Exxon Mobil Corporation (XOM) Q2 2018 Earnings Report, Transcript and Summary

Thank you, and good morning. Welcome to Exxon Mobil's second quarter earnings call. By way of introduction, my name is Neil Hansen. I assumed the role of Vice President of Investor Relations on July 1. I look forward to interacting with each of you and discussing Exxon Mobil's performance and long-term value proposition. That will include ongoing efforts to improve transparency and increase engagement, which we'll continue with the call today. As you saw with the earnings release this morning and as we will discuss during the call, the second quarter results were well below market expectations. We'll review some of the factors that resulted in that deviation. Although challenging in some regards, it was also a quarter highlighted by significant progress on key near-term priorities, along with a number of notable milestones related to strategic investments across the Upstream, Downstream and Chemical business lines. These investments underpin our plans to increase long-term earnings potential and shareholder value as we outlined at the analyst meeting in March in New York. As we've previously announced, part of our commitment to increase engagement is participation in earnings calls by members of our management committee, including participation by our Chairman, Darren Woods, for the fourth quarter and full year earnings review. Joining me on the call today is Neil Chapman, Senior Vice President of Exxon Mobil. Neil oversees Exxon Mobil's Upstream business. After I complete the review of the quarterly financial and operating performance, Neil will provide his perspectives on the significant progress we made during the quarter and investments that will create long-term shareholder value. Neil and I will be happy to take your questions following a few 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 will now move to Slide 3 and start by summarizing a number of developments that influenced second quarter performance, specifically as it compares to what we experienced during the first three months of this year. The Upstream benefited from the higher liquids prices experienced during the quarter. The increase in our average liquids realizations was generally consistent with the changing markers, including the $7.60 increase in Brent and the $5.10 increase in WTI. Upstream production in the quarter was impacted by seasonally lower gas demand in Europe and scheduled maintenance, which was undertaken to support operational integrity. A 25% growth in tight oil production in the Permian and Bakken relative to the first quarter provided an uplift to volumes as we ramped up drilling activities and secured logistics capabilities in an area that will continue to see tremendous volumes growth. We also achieved a number of significant milestones on long-term growth plans in Guyana, Brazil and Mozambique, which Neil Chapman will discuss in detail later on the call this morning. In the Downstream, seasonal increases in demand and higher levels of industry maintenance resulted in stronger industry-refining margins in North America and Europe. A widening Brent-WTI Midland spread with Permian production outpacing logistics capacity also helped to strengthen refining margins in North America. We safely and successfully carried out a significant level of scheduled maintenance during the quarter to improve operations and strengthen our refining network, partly in preparation of the upcoming changes for the International Maritime Organization standards, related to the maximum levels of sulfur and marine fuels, which will go into effect in the year 2020. Scheduled maintenance had a significant impact on second quarter refining throughput and associated expenses. The strengthening of the U.S. dollar relative to the euro and British pound resulted in unfavorable foreign exchange impacts. In line with our long-term strategy to grow higher-value products, sales of retail fuels and lubricants increased during the quarter. In addition, we expanded our presence in key growth markets like China, Indonesia and Mexico. We also made significant progress on strategic projects in Beaumont, Antwerp and Rotterdam to increase the production of higher-value products, including premium ultralow sulfur fuels and Group II premium lubricant base stocks. While long-term demand fundamentals remain strong in the Chemical business, we experienced weaker margins in the quarter as improved realizations were more than offset by higher feed and energy costs. On the other hand, the successful completion of strategic growth projects contributed to higher sales. Slide 4 provides an overview of earnings for the second quarter. ExxonMobil's second quarter earnings were approximately $4 billion or $0.92 per share, up 18% from the prior year quarter. The growth in earnings compared to the second quarter of 2017 was primarily driven by the Upstream, moderated by a $0.50 - or 50% decline in Downstream earnings. Earnings declined by 15% from the first quarter of this year with lower contributions from all three business lines. I will start the more detailed review of our second quarter results with reconciliations of the financial and operating performance for each of the business lines relative to the first quarter of 2018, and starting first with the Upstream on Slide 5. Second quarter 2018 Upstream earnings were $3 billion, a $457 million decrease from the first quarter. Crude realizations rose nearly $8 per barrel or 13% versus the first quarter, while gas realizations were down slightly. Lower seasonal gas demand in Europe contributed significantly to a $180 million negative impact on earnings compared to the first quarter. Downtime, representing the impact on earnings from both lower volumes and increased maintenance spend, reduced earnings by $210 million, largely driven by scheduled maintenance in Canada. Other items, including higher exploration and production expenses, decreased earnings by $190 million. Finally, the absence of the first quarter gain on the Scarborough asset sale contributed to a reduction in earnings of $420 million. Moving to Slide 6 and a comparison of second quarter Upstream production to the first quarter of this year. Oil-equivalent production in the quarter was 3.6 million barrels per day. Liquids production was essentially flat versus the prior quarter, while natural gas was down 14% or 238,000 oil-equivalent barrels per day. Increased downtime mostly related to scheduled maintenance in Canada at Kearl, Cold Lake and Syncrude, negatively impacted production in the quarter. Lower seasonal demand in Europe accounted for approximately 85% of the change in volumes compared to the first quarter. Liquids growth in the quarter included a continued increase in unconventional Permian and Bakken production and the ongoing ramp-up of Hebron volumes, which more than offset natural fuel decline. Moving to Slide 7 and a comparison of second quarter Upstream earnings to the second quarter of the prior year. Second quarter 2018 Upstream earnings increased by $1.9 billion from the prior year quarter. Higher prices increased earnings by $2.4 million, driven by a $22 per barrel or 49% improvement in ExxonMobil's crude realizations, which was consistent with the change in markers. Lower volumes reduced earnings by $120 million, with unfavorable entitlement effects from the higher prices, partially offsetting growth. Downtime relative to the prior year quarter decreased earnings by $230 million, with impacts essentially evenly split between scheduled and unscheduled downtime. Impacts from the earthquake in Papua New Guinea was the largest single contributor to the losses from unscheduled downtime. Production in PNG reached full capacity in April, following the earthquake in the first quarter and is now consistently operating above original design capacity. All other items decreased earnings by $170 million, largely due to higher production expenses and increased exploration activity, primarily in Brazil. Moving now to Slide 8 and a comparison of second quarter volumes relative to the same period as