Jeff Woodbury - Vice President, Investor Relations and Secretary

Sam Margolin - Cowen & Company Ryan Todd - Deutsche Bank Doug Leggate - Bank of America Merrill Lynch Phil Gresh - JPMorgan Neil Mehta - Goldman Sachs Doug Terreson - Evercore Blake Fernandez - Scotia Howard Weil Guy Baber - Simmons & Company Paul Cheng - Barclays Roger Read - Wells Fargo Jason Gammel - Jefferies Rob West - Redburn Pavel Molchanov - Raymond James Theepan Jothilingam - Exane BNP

Good day, everyone, and welcome to this Exxon Mobil Corporation First Quarter 2018 Earnings Call. Today's call is being recorded. At this time, I would like to turn the call over to Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead sir.

Thank you. Ladies and gentlemen, good morning, and welcome to Exxon Mobil's first quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. Consistent with our recent Analyst Meeting, you'll note additional detail in our press release and this morning's prepared comments. Our objective is to provide clarity on key business drivers in the quarter and describe progress being made to deliver on value growth potential outlined in the Analyst Meeting. In the interest of time, I’ll move through the prepared material efficiently to ensure there is sufficient time for your questions. While we go further, I’d like to draw your attention to our cautionary statement shown on Slide 2. Please also see the supplemental information included in today's presentation. Turning now to Slide 3, let me begin by summarizing the key headlines of our first quarter performance. Exxon Mobil earned $4.7 billion in the quarter. Cash flow from operations and asset sales was $10 billion, the highest since 2014. Importantly, cash flow exceeded net investments in the business, distributions and other financing activities by almost $3 billion. In the United States, we achieved positive Upstream earnings of about $430 million. In Papua New Guinea, facility shut in resulting from the earthquake reduced this quarter's earnings by about $80 million in volumes by 25,000 oil current barrels per day. We've since resumed production and expect to reach full capacity in early May. As I’ll discuss shortly, we made good progress during the quarter in a number of areas that will support our value growth potential. Moving to Slide 4, we provide an overview of financial results. As indicated, the Exxon Mobil's first quarter earnings were $4.7 billion or $1.09 per share up 16% from the prior year quarter. Cash flow from operations and asset sales was $10 billion including $1.4 billion in proceeds from asset sales that I'll discuss shortly. In the quarter, Corporation distributed $3.3 billion in dividends to our shareholders. Our CapEx was $4.9 billion up 17% from the prior year quarter resulting increased activity in the Permian consistent with our growth plans. Debt was down to $40.6 billion at the end of the quarter and cash increased to $4.1 billion. Next slide provides a high-level look at the key drivers for these business results. Upstream, we benefited from higher realizations for both liquids and natural gas. However, our liquid realizations rose less in the benchmark prices due to widening of the Canadian heavy oil discount. These higher prices resulted in lower volume entitlements. Production was also reduced by downtime in the quarter and divestment of assets. We’re continuing to progress growth initiatives as outlined in our Analyst Meeting including increased drilling in the Permian, advancing attractive new projects and completing maintenance activities, enhance performance over existing assets. Finally, we're actively strengthening our portfolio to the acquisition of new assets such as exploration acreage offshore Brazil. We also captured incremental value through divestments of assets. Refining margins remain strong in the Downstream especially in North America. However, joint product demand was seasonally lower. U.S. manufacturing reliability recovered from the fourth quarter and notably Joliet returned to full capacity in March. We also continue to make progress in growing our chemical business. Integration of the Jurong Aromatics plant into our existing Singapore business is progressing as planned. In North America sales are increasing with the ramp-up of the new polyethylene lines at Mont Belvieu supplying the growing demand for petroleum products. Within our base business we successfully completed turnarounds in the Middle East and the U.S. Gulf Coast. The next slide provides additional detail on sources of cash. Earnings adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program yielded $10 billion in cash flow from operations and asset sales. A positive adjustment for working capital mainly reflects favorable seasonal changes in payables which were partly offset by an inventory build in the Downstream business mostly due to maintenance. Negative adjustment for other balance sheet items reflects timing of equity company distributions. Asset sales included Upstream properties, notably the Scarborough gas field and Downstream distribution and retail assets. Note that, cash flow was higher than the prior quarter largely due to the higher earnings. Moving to Slide 7, I’ll describe the uses of cash. Over the quarter, our cash balance increased from $3.2 billion to $4.1 billion. From a cash flow, we made shareholder distributions of $3.3 billion and confirmed our commitment to reliably grow the dividend. Earlier this week, the Board of Directors declared a second quarter cash dividend of $0.82 per share representing a 6.5% increase from last quarter and marking our 36th consecutive year of per share dividend growth. Net investments in the business were $3.3 billion lower than the prior quarter due to the absence of acquisition payments. Debt and other financing items decreased cash by about $2.5 billion. This included $1.9 billion in debt repayment and $425 million used to purchase 5 million shares to offset dilution related to benefit plans and programs. In the second quarter of 2018, Exxon Mobil will limit share purchases to amounts needed to offset dilution related to our benefit plans and programs. Moving to Slide 8 for a review of our segmented results. Exxon Mobil's first quarter earnings of $4.7 billion increased $918 million from the previous quarter excluding the fourth quarter impacts of U.S. tax reform and impairments. Upstream earnings increased about $980 million primarily due to higher prices. Downstream earnings decreased $12 million driven by weaker refining margins. Chemical business increased earnings by $76 million primarily due to lower operating expenses. These were all partly offset by higher expenses in corporate and financing segment due to the lower U.S. corporate tax rate and higher pension expenses. Our total corporate and financing charges for the quarter were about $800 million. After further evaluation of the full impact of the U.S. tax reform, we expect these expenses to range between $700 million and $900 million per quarter for the remaining of 2018. Our effective tax rate for the quarter was 40%, reflecting a higher proportion of non-U.S. Upstream earnings. Looking at the remainder of the year, we expect the effective tax rate to range between 30% and 40% at current commodity prices and the current portfolio mix. The increase in guidance is driven by Upstream's higher proposition of earnings. Moving to Slide 9 for a comparison to the prior year quarter. Exxon Mobil's first quarter earnings increased $640 million from the year ago quarter driven by higher upstream realizations. This is partly offset by lower downstream earnings resulting from lower asset, management gains, and lower volumes to the higher maintenance in the U.S. Chemical earnings decreased due to lower margins and corporate and financing charges reduced earnings by another $270 million again due to the lower U.S. corporate tax rate and higher expenses. Moving to Slide 10, we’ll highlight some of the progress we've made over the first quarter that supports our growth plan shared at the Analyst Meeting. We made our 7th discovery on the Stabroek block enabled by our proprietary subsurface imaging technology. Oil well encountered 65 feet of high-quality oilbearing sandstone. Oil will be developed in conjunction with the giant Payara field along with other development phases this will help bring Guyana's total production potential to more than 500,000 barrels per day. Common activities are on Liza Phase 1 and are progressing well. The Stena Carron is currently drilling Liza 5 appraisal well which will help to delineate the greater Liza resource. A well test is planned at Liza 5 and will begin shortly. After the completion of the test, the rig will return to the Turbot area to drill a delineation well named Longtail. Previously indicated, we mobilized the second rig to the basin which drove the exploration well Suburban [ph] in advance of the start of development drilling for Liza Phase I. Suburban well reached total debt this week but failed to encounter commercial quantities for hydrocarbons. We have additional exploration drilling planned later this year as we continue to explore the full potential of the Stabroek block. In Papua New Guinea, resource assessment certified an 84% increase in the size of the P'nyang field, more than 4 trillion cubic feet of natural gas. These resources support our discussions with joint-venture partners regarding a three train expansion concept for the PNG LNG facility. One train will be dedicated the gas from P'nyang and two trains will be dictated to gas associated with the Papua LNG project. This development concept would add approximately 8 million tons per annum doubling capacity over existing plant. As planned, we continue to increase our U.S. tied oil activity. We currently have 27 operated horizontal rigs in the Permian and four operated rigs in the Bakken. We remain focused on maximizing capital efficiency, drilling wells that are consistently longer than the industry average. Total unconventional production in the Permian and Bakken has increased by 18% versus the first quarter of 2017 with strong well performance supported by optimized completions. With respect to our portfolio, we added 8 new box offshore Brazil which I will talk about shortly and signed agreements for deepwater blocks, offshore Ghana and Namibia. As indicated, we continue to monetize assets including a 50% interest in the