Earnings Call: Q1 2018

Apr 27, 2018

Good day, everyone, and welcome to the ExxonMobil Corporation First Quarter 2018 Earnings Call. Today's call is being recorded. At this time, I'd 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 ExxonMobil's Q1 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. Before 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 Q1 performance. ExxonMobil earned $4,700,000,000 in the quarter. Cash flow from operations and asset sales was $10,000,000,000 the highest since 2014. Importantly, cash flow exceeded net investments in the business, distributions and other financing activities by almost $3,000,000,000 In the United States, we achieved positive upstream earnings of about $430,000,000 In Papua New Guinea, facility shut in resulting from the earthquake reduced this quarter's earnings by about $80,000,000 and volumes by 25,000 oil crude barrels per day. We have 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 our financial results. As indicated, ExxonMobil's 1st quarter earnings were $4,700,000,000 or $1.09 per share, up 16% from the prior year quarter. Cash flow from operations and asset sales was $10,000,000,000 including $1,400,000,000 in proceeds from asset sales that I'll discuss shortly. In the quarter, the corporation distributed $3,300,000,000 in dividends to our shareholders. Our CapEx was $4,900,000,000 up 17% from the prior year quarter, resulting increased activity in the Permian, consistent with our growth plans. That was down to 40.6 $1,000,000,000 at the end of the quarter and cash increased to $4,100,000,000 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 liquids realizations rose less than 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 to enhance performance of our existing assets. Finally, we're actively strengthening our portfolio through the acquisition of new assets such as exploration acreage offshore Brazil. We've also captured incremental value through divestments of assets. Refining margins remained strong in the Downstream, especially in North America. However, petroleum product demand was seasonally lower. U. S. Manufacturing reliability recovered from the 4th 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 Mount Bellevue, 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 $10,000,000,000 of 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 reflect 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 $3,200,000,000 to $4,100,000,000 From our cash flow, we made shareholder distributions of $3,300,000,000 and confirmed our commitment to reliably grow the dividend. Earlier this week, the Board of Directors declared a 2nd 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 $3,300,000,000 lower than the prior quarter due to the absence of acquisition payments. Debt and other financing items decreased cash by about $2,500,000,000 This included $1,900,000,000 in debt repayment and $425,000,000 used to purchase 5,000,000 shares to offset dilution related to benefit plans and programs. In the Q2 of 2018, ExxonMobil 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. ExxonMobil's 1st quarter earnings of $4,700,000,000 increased $918,000,000 from the previous quarter, excluding the 4th quarter impacts of U. S. Tax reform and impairments. Upstream earnings increased about $980,000,000 primarily due to higher prices. Downstream earnings decreased $12,000,000 driven by weaker refining margins. Chemical business increased earnings by $76,000,000 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 $800,000,000 After further evaluation of the full impact of the U. S. Tax reform, we expect these expenses to range between $7,000,000 $900,000,000 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% 40% at current commodity prices and the current portfolio mix. The increase in guidance is driven by Upstream's higher proportion of earnings. Moving to Slide 9 for a comparison to the prior year quarter. XL Mobile's 1st quarter earnings increased $640,000,000 from the year ago quarter, driven by higher upstream realizations. This was partly offset by lower downstream earnings resulting from lower asset management gains and lower volumes due to the higher maintenance in the U. S. Chemical earnings decreased due to lower margins and corporate and financing charges reduced earnings by another $270,000,000 again due to the lower U. S. Corporate tax rate and higher pension expenses. Moving to Slide 10, we'll highlight some of the progress we've made over the Q1 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. Cora well encountered 65 feet of high quality oil bearing sandstone. Cora will be developed in conjunction with the giant Pariara field. Along with other development phases, this will help bring Guyana's total production potential to more than 500,000 barrels per day. Feltman activities on Liza Phase 1 are progressing well. Astena Carren is currently drilling the Liza 5 appraisal well, which will help delineate the greater Liza resource. The well test is planned at Liza V and will begin shortly. After the completion of the test, the rig will return to the turbid area to drill a delineation well named Long Tail. Previously indicated, we mobilized the 2nd rig to the basin, which drilled the exploration well Surbin in advance of the start of development drilling for Liza Phase 1. Servin well reached total depth this week, but failed to encounter commercial quantities of hydrocarbons. We have additional exploration drilling planned later this year as we continue to explore the full potential of the Starbuck Block. In Papua New Guinea, a new 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 3 train expansion concept for the PNG LNG facility. 