Neil A. Hansen - Exxon Mobil Corp. Jack P. Williams - Exxon Mobil Corp.

Neil Mehta - Goldman Sachs & Co. LLC Sam Margolin - Wolfe Research LLC Philip M. Gresh - JPMorgan Securities LLC Doug Leggate - Bank of America Merrill Lynch Thomas Klein - RBC Dominion Securities, Inc. Jason Gammel - Jefferies International Ltd. Paul Y. Cheng - Barclays Capital, Inc. Alastair R. Syme - Citigroup Global Markets Ltd. Roger D. Read - Wells Fargo Securities LLC Rob West - Redburn (Europe) Ltd. Jason Gabelman - Cowen & Co. LLC

Good day, everyone. Welcome to this Exxon Mobil Corporation Third Quarter 2018 Earnings Call. Today's call is being recorded. At this time, I'd like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. Neil Hansen. Please go ahead, sir. Neil A. Hansen - Exxon Mobil Corp.: Thank you. Morning, everyone. Welcome to our third quarter earnings call. We appreciate your participation and continued interest in ExxonMobil. This is Neil Hansen, Vice President of Investor Relations. Joining me on the call today is Jack Williams. Jack is a Senior Vice President with responsibility for the Downstream and Chemical business lines. As we'll discuss on the call today, we are very pleased with our performance in the third quarter. It was a quarter highlighted by strong operating performance, significant growth in liquids production, and considerable value from our integrated business model. As a result, we delivered the highest level of cash flow from operating activities since 2014. In addition, we completed several advantaged projects and made significant progress on investments that will generate long-term accretive value for our shareholders. After I review the quarterly financial and operating performance, Jack will provide his perspectives on third quarter results and give an update on several key investments and strategic focus areas. Jack and I will be happy to take your questions following our prepared remarks. Our comments this morning will reference the slides available on the Investors section of our website. I would also like to draw your attention to the cautionary statement on slide 2 and the supplemental information at the end of the presentation. I'll move now to slide 3, which summarizes a number of developments that influenced our third quarter performance. As I mentioned previously, cash flow from operating activities was the highest it's been in four years, dating back to the third quarter of 2014. Corporate charges for the quarter were outside the $700 million to $900 million range that we typically experience. This was due to net favorable absolute one-time items of $420 million, primarily related to tax. Now it's important to note that we expect fourth quarter corporate charges to be at the high end of the normal range of $700 million to $900 million. Crude oil prices increased slightly during the quarter, with Brent up $0.92 and WTI up $1.71. Permian tight oil production increased by 17% relative to the second quarter. We continue to ramp up drilling activities in the Permian, while also maximizing the value from our integrated midstream and manufacturing operations. We had lower levels of downtime in the third quarter and stronger operating performance in Canada, where Kearl delivered quarterly record net production of 230,000 barrels per day. We also achieved a number of significant milestones on long-term Upstream growth plans in Guyana and Brazil. Jack will discuss this a bit later in the call. In the Downstream, tighter supply resulted in stronger fuels margins in Europe, while wider crude differentials contributed to improved margins in North America. We successfully leveraged our midstream logistics capacity to capture significant value by moving advantaged crudes from the Permian and Western Canada to our manufacturing facilities. Improved utilization from lower scheduled maintenance and better reliability also contributed to stronger earnings in the quarter. In line with our strategy to grow sales of higher-value products, we successfully started up a new hydrofiner at our Beaumont, Texas, facility and a delayed coker at our Antwerp refinery. The hydrofiner will increase production of ultra-low sulfur fuels by 45,000 barrels per day, using a proprietary catalyst that will remove sulfur, while minimizing octane loss. The Antwerp delayed coker will increase supply of distillates and marine gas oil, further strengthening our Downstream portfolio ahead of IMO 2020. The long-term demand fundamentals remain strong in the Chemical business. We experienced weaker margins during the quarter. Improved realizations were more than offset by higher feedstock costs, primarily U.S. ethane. A significant scheduled turnaround at our Singapore facility also impacted quarterly results. We continue to expand Chemical manufacturing on the U.S. Gulf Coast. This included start-up of the 1.5 million metric ton per year ethane cracker at our Baytown, Texas, chemical and refining complex. Now moving to slide 4, which provides an overview of third quarter financial results. Third quarter earnings were $6.2 billion or $1.46 per share, up 57% from the prior-year quarter. Cash flow from operations and asset sales was $12.6 billion, including a $1.5 billion in proceeds from asset sales. Third quarter CapEx was $6.6 billion. We continue to progress investment to support our long-term growth plans, including increased activity in the Permian and the acquisition of additional acreage in Brazil. CapEx through the first three quarters of the year was $18.1 billion. Now if you exclude the acquisition of incremental Brazil acreage of about $1 billion, we remain on pace to meet full-year guidance of approximately $24 billion. Free cash flow after investments was $7.2 billion, more than enough to cover the $3.5 billion in dividends. Debt ended the quarter at $40 billion, a $1.2 billion decrease compared to the second quarter. And as a result, we've reached the lowest level of debt that we've had since the end of 2015. Cash increased to $5.7 billion at the end of the quarter. This increase, which was above our normal operating levels, due primarily to the timing of proceeds from the Germany retail divestment, which closed in the fourth quarter. So again, we received those proceeds the day before the quarter ended, and the transaction closed on October 1. We don't have the earnings impact in this quarter, but we did receive the cash. I'll start the more detailed review of our third quarter results with a reconciliation of Upstream financial and operating performance. Slide 5 provides a look at Upstream results relative to the second quarter. Liquids growth contributed to Upstream earnings of $4.2 billion, a $1.2 billion increase. Gas prices increased by 7%. Crude realizations were essentially flat, impacted by wider Permian and Western Canadian differentials. However – and we look at this – the estimated unfavorable impact of those wider differentials on our Upstream was $170 million, but given our integrated logistics and manufacturing position, that value and more was captured in the Downstream. Having the takeaway capacity that we have that exceeds our Upstream production allows us to – allowed us to realize a corresponding estimated benefit of approximately $280 million in the Downstream. Lower scheduled downtime and the absence of impacts from the PNG earthquake increased Upstream earnings by $130 million. An increase in production, in addition to the volume recovery we saw from lower downtime, contributed $320 million to third quarter earnings. Other items included net absolute favorable one-time tax impacts of $370 million. Now moving on to slide 6 and a comparison of third quarter Upstream production to the second quarter of this year. Oil-equivalent production in the quarter was 3.8 million barrels per day, an increase of 139,000 oil-equivalent barrels per day. Exclude the impact of entitlements and divestments, volumes were up 5% as a result of improved operations and a continued focus on growing volumes with the highest value. Liquids increased 3%, driven by continued growth in the Permian and improved performance at Kearl. Natural gas production was up 5%, lower downtime across the LNG portfolio including Qatar, PNG, and Gorgon. Moving to slide 7 and a comparison of third quarter Upstream earnings with the third quarter of 2017. Higher prices increased earnings by $2.6 billion, driven by a $19 per barrel or 41% improvement in crude realizations and a 30% increase in natural gas prices. Again, we estimate the unfavorable impact of wider Permian and Western Canadian differentials on our Upstream results, in relative to last year, to be approximately $360 million. The total estimated benefit though that we captured in the Downstream from our fully-integrated value chain was $590 million compared to the third quarter of last year. Downtime decreased earnings by $80 million. This was largely driven by carry over from the second quarter Syncrude outage. And just to give you an update, as of mid-September all cokers at Syncrude were back online. Other volume impacts increased earnings by $130 million. Liquids growth, largely driven by U.S. unconventional and Hebron, was partly offset by the impact from lower entitlement volumes. Slide 8 provides us a comparison of third quarter volumes relative to the same period as last year. Oil-equivalent production declined by approximately 90,000 barrels per day. However, and this is important, if you exclude the impact of entitlements and divestments, volumes increased by more than 60,000, with liquids production up 6%, including 57% growth in the Permian. Gas decline year over year was mostly in U.S. unconventional, again, aligned with our focus on value and our near-term prioritization of liquids growth opportunities. Lower entitlements, resulting from higher prices, reduced volumes, as did continued efforts to high-grade our portfolio. And the largest impacts came from the divestments of our operated assets in Norway and a number of U.S. Rockies gas assets. Increased downtime in the quarter was driven by carryover again of the second quarter unplanned outage at Syncrude. Liquids growth more than offset decline from mature fields. This was led by the significant increase in unconventional Permian and Bakken production and the continued ramp-up at Hebron. Improved performance at Kearl also contributed to the increase in volumes. Moving now to slide 9. I'll review Downstream third quarter financial and operating results, starting first with a comparison to the second quarter. Downstream earnings of $1.6 billion increased by $918 million, proved operations and the capture of significant value from our integrated business