Stabroek gas field. We also closed several downstream divestments including distribution and marketing assets in South America and retail sites in Europe. Further portfolio highgrading remains a priority. In the chemical segment, we continue to be focused on increasing capacity to meet growing demand for higher value chemical products. We began commissioning our ethylene cracker in Baytown Texas with startup plan midyear. This will enhance integration to lower feedstock costs for the associated polyethylene lines that started up in the fourth quarter of 2017. Turning now to the Upstream financial and operating results starting on Slide 11. First quarter Upstream earnings were $3.5 billion, an increase of about $980 million from the last quarter excluding the fourth quarter 2017 impacts of U.S. tax reform and impairments. Realizations increased earnings by $640 million, crude prices rose just over $3 per barrel versus last quarter but less than benchmark prices due to the widening of the Canadian heavy oil discount. Gas realizations increased $0.80 per thousand cubic feet. Volume mix effects decreased earnings by $130 million primary drivers for this with the effect two fewer days in the quarter, higher downtime and lower entitlements partly offset by project growth and seasonal gas demand. All other items increased earnings $470 million largely due to lower operating expenses and positive net asset sales. Upstream unit profitability for the quarter was $10.30 per barrel excluding the impact of non-controlling interest volumes. Moving to Slide 12, oil equivalent production in the quarter was 3.9 million barrels per day a decrease of 3% compared to the fourth quarter of 2017. Liquids production decreased 35,000 barrels per day as downtime in Canada, lower entitlements and divestment of our Norway operated assets more than offset growth from new projects and work programs. In particular we were pleased with initial results at Hebron where performance for the new wells have exceeded expectation. Natural gas production decreased about 400 million cubic feet per day due to lower entitlements and downtime notably in Papua New Guinea. This was partly offset by higher seasonal gas demand and project growth volumes. Moving to Slide 13 for a comparison to the prior year quarter, first quarter upstream earnings increased $1.2 billion due to higher realizations. Crude prices rose $10.80 per barrel versus the year ago quarter and gas realizations increased $0.90 per thousand cubic feet. Volume and mix effects decreased earnings by $190 million lower entitlements and increase downtime specifically in Papua New Guinea were partly offset by project volume growth. All other items increased earnings $10 million as net gains from asset sales were offset by higher operating expenses. Moving to Slide 14 oil equivalent production decreased 6% compared to the first quarter of 2017. Liquid production was down 117,000 barrels per day due to field decline in the fourth quarter divestment of our operated assets in Norway and lower entitlements partly offset by new project volumes. Natural gas production decreased 870 million cubic feet per day driven by higher downtime, lower entitlements and a decline in the U.S. This is partly offset by project and work program volumes. Turning to Slide 15 we’ll provide an update on earthquake recovery efforts in Papua New Guinea. First and foremost on behalf of Exxon Mobil and in particular our staff in Papua New Guinea I want to extent our thoughts and well wishes to the people of PNG as recovery continues falling the devastation brought by this powerful earthquake and its aftershocks. Sponsor and initial earthquake all of our production gathering pipeline and processing facilities were safely shutdown. Exxon Mobil's humanitarian response to-date is included to distribution of food, water, emergency, shelters and other supplies along with the transportation of medics into affected areas. We focus support of the most impacted remote communities may bring our operations and have also made a donation to relief agencies. Our facilities successfully withstood the magnitude 7.5 earthquake in late February and its aftershocks due in large part a robust design and the immediate and effective response by our people. As of its location we accounted for a wide range of seismic activity in the original design, engineering and construction of the PNG/LNG project. In mid-April ahead of our projected recovery timeframe we announced a safe resumption of LNG production the second LNG train started up this week and the facility is wrapping up to full capacity. LNG exports have also resumed. During the period that production was shutdown we also brought forward and completed maintenance store facilities that was planned for later this year enabling more efficient operations in the months ahead. We proud of the response of our people in managing this extreme event and importantly churn for the community. On Slide 16 we take a closer look at ExxonMobil's current acreage position offshore Brazil which positions us with significant high quality resource potential. You’ll recall that last year we captured several attractive opportunities including a combined farm and bid round award for the discovered undeveloped Carcara field which extends across both the BM-S-8 and North Carcara blocks. Carcara field contains an estimated recoverable resource of more than 2 billion barrels for which the co-venture group is progressing development planning activities. Groups near-term plans include up to three wells in the field better delineate the resource and deploying the development concept. As we shared at the analyst meeting this proposed development yields attractive returns even at crude prices of $40 per barrel. At bid round 15 held last month we were awarded an additional eight deepwater blocks containing multibillion barrel prospects in the pre-salt play taking our total acreage to more than 2 million acres across 24 blocks. ExxonMobil operates more than 60% of these acreage holdings and we will leverage our capabilities and proprietary technologies maximize potential resource value. We will be acquiring more than 19,000 square kilometers of 3-D seismic data in 2018. As we already have 3-D seismic of some of the blocks we’re also progressing plans for the first exploration well scheduled for the latter part of next year. Moving to Slide 17 we’ll now discuss downstream financial and operating results. Downstream earnings for the quarter were $940 million a decrease of 12 million from the previous quarter excluding the fourth quarter 2017 impacts of U.S. tax reform and impairments. Global refining margins decreased earnings by $200 million unfavorable volume and mix effects decreased earnings by $40 million mainly due to lower seasonal demand and higher maintenance activity partly offset by improved operations in the U.S. All other items increased earnings by $230 million mainly driven by lower operating expenses partly offset by the absence of last quarter's Norway retail divestment. Moving now to Slide 18 downstream earnings decreased to 176 million compared to the first quarter of 2017. Margins were down 30 million due to lower non-U.S. margins partly offset by higher margins in the U.S. Unfavorable volume and mix effects decreased earnings by $60 million due to continued higher U.S. maintenance activity mostly at Joliet which resumed full capacity in March. All other items reduced earnings by $90 million mainly due to do the absence of asset management gains from last year's Canadian port credit asset sales. Moving now to chemical financial and operating results on Slide 19, first quarter chemical earnings were about more than $1 billion up 76 million versus the previous quarter excluding fourth quarter 2017 impacts from newest tax reform. Weaker margins and lower volumes primarily due to turnaround activity negatively impacted earnings by $30 million each. Lower operating expenses and favorable impacts from foreign exchange increased earnings by $140 million. Turning to Slide 20 first quarter chemical earnings were down $160 million compared to the prior year quarter. Weaker margins resulted in a decrease in earnings of 270 million as increase feedstock costs outpaced stronger realizations. Higher product sales from our new chemical operations in Singapore and the U.S. improved earnings by $120 million All other items in the quarter included higher expenses related to new operations and other growth opportunities which were mostly offset by favorable foreign exchange effects. These growth opportunities are key the component of our plans detailed at the Analyst Meeting. Now turning to our final slide, corporations focused on growing value across our integrated businesses. Each of our businesses contributed to solid financial performance in the quarter together earning $4.7 billion. Cash flow from operations and asset sales of 10 billion covered our net investments and dividends with free cash flow of $6.7 billion. Upstream production volumes were 3.9 million oil equivalent barrels per day in line with our expectations. We expect second quarter volumes to be lower due to seasonal gas demand and then growth in the second half with project entitlement volumes, seasonal demand and volume benefits from accelerated maintenance completed in the first quarter. Total CapEx was $4.9 billion with no change to your guidance. Strengthened, the Upstream portfolio to exploration, acreage capture and selected divestments as well as disciplined execution for our investment program. In the Downstream we are progressing our advantage investments such as those in Rotterdam and Antwerp manufacture higher value products capitalizing our proprietary technology and integration. And in the chemical business we’re focused on growing sales of our differentiated products supported by new assets that are well-positioned to meet global demand growth. Finally, we remain committed to our shareholders as demonstrated by 36 consecutive years of dividend increases. That concludes my prepared remarks, before we turn to your questions I’d like to note that in the remaining quarters of this year one of our management members will participate in the call to provide further perspective on progress and key developments relative to our plans. Chairman and CEO will participate in the fourth quarter. With that I would now be happy to take your questions.