1 train will be dedicated to gas from P'nyang and 2 trains will be dedicated to gas associated with the Papua LNG project. This development concept would add approximately 8,000,000 tons per annum, doubling capacity of our existing plant. As planned, we continue to increase our U. S. Tight oil activity. We currently have 27 operated horizontal rigs in the Permian and 4 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 Q1 of 2017, with strong well performance supported by optimized completions. With respect to our portfolio, we added 8 new blocks offshore Brazil, which I'll talk about shortly and signed agreements for deepwater blocks offshore Ghana and Namibia. As indicated, we continue to monetize assets, including our 50% interest in the Starbird gas field. We also closed several downstream divestments, including distribution and marketing assets in South America and retail sites in Europe. Further portfolio high grading remains a priority. In the Chemical segment, we continue to be focused on increasing capacity to meet growing demand for higher value chemical products and began commissioning our ethane cracker in Baytown, Texas with startup plan mid year. This will enhance integration through lower feedstock costs for the associated polyethylene lines that started up in the Q4 of 2017. Turning now to the Upstream financial and operating results starting on Slide 11. 1st quarter upstream earnings were $3,500,000,000 an increase of about $980,000,000 from the last quarter, excluding the Q4 2017 impacts of U. S. Tax reform and impairments. Realizations increased earnings by $640,000,000 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 1,000 cubic feet. Volume and mix effects decreased earnings by $130,000,000 Primary drivers for this were the effect of 2 fewer days in the quarter, higher downtime and lower entitlements, partly offset by project growth and seasonal gas demand. All other items increased earnings $470,000,000 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 3,900,000 barrels per day, a decrease of 3% compared to the Q4 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 from the new wells have exceeded expectation. Natural gas production decreased about 400,000,000 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. 1st quarter upstream earnings increased $1,200,000,000 due to higher realizations. Crude prices rose $10.80 per barrel versus the year ago quarter and gas realizations increased $0.90 per 1,000 cubic feet. Volume and mix effects decreased earnings by $190,000,000 Lower entitlements and increased downtime, specifically in Papua New Guinea were partly offset by project volume growth. All other items increased earnings $10,000,000 as net gains from asset sales were offset by higher operating expenses. Moving to Slide 14, oil equipment production decreased 6% compared to the Q1 of 2017. Liquid production was down 117,000 barrels per day due to field decline, the 4th quarter divestment of our operated assets in Norway and lower entitlements, partly offset by new project volumes. Natural gas production decreased 870,000,000 cubic feet per day, driven by higher downtime, lower entitlements and the decline in the U. S. This was partly offset by project and more program volumes. Turning to Slide 15, we'll provide an update on earthquake recovery efforts in Papua New Guinea. 1st and foremost, on behalf of ExxonMobil and in particular, our staff in Papua New Guinea, I want to extend our thoughts and well wishes to the people of PNG as recovery continues following the devastation brought by this powerful earthquake and its aftershocks. In response to the initial earthquake, all of our production gathering, pipeline and processing facilities were safely shut down. ExxonMobil's humanitarian response to date has included the distribution of food, water, emergency shelters and other supplies, along with the transportation of medics into affected areas. We focus support on the most impacted remote communities, neighboring our operations and have also made a donation to relief agencies. Our facility successfully withstood the magnitude 7.5 earthquake in late February and its aftershocks, due in large part to robust design and the immediate and effective response by our people. Because 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 the safe resumption of LNG production. The second LNG train started up this week and the facility is ramping up to full capacity. LNG exports have also resumed. During the period that production was shut down, we also brought forward and completed maintenance to our facilities that was planned for later this year, enabling more efficient operations in the months ahead. We're proud of the response of our people in managing this extreme event and importantly caring 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 in and bid round award for the discovered undeveloped Kokara field, which extends across both the BMS-eight and North Kakara blocks. Karkar field contains an estimated recoverable resource of more than 2,000,000,000 barrels for which the CoVenture Group is progressing development planning activities. Group's near term plans include up to 3 wells in the field to better delineate the resource and define the development concept. As we shared at the analyst meeting, this proposed development yields attractive returns even at crude prices of $40 per barrel. In bid round 15 held last month, we were awarded an additional 8 deepwater blocks containing multi 1,000,000,000 barrel prospects in the pre salt play, taking our total acreage to more than 2,000,000 acres across 24 blocks. ExxonMobil operates more than 60% of these acreage holdings, and we will leverage our capabilities and proprietary technologies to maximize potential resource value. We will be acquiring more than 19,000 square kilometers of 3 d seismic data in 2018. Since we already have 3 d seismic over some of the blocks, we are also progressing plans for the 1st 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 $940,000,000 a decrease of $12,000,000 from the previous quarter, excluding the Q4 2017 impacts of U. S. Tax reform and impairments. Lower refining margins decreased earnings by $200,000,000 Unfavorable volume and mix effects decreased earnings by $40,000,000 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 $230,000,000 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 $176,000,000 compared to the Q1 of 2017. Margins were down $30,000,000 due to lower non U. S. Margins, partly offset by higher margins in the U. S. Unfavorable volume and mix effects decreased earnings by $60,000,000 due to continued higher U. S. Maintenance activity mostly at Juliet, which resumed full capacity in March. All other items reduced earnings by $90,000,000 mainly due to the absence of asset management gains from last year's Canadian Port Credit Asset Sale. Moving now to Chemical Financial and operating results on Slide 19. First quarter chemical earnings were about more than $1,000,000,000 up $76,000,000 versus the previous quarter, excluding Q4 2017 impacts from U. S. Tax reform. Weaker margins and lower volumes, primarily due to turnaround activity, negatively impacted earnings by $30,000,000 each. Lower operating expenses and favorable impacts from foreign exchange increased earnings by $140,000,000 Turning to Slide 20. 