model. Refining margin strengthened in North America supported by wider crude differentials and in Europe with tighter supply. Stronger margins contributed $150 million to earnings. As previously mentioned, our integrated logistics network that allowed us to connect barrels in the Permian and Western Canada to our manufacturing facilities enabled us to capture significant benefit from wider differentials. And we estimate the favorable impact to the Downstream to be approximately $280 million versus the previous quarter. Lower levels of scheduled maintenance and improved reliability increased earnings by $460 million. The absence of last quarter's unfavorable foreign exchange impacts resulted in a positive $140 million contribution to earnings. But let me tell you, the absolute impact from foreign exchange on third quarter earnings was immaterial. In fact, it was about a $15 million help. And then finally, other items included improved refining yield and mix and minor asset sales gains. All right. Now moving to slide 10 and the comparison of current quarter Downstream earnings relative to the third quarter of the prior year. Downstream earnings for the quarter were up $110 million. Margins had a negative impact on earnings of slightly more than $100 million. And this was mostly driven by lower lubricants and fuels margins in Europe and Asia Pacific. The absence of supply tightness that resulted from Hurricane Harvey last year also impacted our relative margins. Now before I move on, let me give you some additional perspective on lubricants margins. With higher feedstock costs and softer market fundamentals for base stocks, the negative impact on third quarter earnings from lubricants margins was more than $200 million compared to last year. And then if you look at it on a year-to-date basis, we've experienced approximately $500 million in downward pressure from lubricants margins. This was partly offset again by our ability to successfully capture approximately $590 million of benefit across our value chain from wider Permian and Western Canadian differentials. Downtime and maintenance resulted in a $10 million negative impact in quarter-over-quarter earnings. Higher maintenance activities were offset by the absence of the volume and expense impacts that resulted from Hurricane Harvey last year. Other items reflect the impacts of the lower U.S. tax rate, benefits from minor asset sales gains, and improved refining yield and mix. Moving now to Chemical financial and operating results on slide 11, starting first with the comparison of the third quarter with the second quarter. Third quarter Chemical earnings were $713 million, a $177 million decrease. This was mainly driven by higher planned maintenance, partly offset by growth in sales of higher-value products. Margins decreased by $20 million, as increased ethane prices impacted polyethylene margins. This was mostly offset though by stronger aromatics margins. Sales volumes increased earnings by $40 million with higher polyethylene demand and contribution from our new assets in Singapore and the U.S. Downtime and maintenance negatively impacted earnings by $140 million, mainly driven by planned turnaround activities in Singapore. The other items you see there included some unfavorable foreign exchange impacts. Now turning now to slide 12 and a review of current quarter Chemical earnings relative to the third quarter of last year. Lower margins resulted in a decrease of $140 million; higher feed and energy costs outpacing stronger realizations. Higher product sales improved earnings by $30 million, supported by an increase in sales from new assets. Downtime and maintenance had a negative impact of $90 million, and again this was driven by the Singapore turnaround. It was partly offset by the absence of last year's impacts from Hurricane Harvey. Other items included operating expenses for the new assets and upcoming projects, as we continue to position our Chemical portfolio for long-term accretive growth. And unfavorable ForEx also had an impact on earnings. Slide 13 provides a review of sources and uses of cash. Third quarter earnings, adjusted for depreciation expense and changes in working capital, yielded $11.1 billion in cash flow from operating activities. Asset sales contributed $1.5 billion in the quarter, including proceeds with the previously mentioned Germany retail divestment, which again closed in the fourth quarter. In line with our capital allocation strategy, cash flow from operations and asset sales fully funded year-to-date investments and shareholder distributions. We've also been able to reduce debt levels, further strengthening our industry-leading financial flexibility. Cash used to fund investments and shareholder distributions in the third quarter were $5.4 billion and $3.5 billion respectively. Our ending cash balance of $5.7 billion was up $2.3 billion from the prior quarter. And again this was driven primarily by the timing of asset sales proceeds. At this time, I'd like to turn it over to Jack. He will provide some additional perspectives on third quarter performance and discuss the progress we've made on the long-term growth strategy we outlined at the 2018 Analyst Meeting. Jack P. Williams - Exxon Mobil Corp.: Well, thank you, Neil. I'm glad to be here today. And I'd like to thank all the folks on the line today for their interest in ExxonMobil. Let me make a couple of comments about the quarter. And then I'll go into some more updates on the strategic progress. We're very pleased with the business progress that's reflected in the third quarter results. First, if you look at the Upstream, if you ex entitlements and divestments, the net positive volumes growth versus both sequential and year-ago quarters really bodes well, as it reflects the contribution from just one of the five key growth areas that we talked about back in March, and that's of course the Permian. I'd also add that the Hebron ramp-up contributed significantly as well, and it's also going very well. In the Downstream, as Neil mentioned and quantified earlier, we're seeing the benefits of this integration across the value chain. And we're capturing value from low-cost crude feedstock that we purchased in Midland and Edmonton for our Gulf Coast and Midwest refineries. And that's enabled by the strong logistics position that we have. And of course, in both the Upstream and the Downstream, we're very pleased with the improved reliability. This level of performance is much more in line with our ongoing expectations and has continued into October as well. Now the Downstream did benefit from seasonally lower refinery turnaround activity. And in the fourth quarter you should see scheduled maintenance activity more in line with second quarter levels. In the Chemicals business, we are seeing some near-term impacts of recent industry supply growth, including our own, which does not change our view of the long-term attractiveness of this business. The fundamentals continue to remain strong. Our growth plans remain on track. And that's evidenced by the recent start-up of the new Baytown steam cracker. So all in all, a good quarter. So now let me cover a few slides to highlight some of the progress we're making in our Downstream and Chemical businesses. I'll start with a reconnect in the Downstream. And what we talked about was the key driver for Downstream earnings growth is this yield shift to grow higher-value products. And that's largely through the deployment of our proprietary catalyst and process technology. Now this yield shift is accomplished primarily through six advantaged refining projects. Three of these are in the near term, the Beaumont hydrofiner and Antwerp coker, both of which are now online, and then the Rotterdam advanced hydrocracker, which should start up around year-end. And just for completeness, the other three are the Fawley hydrofiner, Beaumont light crude expansion, and the Singapore is the upgrade project. So just a couple of comments on that. When I say advantaged, what I mean there is that either due to proprietary technology application or to integration benefits or both, these projects generate from mid-teens to mid-20s discounted cash flow returns. And when I say primarily, in terms of primarily those six projects, those projects really are needle movers in that regard. But there's also a few hundred other smaller optimization projects that are collectively having a big impact as well. As a matter of fact, as you think about the 2018 and 2019 turnarounds, in over 80% of those, the scope includes work on these small optimization projects. And I think it's just really a great example of how our Downstream teams are continually working to improve the performance of our assets. And the other main strategic area for us is this integration across the value chains. And in the Permian, we really have a unique position that's already generating additional value today. We're progressing a very attractive pipe-still expansion at Beaumont. And we're further building our logistics position to capture the advantaged feeds on the Gulf Coast integrated facilities. I'll talk more about that logistics in a second. On Beaumont, just a quick reminder on that project. We're adding a 250,000 barrel a day atmospheric pipe-still and some hydrotreating conversion capacity. But we're utilizing an existing gas plant and utility capacity. And we're replacing over 100,000 barrels a day of intermediate products that are purchased at Baytown and Baton Rouge. So this project is highly attractive. You're essentially getting a large-scale capacity addition for the unit cost of a debottleneck project. So very, very attractive project. And it significantly improves the Beaumont complex earnings profile. Okay moving on to Chemicals. In March we spoke of 13 new Chemicals manufacturing facilities, and these are all underpinned by these competitive advantages that we were talking about, integration, proprietary technology, performance products, and global market access. Seven of the 13 are now operational, with the steam cracker at Baytown that started up in early – early in the third quarter. We're actively progressing projects to increase our Chemical product manufacturing capacity by 40%. So if I look forward, we have the Beaumont polyethylene expansion that should start up middle of next year. We're progressing a new ethane cracker in Corpus Christi. And we've recently announced a plan to pursue a new liquids cracker in China. I'll expand on these in a later slide, but I just want to leave you with the point that we're on track with our Chemicals growth plan. So now for a couple of business updates. Start with the Antwerp