[Operator Instructions] We'll go first to Sam Margolin with Cowen & Company.

I guess just to start on the overall profitability spectrum. At the Analyst Day you offered a pretty clear view that the Upstream contributions would be you know after the post-2020 long cycle development program is wrapping up and in the interim Downstream and Chemicals would carry a lot of earnings growth. I understand the slides clarified that the margin environment wasn't necessarily supportive of that in 1Q, but maybe just an update on how those two segments are performing in an apples to apples margin picture and sort of what the fundamental outlook looks like for the remainder of the year and into that 2020 period where Upstream starts to contribute more?

Yes Sam good question, and thanks for taking us back to what are our plans as we detailed in the analyst meeting. As you may recall let me take each of them separately in the Downstream, we are making - we have been making very strategic investments in order to high-grade our products. I highlighted in my prepared comments Antwerp and Rotterdam which is going to take us out of lower value products into higher value products. We’ll have Antwerp that will start up in the middle of the year and then Rotterdam will start up by the end of the year okay. As well in the Downstream, we have continued to expand our entry into some high growth areas such as Mexico and Indonesia everything is moving consistent with the plans that we laid out in the analyst meeting. On the Chemical side, same story we had laid out for you a plan of growth commensurate with what we saw in terms of chemical products. Importantly, as I indicated in the prepared comments that the Baytown cracker will be starting up middle of this year it is the really the second half of the overall project remember the first half being the two polyethylene lines in Mont Belvieu which have started up and have been wrapping up to full capacity and that will add a significant additional comp on it to our chemical portfolio. You also recall there are a number of other investments that we made in chemicals in Singapore importantly but we are making great progress on integration of our Jurong Aromatics acquisition. But we see significant value there and as the organization continues to integrate that into our big Singapore manufacturing facilities we continue to see additional opportunity but right now the focus on Singapore and Jurong Aromatics primarily the integration and capturing the synergies that we saw. I leave it there unless you have more questions on it.

No that’s all right I assume they’ll be more later in the Q&A. My follow-up is on Upstream. I wonder if we could dig in a little bit on these entitlement effects, specifically they were a little bit accelerated from 4Q even though the oil price move was actually somewhat more substantial in 4Q versus 1Q. I know there is a lot of nuances in these contracts and some of them are subject to some nondisclosures and confidentiality. But anything we could glean on the forward look for these entitlements and maybe some future impacts maybe decelerating here considering the quarter-over-quarter increase in that piece of the production number?

Yes, I mean you’re highlighting an important issue that has historically been a key criteria on how our overall volumes play out. I mean if you go back and look at just sequential analysis versus last quarter it was over 90,000 barrels a day that impacted us. And as you appropriately recognize each of these contracts that we have that have entitlement volumes are very unique. They are really a function of the commercial structure, the expenditure level and obviously prices. Now the good news side just don't lose sight of the fact that if you have an acid that is not cause current that just means accelerated recovery sooner. But it's hard for us to convey specific guidance given the unique aspects of - each of these contracts. But if you just think about what you’ve seen sequentially 90,000 barrels a day and you think about it quarter on quarter which I believe is around 70,000 barrels a day. It can have a material impact, but remember what our fundamental objective here is to really manage the business to maximize the value proposition. And that’s what most important here and as I said on the volumes going forward you can really think about our volumes contributions in 2018 coming from the areas that I mentioned you know our project growth notably in places like Hebron, Odoptu and Upper Zakum the title oil growth that we’ve been advertising, but we’re making great progress. We said that we’d be there at about 30 rigs by the end of this year. We’re already at 27 rigs so we’re really ahead of schedule. The second piece that you got to remember is that, as I alluded to there has been a number of unplanned downtime events in the first quarter and we went ahead and took advantage to accelerate scheduled downtime that we have in the latter part of this year into that first quarter to be more efficient and the downtime on the facility notably in Papua New Guinea as I reference and the second area in Syncrude. So we took full advantage of the opportunity to optimize the business and we’ll, as a result, have more efficient operations in the second half of the year, won't have those planned events, and therefore, we will get some volume recovery. The third thing that you'll recall is, as I mentioned is in the second half of the year, we'll start seeing that seasonal demand start ticking-up on this again. And then, lastly, I'll mention and I didn't say in my prepared comments, but we always have a very robust conventional work program and we're -- those are fairly cheap high value barrels that we're able to capture through the propane.

We will go next to Ryan Todd with Deutsche Bank.

Great. Thanks. Good morning, Jeff.

Good morning, Ryan.

And I would like to pass along things not just for the incremental disclosure, but I think the addition of management team members to the call to be welcomed going forward by investors, so that's great. And the first one from me would maybe on Groningen and again one of your partners wrote off reserves and booked an impairment of Groningen associated with the recent government announcement there. Can you speak to your thoughts here going forward, as well as maybe help frame what the potential impact would be or -- and whether you view there being a possibility of any compensation going forward?

Yeah. Well, I mean, as you can appreciate, it is a very dynamic situation. We continue in discussions with NAM, the operator and the government. Those are confidential discussions. Really Ryan at this stage we just don't want to speculate until we conclude those discussions. But we're still operating, the field is still operating under the current cap of 21.6 billion cubic meters per year.

Okay. And maybe a follow-up on Canada, I know you brought forward some of the turnaround there at Syncrude. But can you talk about your availability to get Canadian heavy out of there, I mean, how are you seeing when Syncrude comes back, are you anticipating limits on your ability to get it out, is it -- are you moving things on, how much on rail versus pipe and how much you're able to run through your refineries to capture the benefit there?

