turning to slide 18. Cash balances were flat to year end 2015 at $3.7billion. Earnings, adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program, resulted in $26.4 billion 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 $12.5 billion and net investments of $16.7 billion. Debt and other financing items provided $2.8 billion 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 operations and asset sales to support the dividend and most of our net investments in the business, supplemented by a moderate increase in debt financing. We maintain financial flexibility to continue to invest through the cycle in attractive opportunities. As indicated, shareholder distributions totaled $12.5 billion. Annual per share dividends were up 3.5% compared to 2015 and this marks the 3fourth consecutive year of per share dividend growth. In the fourth quarter of 2017, ExxonMobil will limit share purchases to amounts needed to offset dilution related to our benefit plans and programs. During the year, ExxonMobil generated $9.7 billion of free cash flow, up $3.2 billion 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 billion. I 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 on to slide 20 and a review of our full year segment results. 2016 earnings fell $8.3 billion as the impact of lower realizations in 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 30%. Now assuming current commodity prices and the existing portfolio mix, we do anticipate that the effective tax rate will be between 25% and 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 million were $6.9 billion lower than 2015. Realizations reduced earnings by $5.3 billion as crude oil prices decreased over $7 per barrel and natural gas prices declined by $1.40 per thousand cubic feet. Favorable volume and mix effects increased earnings by $130 million driven by new project growth. All other items added $310 million dollars due to lower operating expenses partly offset by the absence of favorable tax items. Excluding the impairment charge, 2016 upstream earnings totaled $2.2 billion. Moving to slide 22. As indicated, volumes ended the year at 4.1 million oil equivalent barrels per day, down about 1% compared to last year but within our full year guidance of four to 4.2 million 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 third-party impacts in Nigeria and wildfires in Canada. Natural gas production, however, decreased 388 million cubic feet per day. Growth in projects and work programs was more than offset field decline, regulatory restrictions in the Netherlands and divestments. The full year comparison for downstream results as shown on slide 23. Earnings were $4.2 billion, a decrease of $2.4billion from 2015. Weaker margins decreased earnings by $3.8 billion. Favorable volume, mix effects increased earnings by $560 million and all other items primarily asset management gains increased earnings by $920 million. On slide 24, we show the full year comparison for chemical results. 2016 earnings were $4.6 billion, up $197 million from 2015. Stronger commodity margins driven by advantage liquids cracking increased earnings $440 million while higher volumes added $100 million. Other items reduced earnings by $340 million 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. Five major projects started up in 2016, adding 250 thousand oil equivalent barrels per day of working interest production capacity. In the fourth quarter, 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 two years. These projects we will together contribute 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 fourth quarter. In Guyana, ExxonMobil submitted the 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 third quarter earnings call, the Liza-3 appraisal well successfully encountered an additional deeper reservoir which was being evaluated at the time. This reservoir is now estimated to contain 100 to 150 million oil equivalent barrels beneath the Liza field. Also, offshore Guyana, the Payara exploration well discovered hydrocarbons marking the second discovery on the Stabroek Block. The well encountered more than 95 feet of high quality oil bearing sandstone reservoirs. Two 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 Payara well test, the Stena Carron drillship will next move to the Snoek prospect just south of the Liza discovery. ExxonMobil also made two additional discoveries in the fourth quarter including the Nigeria Owowo-3 oil discovery announced in the third quarter earnings call and the Muruk discovery in Papa New Guinea. Both Owowo and Muruk are near currently producing fields which will enable capital efficient development. We also continued to capture new prospective exploration acreage. In Mexico's offshore bid round one, 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 Qatar Petroleum have been selected as the winners of offshore Block 10 in a 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. The 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 two-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 six billion 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 $5.6 billion in Exxon Mobil shares plus additional continued cash payments totaling up to $1 billion based on development of the resource over a specified timeframe. The map on the left shows our heritage acreage in yellow, acreage acquired in transactions in 2014 and 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 3.4 billion oil equivalent barrels in multiple stacked plays, 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 two 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 and 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 V synthetic base stocks sourced from facilities that started up last year at our adjacent Baton Rouge chemical plant. Across the fuels, lubricants and chemical value chains, we continued 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 their 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, at Mont Belvieu, Texas, the construction of our new 1.5 million ton per annum ethane steam cracker and associated metallocene polyethylene facility 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 65% increase in polyethylene capacity at the site. Together, the projects at Beaumont and Mont Belvieu represent multibillion dollar investments that will increase ExxonMobil's U.S. polyethylene production by nearly two million 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 would 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 $7.8 billion in the year, while managing through a challenging business environment. Corporation delivered on its plan to produce 4.1 million oil equivalent barrels per day and maintained 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 $19.3 billion, down 38% from 2015 as we exercised capital discipline and investment selectivity and continued 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 $26.4 billion and positive free cash flow of $9.7 billion. As I mentioned in the fourth quarter, cash flow from operations and asset sales more than cover the dividend and net investments in the business. Our commitment to shareholders remain 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. I will 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 your questions.

