Earnings Call: Q3 2016

Oct 28, 2016

Good day, and welcome to the ExxonMobil Corporation's Third Quarter 2016 Earnings Call. Today's call is being recorded. At this time, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. Jeff Woodbury. Please go ahead, sir. Thank you. Ladies and gentlemen, good morning, and welcome to ExxonMobil's 3rd quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement shown on Slide 2. Turning now to Slide 3. Let me begin by summarizing the key headlines of our 3rd quarter performance. ExxonMobil earned $2,700,000,000 in the 3rd quarter. Corporation continues to deliver solid cash flow despite a challenging business climate. Cash flow results are underpinned by integration benefits from our Downstream and Chemical segments. ExxonMobil's diverse product portfolio and flexible integrated manufacturing platforms remain a distinct competitive advantage through the business cycle. We maintain a relentless focus on business fundamentals. While we continue to capture market savings in the current environment, we also remain resolute in our drive to implement long term structural improvements across our integrated businesses. We are well positioned to create value in any operating environment. Finally, as I'll share with you today, the corporation continues to deliver on its operating and investment commitments. We are effectively progressing selective, strategic investments, while maintaining our steadfast commitment to safe, reliable operations. Moving to Slide 4, we provide an overview of some of the external factors affecting our results. We saw modest global economic growth in the Q3. While the U. S. Economy improved relative to the first half of the year, growth rates slowed in China and remained soft in Europe and Japan. Food oil prices were largely flat, although volatile, whereas natural gas prices strengthened on average compared to the Q2. Global refining margins decreased as production continued to outpace demand and chemical commodity product margins remained strong, while specialty margins held relatively flat. Turning now to the financial results as shown on Slide 5. As indicated, ExxonMobil's 3rd quarter earnings were $2,700,000,000 or 0 point 6 Corporation distributed $3,100,000,000 in dividends to our shareholders. CapEx was $4,200,000,000 down 45% from the Q3 last year, reflecting the corporation's capital discipline and strong project execution. Cash flow from operations and asset sales was $6,300,000,000 and at the end of the quarter, cash totaled $5,100,000,000 and debt was $46,200,000,000 The next slide provides additional detail on sources and uses of cash. So over the quarter, cash balances increased from $4,400,000,000 to $5,100,000,000 Earnings adjusted for depreciation expense, changes in working capital and other items and our ongoing asset management program yielded $6,300,000,000 of cash from operations and asset sales. Uses of cash, including shareholder distributions of $3,100,000,000 and net investments in the business of $4,200,000,000 Debt and other financing increased cash by $1,700,000,000 Moving now to Slide 7 to review our segmented results. ExxonMobil's 3rd quarter earnings decreased $1,600,000,000 from a year ago quarter due to lower upstream and downstream results. Corporate and financing costs were approximately flat to the prior year quarter, although below our guidance, which remains at $500,000,000 to $700,000,000 on average over the next few years. In a sequential quarter comparison, shown on Slide 8, earnings decreased by $950,000,000 on stronger results in both the upstream and downstream segments, as well as lower corporate charges. Turning now to the upstream financial and operating results starting on Slide 9. 3rd quarter upstream earnings were $620,000,000 down $738,000,000 from year ago quarter. This result was driven primarily by lower realizations, which decreased earnings by $880,000,000 Food prices declined nearly $4 per barrel and gas realizations fell by $1.13 per 1,000 cubic feet. Favorable and sales mix effects increased earnings $80,000,000 and all other items added $60,000,000 driven by lower operating expenses. Moving to Slide 10. Oil equivalent production decreased almost 3% compared to the Q3 of last year, totaling just over 3,800,000 barrels per day. Liquids production decreased to 120,000 barrels per day as growth from projects and work programs was more than offset by impact of field decline and downtime events, most notably in Nigeria due to third party impacts. Natural gas production, however, increased 77,000,000 cubic feet per day as new project volumes were partly offset by divestment impacts. Turning now to the sequential comparison starting on Slide 11. Upstream earnings were $326,000,000 higher than the 2nd quarter. Improved realizations increased earnings by $240,000,000 Crude realizations decreased by $0.30 per barrel and gas realizations increased about $0.55 per 1,000 cubic feet. Unfavorable volume and mix effects reduced earnings by $40,000,000 All other items increased earnings by $120,000,000 benefiting from reduced operating expenses and favorable foreign exchange effects. Moving to Slide 12. Sequentially, volumes