Yeah. You have really covered some of the answer there. In the first quarter we did experience some constraints due to logistics. It was about 12,000 barrels a day in the quarter itself. If you think about going forward, right now we're able to clear all the barrels. Importantly, if you think back in the prior discussions, one of the objectives that we've continued to press within our business is maintain logistic flexibility. Several years ago we went ahead and tested by way of example in Edmonton Rail Terminal that gives us another export option. Obviously, we've got pipeline capacity that we can leverage. And then, importantly, as you point out is that, we're also trying to capture the full value chain benefits by bringing the heavy oil into our own equity pass beyond on refining. But we will -- we continue to find them the best value option for us in order to deliver those barrels to market. So it's all about making sure that we're looking well ahead of the issue and identifying how do we maximize that flexibility, either take it into our equity, capacity in our manufacturing footprint or to export it to capture a greater value.

We will go next to Doug Leggate with Bank of America Merrill Lynch.

Thanks. Good morning, everybody. Again, Jeff, thanks for the incremental disclosure, but I think there is still some confusion out there on what's really going on in the operating cash flow. So I wonder if I could trouble you to just walk through the dynamics of the net PP&E odds, what is the timing of affiliate distributions and reconcile that with net income plus DD&A, which is $9.2 billion. You see what I mean there is the CapEx of the affiliate level, as I understand, is reported on a net basis above the operating line, if you could confirm that and just walk through the delta, because I think folks think that your cash flow number was closer to $8.2 billion.

Yes. So our -- if you look at our net PP&E it was $3.3 billion and that reflects -- that's absent the cash requirements for affiliates, okay.

Right.

And that is down versus both the prior quarter, fourth quarter of 2017, as well as the prior year quarter, primarily due to the absence of acquisition funding.

Just on that point did you pay for Brazil in the first quarter?

In the first quarter -- what’s specific Brazil, there has been a number of transactions?

The Carcara acquisition, that was the money outdoor in the first quarter for Carcara?

Not yet

Okay.

That is to come later this year.

All right. But your net capital spend after affiliates are the -- below the operating cash flow line was $3.3 billion, is that number we should be looking at.

That's correct.

Okay. Great. Thank. My follow-up is, obviously, you said in your commentary about the Sorubim-1 successful well. When we met with you a couple weeks ago my cousins had made a comment that in a success case there could be a third rig option because of the potentially open another play type. Has that option now gone away, is that play type now abandoned or does just condemned that upside exploration case or maybe you could just frame how these changes the rest profile of the block and I'll leave it there. Thanks.

Yes. Sure. I mean, let me just characterize, I mean, Sorubim, like any exploration program there is a fair degree of risk in all these exploration prospects. As I've indicated previously, every time we drill one of these well, we pick up some additional insight of learning’s and I wouldn’t say that the well in itself would condemn the play or the prospect opportunities that we've got in Stabroek Block. As it relates to the potential of the third rig, Doug, I would tell you that that is always a possibility, but we will make that decision based on the technical maturity of our prospects as we integrate the real time data that we get things from Sorubim, from Liza-5, and other analysis that we're doing based on that 3D seismic that we went hit and took. Right now we've got, the plan is to go ahead and run the two rigs in parallel. One primarily focusing on the development wells for Liza Phase 1 following the completion of the Liza Phase --Liza-5 well test and in the second we will be following up on some prior discoveries and again we will think about how we modify that rig line based on how we mature the technical prospects.

We’ll go next to Phil Gresh with JPMorgan.

Yes. Hi. Good morning, Jeff.

Good morning, Phil.

First question is actually a little bit of follow-up to Doug’s question, you noted the equity affiliates headwind in the quarter of a $1 billion. Certainly appreciate you breaking that out from the working capital. So just wondering how you think about that number for the full year and one of your peers, for example, has said that the affiliates will be a $2 billion headwind on an annual basis, I know it’ll be lumpy quarter-to-quarter, so just any additional color you can provide there.

Yes. Well, so, I mean, if you think about the equity companies. I mean, obviously, a big part of the $1 billion that we think about it, I mean, that's typically a seasonal pattern for us, okay. Usually we don't see those distributions until later in the year if that's what you're trying to get your hands around.

Yes. That was definitely part of it. It did sound a seasonal on the quarter, but I was wondering on an annualized basis also is it, you kind of lumped together a number of factors…

Yeah.

… and your disclosures in your filings, I just wonder if that affiliate headwinds on an annual basis which still be headwind.

We think, I mean, broadly speaking without giving you a specific numbers, Phil, I would tell you that most all the earnings are distributed throughout the year.

Okay. So more of the one to one, I guess, is what you're saying?

Yeah. I mean…

Earnings to cash…

… broadly speaking, I mean, it is going to be some timing impacts depending on cash requirements from the equity companies.

Yes. Okay. Thanks. Second question would just be one of your peers has also given helpful statistic around base plus shale CapEx. So, I was wondering if there is some kind of framework with underlying your capital spending numbers, you might be able to provide around base plus shale given that for you guys it’s essentially going to drive flat production for the long-term.

Yeah. I think from our prior discussions, Phil, what you really were looking at was capital efficiency. And we clearly pay close attention to that versus how we expect we should perform, as well as how our peers are managing this important area. And our conclusion continues to be that, we lead in that area. Now we don’t think comfort in that only because we think we get always do better. But as you think about how we conclude that it’s through a number of things. One I would say that the ultimate measure of that is our return on capital employed and not only we do lead on return on capital employed, we've laid out a very attractive investment program that shows how we’re going to continue to grow that lead out to 2025. We also have looked at what some are spending annually and while we have a much bigger production base. Our expenditure levels are comfortable on an absolute basis. And lastly, I would say, if you look at another measure and to me it's really simple one. Take your total capital employed per barrel crude reserves, in other words the money spent developed the reserves. We have one of the lowest dollars per barrel out there. So, I mean, if the objective is to really try to qualify the capital efficiency of our business that's what I would offer to you.

We go next to Neil Mehta with Goldman Sachs.

Good morning, Jeff.

Good morning, Neil.

Jeff, when do you think you'll be in a position of the company to make it FID decision around PNG, and then the -- any update on Qatar in the latest in terms of both the timeline and progress around negotiation there?

Yeah. Neil, on the first one regarding the PNG, I mean, as I indicated in my prepared comments, I mean, we have clearly made some really good progress. And if I could just go ahead and recap for the group, we did the Interoil acquisition, significant resource at Elk and Antelope, which is right along the pipeline route from the Highlands to plants, so very clear synergies and opportunities. Total operates those assets and we've been in very close coordination with our existing co-ventures and Total, and as I indicated in prepared comments, I think, we’re aligning on this expansion. In addition to that, two other things to note, one is that we continue to make significant resource -- additional resource captures with, like I mentioned, P'nyang, earlier this year or last year we went ahead and made good discovery at Muruk, and we have got a well that was spud there later this year and we think there is, it’s very significant, very close to the Hides gas field. And then the last point I would make is that picked a lot of good exploration high quality acreage in the Highlands, obviously, through the Interoil and then offshore of the LNG plant. So the message in all that is that we have built a very sizable high quality resource potential in the PNG vicinity and that positions us with this expansion, as well as maybe potential opportunities. In terms of the timing, that is yet to be determined, obviously, there are a lot of different players in this and ultimately the resource owner, the PNG government needs to align with the plants and the timing of that. But I just say that, I think, it is very well-positioned. I think the project in itself has demonstrated outstanding performance and I think the earthquake recovery is just another yet example of quality of the people that we got there and the asset itself. And then as you go forward, I think, we’re very well-positioned to compete as one of the lowest cost of supply providers of gas in that market. So we've got a full focused effort to make sure that PNG is so executed consistent with its history of the best-in-class performance. The timing when we get closer obviously we’ll go ahead and provide a more specific timeline for you. On Qatar, broadly speaking we value that partnership that we've got with the Qataris. We view that is yet again another very successful venture where both parties brought some value to the arrangement and you step back many years later and you look Qatar being one of the largest LNG exporters, again very low cost of supply and we’re very proud of the role that we played in that. We participated in 12 of the 14 trains. We brought some very important technology to play like big LNG trains and the big LNG carriers, and we want to continue that relationship. And you seen us partner with the Qataris in places like Brazil and Cyprus, and we’ll continue to find opportunities where we collectively leverage our mutual experiences and capabilities to go ahead and build our portfolio and ultimately drive that into value for both the Qatar and Exxon Mobil.