Thank you, Mr. Woodbury. [Operator Instructions]. We will take our first question from Neil Mehta with Goldman Sachs.

Good morning Jeff.

Good morning Neil.

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 of 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. Neil, it'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. You know, 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.

I appreciate that. And then my follow-up, Jeff, is on CapEx. I imagine we are going to get a little bit more color on this at the Analyst Day in a couple of weeks, but the $22 billion that you outlined is in line with what you talked about earlier this year, but up from 2016. Can you speak high level to what's driving the growth in 2017 versus 2016 in terms of CapEx? Is that cost inflation? Or is that higher growth? And then bigger picture, can you talk about what you are 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 in a month from now. As you indicated, the $22 billion 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 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 assure that the organization will continue to 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 are capturing those and really leading the cost curve.

Our next question comes from Phil Gresh with JPMorgan.

Hi Jeff. Good morning.

Good morning Phil.

I wanted to start on the working capital and other headwind, $2.4 billion in the quarter, $8 billion 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 do you think about the ability to lessen that headwind in 2017.

Well, I mean obviously there's really two large components that are driving it. Obviously 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 of 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 pieces, as 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 priorities with cash from here, to the extent you have excess free cash flow above the dividend in 2017, is the first priority, with the trending balances where they are, would it be debt paydown or do you feel like you have flexibility to do other things?

I think it's a function of the business climate and the opportunities that we have for ourselves. As you have 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 at the same time continue to selectively invest in our 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 that we don't have 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 will take our next question from Doug Leggate with Bank of America.

Thanks. Good morning, everybody. Good morning Jeff.

Good morning Doug.

Jeff, I wonder if I could kick off with your capital guidance. I guess it's kind of a follow-up. But ask you if could you move it on to talk a little bit about the production capacity that you see that goes along with that capital, because I am assuming the Permian is part of it? What I am really driving at is, you have got a number of projects still ramping up, so could you give us some idea as to what the remaining capacity is of those ramp-ups? In other words, what would the delta be if those projects were running full out in 2017? And then I have got a follow-up, please.

Yes. Doug, I mean first observation would be is that you are 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 will 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 Papa New Guinea in the past, a design at about 6.9, it's now produced above eight million tons per annum. You have heard in the news about Banyu Urip which the development basis was about 165,000 barrels a day. We have been producing about a 185,000 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 am making is above the additional ramp up that's anticipated from the major project startups, there is also another layer of capacity that we are 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. What's the starting point for that? What are you running right now?

So you are talking about the recent acquisition, I believe?

Right.

So let me back up and first I 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, 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 have got 10 rigs running right now. We are planning on ramping up that activity over the near future. But what we would do is, commensurate with the leasehold development requirements, we are very, very positive about this obviously given the acquisition and we want to get to it right away.

Jeff, I appreciate the answer. My follow-up is a very quick one. Payara, I think in Guyana, the limited disclosure you have given us 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 the Liza and Payara reserve expectations ultimately but also like the development plan on both and the outlook of production system? And I will live it there. Thanks.

Yes, Doug. So, as we indicated in the third quarter, given the Liza-3 appraisal well, that really built confidence in a view that we have got at least a billion barrels of recoverable reserve. Since then, we have drilled a deeper zone that added additional volume, as I indicated in the prepared comments. Payara, we are very pleased with the outcome. We moved very quickly two drill 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 test we are starting right now. And that will allow us to size Payara. 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 have got two other blocks that we will have to integrate as well. But right now, we are moving forward with the initial phase development. As we have 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 will wait till the Analyst Day. Thanks, Jeff.

Thank you, Doug.

We will go next to John Herrlin with Societe Generale.

Yes. Hi. Two quick ones for me, Jeff. Regarding your CapEx, is that just strictly E&D or you are including the acquisition costs for Bass?

Well, John, on the Permian acquisition, remember we are purchasing that via shares. So it excludes that share purchase.