decreased 146,000 oil equivalent barrels per day or almost 4%. Liquids production dropped 119,000 barrels per day from downtime events, entitlement impacts and field decline. Natural gas production decreased 161,000,000 cubic feet per day as lower seasonal gas demand and reduced entitlements were partly offset by project growth and increased volumes from U. S. Work programs. So moving now to Downstream results starting on Slide 13. Downstream earnings for the quarter were $1,200,000,000 a decrease of $804,000,000 compared to the Q3 of 2015. Weaker refining margins reduced earnings by $1,600,000,000 Favorable volume and mix effects, mainly from lower maintenance activities, improved earnings by $170,000,000 Other items, including lower operating costs, reduced maintenance expenses and asset management gains increased earnings by $580,000,000 As announced in the Q1, Imperial Oil is selling approximately 500 retail service stations in Canada. To date, more than 40% of the e stations have been converted to the branded distributor model, resulting in an earnings impact of $380,000,000 in the quarter. Turning to Slide 14. Sequentially, downstream earnings increased $404,000,000 Weaker margins reduced earnings by $330,000,000 Favorable volume and mix effects, mainly from lower maintenance activity, increased earnings by $240,000,000 All other items added a further $490,000,000 mostly from asset management gains and lower expenses. Moving now to chemical results, starting on Slide 15. 3rd quarter chemical earnings of $1,200,000,000 decreased $56,000,000 from the prior year quarter. Favorable volume and mix effects were more than offset by higher maintenance expenses. Moving to Slide 16, chemical earnings decreased $46,000,000 sequentially with stronger margins partly offset increased maintenance activity. Moving now to Slide 17. EBITDA delivering on our investment and operating commitments is our disciplined approach to investment and cost management. We continue to drive capital and operating costs down, especially in the current business climate, with year to date CapEx and operating costs lower by a further $12,000,000,000 versus the prior year period. We strive to build structural advantages into our business while minimizing total lifecycle costs. With our global procurement organization, we leverage our worldwide presence and scale of operations to effectively respond to changing market conditions. Importantly, this includes meaningful engagement with the service sector on developing and implementing lower cost solutions. Across our operations and development activities, we pursue unique synergies and innovations throughout the design and execution phases that capture these structural advantages while ensuring high integrity in our operations. For example, by leveraging our fast drill process and flat time reduction initiatives, we have realized cumulative drilling savings of $5,000,000,000 over the last decade. Today, these tools are delivering shorter drill times and improved performance in places like Angola, Guyana and Russia. A hallmark of our success has been our committed focus across the full value chain on technology development, not only to develop lower cost alternatives, but also to enhance integrity and reliability, improve productivity, increase product value and minimize environmental impact. On Slide 18, we would now like to comment on the reporting basis of crude reserves and asset impairments. Our results are in accordance with the rules and standards of the SEC and the Financial Accounting Standards Board. Starting with our oil and gas proved reserves. As I indicated, our reporting is consistent with SEC rules, which prescribe technical standards as well as a pricing basis for calculation of reported reserves. This pricing basis is a historical 12 month average of 1st day of the month prices in a given year. As such, the low price environment impacted our 2015 reserves replacement, resulting in a 67% replacement ratio. This was the net result of natural gas reserves being reduced by 834,000,000 oil equivalent barrels, primarily in the U. S, reflecting the change in natural gas prices, offset by liquid additions of 1,900,000,000 barrels. Given that year to date crude prices are down further from 2015 by almost 25% on the SEC pricing basis, we anticipate that certain quantities of currently booked reserves, such as those associated with our Canadian oil sands, will not qualify as proved reserves at year end 2016. In addition, if these price levels persist, reserves associated with Enfield Life production for certain other liquids and natural gas operations in North America also may not qualify. However, as you know, amounts required to be de booked on an SEC basis are subject to being rebooked in the future when price levels recover or when future operating or cost efficiencies are implemented. We do not expect the de booking of reported reserves under the SEC definitions to affect the operation of these assets or to alter our outlook for future production volumes. And you can find further details of our reserves reporting in our 2015 10 ks. Now regarding asset impairments, we follow