1st quarter chemical earnings were down $160,000,000 compared to the prior year quarter. Weaker margins resulted in a decrease in earnings of $270,000,000 as increased feedstock costs outpaced stronger realizations. Higher product sales from our new chemical operations in Singapore and the U. S. Improved earnings by $120,000,000 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 a key 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 $4,700,000,000 Cash flow from operations and asset sales of $10,000,000,000 covered our net investments and dividends with free cash flow of $6,700,000,000 Upstream production volumes were 3,900,000 oil crude barrels per day, in line with our expectations. We expect 2nd quarter volumes to be lower due to seasonal gas demand and then growth in the second half with project and tight oil volumes, seasonal demand and volume benefits from accelerated maintenance completed in the Q1. Total CapEx was $4,900,000,000 with no change to our guidance. We strengthened the upstream portfolio through exploration, acreage capture and selected divestments as well as disciplined execution of our investment program. In the Downstream, we are progressing our advantaged investments such as those in Rotterdam and Antwerp to manufacture higher value products, capitalizing on 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 committee 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 Q4. With that, I would now be happy to take your questions. Thank you, Mr. Woodbury. The question and answer session will be conducted electronically. We'll go first to Sam Marwan with Cowen and Company. Good morning, Jeff. How are you? Good morning, Sam. I'm doing well. How are you? I'm good. Thanks. I guess just to start on the overall kind of profitability spectrum. At the Analyst Day, you offered a pretty clear view that the upstream contributions would be after the post 2020 long cycle development program is wrapping up and in the interim, downstream in 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 into that 2020 period where upstream starts to contribute more? Yes, Sam, good question. And thanks for taking us back to what our plans are 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, 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 2 polyethylene lines in Mount Bellevue, which have started up and have been ramping up to full capacity. And that will add a significant additional component to our chemical portfolio. You'll also recall there are a number of other investments that we've made in chemicals in Singapore. Importantly, we are making great progress on integration of our Jurong Aromatics acquisition. We see significant value there and as the organization continues to integrate that into our big Singapore manufacturing facilities, we continue to see additional opportunities. But right now, the focus on Singapore and drawing Aromatics is primarily the integration and capturing the synergies that we saw. I'll leave it there unless you have more questions on it. No, that's all right. I assume there'll be more later in the Q and 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's a lot of nuances in these contracts and some of them are subject to some non disclosures 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? 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 the 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're really a function of the commercial structure, the expenditure level and obviously prices. Now on the good news side, just don't lose sight of the fact that if you have an asset that is not cost 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 if you think about it quarter on quarter, which I believe is around 70,000 barrels a day, it is 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's 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, our project growth, notably in places like Hebron and Adopt2 and Upper Zakim, the tidal oil growth that we've been advertising. 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 we as I alluded to, there have been a number of unplanned downtime events in the Q1 that we went ahead and took advantage of to accelerate scheduled downtime that we have in the latter part of this year into that Q1 to be more efficient and the downtime on the facility, notably in Papua New Guinea, as I referenced, and the second area is 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'll get some more 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 picking up on us again. And then lastly, I'll mention and I didn't say it 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 program. We'll go next to Ryan Todd with Deutsche Bank. Thanks. Good morning, Jeff. Good morning, Ryan. And I'd like to pass along thanks not just for the incremental disclosure, but I think the addition of management team members to the call will be welcomed going forward by investors. So that's great. The first one for me would maybe be on Groningen. 1 of your partners wrote 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 impacts would be? And whether you view there being a possibility of any compensation going forward? Yes. 