last year. Oil-equivalent production in the quarter was 3.6 million barrels per day, representing a quarter-over-quarter decline of 275,000 oil-equivalent barrels per day, with liquids down 3% and natural gas down 13%. Lower entitlements resulting from higher prices reduced volumes, as did continued efforts to high grade our portfolio, with the largest impact versus last year coming from the divestment of our operated assets in Norway. Increased downtime, primarily for scheduled maintenance, also reduced volumes in the quarter with the most significant impact coming in Canada at Syncrude, Cold Lake and Kearl. The decline we experienced in the quarter was in line with our general expectation that base volumes will reduce by 3% each year. However, the more pronounced impact of decline on gas production, in part, represents an intentional near-term effort to focus growth on higher-value production. Thus, we saw a decrease of approximately 12% in U.S. unconventional gas volumes, reflecting minimal investment. This shift to value is also evident in the growth we saw in liquids, which was more than offset - which more than offset decline in mature assets as production in the Permian and Bakken increased compared to the same quarter as last year and production from Hebron continue to ramp up. Moving now to Slide 9, I will review Downstream financial and operating results, starting first with a comparison of second quarter performance with the first quarter of 2018. Downstream earnings for the quarter were $724 million, a decline of $216 million compared to the first quarter. Refining margins strengthened in North America and Europe, driven by seasonal demand; higher industry maintenance; and for North America, a widening Brent-WTI differential, contributing $630 million to earnings relative to the first quarter of the year. An increase in higher-value sales contributed a positive $50 million, including an increase in retail fuel sales with additional sites in the U.S., Belgium, Netherlands and Luxembourg and record quarterly Mobil 1 sales in the U.S. and China. Major plan turnaround activities at SAMREF, Gravenchon, Baytown, Strathcona and Beaumont significantly impacted second quarter results, largely driving the $620 million decline in earnings relative to the first three months of the year. This includes the impact on throughput and related maintenance expenses. Depreciation in the euro and British pound relative to the U.S. dollar negatively impacted earnings by $210 million. Moving now to Slide 10 and a comparison of current quarter Downstream earnings relative to the second quarter of the prior year. Downstream earnings for the quarter were down $661 million compared to the second quarter of 2017. Stronger refining margins in North America contributed to a $260 million increase in earnings, as we were able to successfully capture the benefit of widening regional crude differentials, primarily West Canadian and Permian. Growth in higher-value sales of retail fuels, again driven by an increase in the retail network in the U.S., Belgium, Netherlands and Luxembourg, combined with record quarterly sales of our flagship, Mobil 1 lubricants in the U.S. and China, resulted in a $100 million benefit to earnings relative to the prior year quarter. Downtime, including both volume and expense factors, resulted in a $620 million negative impact in quarter-over-quarter earnings. This included approximately $375 million from scheduled maintenance activities in Europe, North America and the Middle East to support operational integrity and to strengthen our global capabilities in advance from the change in IMO marine fuel standards. Planned turnaround activities were successfully completed at SAMREF, Gravenchon, Baytown, Strathcona and Beaumont. A majority of the losses from unplanned downtime were carried over from events that occurred in the first quarter, impacting earnings by approximately $245 million compared to the prior year quarter. These reliability incidents were obviously disappointing, however, repairs are now essentially complete and we are returning to full production. Significantly improved reliability is expected in the third quarter. The depreciation in the euro and British pound relative to the U.S. dollar negatively impacted earnings by $240 million. The absence of asset sale gains, mainly related to the sale of our Downstream Nigeria assets and retail assets in the U.K. and Italy in second quarter of last year, led to a relative decrease in the current year earnings of $130 million. Moving now to Chemical financial and operating results on Slide 11, and starting with a comparison of the current year quarter with the first quarter of 2018. Second quarter Chemical earnings were $890 million, a $120 million decrease from the prior quarter. Weaker margins negatively impacted earnings by $90 million as higher feed and energy costs outpaced stronger realizations. Earnings increased by $50 million compared to the first three months of the year as new assets in Singapore and U.S., combined with the absence of the Yanpet turnaround increased sales volumes. The depreciation in the euro relative to the U.S. dollar negatively impacted earnings by $50 million. Turning now to Slide 12 and a review of the $95 million decline in the current quarter earnings relative to the second quarter of 2017. Weaker margins resulted in a decrease of $210 million as higher feed and energy costs outpaced stronger realizations. Higher product sales improved earnings by $120 million and resulted from the startup of the Mont Belvieu polyethylene expansion and the addition of volumes from the Jurong Aromatics acquisition in Singapore, combined with stronger demand. Moving now to Slide 13, which provides an overview of key second quarter financial results. Cash flow from operations and asset sales was $8.1 billion, including $300 million in proceeds from asset sales. Second quarter CapEx was $6.6 billion, reflecting continued investments to support long-term growth plans. Including the acquisition of additional interest in the BM-S-8 block in Brazil and the purchase of PT Federal Karyatama, one of Indonesia's largest manufacturers and marketers of motorcycle lubricants. Free cash flow was - free cash flow after investments was $2.7 billion. We distributed $3.5 billion in dividends to our shareholders during the quarter, reflecting a 6.5% increase from the first quarter. Debt into the quarter of $41.2 billion, a slight increase compared to the first quarter, while cash declined slightly to $3.4 billion. Moving to Slide 14 and a review of 2018 sources and uses of cash. First half earnings, adjusted for depreciation expense and changes in working capital, combined with the proceeds of our ongoing asset sales program, yielded $18 billion in cash flow from operations and asset sales. In line with our capital allocation strategy, cash flow from operations and asset sales fully funded first half investments and shareholder distributions, while also allowing for reduction in debt, further strengthening our industry-leading financial flexibility. PP&E Adds and Investments and Advancements of $5.4 billion in the second quarter were slightly above the first half trend, again primarily due to discrete outlays in the quarter related to the acquisition of the additional offshore interest in Brazil and the previously mentioned lubricants acquisition in Indonesia. Shareholder distributions of $3.5 billion in the second quarter reflect the 6.5% increase in the dividend. Finally, the negative change in working capital seen in the first half of the year was driven primarily by inventory build due to the planned maintenance activities and the use of longer haul crudes as we leverage our integrated business to take advantage of favorable economics by exporting WTI-linked crudes to our refining networks in Europe and Asia. At this time, I would like to hand the call over to Neil Chapman, Senior Vice President of ExxonMobil, to provide some perspective on second quarter performance and the progress we have made towards the long-term growth strategy we outlined in the 2018 analyst meeting.