U. S. GAAP successful efforts. And under this standard, assessments are made using crude and natural gas price outlooks consistent with those that management uses to evaluate investment opportunities. This is different than the SEC price basis for reserves that I just described. As detailed in our 2015 10 ks, last year we undertook an effort to assess our major long life assets most at risk for potential impact. The price base is used in this assessment generally consisted with long term price forecast published by 3rd party industry and government experts. The results of this analysis indicated that the future undiscounted cash flows associated with these assets exceeded their carrying value. Again, this is detailed in our 2015 10 ks. In light of continued weakness in the upstream industry environment and in connection with our annual planning and budgeting process, we will again perform an assessment of our major long life assets, similar to the exercise undertaken in 2015. We will complete this assessment in the Q4 and report any impacts in our year end financial statements. Moving to Slide 19, I'd like to provide an update on efforts to further enhance our development portfolio and advance major projects. 1st in Guyana, the Liza 3 appraisal well was successfully completed in October, increasing our confidence in the aerial extent of this world class resource. Well results now confirm the Liza discovery to be in excess of 1,000,000,000 oil equivalent barrels. These results are being incorporated into early engineering plans for the initial phase of 100,000 barrel per day development. The Stena Caron drillship will next move to the Payara exploration prospect located approximately 10 miles to the northwest of the Liza 1 discovery. Ayara is expected to be completed late this year or early next year, after which the rig will move to another exploration opportunity also on the Stabroek Block. In West Africa, the Awolow-three well located approximately 56 miles offshore Angola reached target depth in October and discovered significant oil resources. This well builds on our successful Oyu II well drilled in 2012 on the neighboring license. Together, these wells confirm a 500,000,000 to a 1000000000 barrel oil discovery. ExxonMobil continues to invest in its exploration activity to grow our prospect inventory across the globe. Recognizing the opportunity presented by current market conditions, we are investing countercyclically in large scale seismic acquisition programs. Through 2016, we have acquired over 60,000 square kilometers of 3 d seismic data covering diverse geological basins around the world, including Eastern Canada, Mexico, Guyana, Ireland, South Africa and Mozambique. These new seismic data will enable us to evaluate recently captured acreage and ultimately identify new potential drone locations. ExxonMobil also continues to invest in proprietary research in advanced seismic imaging and high performance computing to enhance our ability to extract maximum value from seismic data. In addition to our active exploration program, we continue to advance several large scale developments. The Kashagan project in Kazakhstan achieved a stable restart of production in October. Work is ongoing to safely and gradually increase production to a target level of 370,000 barrels per day over the next year. In Australia, ExxonMobil has shipped 4 LNG cargoes from Gorgon since August and the second LNG train has now started up. In Eastern Canada, after transportation from the fabrication yard in South Korea, the Hebron Utilities and Process Module or UPM was safely offloaded at the Bullarm Fabrication site in the Canadian province of Newfoundland and Labrador. Our top sites, including UPM, will next be mated with the concrete gravity based structure shown in the background of the photo. Hebron remains on track to start up by year end 2017. Moving to Slide 20. This slide illustrates the corporation's year to date sources and uses of cash and highlights our ability to fund shareholder distributions while maintaining our selective investment program. As shown, cash flow from operations and asset sales of $16,900,000,000 funded shareholder distributions and together with a moderate increase in debt financing, supported net investments in the business. We continue to maintain our financial flexibility, a competitive advantage that allows us to selectively invest through the cycle and capitalize on unique opportunities. ExxonMobil generated $4,000,000,000 of free cash flow year to date, reflecting capital discipline and the strength of our business. And we remain resolute in our commitment to pay a reliable and growing dividend. Quarterly dividends per share of $0.75 were up 2.7% versus the Q3 of 2015. Moving now to Slide 21. So in conclusion, ExxonMobil remains focused on creating long term value through the cycle. Year to date, the corporation has earned $6,200,000,000 and generated $16,900,000,000 of cash flow from operations and asset sales, benefiting from the resilience of the integrated business. Upstream volumes were 4,000,000 oil crude barrels per day and we anticipate that full year production volumes will be within our