Jeff, a quick modeling question here, in the Analyst Day deck you provided some cash flow levels at 60/80 Brent levels. What’s the rule of thumb, every dollar change in the price of Brent was that due to the Exxon Mobil cash flow?

Yeah. We have the earnings sensitivity that's in our 10-K and it’s -- for every dollar per barrel it's about $500 million of earnings per barrel -- of cash per barrel.

We’ll go next to Doug Terreson with Evercore.

Good morning, Jeff.

Good morning, Doug.

The dividend increase of 7%, while pretty similar to the growth rate and the median during the past 10 years and 20 years it’s pretty significant I think. And on this point when considering the new financial disclosure that Darren is going to be on the call later in the year and it returns targets. There has been lot of positive change at the company this year at least in my opinion. So my question is, what is the company trying to convey from the size of the dividend increase if anything and if there is new underlying message from this change or some of the other changes we seen this year what is it.

Yeah. Well, Doug thanks for the question. I mean, simply put, remember we keep -- we’re keeping very focused on our core mission and that is to grow shareholder value. I mean there is an intense focus by the corporation on value growth, okay. And part of if you think about our capital allocation approach fundamentally what we said was one of the first priority is growing shareholder value and distributing that success to our shareholders through our dividend and you’ve seen us s for 36 consecutive years continue to grow that that dividend. And I think when you look at what the Board's decision was earlier this week, it was really underpinned by the confidence that we've got in our business plan. And we made a decision given a number of factors that coalesce to be much clearer in terms of where we saw that value growth potential. And frankly, Doug, I would tell you, because we believe that the investment community did not have a very good understanding of what our value growth potential was.

Yeah.

And we believe it was important to go ahead and make that much clearer. And I can tell you that every one of the senior leadership that are running these businesses are committed to delivering that value potential. Now a key aspect of that is making sure that we are being very thoughtful and selective in growing that investment program that is going to generate that accretive value. But ultimately all these steps are around a simple message of value growth and making sure that that is clearly understood by the investment community as to where we’re going and that we think ultimately it's differentiated by our technology, by the integration of our businesses that add additional value that we believe is sustainable. And I think as we go through this year and into next year, and you see us delivering on those expectations, I think, ultimately, I think, people are going to have much more understanding, better understanding of what the full scope potential this corporation has, notably from the integration of our three world-class businesses.

Okay. Well, Jeff, your tone surely underscores your enthusiasm towards the new value proposition, that's a good thing. And then I had another question, what was the earnings impact from the gains on asset sales in the quarter and if you have specificity outside of Scarborough, which I think, you mentioned that will be appreciated to?

Yeah. So, if you look at, I’ll give you a couple comparisons to give you perspective. So if you look at the quarter-on-quarter…

Okay.

… impact from earnings, it was about $180 million and most of that was in the upstream, okay.

Okay.

Sequentially…

Okay.

… it was a negative impact of about $130 million, sequentially being versus the fourth quarter of 2017 and most of that negative impact was in our downstream business.

Okay. Thanks a lot, Jeff.

Yeah. The key aspects just a little bit more Doug…

Yeah.

… is you mentioned Scarborough.

Okay. Yeah.

And then I mentioned the some marketing and distribution assets in South America and also I mentioned…

Okay.

… the European assets primarily retail assets, okay.

Okay. Okay. Thank you.

You’re welcome.

We’ll go next to Blake Fernandez with Scotia Howard Weil.

Hey, Jeff. Good morning. I know you ran through some pretty good detail on the downstream, but I wanted to ask you more specifically on the upcoming IMO changes in 2020. There's an awful lot of optimism among your independent refining peers. And I didn't know if Exxon had any view, do you share in the same kind of enthusiasm as far as what that’s going to do to just look demand in some of the heavy oil discounts, so just didn’t know if the company had a view?

Yeah. Well, its good question and good morning, Blake. So if you think about our investments. They’re all really embedded in our deep understanding in the energy markets that are -- that’s really informed by our energy outlook. I mean that’s why we do it, is to get down into the very deep insights that really guide our business strategy and our investment plans going forward. And this is one of those factors is our policy ultimately will impact the energy system and the products ultimately the society will need. We've been watching this closely for some time. You have seen that we've made a number of strategic investments notably in places like our European assets with Antwerp and Rotterdam. We are going to Coker and Antwerp. As I said Rotterdam were putting the hydro cracker in that’s going to take us out of the lower value products like marine fuel oil into higher value distillates like ultra low sulfur diesel. As well as grow to lubricant-based stocks. The -- when you think about IMO 2020 specifically, what we want to be position to do is to offer a suite of options for the marine industry. So we are going to positioned to provide things like low sulfur blends. We’re going to provide also sulfur marine gas oil. We will have LNG capability to provide. But also high sulfur fuels for ships with scrubbers. So one of the advantages in addition to these investments we’re making in Europe is that we got a fairly comprehensive conflicts of refinery network in the in the U.S. Gulf Coast that will be able to provide these products as well. So, I think, in short I just say that we are providing a lot of optionality and we think we are very well-positioned to address this change in sulfur specs, as well as a number of other changes on the horizon.

Understood. Second question I can’t believe buyback hasn’t come up yet, but this quarter, if I am kind of rewinding last year, I think, we went through this, first quarter seems to be fairly elevated as far as the requirement to offset dilution. I think you had $425 million. I am trying to confirm that that number should theoretically roll-off here throughout the year. And then I didn’t know if there were triggering pointing, I mean, debt reduced, you’ve get free cash flow, is there anything else you really kind of need to see in order to get the buyback program kind of up and running over and above this dilution?