delayed coker. This 50,000 barrel a day coker is now operational. And the point I want to make here is that it is located at Antwerp, but I want to stress that it's a regional coker. In other words, we're planning to process resids from our entire European circuit at this coker. And you can see on the map that we're showing here that it's centrally located in the manufacturing center of northwest Europe, so we can process third-party resids as well. At the time of FID on this project back in 2014, it was not clear when the IMO bumper fuel spec change was going to come into effect. But the project was attractive based on just trendline industry margins. And we knew the spec change provided potential upside. Of course, looking at the start-up timing today, it looks very likely we're going to achieve that upside, that additional upside. Once we achieve stable operations on the coker, we'll be looking for debottleneck opportunities to further increase capacity in the unit. And typically we're able to get about another 10% or 15% of more throughput over time. So this coker positions us well in Europe for the 2020 IMO spec change. But we're in good shape in the rest of the world as well, with the most global coking capacity of any of the IOCs. And we're also going to offer a marine gas oil and a low sulfur fuel oil option for our customers. And of course, we'll continue to offer a high-sulfur fuel oil product to the ship owners who invested in onshore scrubbers. Moving on to the Permian. We are positioned well in the Permian across the full value chain. It starts with the Upstream position, where we continue to see positive indicators on both the quality and the size of the resource in the northern Delaware Basin acreage. You can see on the chart on the left that we're making good progress versus the growth potential communicated back in March. Our XTO Permian team is very excited with the results they're seeing out there in this new acreage. And the vector is clearly up on the Permian developments. I was out there about a month ago. And in fact, the entire management committee and the board went out there. We even let Neil go out there with us. And the team, it was clear to see that the team was very energized. They're really starting to hit their stride. It was really good to see that operation. Still early days, but again, the vector is up there. Today – looking more Downstream, today we have the ability to run 450,000 barrels a day of light crude in our Gulf Coast refining circuit. And this has provided ample incentive to secure efficient transportation capacity to our refineries well in excess of equity production from the Permian. Currently, we have about 270,000 barrels a day of committed capacity. And that's likely going to grow further in the coming quarters. And the 450,000 barrels a day is growing too. In addition to the Beaumont expansion, we're working on some other smaller debottleneck projects to add about another 50,000 barrels to ultimately take our Gulf Coast light crude processing capacity to over 750,000 barrels a day. And then in addition to our three Gulf Coast integrated facilities, we run Permian crude at 10 other sites outside the U.S., including our Singapore crude cracker. On the lower left of the chart is a chart from Mark (28:05) showing the integrated earnings based on 2017 prices and margins. Year to date with the actual environment we're seeing, we've made well over $1.2 billion across this value chain. And it's clear from the current environment, it's highlighting the value of our approach in the Permian. So last thing I'd like to say is given the growth plans we have in both the Upstream and the Downstream here, we're progressing a large 1 million barrel a day plus crude pipeline system with our JV partners that's going to provide long-term efficient transportation to our Gulf Coast refineries and also other outlets. FID is planned for next year, will start-up in 2021. And we plan to be both an owner and an anchor shipper on the line. Moving on to Western Canada. And our position across the full Western Canada crude value chain is somewhat similar to the Permian, with strong Upstream and Downstream positions that facilitate a development of a really valuable midstream logistics position that ensure we capture the full value of West Canada crude, even when there's a large WTI/WCS differential. And just to clarify here, when I say we and our on this slide, I'm also including IOL [Imperial Oil Limited]. All the assets in Western Canada are fully or partially owned by IOL, and they're of course operating everything up there. Our Upstream position is comprised primarily of interest in Cold Lake, Syncrude, and Kearl. And this production is processed at the Strathcona and Sarnia refineries in Canada; our Midwest Joliet and Billings refineries; and then all of our three large U.S. Gulf Coast integrated facilities. And all of these with heavy oil processing capabilities. During the early days of bringing Kearl on stream, we made the decision to invest in a 210,000 barrel a day capacity rail terminal in Edmonton. And that's to allow efficient unit rail transportation to the Midwest and U.S. Gulf Coast in case Canadian production growth out-ramped pipeline capacity. As you can imagine, the utilization of this terminal is increasing rapidly in this current pipeline constrained environment, which provides another transportation option down to the Midwest and Gulf Coast refineries, in addition to our committed pipeline capacity. Today, we're running about 100,000 barrels a day through this terminal. That should grow to about 170,000 barrels a day by the first quarter of next year. Our Downstream logistics positions in this value chain are unique, and like the Permian, added a significant earnings contribution in this quarter. Moving to Chemicals. The chart on the left here was shown back in March. And it shows the market position of over 75% of our Chemical product sales, where we're either number one or number two in the market. Our seven new facilities that are now online have added about five MTA of additional manufacturing capacity. And as shown in the red stars on the chart, they're focused on many of the products where we already have a leading market position. We continue to progress a new 1.8 MTA ethane steam cracker along with ethylene glycol and two polyethylene derivative units at a site near Corpus Christi, Texas. Construction of that project is pending completion of the environmental permitting process. And expected start-up is in 2022. In September, we announced an agreement to pursue a liquid steam cracker complex in China's Guangdong province to produce performance polyolefin products for the domestic Chinese market. The current plan is the unit will have a direct crude cracking capability similar to our Singapore operation. And we're growing all these new facilities with a significant proportion of performance products, which currently are about 30% of our overall Chemical sales. They're growing at a rate of about double that of the commodity Chemical sales we're having. And they achieve, due to superior performance characteristics, on average about a 30% higher price than commodity products. So now let me wrap up with sharing a few other highlights in our business that – milestones since the end of the second quarter. In Brazil's fifth pre-salt bid round, we were the successful bidder on the Titã offshore block, adding up more than 71,000 net acres and bringing our offshore acreage build to about – well not to about – to precisely 26 blocks, two-thirds of which we're the operator. In Guyana, we made our ninth offshore discovery and fourth year to date, the Hammerhead-1 well. This discovery reinforces the potential of the Guyana Basin. So as I think Neil highlighted last month, we've added a second exploration rig. In fact, I can verify that rig has now spudded the Pluma exploration well. And we're also fast-tracking the Liza Phase 1 development, so the vector is certainly looking up in Guyana. Our Permian tight liquids production growth continued. It's up 57% quarter on quarter 2018 versus 2017. And we're currently running 38 rigs in the Delaware and Midland basins. In Angola, the first Kaombo FPSO successfully started up in late July, with production expected to reach 115,000 barrels a day. And a second FPSO is planned to start up in mid-2019. Moving to the Downstream. Our Indonesia lubricants acquisition is proceeding well. Transition with Federal (sic) [PT Federal Karyatama] (34:33) is on track. The expertise in motorcycle lubricants is complementing the mobile lubricants offer. And we think we're positioned well now to be a strong competitor in a growing market. Mexico, our fuels market entry is progressing well. Recently, we've been streaming new sites at the rate of three new retail stations per week. And in Germany, our retail divestment was completed October 1. So we're moving to our branded wholesale model there. And the Augusta Refinery and Terminals divestment is on track for completion at year end. So if the Augusta sale does close in the fourth quarter, we expect a combined earnings benefit in the Downstream from both the Germany and the Augusta divestments of about $700 million to $1 billion with forex movements being one factor that could impact the final earnings. And moving to Chemical. Start-up has commenced at our Newport, Wales, Santoprene specialty elastomer expansion project, with the first production line now in service and the second line planned for start-up in next year. And our Beaumont polyethylene plant expansion that I mentioned earlier will take the remainder of the ethylene from the new Baytown cracker that's not going to Mont Belvieu. And that's progressing well, and the start-up is planned for mid-2019. So before I hand it back to Neil for some – to start the Q&A, let me just wrap up by telling you that we're on track with our growth plans. We've seen a bit of upside in Guyana and in the Permian. And we've hit a couple of important milestones with the Antwerp coker and the Baytown steam cracker start-ups. So I feel good about where our businesses are positioned today and the underlying path we're on. We are all excited about the opportunities in front of us. And I can assure you the organization is working very hard on it. So with that, I'll hand it back to Neil. Neil A. Hansen - Exxon Mobil Corp.: Great. Thank you for the comments, Jack, and I do appreciate you letting me go on that Permian trip. It was wonderful. Jack P. Williams - Exxon Mobil Corp.: No problem. No problem. Neil A. Hansen - Exxon Mobil Corp.: All right. We'll now be more than happy to take any questions that you have.