guidance of 4,000,000 to 4,200,000 barrels per day, driven by our value based choices. ExxonMobil remains dedicated to capital and cost discipline regardless of the business environment. Year to date capital spending is down 39% to $14,500,000,000 and we remain committed to sharing the corporation's success directly with shareholders through the dividend. Year to date dividend distributions totaled $9,300,000,000 That concludes my prepared remarks and I would now be happy to take your questions. Thank you, Mr. Woodbury. The question and answer session will be conducted electronically. We'll go first to Phil Gresh at JPMorgan. The first question is on the capital spending. You continue to see a reduction sequentially in the CapEx year to date. And it's obviously trending well below what you had expected at the beginning of the year. So I guess my first question is, given the degree that it's lower than you had guided, are you surprised by the degree of savings you've been able to achieve? And as we look ahead, where are we in this cycle of CapEx savings? Yes, that's a real good question, Phil. And I'd say that first, I just want to recognize the organization for how focused they've been on, and particularly in the low price environment, continuing to capture benefits. We, as you've highlighted, have been below our capital guidance to you all. We'll be able to capture the many capital efficiencies. We've continued to effectively respond to the market and capture market benefits. Importantly, Phil, we continue to excuse me, deliver the projects on budget and on schedule. And as I've said previously, we have adjusted the pace of some of our investments in order to make sure that we're maximizing the value proposition given where we are in business cycle. If you look at our spending pattern, I would tell you that it is trending towards an outlook of between $20,000,000,000 to $21,000,000,000 $20,000,000 to $21,000,000 for the full year? For the full year. Okay. And then as you look at the M and A activity, there's been a lot of M and A activity in the U. S. Shale space lately, some of which has been acreage that's been contiguous to yours. Maybe if you could just comment about how you're thinking about valuations in U. S. Shale today? Yes. So as we've talked in the past, Phil, we continue to be very alert to where there may be some value propositions. We're looking for opportunities that would create incremental value. These opportunities need to compete with our existing investment portfolio and provide accretive strategic long term value to us. We have been successful in over the recent past picking on bolt on acquisitions, particularly in unconventional business, where we saw some of those unique synergies that added accretive value. We continue to be very alert to where there are opportunities, but as I said, they really need to be able to add incremental value versus the portfolio that we currently have. Okay, thanks. Thanks, Phil. We'll go next to Neil Mehta at Goldman Sachs. Good morning, Jeff. How are you? Good morning, Neil. How are you? Doing well. Jeff, I always appreciate your views on the near term oil macro. I know Rex had made some comments out in London, talking about a more subdued market over the next couple of years. Can you just talk about how you see the balances over the next couple of years, both from a supply and demand perspective? And then I'll have a follow-up. All right. So, Neal, if you think back and look at where we've been here in the recent past, I'll start with demand. Demand has been generally reasonably strong. I mean, when you think about a 10 year average demand growth of somewhere between 1,000,000 to 1,100,000 barrels per day, Since 2014, we've seen demand growth in excess of that. So fairly reasonable demand growth in recent past. If you look focus now on the 1st part of 2016, we still continue to be in an oversupply situation with production exceeding demand by about 1,100,000 barrels a day in the first half. And as we anticipated, it's we are seeing convergence in the second half. But I'll tell you that as you continue to progress that we'll probably end up this year oversupplied by anywhere from 500,000 to 800,000 barrels per day of supply. Now of course, all this is going into commercial inventories. So as you move into 2017, you see that we continue to see convergence, maybe a little bit oversupplied in the year, but I'd caution that we got to recognize that there's still anywhere from 500,000,000 to 600,000,000 barrels of commercial inventory build since the end of 2013. That's got to come out of inventory at some point. And then, of course, there's still uncertainties in the supply trend, some of the OPEC countries as well as U. S. Unconventionals will have an influence on the supply demand balance. So I think when you heard Rex's comments, he was reflecting on all these factors as to how that will impact price in the near to the medium term. Appreciate that, Jeff. And the follow-up is related to exploration. If you could provide some additional color on both Guyana where there's been some exploration success with Liza 3 and the opportunity set you see in Nigeria, that'd