Yeah. So, let me just make sure you understand the number of that I’ve talked about in the first quarter. The $425 million was anti-dilutive purchase associated with our benefit plans and programs. That usually happens in the first quarter of the year, okay. If you think about the buybacks and I certainly understand the interest around buybacks. I mean, simply put buybacks remain on the table, okay. The first priority is to be true this core mission I talked about previously and that is growing shareholder value. If we have opportunities that will provide accretive value investment opportunities, that's where the dollar will go. We are intensely focused on value growth. Now we do recognize an important distributing value to our shareholders and we do -- we generally do that as a priority through our cash dividend. And I think we’ve shown our commitment to reliably grow dividend as we’ve already talked about. And I think, as I said, it really demonstrate the confidence that the corporation has in it is business. But as you think about the buyback, we continue to think about it quarterly and we think about what is the current financial position of the company. I would say it’s very strong. Second, we look at what our investment and our dividend requirements are, and then we think about the near-term business outlook and the fundamentals, and what we think we need in the near-term in terms of additional cash for our investment program or debt maturity, and all those go into a view on whether we want to go ahead and start buyback shares again in a sustainable way. I’ll just highlight for everybody, remember that since the merger of Exxon Mobil we have bought back about 40% of the shares outstanding. So it has been a key part of our total distributions and it will continue to be one of the options that we will consider. But, first and foremost, reliably growth the dividend, and then, second, accretively invest in our business and then we’ll think about how to use that extra cash. Does that help Blake.

Thank you.

You’re welcome.

We’ll go next to Guy Baber with Simmons & Company.

Thanks. Good morning, Jeff.

Good morning, Guy.

I wanted to take Permian midstream and logistics, I mean, strategy here a little bit, especially such an important growth driver for you all. But we have seen differential widening out in the Permian for oil and for gas, and potentially widening out again later this year for some time for oil, as those oil pipes get filled. Can you just help us to understand how your Permian crude is priced, maybe how much exposure you have to Midland pricing, how much you move to higher price markets. And then, maybe just an update on where you stand regarding some of the midstream capital investment opportunities that you've discussed and the strategy to just maximize the value of your product there and then I have a follow-up.

Yeah. That’s good, Guy. I am happy you brought this point up. Because remember what -- a very -- the fundamental strategy that we've taking within our business is this value chain perspective. Permian is an outstanding example where we built this, what we believe an advantage position in the Permian, such that we can go ahead and develop the resource leveraging our expertise and things like development planning, extended-reach drilling, completion technology, reservoir management and drive the unit cost down lower than what we believe others will be able to do. But, importantly, we’ve got to carry that all way to what we think is we’ve got a very advantage footprint -- manufacturing footprint in the Gulf of Mexico and thus the importance of the midstream segment, okay. And if you think about what we have done is, we have a good line of side on that value chain to make sure that nothing is leaking out of there from a value perspective without making -- us making a decision if that was -- that's good -- that’s a business decision. That we shouldn’t capture that that value ourselves. And we’ve done things like purchase the Wink terminal which we were looking at the potential to go ahead and expand that. We entered into a joint venture with Energy Transfer Partners or a subsidiary of Energy Transfer Partners, where we combined our pipeline assets to gives us a broader export flexibility. But it is important that, that when we think about these things from a value chain perspective, it’s all about making sure that you’ve got a long-term view and then you position yourself smartly such that you’re capitalizing on the value proposition. So as we think about our Permian production, we are -- we’ve positioned not only the logistics network but also the supply chain to make sure that we’re maximizing the value proposition and you think about some of the disconnects or the challenges some we’re having, we’re clearing all of our Permian barrels. We’ve got ourselves lined up that we’re able to make sure that we can get them into market and have the flexibility either to capture the value uplift or manufacturing footprint or send them somewhere else via export in order to capture that value. So a very important example of how the integration has really provided significant value uplift for the corporation, okay?

Yeah. Very helpful. And then I had two follow-ups here, one on the CapEx front, understanding it’s early in the year, the CapEx was up year-on-year as you highlighted. It was actually a little bit below our model, can you just talk about what you’re seeing globally from an inflationary or deflationary perspective, as you’re ramping up activity here in your key areas? And I am sorry if I miss this earlier, but in Guyana, Liza-5, was there anything incrementally share at least the five at this point and maybe how are you thinking about the size of that third FPSO as you integrate those results?

Okay. Let me start with the last question first. In Liza-5 we’re still early days. We’re still -- the well itself was within our expectations and now we’re moving into the testing program. So, there’s really nothing more to share on it. We have -- we still are holding a resource, recoverable resource about 3.2 billion barrels, but I’ll remind everybody that that excludes any additional add from Ranger and Pacora at this point, because we still need to do some more delineation drilling in order to update the resource assessment. All of that is being real time integrated into our development planning for the subsequent phases had to Guyana. First phase under 20,000 barrel a day vessel. Second phase, it looks like we have enough FID, yeah, but it looks like it’s going to be about a 220,000 barrel a day vessel. The third one we’re looking at it based on the data real time. We haven’t landed on anything at this point. But you can see what we’re trying to do is, we’re trying to get into more of these manufacturing routine like we’ve really benefited from in the past like in Angola, is to really get to the point, where you start designing and you start rolling out these comparable similarly designed facility, such as you maximize the value proposition there, but very exciting the time for Guyana. There’s lot going on as you can appreciate from exploration all the way now to planning for production. So watch that space and we’ll provide updates as we progress. On your other question around, generally the market and any inflationary pressures. I mean, clearly, there’re going to be certain services or specific geographic areas that there are inflationary pressures. Like there’s a lot going on in the Gulf Coast, in the manufacturing areas, that have put pressure on craft labor. In Permian, obviously there’s a lot of activity and that’s put some pressure, but it’s always about making sure that you stay ahead of all that and that you’re positioning the business, such that it can offset any type of pressure, and in fact, maintain the focus on structural reductions in our business, and that really, frankly, starts all the way back to how you design these projects. But if you think about the Permian by way of example, we’re continue to drive unit cost down through our drilling efficiencies, it’s all about capital efficiency, so then as you develop or produce these assets to the life that you’re doing it at the lowest cost. But there are areas that we continue to focus on. We are proactive in terms of our contract reward -- awards. We really look at the total cost of ownership to identify supplier cost reduction opportunities. We leverage bidding. We have a very robust supplier relationship management program. We've got the ability because of the financial possibility the corporation to accelerate and bundle equipment purchases. So, it's all about make insure that we drop the cost down which has historically been able to offset that inflationary pressure. Now, you may have some in certain places that we're also working through but by and large it's -- what is the lowest lifecycle cost of our assets. That’s good Guy

Yeah. That's perfect. Thanks, Jeff.

Great. Thank you.

We'll go next to Paul Cheng with Barclays.

Hi, guys. Good morning.

Good morning, Paul.

Jeff, just I think on behalf of the investor that the -- I will appreciate that Darren and the other management team will be coming to the call later in the year. So I think that's a quick step in the right direction. Well, anyway, two quick question. First, I think, you have drill a number of well that is 12,000 to 15,000 feet lateral in both Bakken and Delaware several months ago. So, I presume that they have been producing for at least couple of months by now. Is there any production data that you can share, what you have seen in terms of testing the limit there?

Yeah. Well, Paul, let me give you update where we are on those. First, just remind everybody, we try to give a view of what we saw the value was by extending the lateral lengths in these wells in the Analyst Meeting. You can always go back and refer to that. We have drill the number of these 15,000 foot wells in the Bakken that are still early that they are producing. I would tell you that the results are meeting our expectations in terms of what we would expect in terms of the uplift. We have also drilled some in the Permian. They have not yet being completed at this stage. You remember a lot of these wells have been drilled by pads, so in order to optimize, again focused on capital efficiency they're going to coming in batches. We're being careful. I am going to be very candid with you. We’re being very careful what information we disclose on this, because we do think that there is a competitive adventure here. And but I will tell you that we see the value uplift that we had portrait in the Analyst Meeting.