Good morning, everybody. Thanks for joining the call. Neil, the number one Neil, has provided the details. But I think it will be useful before I get into the progress versus our objectives that we laid out in March to put my perspective on what you just heard from Neil. This quarter was a low point in terms of volumes in the Upstream and Downstream. In the absence of some unknown or extraordinary events, volumes will steadily increase through the second half of the year. In the Upstream, there are two messages. First, lower volumes in the second quarter versus the first quarter were due to the seasonality of our gas business. So I think you all understand, it is primarily in Europe. That reduction was fully anticipated and was consistent with prior year's quarter-to-quarter variation. To our Investor Analyst Meeting in March, I said we anticipate our Upstream volumes this year will be roughly in line with 2017. Of course, that was, as I said at that time, absent of price and divestment impacts. Year-to-date, we've indeed seen an impact from price and from divestments. But on our full year basis is the major driver for reduction of our production forecast. When you combine this with the smaller impacts of unplanned downtime that we experienced in the first half, of course, with the Papua New Guinea earthquake being a significant part of that and the ongoing work to reduce our exposure to the lowest value U.S. gas business, we anticipate 2018 average volume will be around 3.8 million oil-equivalent barrels per day. And of course, again, that assumes no change in the current prices and no further divestments that impact volumes. Going back to reducing our exposure to the U.S. gas business. You saw the impact in Neil's discussion of volumes, but it did not to have a material impact in earnings. As I've commented previously, all volumes are not equal. There is a range of profitability on the volumes we produce. Our focus is on value, and we will continue to upgrade our mix and strengthen our portfolio. In other words, there's no structural change in the Upstream business from the perspective that I provided to all of you in March. Couple of comments on the Downstream business, downstream and refining business. As you have heard, we had a heavy turnaround in scheduled maintenance in the quarter. The cost and loss of sales from these scheduled outages was large and clearly had the most significant impact on the Downstream earnings. These are planned and were fully anticipated. However, as you know in the first quarter, we had significant losses due to reliability incidents in the Downstream. Unfortunately, the impact of these continued into the second quarter. We are not happy about it. We're all over it in terms of getting back to our expected reliability performance. We've thoroughly investigated. There's nothing systemic in these incidents. As of this month, these incidents that originated in the first quarter and carried through into the second quarter, they are behind us. Like the Upstream, there's no structural change in our Downstream business. We are on plan in terms of our strategy and the growth plans that we laid out in March. I will provide some details on that in the coming slide. My focus, of course, will be on the Upstream. So to begin with, a reminder of the five Upstream developments that I outlined at that time. These are key to our midterm growth plans. Our Deepwater projects in Guyana and Brazil, which as I said in March, carry significant upside potential; the transformational opportunity that we have in U.S. unconventional liquids, and of course, that's led by our very strong position in the Permian; and our low-cost LNG opportunities in both Papua New Guinea and Mozambique that we believe will play a key role in capturing the strong growing market demand. These key growth opportunities reflect the strongest portfolio ExxonMobil have had since the merger of our two companies in 1999. They are attractive across a range of prices. They will all begin to produce in the near to the midterm and contribute to our strongly growing Upstream earnings. Let me start with some comments on the - what I regard as really excellent progress we are making on the Stabroek block offshore Guyana. Estimated gross resources for the block, ending assessment of the latest discoveries, is now more than 4 billion oil-equivalent barrels. And that's up from the 3.2 billion that I communicated in March just 4 months ago. We made the eighth discovery on the block with the Longtail exploration well, which accounted over 256 feet of high-quality oil-bearing sandstone and establishes the turbo area as a potential hub of over 500 million oil-equivalent barrels recoverable. We're currently making plans to add a second exploration vessel offshore Guyana, bringing our total number of drillships on this Stabroek block to three. The new vessel, we plan that it will operate in parallel to the Stena Carron to explore the block's numerous, high-value additional prospects. The collective discoveries on the block to date have established the potential for now up to 5 FPSOs, producing over 750,000 barrels per day by 2025, the potential for additional production from significant number of undrilled targets and plans for rapid exploration and appraisal drilling. You may remember in the March meeting, I was outlining that we had three FPSOs in our plan and we were looking at a production level of 500,000 barrels per day, so it's a significant increase. With our ongoing exploration success, we also see an increasing development pace and the potential for increased scope. The Liza-1 Phase 1 project is progressing very well. Pre-drilling at the development well started in May with the Noble Bob Douglas rig. We have batch drilling wells for maximum efficiency, and we've completed the top hole sections on six wells to date and are now working through the intermediate hole sections. Conversion work on the FPSO Lisa Destiny, and that's in Singapore, of course, is progressing well. We remain on track for first oil early in 2020. Liza Phase 2 will be larger, 220,000 barrels per day FPSO. In June, we submitted a draft environmental impact assessment and the development plan for the government's approval. We're targeting start-up of that FPSO in 2022. The Liza-5 well successfully tested the northern portion of that field and along with the giant Payara field, will support the third phase of development to Guyana. Payara development will target FID in 2019, and we'll use an FPSO designed to produce - at this stage, we see an approximately 180,000 barrels of oil per day as early as 2022 - 2023, excuse me. The updated production profile reflects this increased pace of development from what I shared with you in March. We have a strong focus on partnering with the Guyanese and enabling local workforce and supplier development to support this growth and the success of Guyana's new energy industry. About 50% of ExxonMobil's employees, contractors and subcontractors are Guyanese. A number that will continue to grow as operations progress. ExxonMobil spent about $24 million, with more than 300 local suppliers in 2017. And we've opened a center for local business development in Georgetown, to promote the establishment and growth of small- and medium-sized local business. Let me turn to Brazil. Offshore Brazil, we completed the purchase of interest in BM-S-8, containing part of the greater than 2 billion barrel pre-salt Carcara field where development planning activities are rapidly progressing. This high-quality development has better than a 10% return at $40 a barrel Brent. With current drilling in BM-S 8, the Guanxuma well has encountered oil. The preliminary results are very encouraging and, of course, further analysis of this well nature is ongoing with our partners on the block, Equinor, Petrogal and Barra. In Bid Round 15, we were awarded eight deepwater blocks across Santos, Campos and Sergipe basins with exploration activity progressing. And in the fourth pre-salt bid round, we were awarded the Uirapuru exploration block. This is important for us. This block is adjacent to Carcara and we believe offers potential development and production synergies as we move forward. So that leads to our total acreage build offshore Brazil now being 25 blocks, a significant change from what we described in March. We are actively maturing drill well planning for multiple additional wells in the next two years. Looking at the U.S. We continue to grow our unconventional liquids. Our total net production of liquids unconventional in the U.S. is up 30% year-on-year. In the Permian, we brought over 50 new wells to sales in the quarter, resulting in second quarter Permian production up 45% in the first quarter this year. We now have 34 active operating rigs in the Permian, 17 in the Midland, 17 in the Delaware and six active rigs in the Bakken. On the completion side, we have 11 active completion and fracking crews in both basins in the Permian and three in the Bakken. We're actively expanding the wind terminal. This is the terminal, of course, that we acquired in late 2017 to accommodate more throughput. We've executed multiple contracts that will enhance pipeline capacity from the Permian to the Gulf Coast. We have more than secured liquids evacuation capacity to support growth through 2022. And our Gulf Coast refineries are already processing our production levels and more, capturing the benefits of disadvantaged feed cost. Additionally, we signed a letter of intent and it was announced in June with plans to develop a 1 million barrel a day long haul crude transport system that will connect the Delaware production to our world-class refining unit and chemical assets on the Gulf Coast. Finally, we've secured offtake for associated gas through 2020, and are in active negotiations for additional capacity. We have no concerns about evacuation capacity, both in gas and liquids for our Permian business. In liquefied natural gas, we continue to make great progress in Mozambique. The Coral Floating LNG project is progressing on schedule, and the fabrication of the hole is expected to start in the third quarter of this year. For the first phase of the integrated onshore development, the co-ventures have now aligned on two large LNG trains, which will each produce 7.6 million tons of LNG per year. Earlier this month, we announced that the development plan for the first phase has been submitted. ExxonMobil will lead the construction and operation of the onshore liquefaction on behalf of the joint venture. And our partner, Eni, will lead the construction and operation of the upstream facilities. We're targeting final investment decision in 2019, with the first LNG expected to be online, consistent with what I communicated in March in 2024. In Papua New Guinea, the recovery from the devastating earthquake continues. As you all know, our facilities stood the event extremely well, and operations have now returned to full capacity. This - the epicenter of this earthquake was right alongside - right adjacent to our facilities up in the Highlands. But our plant already is consistently operating more than 20% above the original design capacity, and we believe this forms a solid foundation to progress our expansions. Our expansion programs continue on plan. We're aligning on a three train 8 million-ton expansion with one new train dedicated to gas from the P'nyang of PNG LNG fields and two dedicated to gas associated with the Papua LNG project. So finally, I'd like to briefly mention another - a number of other highlights across the businesses that really underscore our progress on pursuing the growth plans that we outlined in March. In the Upstream, we've captured some additional key exploration acreage, Offshore Pakistan, where we signed an agreement to acquire 25% interest in Block G; and in Namibia, we completed the farming agreement to acquire 40% interest in the PEL82 license. Improvements are on track at our large mining operation at Kearl. We anticipate producing 200,000 barrels per day this year as I communicated at the Analyst Meeting. And of course, that's up more than 10% from 2017. In the quarter, we reached the Heads-of-Agreement with the government and our co-venture partner, Shell, on amended fiscals and production outlook and our gas venture in Groningen, Holland. Qatar petroleum farmed into our Argentina unconventional developments with an agreement to purchase 30% of the equity. Consistent with our focused shift towards U.S. liquids on the unconventional space, we divested some of our U.S. Rockies Gas assets in the quarter, representing around about 20,000 barrels per day oil-equivalent of gas production. As Neil mentioned in the lubes business, we've purchased FKT. That's a leading Indonesian distributor of lubricants, and it's included a new 700KB lube oil blend plant for blending and packaging of our products. In the fuels business, in the quarter, we reached agreements with Sonatrach for the sale of the 200KBD Augusta refinery and the three associated fuels terminals. In Chemicals, we announced yesterday that we've begun the operations of our 1.5 million-ton ethane cracker at Baytown. Of course, the associated 1.3 million tons of polyethylene facilities, which are on the other side of Houston at Mont Belvieu, are already in operation. They've been operating on purchased ethylene and are operating at full rates, in other words, at capacity. The cracker startup will enable us to back out these ethylene purchases and replace it with our own ethylene volume. In May, we announced the creation of a new joint venture with SABIC for a 1.8 million-ton ethane cracker with associated derivatives in polyethylene and glycol. The plan is this will be located in South Texas near Corpus Christi and close to the Permian Basin. Finally, we've completed the startup of our 230,000-ton Singapore Specialties in the Chemical business with production fully online. This contains the world's largest adhesive tackifier units and the world-scale halobutyl plant. So that's the comments. Neil. I'll hand it back to you, and we'll get into some Q&As.