be appreciated. Yes. So as I said in my prepared comments on Guyana, we were very pleased with the outcome of the Liza III well. The well is located just north of Liza-one. It has given us confidence in terms of the aerial extent, the reservoir quality and thus our communication that we believe we're in excess of 1,000,000,000 barrels now. We're completing the Liza-three well. As I indicated, we'll move on to an exploration well, which is to the northwest of the Liza discovery. We are integrating real time all of this well data. And of course, we took a very extensive 3 d seismic survey and all that's being integrated into our development planning. So in short, I'd say we're very encouraged by not only Liza, but the prospectivity on the block and we see this as a high quality asset for the corporation. Pivoting over to Nigeria and the Awo development, I'd tell you that this is a continuation of initial discovery. The Awoobi III well appraised part of that initial discovery, but also discovered new hydrocarbon columns in a deeper 1,000,000,000 barrels of oil discovery, and we will clearly integrate that into our development planning. I think I will also note that the Evoloa-three well is a really good indication of how the organization and its integration is able to continue to enhance the value proposition. We saw the potential to add additional resource. We drilled this deeper exploration objective and added significant more resource to the potential development there. So I think it's a great example about the value it will bring from the general interest integration of the corporation. Thanks, Jeff. Thank you, Neil. We'll go next to Jason Gammel at Jefferies. Thanks very much. Hi, Jeff. I had two questions for you actually. The first was around the impact of the forward statement that you have and the comments that you made about the proved reserves. Just trying to understand in Canada, it looks like in 2015, you actually had some fairly significant positive reserve revisions. And so I'm just wondering if the sort of $7 change that we've seen in WTI from year to year is the primary driver on why those reserves could now potentially be at risk? And is Kroll kind of an all or nothing thing where it would be the full 3,600,000,000 barrels or it would be nothing? If you could just comment around that. Yes. Good questions, Jason. I mean, the first point is that as I mentioned, we're seeing almost a 25% reduction in prices on an SEC basis year to date. Now, of course, we need to wait until we get the last two data points for that calculation. But given what we were seeing to this point, we felt it was appropriate to signal the potential impact from the SEC pricing basis on crude reserves. Yes, we did add some reserves in Kearl in 2015 and then the drop that we're potentially going to experience in 2016 is all due to the pricing basis. The second question was I'm sorry, Jason, was related to what? Well, it was really just you referenced 3,600,000,000 barrels in the press release that's related to Kearl. Is that kind of an all or nothing thing? In other words, is it the full operation or? Yes, for the most part it is. For Kearl itself, you remember, it's a very, very long flat plateau. So it would be all or nothing. Sure. And are you positive cash margin there right now, Joe? Well, we manage all of our assets to maximize cash flow. I will tell you that the organization has done a remarkable job at Kearl. Remember, if I step back a little bit, Kearl is an advantage asset from the standpoint that we did not put an upgrader in place. We use proprietary technology in order to avoid that upfront capital investment and the subsequent operating costs associated with it. The organization has just what we're really trying to do is continue to improve overall reliability of the mine operation as well as significantly reduce our cost structure there and they will continue to work on it like we do everywhere. And we manage these assets in order to maximize long term return and very confident that that will happen here in Kearl as well. Great. Appreciate your comments, Jeff. We'll take our next question from Evan Kallo at Morgan Stanley. Hey, good morning. Good morning, Evan. Ken, maybe my first question is that it's a different slant to a prior to Phil's prior question. Just given the success you've had at adding resource to the drill bit in Guyana, Nigeria, brownfield opportunity in places like PNG, pretty significant opportunity set. Does that really contribute to your cautious take so far on the asset market or the acquisition market? Maybe broad mix, I know it's asked more for U. S, but your view on the global market and kind of perceived need and or interest? Yes, it's a good perspective, Evan. I mean, I would tell you it's not either or for us. We're looking at where can we get the greatest value. But I think you draw out a very important point as it relates to how we manage the portfolio and that is we maintain an active exploration program that is clearly defined at high grading the value proposition in our portfolio and you've highlighted some of the important resources. When we get to the point in the asset's life