Thank you, Mr. Williams and Mr. Hansen. The question-and-answer session will be conducted electronically. We request that you limit your questions to one initial with one follow up, so that we may take as many questions as possible. And we'll pause for just a moment to provide everyone the chance to signal. We will first go to the line of Neil Mehta with Goldman Sachs. Neil Mehta - Goldman Sachs & Co. LLC: Good morning, guys, and congrats on a good quarter here. Neil A. Hansen - Exxon Mobil Corp.: And good morning, Neil. Thank you. Jack P. Williams - Exxon Mobil Corp.: Morning. Neil Mehta - Goldman Sachs & Co. LLC: So, Jack and Neil, maybe you could start off by just talking about the LNG cadence of projects. You've got so many different options out there, whether that is Mozambique, Golden Pass, the potential upside of PNG, Qatar. And I think we as an investor community are wondering what are the priorities in terms of most likely to sanction? When? And how should we think about the cadence of that growth? So if you'd just frame out how you're thinking about it and where you stand with some of the key projects, that would be helpful. Jack P. Williams - Exxon Mobil Corp.: Thank, Neil. Let me start off, Neil, and you can chime in if you like. Neil A. Hansen - Exxon Mobil Corp.: Yeah. Jack P. Williams - Exxon Mobil Corp.: We are very happy with the portfolio of opportunities we have in the LNG market. At Papua New Guinea, we're building on success there with the foundation project that's continuing to achieve performance above expectations. Mozambique, a big new area for us, large resource base. We think we're bringing some real unique expertise that we have from both PNG and in Qatar to bring to bear on that resource. And then of course here in the U.S., continuing to look at Golden Pass with QP. And obviously, very interested in any expansions in the North Field as well. So I would say that given the low cost of supply of all these opportunities, they're all attractive. We see a growing LNG demand that would certainly allow all those projects to go forward. Naturally, the Mozambique is a little bit behind PNG in terms of the onshore trains, the offshore coil may make it a little quicker. But – and obviously in Qatar, with the new trains, we would like to pursue that as soon as possible. But that may be a little bit longer term as well. So in terms of the cadence, what I'd tell you is that there's other parties involved in all of those. We find them all attractive. We're wanting to pursue them all in our typical capital efficient deliberate way. But very proud of where we are and the opportunities we have in front of us. And we're excited about pursuing all of them, Neil. Neil Mehta - Goldman Sachs & Co. LLC: That's great. The follow up I had is we've seen some increase in unconventional M&A. One of your peers doing a deal in the lower 48. And then some of the independents as well here over the course of the last week. Just wanted your latest thoughts on pursuing growth in the lower 48, whether to do it organically? Or to do it through transactions? And just what the bid/ask looks like in the market, especially with some of the shale players having a pullback here decently over the last couple months? Jack P. Williams - Exxon Mobil Corp.: Yeah, yeah, thanks, Neil. You mentioned it earlier in your question. Let me just reinforce that, from an organic standpoint, we have a very exciting growth plan. We talked about that earlier. A lot of running room. We had that big acquisition, northern Delaware Basin, that we're now estimating over 5 billion barrels, 9 billion total in the basin. So a lot to go after there. Having said that, we do maintain the financial strength to be able to capitalize on any environment we find ourselves in that might present an attractive opportunity. And we continue to scan the market for all opportunities that play to our strengths. We think certainly unconventional does that. So we're continuing to look. I would say that as we think about those kinds of opportunities, we're certainly thinking about where we can really bring our development strengths. So something that would have a large undeveloped aspect to it. But we do like our organic growth plan. We feel like that's going to give us a lot – many years of substantial growth. And as you may have noticed, our rig counts is increased in the Permian and the vector is up there. And so we got a lot to – a lot on our plate right now, but we continue to look. Neil Mehta - Goldman Sachs & Co. LLC: Thanks, Jack. Thanks, Neil. Neil A. Hansen - Exxon Mobil Corp.: Thank you, Neil.