Okay. Well, it would still be part of the costs incurred at the end of the day, but that's fine. Next on Payara, is that age correlative with the upper Liza pay or the lower Liza 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 will go next to Doug Terreson with Evercore ISI.

Good morning Jeff.

Good morning Doug.

Just for clarification, is it correct that the $2.1 billion in asset sale gains were after tax and included in the $1.7 billion earnings figure and either way, could you provide some guidance as to which operating segments that these gains came from?

So the proceeds of $2.1 billion are -- you are 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 would say about over 80% of it, it's in the downstream.

Okay.

And the largest part of that is in the Canada retail sales.

Can you give guidance on after-tax?

On the proceeds?

Yes.

Now I don't have any numbers to share with you on that.

Okay. And then also, three of your competitors have taken steps to enhance their pay for performance linkage by changing the metrics that they are using for their business units to ones which tie to intrinsic value in 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 P-for-P this year and specifically where there is a need for change given its rising profile as a corporate governance issue with investors?

Well, if you remember -- you are talking about our executive compensation program?

I am.

Yes. As you and I have 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 are 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 payout, it's paid out at the current stock price. Now I will 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 have got, 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. Thanks a lot, Jeff.

Doug, just a follow-up on your question regarding the Canadian retail. As I said in my prepared comments, it was $522 million after tax.

Great. Thanks a lot.

We will 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 would add that to the bucket in one of the later slides about de-lengthening your U.S. nat-gas position, maybe. So I was wondering, I am sure you have made comments on this before, but how do you think now in the new environment or how things have 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 moving forward as you want to develop additional U.S. gas assets in the context of that?

It's a good question, Sam. The best place to start is really thinking about it from our overall energy outlook and our supply and demand balances. Over the long term, we expect that LNG capacity or demand will continue to grow. In fact, almost it's up to like 250% of today's LNG net capacity. A large part of that growth is primarily driven by Asia. Now like most commodities, you are going to have periods in which there is oversupply and periods where there is insufficient supply. And we do expect that with the number of projects coming on that there are some projects where there is period in which they will see LNG over supply. Now if I step back from that that's, if you will, the value proposition and I step back, we have got a very extensive portfolio and I would tell you that brownfield developments that is incremental investments to existing operations like Papa New Guinea or even Golden Pass provide us 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 that we are still waiting for after many years is final Department of Energy approval of non-FTA export authorization. And we are hopeful that that will come shortly. But each one of these projects will be evaluated on their own merit. As you have 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 Golden Pass, within the whole portfolio of investment opportunities that we have, we are pursuing long-term sales contracts. But they all will be evaluated on their own merits.

Okay. I guess my follow-up then, is 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 get those rebooked over time, what do you think is more preferable between uses of that gas for you? Investing in 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 that energy outlook, we expect gas is going to grow about 1.5% per year. That's primarily driven by two things, one, power generation and the second thing petrochemicals. As you know, we have got a very integrated value chain. The anticipation is that resource will not only meet domestic growth and power generation, but we will also look at the utilization of that into our value chain in the chemicals business as well as, well, we started this discussion around LNG export, so optionality gives us tremendous amount of flexibility to make sure that we are maximizing the value proposition.

All right. Thanks Jeff.

You bet.

We will go next to Evan Calio with Morgan Stanley.

Hi. Good morning, Jeff.

Good morning.

I have a question. Any outlook on future project returns, conventional versus your acquired Permian? And I ask 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 future plateau level of production, while there's distress in asset markets globally in regions in which Exxon operates. So I mean just given the assets and these longer laterals you discussed, can you talk about how you think the future returns compete within your portfolio or how advantaged they may be?

Well, from a general perspective, Evan, I would tell you that clearly the recent acquisition, predominantly in the Delaware Basin, is a very competitive. It really goes back to the fundamental objective that we are trying to achieve through acquisitions or through exploration or our investment program that is to make sure that we continue to maintain a focus on value accretive performance. So we are looking for investments that are going to continue to maintain our industry-leading return on capital employed. So certainly very attractive. We have given you sense for the economics where I think back in the second quarter we showed you some of the progress we have made in unit development cost, operating cost. We gave you a sense for the portfolio then, which with the Bakken improvement together, we had over 2,000 wells that achieved greater than 10% return, money forward economics, full and fully loaded on a $40 per barrel price. You add 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 one of making sure that the pace maximizes the learnings that we are integrating and captures a technology application that we want to apply in order to achieve these outcomes like the length of the laterals. But I would say that this acquisition and the investments that we plan under it are going to be very competitive to our existing inventory of opportunities.