where we don't think that there's that much incremental value, that's when we put it into our process of considering how else can you monetize that asset. But at the same time, we're also very alert to where there may be some value propositions from acquisitions. And I think the InterOil transaction is a really good example. We discovered a substantial resource base in Papua New Guinea. We've continued our exploration activity, looking towards an expansion of the existing LNG facility. And in addition to that, we saw the opportunity for synergies, value proposition by acquiring the inner oil and specifically the Elk Antelope Resource that we could combine with our existing resources there. And with the great success we've had in terms of the operating reliability and the cost structure there, I mean, it just is a it puts it right up to the top of the portfolio. So think about all of our actions, Devin, as had what is the best value proposition that may become organically or inorganically. Okay. That's fair. And then a follow-up on Liza, maybe more just more detail here on how success affects your 2017 wildcatting program across your various blocks? I mean, potentially adding another rig and any preliminary thoughts on that effects that development plan you filed in July, potentially adding a second FPSO and maybe just kind of clean it up there. Just any color on Payara or what you learned from Skipjack? Yes. So as I indicated in the earlier question, we're very encouraged with the progress that we're making at Guyana. I think you also know that we also are very measured in our pace in terms of exploration and development. We want to make sure that we are not leaving any value on the table. We also want to make sure in the exploration program that we don't get too far ahead of ourselves. We want to make sure that we're fully integrating the learnings into the regional geology so that we upgrade our potential exploration program going forward. So it's a PACE program. It's making sure that those learnings are being fully integrated and then making sure that when we do discover additional resources or learn important information like we learned at Skipjack that we integrate that into not only our exploration program, but the scope of the full development. As it pertains to our initial phase development, it's been fairly consistent in scope as it was conveyed in the permit application we filed for environmental review with the government. I will tell you that this is real time. The organization is looking for ways to further enhance value. And as we progress that development planning and early engineering, we'll learn more, which will cause us to make adjustments. But very optimistic about the future in Guyana, and we think we're bringing a lot of value to the government and people of Guyana. Great. On the prospect? On Callara? Yes. Yes. So I'd say it is a similar reservoir section to lease up, also a stratigraphic trap. Other than that, it's really too early to say much more. Great. Thank you. You bet. We'll take our next question from Sam Margolin at Cowen and Company. Good morning, Jeff. Good morning, Sam. I'll start out. It's been a number of years since people have had to think about an OPEC cut and filtering through partners. Can you just remind us potential impacts to the business? And I'm thinking specifically of Upper ZACM and some other projects that start up next year within member states? Yes, Sam. I'm not really going to speculate on what OPEC might ultimately decide to do. I think what's important for you all to think about is that rest assured that we are working to create incremental margin in the business. So directionally, it could impact you on several ways. 1, it could there could be restrictions, but we're going to continue to make the value proposition. But I just at this point, it's just too early to speculate on what we may or may not see from the agreement from the OPAC parties. Understood. Thanks so much. And then I'm curious about this evaluation you mentioned in the press release about another chemical complex in the U. S. Gulf. Does that reflect, I recall at the Analyst Day, there were plans to ramp U. S. Unconventional activity that were unveiled. And is that so is this new chemical complex potentially a reflection of a view or associated with that at all and maybe some view on continued at least localized length in liquids and other associated products coming out of your oil fields in the U. S? Or is this just a separate economic decision? Yes. So I mean, like most everything in ExxonMobil, it all starts with our view on the long term energy supply demand picture. And when you think about chemicals, the chemical demand growth based on our latest outlook has from an overall from an overall perspective, chemical growing about 1% above GDP. And from an ethylene perspective, we're expecting that chemical demand will grow such that you need to add about 5,000,000 tons per annum of new capacity per year. And to put that into hardware, that would be 3 to 4 world scale crackers per year. So that really is that sets up the value proposition. First, as you know, we're expanding the Baytown complex