Thank you, Neil. Neil and I will now be happy to take any questions that you might have.

[Operator Instructions]. We'll take our first question from Biraj Borkhataria with Royal Bank of Canada.

Neil, best of luck in your new role. And to the other Neil, thank you for returning the call. So my first question was on the downstream. So it does let you impact quite heavily for some unplanned downtime. Hopefully, that's behind you. But could you just talk about the maintenance time for the rest of 2018, whether there's anything significant in either chemicals or refining that we should be aware of? And I've got a follow-up on U.S. gas.

Thank you, Biraj. Good morning, and thank you for joining the call. And I look forward to interacting with you and talking more about ExxonMobil and our value proposition. So your question on maintenance. One thing that we can say is that we do expect maintenance during 2018 and 2019 to be a bit heavier than normal. Within that, you would expect to see some seasonality, so a bit heavier in the second quarter, coming down a little bit in the third quarter. It's difficult for us to get into specific - mention specific activity at sites. But we can say that given the IMO 2020 change, other maintenance activity that we plan to do over this year and next year will result in a bit heavier activity and then you'll see some seasonality in that. I don't know, Neil, if you wanted to add anything.

No, I'd just say I mean I think I mentioned in my comments, I said that we were at a low point in terms of volume in the second quarter. So with that, you'd anticipate the volumes increasing, but it will be a moderate increase and we have a - still a heavy turnaround schedule in the third quarter and not quite as large as the second quarter.

Great. That's very helpful. So second, just follow-up on U.S. gas and some of your comments there. But my question was really on timing. You talked about reducing your exposure to lower-value business. But the gas market has been supplied for - well supplied for a number of years now. So I was wondering what drove the decision this year to spend less? Is it just the fact that you're bringing other things into the portfolio or what's going on there?

This is Neil Chapman, of course. This is an extraction depletion business as we all know. And so as wells start to deplete, you have choices whether you want to drill more in gas or you want to drill more in liquids. And we believe we have this very strong advantaged position in the Permian, of course. This goes back to the Bass acquisition that we made a couple of years ago. I've mentioned many times since then that we've just seen continuous upside on that liquids opportunity in the Permian Basin. So we have choices to make, and we have priority calls. And what we are doing is we're prioritizing liquids production over gas production. Now when we are progressing our developments in the Permian Basin, it's really important to us that we do this in the most capital-efficient way, which typically will mean drilling a lot of wells on a drill pad and we drill several at a time and then we come in and we frac them up and then we start to evacuate the gas. And that results in, it doesn't result in a steady increase in volumes. It's a little bit lumpy. Some quarters, we get a big increase in volumes. Of course, we had a 45% increase in the second quarter versus the first quarter in the Permian. But sometimes, it's less so, and you're going to see that. And what we're seeing in the first half of the year as we start to focus on liquids and I would say deemphasize somewhat, and I must say somewhat, it's not completely gas business. You've seen - we've seen a lower amount of gas production in the second quarter, first half of the year, and that will be replaced and replaced by some more with liquids in the coming period.

Next we'll go to Doug Terreson with Evercore ISI.

My topic is performance improvement in the upstream. Meaning while it seems like whether because of a higher quality set of opportunities or improvement in process, that the outlook for return in Exxon's 5 key areas of investment is pretty positive. I think Neil made that case. Simultaneously, normalized returns on capital in E&P business declined significantly during the past decade or so. And it seems like there may be opportunities to create value through divestments, too. So my question is with your competitors divesting tens of billions of dollars of assets and either moving on to more productive areas or returning funds to shareholders through repurchases or whatever, also to their benefit, is there a philosophical reason why ExxonMobil hasn't been more assertive in this area? Or would you say stay tuned? So the question's about how you think about value-creation opportunities from underperforming parts of the portfolio?

Yes, Doug, this is Neil Chapman. Thanks for the questions, and you probably answered some of it in your question actually. You were referencing back to a comment that I made in March, I have no doubt, where I sort of indicated, and I didn't say it exactly this way, but it was sort of along the lines of watch the space. And what I really mean about that is we have some really strong value-accretive opportunities. And I commented at the time and I stand by this that they are the most advantaged perspective, the best set of opportunities we've had since the merger and the five, I just talked about the progress and I outlined them at the Investor Analyst call. Now - if you have a portfolio in the upstream, it's really important you don't just add. You look through - for the area, look for the businesses and the assets, which don't deliver the same amount of value. And I indicated at the time, we are looking very hard at that, and that is indeed the case. There is certainly no philosophical intent to hang onto assets that are underperforming. It's far from it, Doug. I can tell you that we are very actively looking at our portfolio. We are actively managing both ends of the portfolio. And I would add to that to tell you that, yes, I really believe strongly we have five great, great assets that we're progressing these big development opportunities. But I'm telling you, if something else better comes along, we're going to progress that as well. At the same time, we're actively managing the other side of our portfolio. And it's a focus that we had in this company now for the last - at least for a long time but even more focused, I would say, in the last 18 months and certainly in the last six months. So I'm not wanting to lead that we have anything coming immediately, but we are looking and we are very, very active. So I think I'll stop there.

Next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

Let me also welcome one Neil and - both Neils actually, and second Neil for getting on the call this quarter. Guys, I wonder if I could just start with a comment, and I've got two questions. My comment is the market, looking at the numbers, clearly didn't know or didn't expect the downtime. You guys obviously did. It would be extremely helpful if you could find some way of signaling to us that these kind of planned events are in your plan for the year to avoid the kind of volatility that we have quarter-to-quarter in your share price. So maybe something to think about. My two questions is, first of all, a follow-up to Doug Terreson's question on disposals. But Neil Chapman, I'd like to get very specific, if I may. There has been a lot of chatter from Qatar Petroleum about sanctioning the Golden Pass project and moving Upstream in vertical integration into onshore gas. So my question to the extent you're able to answer it is, is the Golden Pass sanction in your plans as it stood at the Analyst Day? And could you envisage yourself partnering upstream on your onshore gas production with Qatar Petroleum?