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 21.6000000000 cubic meters per year. Okay. And then 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 that when Syncrude comes back up, are you anticipating limits on your ability to get it out? Are you moving things on how much on rail versus pipe and how much are you able to run through your refineries to capture the benefit there? Yes. You've really covered some of the answer there. In the Q1, 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 our prior discussions, one of the objectives that we have continued to press within our business is to maintain logistic flexibility. Several years ago, we went ahead and invested by way of example in the 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 capacity on refining. But we'll we continue to find 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 to either take it into our equity capacity in our manufacturing footprint or to export it to capture a greater value. We'll 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's still some confusion out there on what's really going on with operating cash flow. So I wonder if I could trouble you to just walk through the dynamics of the net PP and E adds with the timing of affiliate distributions and reconcile that with net income plus DD and A, which is $9,200,000,000 Do you see what I mean? There's the CapEx at the affiliate level, as I understand it, 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 $8,200,000,000 Yes. So if you look at our net PPE adds, it was $3,300,000,000 and that reflects that's absent the cash requirements for affiliates, okay? Right. And that is down versus both the prior quarter, Q4 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 Q1? In the Q1, what specific Brazil, there's been a number of transactions The Carcara acquisition, was the money out the door in the Q1 for Carcara? Not yet. That is to come later this year. All right. But your net capital spend after Affiliates at the below the operating cash flow line was $3,300,000,000 Is that number we should be looking at? That's correct. Okay, great. Thank you. My follow-up is, obviously, you saw it in your commentary about the SORBIM unsuccessful well. When we met with you a couple of weeks ago, Mike Cousins had made the comment that in a success case, there could be a 3rd rig option because of the potentially could potentially open another play type. Has that option now gone away? Is that play type now abandoned? Or does this condemn the upside exploration case? Or maybe you could just frame how this changes the risk profile at the block? And I'll leave it there. Thanks. Yes, sure, Doug. I mean, let me just characterize, I mean, Sorbin, 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 wells, we pick up some additional insight and learnings. 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 a 3rd 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're getting things from Surbin, from Liza-five and other analysis that we're doing based on the 3 d seismic that we went ahead and took. Right now, we've got the plan is to go ahead and run the 2 rigs in parallel. 1, primarily focusing on the development wells for Liza Phase 1 following the completion of the Liza Phase, Liza 5 well test. And then the second, we'll 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 Bresch with JPMorgan. Yes. Hi, good morning, Jeff. Good morning, Phil. First question is actually a little bit of a follow-up to Doug's question. You noted the equity affiliates headwind in the quarter of $1,000,000,000 Certainly appreciate you breaking that out from the working capital. So just wondering how you think about that number for the full year. And if one of your peers, for example, has said that the affiliates will be a $2,000,000,000 headwind on an annual basis. I know it can 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 $1,000,000,000 that we think about. 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 seasonal in the quarter, but I was just wondering on an annualized basis also, is it you kind of lumped together a number of factors in your disclosures in your filings. I was just wondering if that affiliate headwinds on an annual basis would still be a headwind? We think, I mean, broadly speaking, we're not giving you specific numbers, Phil, I would tell you that most all the earnings are distributed throughout the year. Okay. So more of a one to one, I guess is what you're saying? Yes. I mean broadly speaking, I mean, there's 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 a 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? Yes. I think from our prior discussions, Phil, what you really were looking at were 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 take comfort in that only because we think we got to always do better. But if you think about how we conclude that, it's through a number of things. One, I'd say that the ultimate measure of that is our return on capital employed. And not only do we lead in 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 comparable on an absolute basis. And lastly, I'd say if you look at another measure, to me it's a fairly simple one, take your total capital employed per barrel of proved reserves, or in other words, the money spent to develop 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'll 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 as a company to make an FID decision around P and G? And then any update on Qatar and the latest in terms of both the timeline and progress around negotiations there? Yes, Neal. On the first one, regarding the P and G, 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 the plant. So very clear synergies and opportunities. Total operates those assets and we've been in very close coordination with our existing co ventures in Total. And as I indicated in the prepared comments, I think we're aligning on this expansion. In addition to that, 2 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 a good discovery at Marook and we've got a well that was spud there later this year and we think there's it's very significant, very close to the hides gas field. And then the last point I'd make is that we picked up a lot of good exploration, high quality acreage in the Highlands, obviously through the inner oil and then offshore of the LNG plant. So the message in all that is, is that we have built a very sizable, high quality resource potential in the P and G vicinity And that positions us for 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 PG government needs to align with the plans 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've 