to add another 1,500,000 tons per annum of ethylene capacity, a corresponding investment at Mount Bellevue adding derivative units to produce ExxonMobil's high value metallicy and polyethylene. And then we announced to your question, we announced a potential joint venture with Sabik to jointly own and operate a complex in the U. S. Gulf Coast that would notionally be another ethylene steam cracker to produce ethylene about 1,800,000 tons per annum and a corresponding derivative units that would be built alongside that. But I think the value proposition is there. I think we're ahead of the game in terms of making some world scale investments in this and a very strong component of our chemical business. Thanks so much. You bet. We'll move next to Doug Leggate at Bank of America Merrill Lynch. Thank you. Good morning, everyone. Good morning, Jeff. Good morning, Doug. So Jeff, the new CapEx guidance seems to be following a trend that you've indicated goes lower again next year. But you've also said that in a recovering environment, you could quickly pivot back to unconventionals in the whole eight. And I think the number I have in my head is an incremental 200,000 barrels a day net to Exxon by the end of 'eighteen. Can you just walk us through where you stand on making that decision and whether I'm characterizing it correctly? Yes. So if you recall back in the March analyst meeting, we provided an outlook through the end of the decade for our capital investment program. And if you remember, we had 2017 flat to down. And of course, the experiences that we've realized during 20 16 will be integrated into that and we'll update that outlook going into the next analyst meeting in March of next year. As you reflect on our ability to pivot, remember there's 2 components to our investment program. There's a very large component being our long cycle investments. Nothing has really slowed down in that regard and how we're working through the maximizing the value proposition for those investments. And as I've said earlier, we're trying to take full advantage of the cycle benefits. On the short cycle side, you may recall, and I think the number you're picking up with is in our unconventional program we shared in March that we've got the ability to move fairly quick in order to capture a higher price environment in our unconventional program to the order of magnitude of about 200,000 barrels a day by 2018. So we've got a lot of flexibility in our short cycle program. And when you think about what really sets the balance between short and long cycle investment, and the way I think about it from a short cycle perspective, Doug, it's really maintaining a program in a low price environment that allows us to continue to build on our learning curve benefits. You don't want to go much beyond that, because you're trying to also maximize value. So I think we're very well positioned. If you recall in the Q2 of last year, our last earnings call, we shared with you some statistics around our unconventional program where we continue to drop the costs and we have a pretty sizable ready inventory to go ahead and move on. Appreciate the detailed answer, Jeff. My follow-up, if I may, I'm afraid, is back to Guyana again. I wonder if I could just probe a little bit to try and clear up some comments that your partner made. So really about next steps on timing, my understanding is that you're still on location in Liza 3 looking for deeper objectives. So my question is, have you are you done there? Have you found low snow and oil or no water contact? And maybe comment on your partner's suggestion that the range of Liza is now at the top end of your prior disclosure range? Yes. Well, I'll start with the second half of the question. That is, is that right now, our guidance is that we're likely above 1,000,000,000 barrels and really no more detail beyond that at this point, Doug. On the Liza III well, we did go ahead and deepened the well. We were targeting a higher risk deeper interval that had not previously been penetrated on the block. What I would share with you is that the results were positive and it does support the presence of oil bearing sands deeper in this section, but it is still very early. This is real time, evaluation is still ongoing and that information will be used to integrate not only in Alisa, but also in the rest of our exploration. So did you find the oil water contact or is there another appraisal well required? Did I find did we find an oil water contact in the deeper interval? No, no, in the original section. Well, we were targeting it goes back to the objective of the least of 3 well. We were targeting water in the lowermost sands and we did encounter that water in the sand. We're still evaluating the results from the well, Doug, but it's suffice it to say, we're pleased with the results and they are consistent with our pre drill expectations. Right. Thanks a lot. Appreciate it, Jeff. You bet, Doug. We'll go next to Brad Heffern at RBC Capital Markets. Hey, Jeff. Good morning, Brad. Just to continue the probing on the deeper interval, is that included in the 1,000,000,000 plus barrel resource range? Well, to the extent that