Your next question comes from the line of Sam Margolin with Wolfe Research. Sam Margolin - Wolfe Research LLC: Hey. Good morning. Thanks for calling on me. Neil A. Hansen - Exxon Mobil Corp.: Good morning, Sam. Jack P. Williams - Exxon Mobil Corp.: Yeah. Sam Margolin - Wolfe Research LLC: I guess my first question, I'm going to relay a question that I've been encountering in the investment community. And maybe you can have a better answer than I've been able to come up with. But one of the fears that gets brought up occasionally is that fiscal terms internationally are sort of tightening. Renewals are challenging, especially with momentum in commodity prices. And people are afraid there's a lot of contracts that are scattered around the world that are sort of at risk. And that renewals aren't going to be as attractive. Can you talk about how your unconventional business – if that's true, first of all? If it's not, you can just refute it. But if your unconventional business kind of functions as an offset to that, you can simply rotate capital into the U.S. where you're seeing those international headwinds? And whether there's sort of a limit to that strategy? And just generally, if there's a strategic function to the U.S. unconventional business, besides just kind of short cycle volume growth at a high margin? Jack P. Williams - Exxon Mobil Corp.: Okay. Sam, let me start with that and Neil may want to chime in. But on the last part of the question first, around the unconventional. I mean we do see it more than just kind of short cycle place to go invest. We do view that whole unconventional strategically, and it really plays to our strength with the large unconventional organization that we have. So I would certainly characterize the U.S. unconventional as strategic and as a strength of our corporation. Now getting back to the earlier part of your question around PSC extensions and terms and so forth. What I would say is that by the time PSC extensions come up, we typically had 20, 25, 30 years of operations. And we would hope – certainly our expectation, we would hope that the resource owner recognizes the strengths that we bring at that point in time. And that we are able to progress and extend, to the extent the resources are required, extend those terms, obviously with a fulsome negotiation. So I wouldn't want to pre talk about where those things are going to go and when. But I would think – we typically start out with a position, start out from a position of strength in terms of what we've delivered in terms of the value to the resource. And that certainly comes into play in terms of those types of decisions. The other thing I'd like to point out is in terms of this overall comment you made around fiscal starting to tighten and so forth, is when we talked about these five growth areas that we talked about back in March, think about when those were acquired and brought into our portfolio and the environment at the time. So we basically brought all those in kind of at the bottom of the cycle, where we had some – where the environment was reasonable in terms of getting reasonable terms and so forth. And all of those were tested hard at bottom-of-cycle conditions. So to the extent that you think things are tightening now, it makes those resources and those projects all the more attractive. Neil, anything to add? Neil A. Hansen - Exxon Mobil Corp.: Yeah, the only other thing, and maybe just to reiterate some of those points, Jack, we have a long history of execution. We have a good relationship with the resource owners. We tend to be a partner of choice. The diverse portfolio that Jack mentioned does give us that flexibility, Permian certainly being an example of that. The only other thing I'd say is we've successfully renegotiated multiple extensions across our portfolio in the past. So I don't think there's any near-term pending concerns on fiscals. I think we continue to focus on making sure we deliver what we say we're going to deliver, that we establish those good relationships. And that certainly mitigates any of the risk you might have from deteriorating fiscals. Sam Margolin - Wolfe Research LLC: Well, thanks for all that color. And my follow up is quicker, just on this theme of integration. There's obviously a lot of focus on crude takeaway from the Permian and maybe from Western Canada too. But frac has been very tight in the Gulf Coast. And you sort of highlighted it with your Chemicals summary of the period. But just how you think about the full suite of integration, besides just takeaway and refining. But maybe some of those intermediate stages too, if you have investment plans for that. Jack P. Williams - Exxon Mobil Corp.: Well, I can make a comment there. On the broader question of the takeaway capacities and these disconnects, the nice thing about being across the value chain is it doesn't really matter whether those disconnects are there or not in terms of the value we accrue to the corporation. We'll – for instance in the Permian, we'll either accrue that value with higher crude price at the wellhead, or we'll accrue that value through our midstream and Downstream. But we'll get that full value of those molecules going all the way through the value chain to the customer. And really I think the same thing is true in Western Canada. Now on the ethane issue and the NGL fractionation capacity. What I'd tell you on that is that that's a transitory issue. And there's more NGL fractionation capacity being built, constructed right now. We certainly see that going away. We see plenty of ethane supply out there. And quite frankly, a lot of it's getting rejected into the methane stream right now. So that's going to get resolved. And I think it's going to get resolved in a matter of over the span of 2019. But I'd say that's more a transitory sort of issue. Neil? Neil A. Hansen - Exxon Mobil Corp.: Yeah, I'll just reiterate. Long term fundamentals for the Chemical business remain very strong. We look at demand over time still growing at 1% above GDP. You'll see times where you'll see cyclical pressures. We don't try to attempt to time the – when we bring these investments online, we make these investments based on those long term fundamentals. Sam Margolin - Wolfe Research LLC: Thanks so much. Neil A. Hansen - Exxon Mobil Corp.: Thank you.

Your next question comes from Phil Gresh with JPMorgan. Philip M. Gresh - JPMorgan Securities LLC: Hey. Good morning. First area I wanted to just hit was on the Chemicals business, Jack. If we, I know there were some headwinds there from maintenance in the third quarter. But we have seen some pressure for much of the year on the earnings profile in the business. And it's a big area of investment for you guys. So maybe you could just elaborate a bit more on your thoughts here? And just in terms of the margin outlook for the various businesses? Jack P. Williams - Exxon Mobil Corp.: Sure. Neil just mentioned, we do see a longer term growing demand, the fundamentals of the business still look good. The issues have kind of shifted a bit. In the early part of the year, we had depressed aromatics margins. And those look much better now. And now with the U.S. ethane feedstock increases, it hurts the ethylene and polyethylene margins. So there's a few kind of near term things going on. But it doesn't change the fundamental analysis for those supporting those big investments. We still see a growing market. We think our investments are all advantaged in terms of cost of supply. We have these performance products that are unique to us that also enhance our projects as we bring them online. So as we look at the fundamentals, we really still like that business a lot and like the investments that we have made and are making. Philip M. Gresh - JPMorgan Securities LLC: Okay. Second question, just a quick numeric one would be, you had mentioned the two asset sales in Downstream and the earnings impact that you expect to see. What is the lost earnings impact from both of those assets on a go-forward basis? Because that's – you guys have a lot of asset sales. And I think that's the harder part for us to figure out sometimes. Neil A. Hansen - Exxon Mobil Corp.: Boy, I'm not sure what the lost value is going forward. Obviously, when we look at divesting assets, we do that when someone else sees more value for the asset than we do. And so again the assumption is when we sell these divestments, we're getting more value out of them than we would if we were to keep them. But I don't have a specific number on those two individual assets on what we're giving up. But I can assure you that what we're getting today is worth more than what we would get if we were to keep them. Jack P. Williams - Exxon Mobil Corp.: Yeah, I would agree on that. Yeah. Philip M. Gresh - JPMorgan Securities LLC: Okay. If I could just ask one last one then. Neil A. Hansen - Exxon Mobil Corp.: Sure. Philip M. Gresh - JPMorgan Securities LLC: On the cash flows, you had a headwind from deferred taxes. And I think in the first quarter, you had a big headwind from affiliates that you had expected to reverse at some point. Maybe you could just elaborate a little bit on where we would stand on that. Thanks. Neil A. Hansen - Exxon Mobil Corp.: Yeah, you're right. In the quarter, we did see an adjustment for the non-cash impacts from those favorable one-time tax items that I mentioned. If you look full year, we will always see some timing on equity companies in terms of earnings and when the dividends come in. It's tough to predict when that will happen. I think we mentioned in the first quarter that that was the case. And we have seen dividends come in from equity companies. I think another important thing to consider is these equity companies also may prioritize accretive investments over dividends. And so I think one of the things you're seeing and probably the biggest impact on a year-to-date basis is TCO. So TCO is the equity company that holds our Tengiz investment. And so obviously, they're prioritizing dividends over investing in that project. So tough to predict exactly when the dividends come in. There will always be some timing impacts. But again, we've seen some cash come in. But we're certainly supportive of those companies continuing with investments that will provide value to the shareholders. Philip M. Gresh - JPMorgan Securities LLC: Okay. Thank you. Neil A. Hansen - Exxon Mobil Corp.: Good. Thank you.