Yes, thanks, Doug. This is Neil Chapman, of course. And I'll make a comment on the downtime and the scheduled maintenance on refining. So I think it's a very valid point that you make. And of course, we're taking that into account. And Darren Woods talked about our drive towards increased transparency. And that's really our intent. And so we take your comment. And we will, of course, be looking at it. Okay, in terms of Golden Pass, we never - Doug, we're never going to say exactly when we're going to FID a project. It's a very clear that we're actively involved with our partner QP on that project. The place we're at right now is we've got some initial bids in. We are working those bids and working the opportunity. We will work that opportunity with our partner including the Upstream part of that business. There is an obvious opportunity in that space. I would tell you that we see the demand for liquefied natural gas continuing to grow. We see that the major buyers around the world increasingly look for diversity of supply. And so that's a good opportunity for the U.S. gas business. That's one of the drivers in our Golden Pass project. The other driver is, of course, we have a lot of assets already in place now, so we can leverage that. We think it can be - bring us an advantaged opportunity together. I know you want a specific answer of when we will FID. I can't give you one. All I'd tell you is we're actively working the project with our partner. And as soon as we're ready to FID out, we'll let the market know.

I was actually pressing a bit more on your potential to sell gas assets to QB, but I'll move on. My second question, if I may, is really more of a production growth question as it relates to the guidance you gave us back in March. You'll know it's 34 rigs in the Permian. And that appears to be ahead of your schedule. And Guyana is substantially larger, it seems, than what you provided to us in your guidance in March. I just wonder if you could talk to the - what was happening in terms of the momentum and potentially the scale. And if I can risk an add-on, maybe an update as to how much of Ranger you've actually included in your resource estimate at this point. And I'll leave it there.

Yes, thanks, Doug, and thanks for the questions. Look, I'll say what I've said before and I said in my comments I said in March, we're not focused on volume, we're focused on value. And what's really important to me is not the volume outlook for this business, it's the value. Not all volumes as is clearly obvious are created equally. Having said that, what I was trying to indicate in my remarks a few minutes ago, both in the Permian and in offshore Guyana is we have seen considerable upside in a short space of time. I mean, it's only three months, four months since I was up there describing both those opportunities to you. Yes, we are further ahead in terms of drill rigs than we had said at that time. And yes, we have had more discoveries in Guyana than we said at that time. We're going to develop them at the pace that we think is the best in terms of capital efficiency and the best in terms of value. I would tell you that we're not giving any different update in terms of our outlook right now in terms of a total versus what we said in March. But I do want to indicate, and it's clearly obvious from my comments earlier on, that we've seen considerable upside versus what I talked about in March. Going back to Guyana and Ranger, we have some more appraisal wells to go in Ranger. We know we have - we know, of course, from our discovery that we have a considerable resource. We're not at a position where we can quantify that right now.

Your next question comes from the line of Jon Rigby with UBS.

I just want to return back to the issue of performance improvement and actually related to the Downstream. I'm thinking back to the March investor update. It seems to me that the focus was pretty much on adding new capacity, new complexity to move the earnings dial. But would you recognize a comment that would say that over the last sort of 18 to 24 months is the underlying earnings performance of the Downstream, looks like it's been deteriorating, vis-à-vis competition? And I just wondered whether you felt that the performance of the business as it stands right now can deliver the kind of earnings performance you're expecting over the next 7 or 8 years just by adding the capital that you talked about, and whether this actually quite significant performance improvement also needs to be delivered by that business.

Yes, Jon, this is Neil Chapman again. And maybe I'll take that question. I understand why you're asking the question on underlying performance. And I commented earlier on that we're not happy with the reliability performance that we have seen certainly in the fourth quarter, first quarter - fourth quarter of last year, first quarter of this year and rolled over, of course, into the second quarter. However, I don't recognize at all your comment that this may be signaling some underlying deterioration of performance. It's far from it. We are absolutely all over these reliability incidents. We pride ourselves in this company as being the leader in terms of safety, in terms of reliability, in terms of cost performance in all segments of our business and I would say probably as much as anywhere in the reliability and in the performance of our Downstream business. So no, we do not believe at all. We think it is as robust and there is no change in that at all. The projects that we discussed in March, let me just - I'm going to correct you a little bit in what you said. I don't regard these as capacity projects. They will bring a little bit of additional capacity. But they are driven about getting more value out of a barrel of oil. That's what we are trying to do. And it's all about upgrading bottom of the barrel, low-margin products like fuel oil into higher-value products. And we highlighted three projects, I believe, when we were with you in March at Beaumont, at Antwerp and at Rotterdam. The Antwerp and Rotterdam expansions, we anticipate, will be up and online in the second half of this year. And that's consistent with what we talked about before. The only capacity that we're adding is capacity that will enable us to refine more light oil on the U.S. Gulf Coast out of the Permian. That is a terrific advantage that we have. We have a refining footprint on the Gulf Coast with some small modifications, particularly at Beaumont, will enable us to purchase - to process more of this high-quality light oil from the Permian, which gives much higher value as we process that versus processing other crude oils. I absolutely understand your concern in your question around reliability. I can assure you from Darren Woods through myself through all of that leadership of this team, we're all over the reliability issue. Nobody in this organization is going to be happy if we're not meeting plan in terms of reliability. We strongly believe that the big incidents that we really had in the first quarter that rolled into the second quarter, they are all behind us. But I can tell you, there's nobody, nobody is not focused on this. And I'm absolutely confident, we are absolutely confident, it doesn't reflect any underlying deterioration in the capability or performance of our refining assets.

Next, we'll go to Neil Mehta with Goldman Sachs.

Neil Hansen, welcome. Neil Chapman, thank you for making the time. We appreciate you doing this. Look, I want to start off on the Canadian side of the business. And getting the Kearl up to operational capacity has taken a little bit longer than expected. You outlined a credible plan at the March Analyst Day to doing that. So where do we stand on that effort? And then on Syncrude, there were some unplanned downtime here that you guys are working through. Lessons learned and where do we stand in terms of getting that to where you want to be?

Yes, let me start with Syncrude, if it's okay, Neil, and I'll come back to Kearl. On Syncrude, of course, we had this significant outage in June. We're back online partially. We are not at full capacity right now. Obviously, the operator, we're in close contact with them. They're anticipating a return to full production some time in September. This was a significant outage, big power outage, caused a lot of damage. We're back now. It will have an impact - did have an impact on volumes in the second quarter, maybe order of magnitude, 10 KBD, something like that. We'll be back online in September. On Kearl, what I said at the Analyst Meeting in Kearl is consistent and it is still the same today. We are targeting 200 KBD production this year. We are on plan to produce 200 KBD this year. We - in the second quarter, we had some planned outage at Kearl. That is behind us now. Actually, the peak daily volumes coming out of that facility are way in excess of the 200 KBD. But in our mining operation, the key to being successful is ongoing reliability of these operations. We communicated sometime last year, I believe, that we are making an investment in a parallel crusher at Kearl. And why we're doing that is because that's the most vulnerable part of this production. And we feel that once we get that crusher online, that will enable us to make a significant step change in production. We're targeting to get up to 240 KBD in the coming years. That's what I outlined before. We'll get 200 KBD this year. And that's really the outlook on that facility. I mean, I hope it answers your question.