Can you even mention how much of your expected CapEx, $22 million CapEx, is in shorter cycle, however you define that, whether offshore or onshore? And related, 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 would tell you that we are going there to provide some more color in about a month's time at the Analyst Meeting. So if I ask you to just to hold that thought, we will give you a little bit more perspective at that time. On the second one, the overall balance of short cycle versus long cycle, obviously we have got a very large resource inventory with over 90 billion barrels. We are 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 have 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 objective is to make sure that we have got that flexibility and a key element of when we share a CapEx objective, we have 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.

I appreciate it.

We will go next to Jason Gammel with Jefferies.

Thanks. Hi Jeff. Jeff, I note that in the third quarter 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's 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 are asking, Jason, is I think clearly the question about proved reserves. In the third quarter 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 4.6 billion barrels out of proved and put them in our resource base. And I will 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 will 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 third quarter, but I will also note that we anticipate that there will be some partial offsets to those numbers. So stay tuned, we will be finalizing that shortly and we will be releasing that information here in the next two weeks.

I appreciate that, Jeff. And then just as a follow-up, the InterOil acquisition that you announced this year, I am afraid I am a little bit lost on the process for actually completing the InterOil transaction. Can you talk about what is still outstanding there in order to get that deal done?

Yes. So we are going back through the process following a decision by Canadian courts and we have put in place a new amended agreement between InterOil and ExxonMobil. And I will 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 are 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. I appreciate that.

We will 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 are giving more details next month. But how should we think about capital allocation for the Lower 48 business with the addition of the Permian acquisition? Does that highlight a growing relative share of the capital budget by the U.S. on shore? Is it additive to your existing activity? Or should we expect to see the capital diverted away from areas like the Bakken in Oklahoma and be replaced by activity in the Permian?

Well, Ryan, we will certainly provide more color here in a month or so. But I mean, directionally, it's a fairly sizable acquisition that we are making in the Permian. We feel good about our acreage position in the other unconventional basins. I showed you a map where we have got a meaningful presence in everyone of them. 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 have picked up in acquisition.

Okay. Thanks. That's helpful. And then maybe just one on 2016 CapEx, which came in quite a bit lower than guidance early in the year. Any comments on what were the primary drivers? Is that cost deflation, deferral of activity, change in any expected scope in 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 are in a down cycle and we have got a great opportunity to take advantage during that down cycle. I would 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. But it comes down to capital efficiency opportunities that we are able to continue to capture, regardless of where we are in the commodity price cycle. It includes market capture. We all know that the service sector and the related costs have dropped materially. 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. One, recognizing the business climate, wanting to stay within our means. And two, in a low price environment, there is unique value that we are 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 a opportunity in the down cycle to go ahead and add incremental value to those future investment.

Okay. Thanks Jeff.

Okay. Thank you.

We will go next to Paul Sankey with Wolfe Research.

Hi Jeff.

Good morning Paul.

Jeff, with the changes in Washington, I just wondered what Exxon has done to, firstly, I assume you guys are pro lifting sanctions on Russia. Secondly, I assume that you would be anti the border adjusted tax. And then 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 for many of the areas you talked about, advocate for free market principles. When it comes down to the important discussion that's happening in Congress in the current administration around the tax code, we believe the tax code should be globally competitive. It should be 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 am not going to speculate when or if they are fully satisfied and removed in the future. And then on 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 very dedicated effort within the organization to ensure that we are 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 would rather not talk about specifics, but I will tell you that we are monitoring the situation very closely.

Understood. Jeff, if I could completely change subject, the President of Guyana was commenting earlier in the week that we could see production startup in 2019 from Liza. Is that reasonable, do you think? We have also obviously heard from Hess about a 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 have been talking more 2021?

Yes. It's a good question. Listen, I think first and foremost is that we are 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 will 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 says that the initial phase would startup in 2020.

Got it, Jeff. Thank you.

You are welcome.

We will take our next question from Asit Sen with CLSA Americas.

Good morning Jeff.

Good morning Asit.

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, Asit, 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 could be maintained over multi-decades.

Got you. Okay. And my quick question on the new project startup, Barzan, is that a 2017 startup? And could you remind us on the working interest that you have there? 7% is 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 will go next to Paul Cheng with Barclays.

Hi. This is Moses Sutton, on for Paul. A 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 have completed the review of the entire portfolio.

Great. Thank you. That's it from us.