Second quarter then, given the takeaway capacity in Western Canada, doesn't seems now you are going to resolved anytime soon. And look that, that portfolio within -- those opportunity within your portfolio also seems they have come down in terms of the packing order or ranking. So, how should we look at the incremental oil sands development project at this point from you guys? I think up and until the last year, even May last year that you guys were suppose to go ahead with a number of repetitive project, including the Aspen and the other one. So those deal is being on track to be developed or that there was just being say put back into the paper now?

Yeah. Good question, Paul. What I tell you is, as you know, we've been working oil sands for over three decades both in the mining and in-situ perspective. Fundamentally any new investment is going to compete at the top of our investment portfolio. It’s got to generate as we talk previously generate an attractive return that's accretive to our financial performance and has durable in a lower price environment. We continue to identify opportunities to enhanced profitability in both in-situ and in our mining operations. Imperial just talk about what we're doing in Pacora in terms of improving reliability. The same has been true in the in-situ operations, by and large not only optimizing the steam operations, but trying to leverage the fairly deep technology work that we've been doing in our research facility. And looking how we can best apply the proprietary as I said deep potential that we think we'll not only improve recovery but also reduce costs, and importantly, the environmental impact. So I tell you that portfolio and as you probably aware it is a clearly sizable amount of resource that we’ve got up there, it’s getting a lot of focus around applying the right technologies and capabilities in order to ensure that it competes at the portfolio. So I wouldn’t say that it has fallen down on a rank. It’s just like every other resource we’ve got, we are working on it and if we come to a point at some stage that we think that the value preposition is meets our objectives than we’ll move forward with it. Is that good Paul.

Yeah. One just follow-up on that, will you anyway that go ahead to sanction the project without clear sight takeaway capacity in Canada is being resolved?

Yeah. So it’s a -- it’s very similar to whole Permian discussion I had, Paul, I mean, we have been thinking about making sure that, one, we have got the takeaway capacity, and two, that we’ve got the flexibility to run these crudes in our equity refining capacity. So it stand ahead of that and making sure that we’ve got that flexibility available and that was -- frankly that was one of the or the key justification of why we invested in the Edmonton Rail Terminal. But, obviously, we -- our big supporters are making sure that there is investment and infrastructure, and that has been more challenged in certain areas. But we will continue to look forward to make sure that we are working the value chain in order to maximize that value preposition.

Got it. Thank you.

Thank you, Paul.

We’ll go next to Roger Read with Wells Fargo.

Hello Roger.

Sorry about that, I had to kick the mute off. Can you hear me now?

I can.

Okay. Thanks. Good morning. Hey…

Good morning.

If I could follow-up a little bit on Guy’s question on the Permian. I mean, I totally get it, this is not a -- not anything but a plan program of development for you in the midstream. But are you -- if you were to need more pipeline capacity, should we presume that everything would be done within the joint venture with ETP or would you kind of evaluate the other options as you go forward. I am just kind of thinking over the next several years we are going to have these periods of pipeline over capacity, pipeline under capacity relative to production growth and how you’re looking at maybe specific routes out of the Permian for all of it, both the liquids and the gas side?

Yeah. No. We would be evaluating all options. We would not restrict ourselves to one avenue. Remember, I know I keep on saying the same thing, but it’s all about, how we are going to maximize the value preposition and we’re looking at all the different midstream options that we can go ahead and consider. You may recall, I believe sometime last year that we went ahead and announced that we were looking at spinning another $2 billion in the U.S. for infrastructure investments, things like the expansion of the Wink terminal and enhancing our logistics flexibility and optic. So we’re considering a range of options.

Okay. I appreciate that. And then looking at your rig count the lower 48, four in the Bakken, 27 maybe go into 30 in the Permian. Clearly the Permian area is set up for growth. I was curious so as you think about the Bakken with four operated rigs, is that more of a stability or is that actually also in a growth position?

Well, if you look at the analyst presentation, where we showed the build up from our U.S. tight oil. Roger you’ll see in there that we had segmented that between the Bakken and the Permian and through 2021, 2022, if I remember right, you have got the Bakken actually growing in terms of volumes and then in essence of Plato’s, but of course, we maintain an active drilling program. The biggest build up is coming from our Midland assets, I mean, our Permian assets.

We’ll go next to Jason Gammel with Jefferies.

Thanks. Hi, Jeff. I realize we are not too far or removed from the analyst meeting, but given the comments that you made about, first of all, the importance of integration on U.S. Gulf Coast, with your Permian operations? And second, all the preparations you are making for IMO. I was wondering if you could address any further progress you have made towards FID the Beaumont light oil expansion and the Singapore resid upgrade project and maybe any critical past items to actually reaching those FIDs?

Yeah. No. I appreciate you are asking. If you recall, I think, it was in the analyst presentation on the Permian, we showed that we were looking at significantly increasing our light oil processing capability by about 400,000 barrels a day by 2021 I think it was. And a key aspect to that would be that we’re thinking about as potential expansion of light crude refining capacity in North America, but that is currently still being considered, no final investment decision has been made at this point. We are -- I tell you we were given a lot of thought to a number of options. Clearly, we want to bring that to closure pretty quick and we would expect to see an FID decision probably sometime next year to get us on track to meet the objectives that we laid out in the analyst presentation. The other, I am sorry, Jason remind me, what was the second one?

The Singapore resid upgrade project.

Yeah. So, that continues to move forward in Singapore. I mean, remember there is a number of projects that we have got on -- going on in Singapore right now. The resid upgrade is in progress and it should startup here shortly.

Okay. Great. And then just in terms of the PNG...

Jason, let me clarify.

Yeah.

We are looking at doing FID decision on that here soon.

So that was a way I took it.

Yeah.

And then if I could just ask on the PNG, LNG expansion, Jeff. Are you actually actively marketing volumes from the expansion and have you reached the informal agreements with any buyers HOA type of agreements?

Yeah. So Jason we have got as you can appreciate with the number of LNG projects that we’re progressing forward. We’ve got a number of efforts in progress to go ahead and market those volumes, not just PNG but others elsewhere. Obviously, the specifics of those are confidential but just rest assured, remember we did the fundamental premise that we laid out at the Analyst Meeting is to really move forward these projects that were on the far left side of the cost to supply curve such that they compete very well to that demand growth that we anticipate over the period -- this period out to 2024 or 2040. So very well-positioned and we are moving a number of those discussions -- commercial discussions forward. Thank you, Jason.

We’ll go next to Rob West with Redburn.

Hello, Jeff. I am interested in making a couple of comments on some aspects of the results and interested in your thoughts on how it looks to you and how you way to think about it. But when I look at the production across the different geographies of the upstream business, there’s a lot of red in my spreadsheet of year-over-year decline and particularly in West Africa where I -- and see from one of your partners the investment levels going into some of those box in Angola that looks like it might continue to be in decline for a while? So I am quite excited by the long-term projects you are doing and the new growth that should be coming through in a few years and quite excited by that that next year when the Permian starts really inflecting. But in the near-term should we be expecting more year-over-year decline in the upstream production volumes and how should we think about that?