No, it does. And the second question, Neil, is more of a philosophical question. You've been spending some more time on the road, which we appreciate. And Exxon has got a unique capital spend strategy. There are a lot of companies that are shifting into harvesting mode right now and restraining capital. And your firm is leaning in and making investments, which should be ROC-accretive. As you talked to the investor community, what's been the initial feedback that you've gotten? And how has that sort of shaped the way that you want to communicate with the investment community?

Thanks. And that's a good question. Let me - this is Neil Chapman again. I'll start, and maybe, Neil Hansen, you can add some perspective on cash allocation. The way we look at it is this is if we have value-accretive opportunities that are robust over a wide range of prices, that's the best way to add value to the shareholder. And that is why we have our investment program. And that is why we have the capital expenditure profile that we laid out with all of you, not just at the March meeting. The reason we're doing this is because they're value-accretive businesses, robust over a range of price scenarios. We think that's in the best interest of the shareholders. And remember, I mean, everybody knows this, this is an extraction depletion business. If you don't invest in the Upstream, if you don't invest at all, you've probably got a 6% decline across the business. So it's very important you invest. But it's not just about adding capacity. It's about adding quality capacity. I don't know. You'll have to ask our competitors why they are not investing in new projects. All I can tell you is we have very, very good projects, the best that we've had since the merger. And what I wanted to do, what we wanted to do and Darren wanted us to do is to be very transparent with the investment community on what those projects are, be very transparent in terms of why we're investing in them. We believe they are very value-accretive. And at the March meeting, we even outlaid where we saw the impact that would have on our financial results going forward. I don't know, Neil, have you got anything to add?

Yes, Neil, I will say that the feedback we're getting from investors, both formally and informally, is that they're pleased with the capital allocation strategy that we're undertaking, in great part because what Neil just said. So just to reaffirm our priorities for cash, first of all, is, as Neil said, we're looking to invest in projects that are accretive, projects that will create long-term shareholder value for our - over the long term. And if you look at what we showed you at the Analyst Meeting in the Upstream and Downstream, we expect those projects at $60 a barrel to generate 20% return and in the Chemical, 15% return. So as Neil said, this is a set of portfolio opportunities that is probably the best we've had since the Exxon and Mobil merger. So that's our first priority. And again, the feedback we get from investors, they generally support that. Now after we make those investments, we're going to continue to pay a reliable growing dividend. As we mentioned earlier, we increased the dividend by 6.5% in the second quarter. Following dividends, we'll continue to prioritize our balance sheet. We want to make sure that we maintain a strong balance sheet, that we have the financial flexibility we need to take advantage of opportunities. And then to the extent that we have cash remaining after those priorities are met, we'll distribute cash through buybacks. We tend to view the buyback program as a flywheel. So really nothing has changed in terms of that capital allocation strategy. And as I mentioned, as we interact with investors both formally and informally, they reaffirm that's exactly what they want us to do.

Next question comes from Phil Gresh with JPMorgan.

Thanks for the color and the refreshed guidance on the Upstream production for the year. It sounds like there's several different variables you're talking about here, Neil. Could you break down - I mean, it looks like the guidance is basically like a 4% to 5% decline now on a year-over-year basis. Could you give a little break down between those components, how you would allocate that? And then as we look at the improvement you're expecting for the second half of the year, just to clarify, is it basically Canada and Papua New Guinea running better? Or are there other things we should be thinking about?

Yes, I mean, listen, I mean, obviously getting Papua behind us has been important. We've had great success at Hebron, which is obviously one of the newest facilities we brought online. And that is continuing to outperform our planned expectations. I would say the biggest growth that we're seeing right now in terms of liquids, of course, is what's happening in the Permian. And some questions earlier on from Doug on that on the number of drilling rigs, and I did say that we are up 45% just quarter-on-quarter. And I think that's indicative of what we're seeing there. Not all volumes are alike in the unconventional liquids space. I mean, I made that point many, many times. I think people tend to draw a broad brush across the whole of our Permian and unconventional and see it as absolutely the same everywhere. I can assure you, it is not. There are more - there are plays that are more productive. There are plays of different quality of oil that are easier to extract and lower cost. We are very, very happy with what we sit on right now. So I would say the largest increase we're going to see through this year is most likely going to come from the Permian. In terms of putting color on the number that I outlined, I feel it's very important to explain our volume outlook. And again, I really want to make a point, and I will make this over and over again and you'll get bored of me saying it, but volume is not my focus. It's not our focus. Value is our focus. But I understand the interest in volume. And that's why I elected to give you this outlook for 2018 of 3.8 million oil-equivalent barrels. I don't see that as a material change from what I outlined in March, I do not. Because the vast majority of the difference comes from what I said before, which is the price impacts on entitlements, which in our business has been quite significant year-to-date, and some divestment impacts. That is the majority of the difference between when I said we will be in line with 2017 versus this 3.8 million number. The other two components are - I'm just not going to get back the production that we lost to Papua New Guinea in the first half of the year. I mean, some of this unplanned maintenance, we're not going to get it all back. And so that's going to impact us for the year. It's not a big deal, but I think it's important to highlight to you what it is. And that's why I wanted to be quite specific. But I think the only part of this which again is really a very small amount in terms of volumes, and it's not a lot in terms of earnings this year at all, is this movement, this pivot that I did indicate in March and I'm reinforcing now from gas to liquids in the unconventional space in the United States. We purchased XTO, it's a dry gas business. Everybody understands that. And we've pivoted towards liquids. And we're going to continue to pivot towards liquids because it's a more profitable business for us. And what's really, really important to us in this unconventional space is that we can leverage this unconventional experience and capability of the XTO company that we purchased with ExxonMobil's Upstream development company, who are very skilled in taking on large projects. I mean, obviously we've seen at Sakhalin, we've seen at Papua New Guinea. We saw it in Qatar. We've seen it in lots of different places, the combination of having great expertise and capability on major projects. And let me tell you, the Permian liquids is a major project. It's not a lot of small activities. It's a fully integrated major project. Combine that with our unconventional capability, then I feel like we're in an extremely strong position to develop a high-quality resource. And so that pivot from gas to liquids is really important, not just for the long term but for the mid-term of this business. I would tell you their production profile, I know everybody wants to see a continuous growth quarter-on-quarter. I'm telling it's going to be lumpy. Because the way we are going to do this is we are going to do it in the most capital-efficient manner we can. If that means drilling a whole bunch of wells and then just drilling them and fracking them six months later because that's the way of being capital-efficient, we are going to do that, I can assure you. So it's a little lumpy and it's what we've seen in the first half of the year now. It's my long-winded answer to your question, Phil. But we've seen a dropoff in gas as we've not reinvested as much in the gas business. We've put more of that investment in the liquids in the Permian. And obviously, we would anticipate seeing the results of that in the coming years.

I appreciate that. My second question is just around the CapEx in the quarter. You called out some M&A spending there. Just want to get a refresh on your thoughts on capital spending for the full year. And if possible, if you could call out how much of that was the one-time acquisition spend and if any of that acquisition type of spending bleeds over into the third quarter based on some of the activities that you've been undergoing that may not have closed. Just to - I think people may have been a little bit surprised by the spending number. But obviously, there's some specific activities you had underway.