You are welcome.

We will go next to Alastair Syme with Citi.

Hi Jeff. I also had a question on the impairment. If you look back at your most recent energy outlook, it looks like you have 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 good question, Alastair, but I would tell you, the first point I would make is the reason why we do an annual updated 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 are asking about is really a function of a number of factors. It's not just energy outlook. We do this in conjunction with our annual budget and plans process. And it also is of the function as part of the energy outlook is looking at the competitiveness of different resources that underpin that demand outlook. So it's a number of factors that will drive our decisions and ultimately the choices that we make.

Thank you. 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 are really across a number of the business segments, but the largest in the fourth quarter were primarily in the upstream business.

Is it possible to get any color what they relate to?

No, we don't have any additional information to share.

Okay. Thanks very much, Jeff.

You are welcome.

We will go next to Brendan Warren with BMO Capital Markets.

Thanks Jeff. Just first question, just on those five major project startups. You flagged 2017 into 2018, particularly with Hebron and Sakhalin that you do operate. Are they still in 2017, recognizing Hebron most recently said it was on track for 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 are both in before end-2017. And then my follow-up refers and you would probably say defer this to the capital markets day, but if I refer back to slide 33 from the capital markets day, you had given guidance of cash flow from operations and asset sales for 2016 with a range at $40 a barrel to $80 a barrel. It looks like at $45 average for this year, you have just come in where the $40 a barrel line should be. I am 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. An important dialog that we think is something that we should be talking to and we will update that chart you are 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 will go next to Ed Westlake with Credit Suisse.

Yes. Good morning at top of the hour here. Two questions, I guess. Firstly, decline rates. I mean you guys have done very well on the production side to minimize base decline. You have got long duration assets in a number of geographies. Maybe just a quick update as far out as you could go on expected decline rate on the base business.

Yes. So we assess our long-term decline rate over every year and in fact, it's in our 10-K. And what we have had in terms of a decline rate here in the 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 what we would have.

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. A really good question in terms of OpEx and how we are managing that. I would tell you that we are never satisfied. We clearly understand there's been a lot of progress here over the last two years, but I can tell you that the organization doesn't believe status quo is sufficient. As I alluded to previously, we will continue to look for structural opportunities. We will continue to be very focused on our organizational effectiveness. And importantly, we will continue to work with the service sector to come up with lower cost, higher quality opportunities. And I am sure if the activity continues to build, there is going to be market pressures, but we are 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 that have been through here last couple years.

And margin should also improve with the new projects coming on, presumably?

Well, that's the objective of the investment program. Thanks, Ed.

We will go next to Theepan Jothilingam with Exane BNP.

Yes. Hi. Good morning Jeff. Thanks for taking my questions. I had two actually. Firstly, could you talk about, I know you are 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 place for 2017 and the spend associated? Thank you.

Yes. So Theepan, on the fundamental question of, to me, I interpret it as whether we would buy back any stock and I will 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 have already described. And as I said in the prepared comments, we don't anticipate doing any type of buybacks, other than into to address anti-dilutive impacts associated with the benefits programs and plans. On other exploration focus, we expect for the near term, flat spend out to out through the next several years, but I have shared a number of key areas that we are focusing our attention. Cypress, the high quality block we have got there on Block 10 that we have entered in negotiations on the production sharing contract, but we are 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 have got. Again, very encouraged by it, putting plans in place. I indicated that we continue to expand to our exploration acreage position in Papa New Guinea. You think about some of the big high potential areas for us, Papa New Guinea is very important to us. Guyana, that area has been very important to us. And then as we have been talking about often 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 are trying to deliver to our shareholders.

Okay. Thanks Jeff. I was just wondering, when you think about potential acquisition add between equity and adding debt, could you 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 dialog between the parties with the focus of what the seller wants from the transaction. But I wouldn't read anymore into it relating to our capital structure.

Great. Thank you.

And our final question comes from Pavel Molchanov with Raymond James.

Thanks for taking the question guys. Just two quick ones. You mentioned that almost all of the increase towards the $22 billion 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 are going to provide more color around our investment plans in about a month's time in the Analyst Meeting. I would just ask you to hold out until we get to that point.

Okay. And as far as the InterOil closing process, you are currently doing the rerun of the shareholder vote. Should the Yukon court bock the second attempt, as they blocked 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 will decide how we move forward from there.

All right. I 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 continues interest in ExxonMobil and we really do look forward to visiting with you next month at the Analyst Meeting. So until then, we will 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.