Yeah. Let me talk about more generically that, obviously, there are a number of, let me call, leverage that we pull in order to maximize profitable volumes, I mean, a key aspect of what we’re doing is in the base business where we've got -- this is the depletion decision as you are aware. And we've got a very strong focused on how do you improved reliability and enhanced open recovery and you'll see a lot of what we're be investing are very large resources that give us more flexibility to go ahead and apply our technical knowhow and our technology in order to increase recovery. So, there is a part of the organization that's focused on how do you mitigate the decline by enhancing recovery and operational reliability. Then there is another segment that you got out there that is focused on accretive investment. That's why we've been -- typically that's what we spend a lot of time talking to the investments that we make in these very large resources like Hebron, Sakhalin-1, Upper Zakum and that's all focused on making sure that we bring long-term value to the corporation that is durable with the volatility in commodity price cycles.

I am deeply in favorable of the value approach and but in terms in the next few quarters, should we be expecting decline year-over-year and that's okay because the longer loan growth is coming?

Yes. Well, I mean, certainly, there is decline every quarter. I mean these -- all these reservoirs are depleting. And as I said, in my comments, for 2018, we expect production to be comparable to 2017, okay. As I indicated, in the second quarter, due to reduced seasonal gas demand, we do expect the second quarter to be lower. As we turn the corner to the second half of the year, there are number of things that we would expect that will drive our volume upward and that would be the things I mentioned, and the project activity, the tight oil activity move into the higher gas demand period of the year and then our ongoing conventional program. But no change to our communicated guidance, that we would be generally flat with 2017.

Okay. Thank you. That's clear. If I can have a follow-up, I was reflecting on the charges coming through the business to hit the corporate line over the quarter. And my question is about effectively the tax write back for every dollar of charge has just going down. You used to get a $0.35 on a $1 back and now it’s $0.21. Just -- has that triggered any cost reduction target, cutting corporate costs, or cutting some of those expenses that a lower tax rate back on?

Well, I mean, I'll tell you, Rob, I mean, being with this company for 35 years, there is always an intense focus on optimizing on our cost. It just not in the…

I thought you might say that.

I am sorry.

I thought you might say that so I interrupted you, keep on going.

Yeah. Yeah. I mean, it doesn't require something to trigger that mentality. I mean that need to be part of your DNA. I mean that is an imperative part of a value proposition is finding ways to get more productive and to reduce the cost structure. So, rest assured that that is the focus across all aspects of our business. Thank you, Rob.

We go next to Pavel Molchanov with Raymond James.

Thank you for taking the question. Just one for me, we've seen a lot of headlines about unwinding of your joint ventures with Rosneft due to the U.S. and European sanctions. Can we get an update on the amounts of CapEx that’s you are investing in Russia this year and where that capital is going given the restrictions on where you are able to invest?

Yeah. Pavel, let me clarify this aspect to make sure that there is no misunderstanding. As it relates to resources that are covered by the sanctions. First and foremost I want to be clear that we're fully complied with the sanctions, okay. There were a number of joint ventures we attend joint ventures that were involved in -- that would have been covered by the sanctions and as the U.S. codified those sanctions and expanded in 2017 we chose to go ahead and withdraw, which we've initiated that process with our partners, okay. And we laid out the specifics of -- the specific impacts that in our 10-K. And as you know, specifically, that resulted in a write-down of any expenditures that were associated with those joint ventures. Now separate from that is that we do have other activities that are not impacted by the sanctions. By way of example, we’ve got a very long-standing relationship, successful operation on the east coast of Russia in Sakhalin-1 and that continues as it was previously it has been very successful in terms of the investment program and the value proposition for both resource owner and the co-venture partners. There is also some other joint venture relationships that we have throughout the world with Rosneft that we’re pursuing. So I want to make sure it's clear that as it relates to the sanctions we are fully compliant with them but the rest of our business is progressing as intended.

Okay. Can you share how much capital you're putting into Russia this share?

No. We don't have that information to share.

Okay. Appreciate it.

Thank you, Pavel.

We’ll go next to Theepan Jothilingam with Exane BNP.

Yeah. Hi, Jeff. It’s Theepan here. A couple of questions actually, firstly, just thinking about your disposal program and in the context of higher upstream prices. I was just wondering whether things change in terms of trying to increase that run rate, I saw the first quarter was quite reasonably a bit ahead of that typical $4 billion per annum mark that you've guided to, so any thoughts that would be great. And then, just coming back to refining, could you perhaps talk a little bit in the context of what margins you are seeing so as we come through Q2 and maybe relate that also to what Exxon is seeing the global oil demand for 2018? Thank you.

Well, Theepan, thanks for your question. On the -- what I call our asset management program or divestments, I think I alluded to you in the prepared comments that we have been very focused on taking full advantage of where we think we can get incremental value on certain assets versus what we see as continued operations. So it's all about making sure that we maximize the value proposition sometimes, we don't ultimately get offers that would do that and we continue to operate those assets. We’ve been very careful to make sure that we don't know force a divestment because we’ve communicated an expectation around a certain number of assets or certain dollar value that we expect to get from it. But rest assured, I mean, as you saw in the first quarter we had another $1.4 billion of gross proceeds from divestments that we will continue to pursue where we could get incremental value through the divestment program and I think we've indicated a couple times that we would be very aggressive at that. But we’re not going to go ahead and walk away from value if we -- if the markets not going to offer what we think is worth or more than that. On for the refinery margins, we don't project margins into the future, but I will tell you specifically as we think about demand, we expect demand to be up in the second quarter and third quarter driven by seasonal impacts. And certainly, what we've got to be doing is making sure that we maximize the product value by the offerings that we have, and of course, also maintain the logistics and feedstock flexibility in order to increase the margin that we will get from our downstream business. And, Theepan, did you have a question about oil demand.

Yeah. Just wanted to get in that context, how you see…

Yeah.

… demand year-on-year, clearly you’ve got a very wide footprint globally, so just want to get a sense on that? Thank you.

Yeah. Yeah. So broadly speaking, I mean, I think, recognize that demand has been fairly strong last couple of years. In fact if you put it in the perspective of a 10-year average it’s been in excess of the 10-year average. Round numbers, last year’s demand growth was probably in excess of 1.5 million barrels a day. It's been fairly robust, but as you go into this year and by the way with that demand growth and with the supply, I mean, OPEC objective of get to the kind of five-year average of OECD inventories is within reach, recognizing we still have excess supplies versus where we were at year end 2013, it had something that certainly continue to be mindful of, as well as the significant supply capacity that remains out there in the industry. Going forward, we see it fairly similar to 2017 in terms of demand and that's very consistent if you go back, all the way back to our energy outlook, we see that demand is grown about, oil demand is grown about seven-tenths a percent between now and 2014 per year. So it is the deep insights that we get from that demand assessment that we do that really allows us to guide our business strategies and our investment plans going forward. Thanks, Theepan.

And at this time there are no further questions.

Well, I certainly want to thank everybody for their questions. I do want to clarify just one point to make sure my response was appropriate that there is a question about the earnings and cash sensitivity to the price of crude and we have some of this in our 10-K that you can go ahead and reference. But broadly speaking for every barrel of crude price it relates to about $425 million of earnings and about $500 million a cash for the year. But going forward I want to thank you again for your time and your thoughtful questions. We always appreciate the engagement and the insights that you bring into the discussion, and we're looking forward to continuing that engagement as we go forward. As you would appreciate we have taken an extra effort in order to engage with investment community at all levels with the corporation and I think that is allowing us as we talked earlier to provide a much clearer articulation of that value proposition that we laid out to the investment community in the analyst meeting. So thank you for your time and your interest and we’ll be in touch in the future.

This does concludes today’s conference. We thank you for your participation.