Yes, this is Neil Hansen. I think year-to-date, for the first couple of quarters, we're sitting at about $11.5 billion of CapEx. And I think we indicated at the Analyst Meeting that the full year outlook for CapEx is $24 billion. So there's no changes at this time in that number. As you mentioned, sometimes this comes in lumpy, especially as we make acquisitions. And we did have those two discrete outlays in the second quarter. In addition to those two items, as Neil mentioned and consistent with the Permian story, is we are seeing an increase in capital activity out in the Permian. But the plan is really flexible. It depends on timing. So these things can happen in waves during a quarter. But again, no change in plan for the full year.

Yes, I think that's right. I mean, there's no change signaled in what we said before.

Could you provide the M&A spend that was in the quarter?

No, I don't think we want to provide specific commercial terms for those two acquisitions.

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

I guess you made the comment earlier, Neil, about creating value more so than thinking about production growth. Can you give us an idea, given the intensity of activity in the Permian today, the growth profile laid out on Slide 19, when the Permian becomes more of a value-add or a cash flow provider as opposed to a cash flow consumer? Or thinking of capital intensity right now, it clearly would be running underneath the overall Upstream business, when that might flip to the other side.

Yes, it's a good question. And honestly, I don't - Roger, I don't want to get into the specifics in terms of just the Permian. Having said that, I mean, I think you can work the math yourselves. You get up to a certain volume profile and it becomes cash additional rather than taking cash away. That's really important. We said we'd have cumulative cash flow at the analyst call of over, I believe, $5 billion between '18 and 2025. That was the outlook we gave at that time. There's no change in that. But I do want to point you back to that volume curve that we showed earlier on. It's been called the green wedge in the industry. But you can see where we are on that green wedge. And I think it's just illustrative of we are on plan. And I've indicated that we are optimistic about achieving that plan and frankly some more. So I really don't want to give you a timing and say by 2021, 2022 or 2019 that we are going to be cash positive in there. I don't think that adds a lot of value, albeit I understand what you're saying. What I would tell you though is don't forget the value proposition that we described on the Permian to the investment community. Yes, this is an absolutely foundational part of our earnings growth, financial growth plan, value growth plans in the Upstream. It is also very, very important for the Downstream business. I talked earlier on about our ability to process this light crude and how we see that giving us a distinct advantage in margins over the average of industry because of the facilities. We decided, and we made it clear back in March, that we will get engaged in the connectivity between the Permian and our Gulf Coast refining and chemical assets. In other words, we're going to participate sometimes with equity plays in the logistics. We bought the Wink terminal, we've announced that we're talking about a long-range crude pipeline where we'll have equity. I think what's really important here is that everybody understands being on that end-to-end value chain gives us a significant advantage. Now we've all seen the disconnect in Midland versus Cushing, in Midland versus the Gulf Coast on crude in the last quarter. And of course, a lot of that's driven by - we believe, driven by a tightness on the evacuation capacity of the industry. But if you're processing that crude, you're buying that crude at low value as well, which we just move that value from the Upstream into the Downstream. And when we do that, of course, we're getting more NGLs which our chemical companies benefiting from it. So I think different from most of the competitors in the Permian Basin, that value proposition on the integrated value chain is going to become increasingly important, not just in the Upstream. But we anticipate you're going to see that in the Downstream results. And obviously, the fact that we are making significant Chemical investments, which is all about processing the NGLs, primarily ethane, of course, is another indicator of what we're achieving. So yes, I mean, I know you want an answer on exactly on the cash flow. But I'm going to stay neutral on that. I'm going to tell you no change from what we told you before.

I appreciate that. We've got to try, right? Nice segue for Chemicals. In the quarter, obviously you cited higher feedstock cost, energy cost as a negative for the margins. I was just curious, does that - is that something that looks transitory? Or we should think of that as tied to kind of oil and naphtha prices as that works across maybe some of the global feedstock? Or do you see it as this is what prices have done, and thus this is something that we're just - we need to consider in our forward look for the Chemicals business?

I think you should see it very simply as chemical feedstock is primarily based on a barrel of crude oil. And as the crude oil price goes on, as these processes are through the Chemical business has to pass on that increased price, in other words, low margin to the industry - to the chemical industry. So if you go back in history and look at the chemical business during a period, and I'm talking about the industry now, not just ExxonMobil, if you look at a period of rising crude oil prices, chemical earnings tend to lag. In a period of a falling prices, chemical earnings tend to deliver much more. And it's all about the lag in the industry. Now what is different about our footprint is the price of chemicals, primarily petrochemicals, typically polyethylene plastic, which is the bulk of our business, of course, that is set by crude oil and naphtha price in Asia Pacific because that is what sets the majority of the polyethylene feedstock, which is naphtha-based in Asia. Our Gulf Coast refineries are processing largely ethane, which is coming out of the Gulf Coast. So when there is a big disconnect between the gas and crude price. And obviously, you've seen your Henry Hub gas price has barely moved, but the oil price has gone up significantly in the first half of this year, that is a benefit for anybody who's processing U.S. ethane into chemicals and capturing the price that's been set by crude oil. We've just started up our 1.5 million ton ethane cracker in Baytown. I love the timing of that. It's up now. And we're getting going on that. But also our existing crackers at Baytown, Baton Rouge and Beaumont are processing a heavy percent of ethane, which really captures the way I always like to describe it is this gas-to-crude spread. And when the gas-to-crude spread goes up, then chemical businesses that are processing ethanes and NGLs in North America are going to benefit from that. So one part of the answer to your question is there is a lag in the industry with rising feedstock prices. The other part is if you can capture the benefits of that crude-to-gas spread, obviously that's an advantage in the industry. And quite frankly, Roger, that's why a lot of people are investing in crackers on the Gulf Coast.

Our next question comes from Paul Cheng with Barclays.

Welcome, Neil, the Neil, VP on IR. A couple questions, if I may. Neil, for Qatar, any update you can - I mean, that's probably the most profitable Upstream business that you have today. For the LNG, the government has been talking about expansion. We heard some of your competitors, they're talking that they may come to a conclusion by the end of this year and early next year. Is there any update that you can provide? And also along that, I think that most of your existing operation, they have a 30-year contract. And some of the early ones that come onstream, say, back in the year 2000, those will be coming up for renewal pretty soon. Is there any update you can provide?

Neil Chapman, Paul. Thanks for the question, and thanks for recognizing Neil's first time on the call. Frankly, the short answer to your question is no, we don't have any update. I think the more expansive answer to your question is we've really got a terrific reputation and relationship with the Qataris. It's been a really important part of our portfolio as you just have highlighted for a long time. And we fully expect and we hope it will be a considerable part of our portfolio in the future. We're well aware of what the Qataris have said publicly. We're well aware of what our competitors have said in terms of expansion opportunities in that North Field. I don't like to talk about our ongoing discussions until we have something public. I don't think it's fair on the resource holder. I don't think it's fair on the competition. But I fully understand why you would like to know. In terms of extension of the licenses, unfortunately, my answer to your question is the same. It would be unfair to talk about our ongoing discussions with QP and the Qataris. Of course, we're talking about both with the Qataris. And I'm sure they would tell you the same thing. Our intention is to continue to maintain a very robust business that brings maximum value to the nation of Qatar, but of course, is beneficial to our shareholders. And I know, Paul, you wouldn't expect me to say nothing else. But I'm sorry, I really don't want to get into the details.