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 P and G is executed consistent with its history of 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 as 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 at 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 the big LNG trains and the big LNG carriers. And we want to continue that relationship. And you've seen us partner with the Qataris in places like Brazil and Cyprus. And we will continue to find opportunities where we could 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 ExxonMobil. Jeff, a quick modeling question here. In the Analyst Day deck, you provided some cash flow cash flow levels at 60, 80 Brent levels. What's the rule of thumb? Every dollar change in the price of bread, what does that do to ExxonMobil cash flow? Yes. We have the earnings sensitivity that's in our 10 ks and it's for every dollar per barrel, it's about $500,000,000 per 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 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, the new returns targets, there's been a 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 a new underlying message from this change or some of the other changes we've seen this year, what is it? Yes. Doug, thanks for the question. I mean, simply put, remember, 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 priorities is growing shareholder value and distributing that success to our shareholders through our dividend. And you've seen us for 36 consecutive years continue to grow 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 coalesced 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 does not did not have a very good understanding of what our value growth potential was. 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 it's going to generate that accretive value. But ultimately, all these steps are around the 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 of potential this corporation has, notably from the integration of our 3 world class businesses. Okay. Well, Jeff, your tone surely underscores your enthusiasm your enthusiasm towards the new value proposition. That's a good thing. And then I have 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'd be appreciated too. Yes. So if you look at I'll give you a couple of comparisons to give you perspective. So if you look at the quarter on quarter impact from earnings, it was about $180,000,000 and most of that was in the upstream, okay? Sequentially, it was a negative impact of about $130,000,000 sequentially being versus the Q4 of 2017. And most of that negative impact was in our downstream business. Okay. Thanks a lot, Jeff. The key aspects just a little bit more, Doug, is you mentioned Scarborough and I mentioned the some marketing and distribution assets in South America and I also mentioned the European assets, primarily retail assets. Okay? Okay. Okay. Thank you. Welcome. We'll go next to Blake Fernandez with Scotia Howard Weil. Hey, Jeff. Good morning. I know you ran through with Sam 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 distillate demand and some of the heavy oil discounts? I just didn't know if the company had a view. Yes. Well, it's a good question and good morning, Blake. So if you think about our investments, they're all really embedded in our deep understanding of 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 how policy ultimately will impact the energy system and the products ultimately that 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 Rotterdam. We're putting the delayed coker in Antwerp, as I said. Rotterdam, we're putting the hydrocracker in. That's going to take us out of the lower value products like a marine fuel oil into higher value distillates like ultra low sulfur diesel as well as grow Group II lubricant base stocks. When you think about IMO 2020 specifically, what we want to be positioned to do is to offer a suite of options for the marine industry. So we're going to be positioned to provide things like low sulfur blends. We're going to provide low sulfur marine gas oil. We'll 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 make in Europe is that we've got a fairly comprehensive complex refinery network in the U. S. Gulf Coast that will be able to provide these products as well. So I think in short, I'd 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. The second question, I can't believe buybacks haven't come up yet, but this quarter, if I'm kind of rewinding last year, I think we went through this. Q1 seems to be fairly elevated as far as the requirement to offset dilution. I think you had $425,000,000 I'm trying to confirm that that number should theoretically roll off here throughout the year. And then, I didn't know if there were any triggering points. I mean, debts reduced, you got 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 just dilution? Yes. So let me just make sure you understand the number that I talked about in the Q1. The $425,000,000 was anti dilutive purchase associated with our benefit plans and programs. That usually happens in the Q1 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 to 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 the importance of distributing value to our shareholders and we generally do that as a priority through our cash dividend. And I think we've shown our commitment to reliably grow dividends we've already talked about. And I think, as I said, it really does demonstrate the confidence that the corporation has in its 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'd say it's very strong. 