And next we'll go to Doug Leggate with Bank of America Merrill Lynch. Doug Leggate - Bank of America Merrill Lynch: Well, hi. Good morning, everybody. Neil A. Hansen - Exxon Mobil Corp.: Hey, Doug. Jack P. Williams - Exxon Mobil Corp.: Morning. Doug Leggate - Bank of America Merrill Lynch: Jack and Neil, I wonder if I could pick up, Jack, on one of your comments about fast-tracking Liza 1. I think originally – actually just a broader question on Guyana generally. Hammerhead, my understanding from your partners, could potentially also be fast-tracked in addition to Liza 1. So I'm wondering if you can address where you see the guidance that you laid out for Guyana at your strategy update, versus to what appears to have been fairly rapid progress in the last six months. Jack P. Williams - Exxon Mobil Corp.: Yeah, on Hammerhead, the rig just moved off there. We did some – in addition to drilling the well, we did some dynamic flow testing and so forth. So a little bit too early to provide any EUR estimates on that one. So I think that leaves us at this estimate that's out there right now of over 4 billion oil-equivalent barrels, up to 5 FPSOs, peaking at 750,000 barrels a day, with Liza 1 targeting early 2020 and Liza 2 coming in behind that. We're talking to the government right now about our development plan and environmental permit. Hope to start that one up in 2022 or behind that. So we're continuing to tick on along. But when you look at the time between discovery and this projection of the Liza 1 start-up, it's very impressive in terms of what the industry timelines typically look like. Doug Leggate - Bank of America Merrill Lynch: Sorry, Jack. Just to be clear. You did say fast-track, so has the March 2020 date changed for Liza 1? Jack P. Williams - Exxon Mobil Corp.: No, and I don't think we ever said March. We just said early 2020. (54:52) Jack P. Williams - Exxon Mobil Corp.: Doug, when you go from five years from discovery to online, I view that as fast track. I mean that is very fast movement. That's about as good as it gets in industry. So that was why I took on fast track. Doug Leggate - Bank of America Merrill Lynch: My follow up, guys, if I may is also – I'm afraid, Jack, it's also an Upstream question. Just going to the Permian, the 38 rigs, Q1 – or Q2 sorry, you gave us the completion cadence. You said you brought 50 wells online in Q2. Can you tell me what the – how that completion cadence looked in Q3? And what the – whether you've caught up now with your rig activity? Because obviously, it was still pretty light on the important completion pace. And I'll leave it there. Thank you. Jack P. Williams - Exxon Mobil Corp.: Yeah, and no need to apologize. I don't mind talking Upstream, and I don't mind talking Permian at all. I, in fact, enjoy talking Permian. Yeah, on the – let me answer your question directly, and then I'll expand it a bit. We brought on 58 wells in the Midland Basin, and only eight in the Delaware Basin in the third quarter. And you'll notice the rigs are about equal between the two basins. And what you're seeing is that in the Midland Basin, there's a lot more infrastructure. We had the rigs there longer. And so the timing just worked out to where we have a lot more wells coming online there than the Delaware Basin. Over time, some of that's going to switch over – some of that growth is going to switch over to the Delaware Basin, but it's just less mature. I think it points out the issue that I think that Neil Chapman said a couple times and I've said it as well. It's going to be fairly lumpy coming on. I mean we are basically doing three things. Our teams out in the Permian are doing three things simultaneously. First, we're delineating this big new acreage position we have, and like I said, that everybody says, that looks very promising. There is further upward vector on that resource. We already increased it from 3 billion to 5 billion barrels. And there's further upward tailwinds on that. We're building out infrastructure in the Delaware Basin. We're spending a lot of time and energy on this infrastructure build-out. There's about 200,000 barrels a day of well pad facilities under construction right now, in addition to two major central processing facilities. So – but we had essentially a blank canvas on this 225,000 acres. There was not a lot of facilities out there. So we're building all that from scratch. Which in some respect is an advantage for us, because it allows us to bring other parts of our corporation, this major project expertise, to bear on this. And we're going to wind up with an infrastructure there that's really unlike anything else in the Delaware Basin or in the Midland Basin for that matter or any other unconventional development that I've ever seen. It's going to be very capital efficient and allow us long term to have a very competitively advantaged operation. So – but in addition to those two things, we're also growing production. So they're also having some of the rigs dedicated to just developing where we know we have mature benches. And we feel like we know it pretty well, and we're just growing production. But there's all those things going on at once. So it's going to be pretty lumpy. We draw a nice smooth line, but it's going to be pretty lumpy as we go up there but – as evidenced by this quarter. And... Doug Leggate - Bank of America Merrill Lynch: Jack, may I ask for a point of clarification real quick. I know I've got to jump off here. But Neil did promise a little bit more of a look-forward on some of your commentary. If you're 50 [wells] in Q2, 58 in Q3, can you give some idea as to what that's going to look like in Q4 in your current plan? Jack P. Williams - Exxon Mobil Corp.: No, I can't. I really don't know. I mean I can just tell you the rig activity we have out there – now I will say one thing. A lot of those rigs have been picked up in the last three, four, five months. And when you think about these multi-well pads that you drill four, five, six wells at a time and then have to come back and frac all those wells, all the facilities considerations and so forth, it's seven, eight, nine months between picking up a rig and having production online. So it's coming. The activity is there. We're liking what we see. But I can't give you a number for fourth quarter. Doug Leggate - Bank of America Merrill Lynch: Appreciate the answers, guys. Thank you. Neil A. Hansen - Exxon Mobil Corp.: Thanks, Doug.

And next we'll go to Thomas Kline with the Royal Bank of Canada. Thomas Klein - RBC Dominion Securities, Inc.: Thank you for taking my question. With a good quarter and strong cash generation, I'm just wondering what else you guys would need to see, quantity, price or in terms of the environment, to prompt share buybacks? And especially in light of recent rhetoric on this from peers. Thank you. Neil A. Hansen - Exxon Mobil Corp.: Great. Thank you, Thomas. Yeah, we did have really what was an excellent quarter from a cash generation perspective. We're very pleased with it. I think nothing's changed for us in terms of our capital allocation strategy. And we're in a very fortunate position to have a really impressive portfolio of attractive accretive projects. And we're going to prioritize investing in those. I think we talked about how the fact that in the Upstream, they're going to generate a 20% return and a 15% to 20% return in Downstream and Chemical. So that's certainly a priority. We want to continue to pay a reliable, growing dividend. I think we've paid a growing dividend for 36 years now. And we recognize that those two things are tied together. We need to continue to invest in accretive projects, so we can continue to pay a reliable, growing dividend. Now beyond that – and you've seen a little bit of it this year – we want to ensure that we have the financial capability, the financial strength that we need to take advantage of investment opportunities, regardless of the price cycle. To the extent we can meet that, those objectives, and there's excess cash, we will certainly distribute cash back to shareholders. It's an important part of our capital allocation strategy. I think we've distributed more than $220 billion since the Exxon and Mobil merger, so it's certainly a key factor in that. And I think if you look at it maybe bigger picture, what we're trying to do is we're trying to position the company for long term sustainable distribution to our shareholders. I mean that's the objective. And we think the best way to do that is to ensure that we are taking advantage of, again, a portfolio of opportunities that's probably as attractive if not more attractive than anything we've seen since the Exxon and Mobil merger. So we're not going to prioritize buybacks over doing that, because what we're really focused on is long term sustainable distributions. Anything to add to that? Jack P. Williams - Exxon Mobil Corp.: I would just say that the shareholder accretion from this investment program we have is – we think is going to be very impressive. So I'd just echo that point. That we have a very exciting investment portfolio in front of us. Thomas Klein - RBC Dominion Securities, Inc.: Understood. Thanks you. Thank you. Neil A. Hansen - Exxon Mobil Corp.: Hey, thank you.

Okay. Your next question comes from the line of Jason Gammel with Jefferies. Jason Gammel - Jefferies International Ltd.: Thank you very much, gentlemen. I appreciate the conversation around the coker at Antwerp. I was hoping you might be able to make similar comments about the Rotterdam hydrocracker. First of all, just the size of the unit. And whether you would actually be also processing your European system and potential third-party VGO through that unit? And finally, whether you have the hydrotreating capacity there to be able to handle third-party high sulfur VGO? Jack P. Williams - Exxon Mobil Corp.: Let's see. I think it's primarily handling the feeds from our refinery there in Rotterdam. But let me just kind of give you a sense. Again, this is advanced technology, advanced hydrocracker from the proprietary technology. And we think we're going to generate not only about 20 kbd of high-quality Group II lubes but also some clean products as well. And due to what we already had on the ground in Rotterdam, and this shift to a kind of a real lubes-based stocks generating machine, this is going to have substantial impact on the Rotterdam refinery profitability. Now we talked about, and Neil talked about, some weakness in near term in the base stocks market. And clearly, that's coming because we're adding a bunch of Group II capacity, which long term is going to be very advantaged. So don't know what we're going to be looking at when we first come on in early 2019. But it's fundamentally a very advantaged investment, one of the best returns we have. It doubles the earnings from Rotterdam. And I think again, I think it's primarily focused on – I think most of the feeds into this unit are at the refinery today. Jason Gammel - Jefferies International Ltd.: Okay. Thank you for that. And I was just hoping that you might be able to give us where you're at in the process for that second group of three expansion projects in the Downstream. Have they all reached FID? Are they in construction? Just where are they at in the process? Jack P. Williams - Exxon Mobil Corp.: Yeah, we're looking to FID Beaumont probably first quarter of next year. The Fawley unit is going to be about the same timing as Beaumont, probably more like midyear, working for an FID on that one. Singapore is a little bit behind that. We're looking more like a 2023 or so start-up on Singapore. It's a bigger project. It's a very, very large project in Singapore. Very fundamental – fundamentally shift the whole Singapore, when you take 75 kbd of resids and turn that into a lot of lubes and clean products, that's a very, very large project. That one is a little bit later. But Beaumont, we've been looking at all opportunities to accelerate that and try to get that on as soon as possible, because we see that one as extremely attractive. Jason Gammel - Jefferies International Ltd.: Thanks very much.