Okay. So maybe let me try a different question that perhaps that I have some better luck. Permian and Bakken, you've been doing some pretty long natural well, 12,000, 15,000 feet. I believe that they must be already in production. Is there any kind of data points that you can share?

Well, yes. And I know there's great interest in the length of these laterals. And you know what - and I've heard comments in the industry. And frankly, I've heard comments from the investment community on many occasions about saying, "Well, are these long laterals really beneficial? Are they more capital-efficient? Are they more productive? Do they get more out of the resource base than a shorter well?" Look, the reality is all unconventional space, all unconventional liquids are different, meaning that in some occasions, yes, it absolutely makes sense based on our experience to drill longer laterals. It's a capital-efficient way. It's the best way of extracting the resource. And yes, we do have some in terms of where we can assess the production rates. And we're very comfortable with what they've done. In fact, they've been very positive results. But I do want to caution you, it doesn't mean to say that we're going to drill 3-mile laterals everywhere. We're going to drill the lateral length based on the maximum recovery and the best capital efficiency of that resource base. It is really important, I believe, for people to understand that not all of this resource is the same. So I believe our technology is advantaged. I believe that we can drill these long laterals because we have the technology advantage to be able to do that, some can't. What's really important in the Permian is does your acreage allow you to drill these long laterals? If you do not have contiguous acreage, in other words, if you have acreage that's a mile square or a 2 mile square, you cannot drill a 3-mile lateral. You don't have the capability to do it. The acquisition of the Bass acreage, Poker Lake and in the Big Eddy have been really important because it gives us that opportunity to drill those longer laterals. And really, Paul, I would really encourage you to think of it that way. It would be, in my opinion, a significant mistake to try and generalize that resource base. And I would tell you, not just between the Bakken and the Permian or the Delaware and Midland but even within those basins and even within the multiple horizontal plays. Because as you're well aware, there is multiple plays, and we will extract that resource depending on the quality of that resource in different ways. And I know I sound like a little bit of a squeaky record on this, Paul. But that really is what we believe strongly.

No, absolutely. I mean, we fully understand it's very different, maybe even from session-to-session sometimes. But I guess, the question then that in the - in your - at least in your acreage position in the Permian, do you foresee that, that 3-mile lateral will be a regular or the average that you're going to push for that, let's say, the [indiscernible] or that is only a small session of your asset in the Permian that you think that is advantageous?

Yes, I mean, I would position the way I see it as a tool in our toolkit. That's the way I look at it. It's a tool...

And technically, that you have proved you can do that?

We've just not proved that we can do it. What's really important here is if you look at the amount of resource that's extracted out of the unconventional space - and again, it's very different from play-to-play. But it's a relatively small percentage of the resource is actually recovered. I mean, you'll see the industry talk about it. And I won't tell you what our numbers are. But 8% to 10% of the resource is recovered in an unconventional play. If we can extract more than 8% to 10%, you can understand the potential value for us in that. And so it's not just about the length of the lateral, it's about how much resource you can recover from that rock. That will arguably drive the economics as much as how much resource and how quickly you get the resource. There are statistics, everyone sees them, they are public data in terms of how quickly and what the production rates are from these wells. And I know some players in the industry "with great gusto" that they're getting a lot of early production and a lot of volume out of the wells initially good. Yes, good, I want to get the maximum volume out of these wells over the life of the wells. And so I am less interested in the early production rates. I know people in the industry are - do seem to be interested in that. I am not. I'm interested in the maximum recoverable resource in the maximum or in the most capital-efficient way.

Sure, that's the way to manage it. Neil, can I just sneak in a really quick one. In Guyana that you're talking about 4 billion barrels, is that 4 billion barrel of oil or 4 billion barrel of oil and gas? And if it is the latter, what's the percent of oil?

It's a 4 billion barrel of recoverable resource of oil equivalent. I mean, again I'm not going to give you a number in terms of oil and gas here. Well, to make sure I'm sure, you're talking about Guyana here?

That's correct.

Sorry, I missed the first part. Yes. And so it's primarily oil. Currently, what we're doing with the gas is it will be the - at least the plan currently is for the most part to reinject it to help recovery. We are in discussions with the state around putting some of that gas onshore for power generation, early stages on that. But what we're talking about is recoverable resource. I won't give you a number, Paul. But I will tell you it is primarily oil. It has relatively a low gas content.

Our last question will come from Theepan Jothilingam with Exane BNP.

I've just got two. Firstly, as you think about delivering these mega projects, could you talk about how you mitigate for the risk of cost inflation, particularly an up-cycle for the commodity? Are you thinking about procurement in a different way for this cycle? And the second question was just outside Guyana, could you perhaps outline the areas of interest in the second half in terms of Exxon's exploration program?

Yes. And Neil Chapman here. I would say in terms of exploration program - and of course, we're a global player. I mean, I would highlight Cyprus. We've been quite clear on Cyprus that we anticipate drilling two wells in Cyprus in the fourth quarter of this year. And that is on plan. Of course, we've made a significant investment in Brazil. We won't be - it will be more in terms of acquiring seismic on those blocks in this year if you're looking for this year. And we'll be drilling some exploration wells on these prospective blocks coming in 2019. What was the other part of the question? I forgot.

Yes, I was just wondering about cost inflation, what you're seeing. I mean, you've clearly got some great projects and you're improving things, I think, on the capital efficiency side. But is there a risk you might actually face cost inflation in a higher oil price environment?

Well, there's always a risk. I mean, I think there's always a risk. But obviously, our objective is to be the most efficient, you'd understand that. Let me just talk about the Permian for a second because the Permian is really important. And I've heard a lot of discussion around cost inflation there. And of course, the potential exists for high intense activity in a local area to end up with cost inflation. It's one of the areas which I really believe we have an advantage. Because we have such a large position in the Permian, it is allowing us to establish long-term contracts. And I think what's important on these long-term contracts, it's not just about drilling rigs, it's not just about fracking crews. It's about what you do with sand, how you can get sand in. It's about what you do with power and how you get power in. It's about what you do with the recovered water. It's about logistics and evacuation. So we look at all of that. We believe that having the scale that we have is allowing us to mitigate more than anybody else cost inflation in the basin. I've heard discussion around cost inflation in the Permian Basin in recent months. We have not seen a lot of it. And the reason we haven't seen a lot of it is because we're leveraging our long-term position with the partnerships that we have established. I think going forward, obviously it's absolutely on our minds in terms of how would we mitigate that potential inflation if it really goes on. And that could be in terms of how we purchase power or do we produce power? It can be in do we mine our own sand? It can be in lots of different areas. I would also tell you that if I go back to Guyana, and of course, that's a high intense activity for us right now, we're being very careful in the design of these ships. The resource space is quite similar across all these exploration blocks. And what that allows us to do is, using an old ExxonMobil term, of design one and build many. And so what I think you have to do in this environment is you have to look for ways to structurally offset the potential of inflation. Do not wait until it hits you. And that's been our message to our organization. We want to see where we have a structural advantage. It's built into the appropriation. And each of the assets that we are building, we ask our project organization and the business all the time, demonstrate to us how you're going to offset the potential of inflationary pressure. Thanks for the question.

Thank you, Theepan. To conclude, thank you for your time and thoughtful questions this morning. We appreciate your continued interest in ExxonMobil.

And that does conclude today's conference. We thank everyone again for your participation. You may now disconnect.