2nd, 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're going to 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 buying back shares again in a sustainable way. I'll just highlight for everybody, remember that since the merger of Exelon Mobile, 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'll consider. But 1st and foremost, reliably grow 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 and Company. Thanks. Good morning, Jeff. Good morning, Guy. I wanted to talk Permian Midstream and Logistics and strategy here a little bit, especially as it's such an important growth driver for you all. But we've seen differentials 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 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 priced 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. Yes, that's good, Guy. I'm happy you brought this one up because remember, the very the fundamental strategy that we've taken within our business is this value chain perspective. Permian is an outstanding example where we've built this, what we believe an advantage position in the Permian, such that we can go ahead and develop the resource, leveraging 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 got to carry that all the way to what we think is we've got a very advantaged 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 sight on that value chain to make sure that nothing is leaking out of there from a value perspective without us making a decision that that was that's good. That's a good business decision that we shouldn't capture that value ourselves. And we've done things like purchase the Wink Terminal, which we are looking at the potential to go ahead and expand that. We entered into a joint venture with Energy Transfer Partners or subsidiary of Energy Transfer Partners, where we combined our pipeline assets, it gives us a broader export flexibility. But it's important 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 that you're positioning yourself smartly such that you are capitalizing on the value proposition. So as we think about our Permian production, we have 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 are having, we are 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? Yes, very helpful. And then I had 2 follow ups here. 1 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 then sorry if I missed this earlier, but in Guyana, Liza 5, was there anything incremental to share at Liza 5 at this point? And maybe how are you thinking about the size of that 3rd FPSO as you integrate those results? Okay. Let me start with the last question first. Liza, V, 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 and a recoverable resource of about 3,200,000,000 barrels. But I will 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 at Guyana. 1st phase, 120,000 barrel a day vessel. 2nd phase, it looks like we haven't FID ed yet, 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 this 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 facilities such as you maximize the value proposition there. But very exciting time for Guyana. There's a lot going on as you can appreciate from the 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 are 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 and the manufacturing areas that have put pressure on craft labor. In the Permian, obviously, there's a lot of activity and that's putting 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 pressures 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'll continue to drive the unit cost down through our drilling efficiencies. It's all about capital efficiency. So that as you develop 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 rewards. 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 flexibility of the corporation to accelerate and bundle equipment purchases. So it's all about making sure that we drive the cost down, which has historically been able to offset that inflationary pressure. Now you may have some in certain places that we're obviously working through, but by and large, it's what is the lowest life cycle cost of our assets. The good guy? That's perfect. Thanks, Jeff. Great. Thank you. We'll go next to Paul Cheng with Barclays. Hey, guys. Good morning. Good morning, Paul. Just I think that on behalf of the investor that they all 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 questions. First, I think you have drilled a number of wells that is 12000 to 15000 feet lateral in both Bakken and there was several months ago. So I could assume that they've been producing for at least a couple of months by now. Is there any production data that you can share what you have seen in terms of testing the NIM there? Yes. Well, Paul, let me give you update where we are on those. First, just to remind everybody, we tried to give a view of what we saw the value was by extending the lateral lengths on these wells in the analyst meeting. You can always go back and refer to that. We have drilled a 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 been completed at this stage. You remember, a lot of these wells are being drilled by pad. So in order to optimize, again, focused on capital efficiency, they're going to come in batches. We're being careful. I mean, I'll be very candid with you all. We've been very careful what information we disclose on this because we do think that there is a competitive advantage here. And but I will tell you that we see the value uplift that we had portrayed in the analyst meeting. A second question that given the takeaway capacity in Western Canada, it doesn't seem like you're going to be resolved anytime soon. And looking at that portfolio within those opportunity within your portfolio also seems that it has come down in terms of their packing order or ranking. So how should we look at the incremental oil sand development projects at this point from you guys? I think up until last year or even late last year that you guys were supposed to go ahead with a number of reputator projects, including the Aspen and the other one. So are those still being on track to be developed or that those just being, say, put back into the back burner? Yes. Good question, Paul. What I'd tell you is, as you know, we've been working oil sands for over 3 decades, both in a mining and in situ perspective. Fundamentally, any new investment has got to compete at the top of our investment portfolio. It's got to generate, as we talked previously, generate an attractive return that's accretive to our financial performance and is durable in a lower price environment. We continue to identify opportunities to enhance profitability in both in situ and in our mining operations. And Kearl just talked about what we're doing in Kearl 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 at how we can best apply the proprietary