And your next question comes from the line of Paul Cheng with Barclays. Paul Y. Cheng - Barclays Capital, Inc.: Hey, guys. Good morning. Neil A. Hansen - Exxon Mobil Corp.: Morning, Paul. Paul Y. Cheng - Barclays Capital, Inc.: Jack, just on the Beaumont cool unit, 200,000 barrels per day. Can you share a little bit more detail in terms of how the – you're talking about that replacing maybe 100,000 barrels per day of the feed. So how's the output is going to look like at the end? How that is going to change? And what kind of CapEx we may be talking about? And when that is supposed to come on stream? Jack P. Williams - Exxon Mobil Corp.: Yeah, we're looking at 2022, maybe perhaps 2021. Still looking at that pretty hard in terms of when it's going to come on stream. What we're looking at doing is a new atmospheric pipe still. 250,000 barrels a day coming in. We'll take the middle of that tower, hydro treat it there on-site, and get some diesel fuels coming out of Beaumont. So Beaumont will net increase diesel coming out of the refinery. And then the bottom and the top of the tower are going to be intermediate products to Baytown and to Baton Rouge, again replacing products that they're buying today. So not a lot of net increase in new product coming out of those, just lower cost. And again, given the advantage, 30% less than industry cost, because of all of these advantages, the utilizing existing infrastructure I talked about, and well in excess of a 20% return project. Paul Y. Cheng - Barclays Capital, Inc.: Jack, should we assume that the diesel or distillate increase in Beaumont is somewhere in the 30,000 to 50,000 barrel per day, based on what you described? Jack P. Williams - Exxon Mobil Corp.: Probably higher. Paul Y. Cheng - Barclays Capital, Inc.: Higher than that? Jack P. Williams - Exxon Mobil Corp.: Yeah, yeah, probably more like 60,000. Paul Y. Cheng - Barclays Capital, Inc.: 60,000? Okay. Jack P. Williams - Exxon Mobil Corp.: I mean, ballpark. I don't have the number in front of me, but something like that. Paul Y. Cheng - Barclays Capital, Inc.: And where – sure. Would that be all in ULSD, or that would it be a combination? Jack P. Williams - Exxon Mobil Corp.: It'll all be ultra-low sulfur diesel that'll be coming out, clearly, and yeah. Paul Y. Cheng - Barclays Capital, Inc.: I see. And that in terms of the other, say, debottleneck opportunity, 150,000 barrel per day expansion, what kind of timeline we may be talking about? Jack P. Williams - Exxon Mobil Corp.: Which project is that? Neil A. Hansen - Exxon Mobil Corp.: Paul, I assume you're talking about the debottlenecks at the other facilities. Paul Y. Cheng - Barclays Capital, Inc.: That's correct. Sorry. Neil A. Hansen - Exxon Mobil Corp.: So Baytown, Baton Rouge. Yeah. Jack P. Williams - Exxon Mobil Corp.: Yeah, it was not 150,000, Paul, it was just 50,000. Paul Y. Cheng - Barclays Capital, Inc.: Oh, it is 50,000. Jack P. Williams - Exxon Mobil Corp.: So we have 450,000 capacity today; Beaumont would be another 250,000; another 50,000 on top of that; and then over 750,000 total. And I'm rounding the numbers here, but over 750,000 barrels a day after Beaumont and these other attractive debottleneck projects. Paul Y. Cheng - Barclays Capital, Inc.: Okay. A final short one. Neil, I think earlier that you say that you will be on track to the $24 billion CapEx if we exclude the $1 billion you spent in Brazil recently. So is that means that we're going to be roughly, say, $25 billion for the year? Neil A. Hansen - Exxon Mobil Corp.: Yeah, Paul, our – and as again, subject to what happens in the fourth quarter. But our current outlook is – for the full year is $25 billion. What we've seen though throughout the year, fortunately, is some incremental opportunities to acquire additional acreage in Brazil. And that's roughly about $1 billion above what we thought we were going to get. And so that's where you get to the $25 billion. Again, that's heavily dependent on what happens in the fourth quarter. Paul Y. Cheng - Barclays Capital, Inc.: Sure. Thank you. Neil A. Hansen - Exxon Mobil Corp.: You're welcome, Paul. Thank you.

Next we'll go to Alastair Syme with Citi. Alastair R. Syme - Citigroup Global Markets Ltd.: Thanks for taking my questions. In the Analyst Day, Jack, you put out earnings expectation shots on both the Downstream and Chemicals. And I know they were the long term, but there were also numbers for 2018 and 2019. And I'm just sort of aware your run rating well behind these, both for 2018 and sort of the expected 2019 performance in both Downstream and Chemicals. Can you sort of help us with how much of this is macro and how much of this is unplanned downtime? Jack P. Williams - Exxon Mobil Corp.: Yeah, Al, so let me just say this. The market environment is very different than what we had. We assumed 2017 flat conditions. And in the Chemicals business very different. Well, actually Chemicals and Downstream both very different margin environment. But the underlying activity that we talked about on those projections is on track. That's why I was saying these milestones of these projects starting up. So the underlying activity that's driving these earnings results that we're – these earnings projections, earnings potential projections that we talked about in March are all there. As a matter of fact again, I think we're seeing a bit of upside. So don't know in terms of – can't give you any definite numbers in terms of earnings themselves, but I can tell you the activity is going well. Alastair R. Syme - Citigroup Global Markets Ltd.: So you would see it more as a macro then? Jack P. Williams - Exxon Mobil Corp.: Yeah. Alastair R. Syme - Citigroup Global Markets Ltd.: And on my follow-up, can you just talk around IMO? In particular, if you see scope for an emergence of compliant blends, particularly in the Asian region? Jack P. Williams - Exxon Mobil Corp.: I don't know if I can answer that question specifically. But I can just tell you that we're supportive of the timing. We think that the industry will be able to adapt. We think it's the right thing to do in terms of going from 3.5% sulfur down to 0.5%. And we're going to be ready. And we're going to be ready with a bunch of different options. So as I mentioned, we'll still have HSFO, we'll have a low sulfur fuel as well, we'll have a marine gas oil, and we'll have LNG. To the extent that some ships convert to LNG, we'll have that as well. And then also we have a lot of coking capacity that will be churning out some – destroying that distillate and churning – destroying that resid and churning out some high-quality distillate. So I think we're going to be ready. And we're looking forward to that environment. So I can't really tell you anything specific about what others are doing or what the markets are doing. Going to be hard to see how that – what the impacts are going to be on that overall. Obviously, the clean/dirty spread is going to grow. And we don't know how much and don't know for how long. So I think the industry is going to deal with it just fine. Alastair R. Syme - Citigroup Global Markets Ltd.: Thank you.