SSAG D potential that we think will not only improve recovery, but also reduce costs and importantly the environmental impact. So I'll tell you that that portfolio and as you probably are aware, it is a fairly sizable amount of resource that we've got up there is getting a lot of focus around applying the right technologies and capabilities in order to ensure that it competes at the top of the portfolio. So I wouldn't say that it has fallen down in the 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 proposition is meets our objectives, then we'll move forward with it. Is that good, Paul? Yes. One just follow-up on that. Will you anyway that go ahead with potential new project without a clear site takeaway capacity in Canada is being resolved? Yes. So it's very similar to the whole Permian discussion I had, Paul. I mean, we've been thinking about making sure that, 1, we've got the takeaway capacity and 2, that we've got the flexibility to run these crudes in our equity refining capacity. So staying ahead of that and making sure that we've got that flexibility available. And that was the frankly, that was one of the or the key justification on why we invested in Edmonton Rail Terminal. But obviously, we are big supporters of making sure that there's investment in 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 proposition. All right. Thank you. Thank you, Paul. We'll go next to Roger Read with Wells Fargo. Hello, Roger. Whoops, sorry about that. I had to kick the mute off. Can you hear me now? I can. Okay. Thanks. Good morning. Hey, if I could follow-up a little bit on Guy's question on the Permian. I totally get that this is not anything but a planned 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 other options as you go forward? I'm just kind of thinking over the next several years, we're going to have these periods of pipeline overcapacity, pipeline undercapacity 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? Yes. No, we would be evaluating all options. We would not restrict ourselves to the one avenue. Remember, I know I keep on saying the same thing, but it's all about how we're going to maximize the value proposition. And we're looking at all different midstream options that we can go ahead and consider. You may recall, I believe it was sometime last year that we went ahead and announced that we were looking at spending another $2,000,000,000 in the U. S. For infrastructure investments, things like the expansion of the wind terminal and enhancing our logistics flexibility and offtake. So we're considering a range of options. Okay. I appreciate that. And then looking at your rig count, the lower 48, 4 in the Bakken, 27 maybe going to 30 in the Permian. Clearly, the Permian area is set up for growth. I was curious though, as you think about the Bakken with 4 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 buildup 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've got the Bakken actually growing in terms of volumes. And then in essence, it plateaus, but of course, we maintained an active drilling program. The biggest buildup 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're not too far removed from the analyst meeting, but given the comments that you made about, first of all, the importance of integration on the U. S. Gulf Coast with your Permian operations and second of all, the preparations you're making for IMO, I was wondering if you could address any further progress you've made towards FID of the Beaumont light oil expansion and the Singapore Zuid upgrade project and maybe any critical path items to actually reaching those FIDs? Yes. No, I appreciate you 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 of that would be that we're thinking about is potential expansion of a light crude refining capacity in North America. That is currently still being considered. No final investment decision has been made at this point. We are I'd tell you, we're giving 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'm sorry, Jason, remind me, what was the second one? The Singapore Resid upgrade project. Yes. So that continues to move forward in Singapore. I mean, remember, there's a number of projects that we've got going on in Singapore right now. The RISID upgrade is in progress and it should start up here shortly. Okay, great. And then just in terms of the P and G Jason, let me clarify. We're looking at to an FID decision on that here soon. Sorry, that was the way I took it. 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 any informal agreements with any buyers, HOA type of agreements? Yes. So Jason, we've got, as you can appreciate with a 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 P and G, but others elsewhere. Obviously, the specifics of those are confidential, but just rest assured, remember, we did the fundamental premise that we laid out in the analyst meeting is to really move forward these projects that were on the far left side of the cost of supply curve, such that they compete very well to that demand growth that we anticipated over the period this period out through 2024 or 2,040. 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 Wedbush Redburn. Hello, Jeff. I'm 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'd urge me to think about it. But while 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 see from one of your partners the investment levels going into some of those blocks in Angola. It looks like it might continue to be in decline for a while. So I'm quite excited by the long term projects you're doing and the new growth that should be coming through in a few years. And quite excited by that bit 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? Yes. Let me talk about it more generically that, obviously, there are a number of, let me call them, levers 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 a depletion business as you're all aware. And we've got a very strong focus on how do you improve reliability and enhance ultimate recovery. And you'll see a lot of what we invest in are very large resources that give us more flexibility to go ahead and apply our technical know how and our technology in order to increase recovery. So there's a part of the organization that's focused on how do you mitigate the decline by enhancing recovery and operational reliability. Then there's another segment that you've got out there that is focused on accretive investment. And that's what we've been 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, like Sakhalin 1, Upper Zocum 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'm deeply in favor of the value approach. But in terms of the next few quarters, should we be expecting decline year over year and that's okay because the longer run growth is coming? Yes. Well, I mean, certainly there's decline every quarter. I mean, 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 Q2, due to reduced seasonal gas demand, we do expect the Q2 to be lower. As we turn the corner to the second half of the year, there are a number of things that we would expect that will drive our volumes upward and that would be the things I mentioned, the project activity, the tight oil activity move into the higher gas demand period of the year and in our ongoing conventional program. But no change to our communicated guidance that we'd be generally flat with 2017. Okay. Thank you. That's clear. If I could have a follow-up. Reflecting on the charges coming through the business, particularly the corporate line over the quarter. And my question is about, effectively, the tax write back for every dollar of charge has just gone down. You used to get $0.35 on the dollar back and now it's $0.21 Has that triggered any cost reduction targets in terms of cutting corporate costs or cutting some of those expenses that I get a lower tax write 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 our cost. It's just not in the I thought you might say that. I'm sorry? I thought you might say that. Sorry, I interrupted you. Keep on going. Yes. I mean, it doesn't require something to trigger that mentality. I mean that needs 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 a focus across all aspects of our business. Thank you, Rob. We'll go next to Pavel Molchanov with Raymond James. Thanks 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 you're investing in Russia this year and where that capital is going given the restrictions on where you're able to invest? Yes. Pablo, let me clarify this aspect to make sure that there's no misunderstanding. As it relates to resources that are covered by the sanctions, 1st and foremost, I want to be clear that we have fully complied with the sanctions, okay? There were a number of joint ventures. We had 10 joint ventures that were involved in that would have been covered by the sanctions. And as the U. S. Codified those sanctions and expanded them in 2017, we chose to go ahead and move trial, which we've initiated that process with our partners, okay. And we laid out the specifics of the specific impacts of that in our 10 ks. And specifically, that resulted in a write down of those 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 and Sakhalin 1. And that continues as it was previously and has been very successful in terms of the investment program and the value proposition for both the resource owner and the co venture partners. There's 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. Can you share how much capital you're putting into Russia this year? No, we don't have that information to share. Okay. Appreciate it. Thank you, Pavel. We'll go next to Seifkanajangivan with Exane BNP. Yes. Hi, Geoff. It's Teifan 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 Q1 was quite reasonable, a bit ahead of that typical $4,000,000,000 per annum mark that you've guided to. So any thoughts there would be great. And then just coming back to refining, could you perhaps talk a little bit in the context of what margins you're seeing sort of as we come through Q2 and maybe relate that also to what Exxon is seeing for global oil demand for 2018? Thank you. Well, Tapan, thanks for the question. On the what I call asset management program or divestments, I think I alluded to 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 force a divestment because we've communicated an expectation around a certain number of assets or a certain dollar value that we expect to get from it. But rest assured, I mean, as you saw in the Q1, we had another $1,400,000,000 of gross proceeds from divestments that we will continue to pursue where we can get incremental value through the divestment program. And I think we've indicated a couple of times that we're going to be very aggressive at that. But we're not going to go ahead and walk away from value if we if the market is not going to offer what we think it's 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 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'll get from our downstream business. And, Tipan, did you have a question about oil demand? Yes. I just wanted to get in that context how you see demand year on year. Clearly, you've got a very wide footprint globally. So just wanted to get a sense of that. Thank you. Yes. So broadly speaking, I mean, I think everybody recognizes 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 1,500,000 barrels a day. It's been fairly robust As you go into this year and by the way, with that demand growth and with the supply, I mean, OPEC's objective of getting to the kind of the 5 year average of OECD inventories is within reach, recognizing we still have excess supplies versus where we were at year end 2013. And that's 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 has grown about oil demand has grown about 0.7 percent between now 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, TeePens. 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 was a question about the earnings and cash sensitivity to the price of crude and we have some of this in our 10 ks that you can go ahead and reference. But broadly speaking, for every barrel of crude price, it relates to about $425,000,000 of earnings and about $500,000,000 of 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 had taken an extra effort in order to engage with the 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 conclude today's conference. We thank you for your participation.