Next we'll go to Roger Read with Wells Fargo. Roger D. Read - Wells Fargo Securities LLC: Yeah, thank you. Good morning. Neil A. Hansen - Exxon Mobil Corp.: Hey, Roger. Jack P. Williams - Exxon Mobil Corp.: Morning. Roger D. Read - Wells Fargo Securities LLC: I guess the question earlier was asked about buying things or whatever. And you detailed in the fourth quarter some of the asset sales coming through on the Downstream side. I was wondering, in a market where oil prices have recovered, you clearly are focused on the investment side, but everything has to compete for capital. Do you see any acceleration potential in dispositions over the next couple of years? And particularly as the Upstream starts to transition with a greater component from the lower 48, if that makes it an easier decision to move forward on asset sales? Jack P. Williams - Exxon Mobil Corp.: Yeah, let me just – we kind of hinted at this and talked about it a little bit back in March and certainly in dialogue. I think we've all been having – we've been saying that we are going to be more active in terms of looking at our Upstream assets. And as we bring on – as you mentioned, as we bring on all these high-quality assets and invest in these new accretive volumes clearly we need to be looking at the other end of the portfolio and seeing what might be worth more to somebody else than it is to us, given where our portfolio is heading. So we are already more active and we'll continue to be more active in that area. What I can't give you is any specifics right now in terms of the timing, in terms of how those transactions, when those transactions may happen. Obviously, we need to have an active buyer as well as a seller. But we have had some – and if you think about what we've announced year to date with the Norway divestment that was last year and then Scarborough and the Rockies gas, that we have been active. And that activity is going to continue to ramp up. Roger D. Read - Wells Fargo Securities LLC: Thanks for that, Jack, and I appreciate the greater disclosure Exxon is giving. But I didn't really expect you to give me a list of projects that you were going to be unloading here. As a follow-up – oh, sorry. Just as a quick follow-up, the question about share repos was asked. But I was wondering since you mentioned debt had declined to $40 billion, lowest since 2015, I was just curious. Is there a debt goal, debt-to-cap, net debt, total debt number, recapturing the top credit rating? Any of that kind of drivers that we should think about in terms of where debt goes down the road? Neil A. Hansen - Exxon Mobil Corp.: Yeah. This is Neil, Roger. I'll take that one. We don't target a specific credit rating. We don't target a specific debt level. Again, I think the aim or the goal is to ensure that we maintain financial strength, financial capacity, so that we can act countercyclically. We can take advantage of investment opportunities regardless of the price cycle. But aiming or putting a specific target out there, we don't typically do that. But again, we already have a very – as you know, we have industry leading strength on the balance sheet. And then we want to maintain that, so we can take advantage of opportunities, but we don't target any specific debt level or credit rating. Roger D. Read - Wells Fargo Securities LLC: Okay. Thank you. Neil A. Hansen - Exxon Mobil Corp.: And we view it as a competitive advantage, Roger. I mean you can imagine it gives us a lot of capacity to use that balance sheet when we see accretive opportunities. Roger D. Read - Wells Fargo Securities LLC: All right. Thanks. Neil A. Hansen - Exxon Mobil Corp.: Yeah, thank you, Roger.

Our next question comes from the line of Rob West with Redburn. Rob West - Redburn (Europe) Ltd.: Oh, hi. Thank you for taking my question. I'd like to ask the first one about the comments you made earlier around your Downstream investments. And the question is, are you surprised how little some of your peers are investing in new either capacity or complexity at their refining base? And could you just make some comments about why you think that might be, if it is a trend that you are seeing? Jack P. Williams - Exxon Mobil Corp.: Yeah, I would just say, mildly, yes, surprised. But I don't really know why. I mean I think that's something you'd have to ask them. One thing I would like to say though, is as we think about refining investments, we're really not interested in kind of plain vanilla industry standard refining at an industry standard unit, that conversion capacity, that kind of thing. We're bringing proprietary technology and/or footprint advantages on all those projects we had. So they are all well in excess of what others might see on their potential refining investments. And I think that probably differentiates us. In addition to that, you look at some of the differentiated products we have coming out as well. So I think that may be a reason why. Rob West - Redburn (Europe) Ltd.: Okay. Thank you. Just second one would be on digital. And really the question is, what is your number one highlight in the digital space in the last 12 months? And the context for asking is, I've seen one of your peers talk about having 20 million data points a day at a new Gulf of Mexico platform. And I've seen one of your other peers just signed a big new agreement with a machine-learning company. Is there something that you'd point to in that space? Or would you say it's less active than peers there? Jack P. Williams - Exxon Mobil Corp.: Well, let me – Neil might want to weigh in on this one too, but let me just make a comment. I can assure you we are very active in this space. We have had a lot of discussions at the management committee level around all the things we're doing in digital. We are not rushing out to do a me-too type project in digital. But we are putting in the underlying infrastructure to give us advanced analytic capabilities. We are doing things like pervasive Wi-Fi in our facilities to where we can make our operators much more productive. We have real-time data feeding in from all our major pieces of equipment that's improving reliability. So we are – we don't – you're right. We haven't talked about it as much as some of our competitors, but we are very active in the space. All aspects of our business have big digital organizations in them, looking at all that opportunity. And that's coordinated with a central IT organization that's looking at the overall strategy. So very active, and we are seeing some bottom-line benefits for sure. Neil A. Hansen - Exxon Mobil Corp.: And maybe one example I can give. You look at what we're doing on the subsurface. And you can imagine over time how much seismic data we've collected as a company. And so one of the areas we're looking at is digitizing that. And again, with the idea of using artificial intelligence and big data to help us continue to look for resources. That's one specific example. But again, I think it's happening across the business. Rob West - Redburn (Europe) Ltd.: Thank you. Thank you for those perspectives. Neil A. Hansen - Exxon Mobil Corp.: Good. Thank you, Rob. I think we have time for one more question.

Okay. We'll take our last question from Jason Gabelman with Cowen. Jason Gabelman - Cowen & Co. LLC: Hey, guys, and thanks for squeezing me in at the end of the call. Neil A. Hansen - Exxon Mobil Corp.: Yeah, good morning, Jason. Jason Gabelman - Cowen & Co. LLC: Firstly, just on – yeah, morning. Just on the Brazil acreage footprint expanding here. Can you first remind us, of that $1 billion, how much has been spent year to date? And secondly on that, there haven't really been many updates on the Carcara development. Can you give us any updates that you have? Or how you're thinking about this project coming along, given not much coming from you or your partners in that project? Jack P. Williams - Exxon Mobil Corp.: Yeah. Let me handle the last part of the question, and maybe Neil could chime in on the numerics on the investments this year. On Carcara, we're working with Equinor on that, as they're operating that development. And again, we see that as a recoverable resource of more than 2 billion barrels of high-quality oil. We've had another on-block discovery that could increase that further. So it's looking good, continuing to progress. We're still talking, continuing to talk about what's the optimum development plan and timing on that. But we see it as very attractive. I think we both absolutely agree it's very attractive. And we see that as kind of being a 2023, 2024-type start-up, depending on a number of factors on the permits and when we get going there. But one thing I'd like to mention is that I talked about 26 blocks in Brazil. And all these are blocks we went after because we saw on seismic some attractive features that we wanted to look at a lot harder. The only thing we had in our outlook from Brazil that's been included in those earning projection outlook we talked about back in March is just the one Carcara. Everything else in Brazil is complete upside to the outlook we had. And we do see it as very, very prospective. We're very excited about the program now. We're probably going to spend the rest of this year, next year acquiring additional 3D seismic, interpreting that. Maybe 2020 before we're out there drilling new exploration wells. But we see they're very prospective. And we're very excited about the opportunities there. Neil A. Hansen - Exxon Mobil Corp.: Right. Maybe I can give you a little perspective on year to date. So again, with the acquisition of the Titã block, which was roughly 71,000 acres, we're now up to 2.3 million net. I think year-to-date approximate numbers will be – I think full year will be around $2 billion, which is again about $1 billion above what we had in plan. And Jack mentioned the 26 blocks that we're in. I think the other thing that's attractive is we operate approximately 66% of those blocks. And then most of them are under concession contracts as well. So a very attractive position. Jason Gabelman - Cowen & Co. LLC: All right. Great. Thanks a lot. Neil A. Hansen - Exxon Mobil Corp.: Great. Thank you, Jason, and thank you for your time and thoughtful questions this morning. We appreciate you allowing us the opportunity to highlight a third quarter that included strong earnings and cash flow performance, supported by improved operations and significant liquids growth. I'd also like to remind you that our Chairman and CEO, Darren Woods, will participate in our fourth quarter and full year earnings review. We appreciate your continued interest, and hope you enjoy the rest of your day. Thank you.

And that does conclude today's conference. We thank everyone again for their participation.