I say in excess of 1,000,000,000 barrels, yes. Okay. And then I was wondering if you could just give a little more detail around Skipjack. Can you describe at all what happened there and why it was ultimately a dry hole? And how did it inform the future drilling plans? Were prospects eliminated based on that result or was the drilling schedule changed? Well, Skipjack did not find commercial quantities of hydrocarbons, but it did find the same excellent reservoir quality sands that we see in Liza. We have as we've been saying, we have numerous additional prospects as well as different play types on the block. So we're very encouraged by the successes to date as well as the future exploration wells. There's really nothing more to share on Skipjack at this point. We are still doing some final evaluation. And of course, as I alluded to earlier, those learnings are being fully integrated into our exploration program. Okay, understood. And then switching to Nigeria, certainly very large apparent production impacts in this quarter. Can you talk about what the current status is of your production there? I know you at least reportedly recently lifted the force majeure there. Yes. So when you think about our liquid shortfall versus the Q3 of last year as well as sequentially, it was all primarily driven to the downtime in Nigeria. And there were 2 third party impacts. The first one, I think I may have mentioned it in the Q2 earnings call, the first one had to do with the 3rd party rig that was transiting that impacted our export line, which had an impact on our production. And that issue has been addressed and the production is back on. The second one had to do with a third party impact to the line. And let me just say that we're still investigating with the government. We do not believe it was accidental or due to mechanical failure. Okay. Thanks, Jeff. Okay. Our next question comes from Ed Westlake at Credit Suisse. Yes, good morning. I guess there's been press releases out of Mozambique saying that you have done a deal with the NI. So I'm just wondering if there's any comments that you can make in public on that. Yes, good morning, Ed. I know there's been a fair bit of media interest in this. There's really nothing that I can comment on with respect to those media reports. You may recall also that ExxonMobil and Rosneft were given the rights to negotiate for a PSC on 3 offshore blocks in Mozambique and we're actively working that opportunity. In fact, we're participating in a 3 d survey right now that started up in January and it's still underway. Okay. And then second question, I mean, I see a lot of ways that you can get on the offense and we've spoken about a lot of them on the call. Maybe we haven't spoken enough about integrated value growth in the downstream. But there is this issue around impairments. So if I may, thanks for putting that on the agenda. One of the triggers that you have in your 10 ks for impairments is operating losses. And obviously, the U. S. Has been in an operating loss for much of 2015 2016. And then oil sands may or may not be in an operating loss, so we don't get the disclosure, but let's say it is. I'm just looking in your accounts and your net capitalized costs for consolidated subsidiaries in the U. S. Is $83,000,000,000 and then in Canada is $36,000,000,000 So maybe just walk through the process of how you'd go through those impairments, say the trigger was there and how the corporation would think about the type of impact it might have? Yes. Well, I mean, as I said in my prepared comments, Ed, we did an assessment in 2015. And in that assessment, as I was very clear in my comments, we saw that the cash flow fully covered the carrying cost of those assets. As I indicated, Ed, we're going to do another analysis very similar to the comprehensive assessment that we did in 2015 and we'll report on any results. But you can see some pretty good detail of what we go through. And in fact, maybe you've already looked at given your comments in our 10 ks that really defines the process pretty clearly. But I really don't have any more to share on the specifics of the mechanics that we go through. But rest assured, we're in full compliance with the rules and standards of both SEC and the Financial Accounting Standards Board. I guess it's we could take the RP ratio as a proxy for the years of undiscounted cash flow and then we can make our own forecast of how much cash flow you make at the strip and compare that to the carrying value would be at least a first approach to it? I guess I just worry that if you de book reserves, then you'll have less reserve life to multiply by the cash flow to then on an undiscounted basis carry against the asset value. Yes. I don't have anything else more to add on this. Ed, we'll continue to be transparent on this. That was the whole purpose of putting the forward statement in there. It was a it's part of our normal planning and budgeting process to look at profitability of our assets and that sometimes causes us to step back like we did in 2015 and do a more comprehensive assessment. Thanks for getting on the front foot on this. Yes. Okay. We'll go next to Asit Sen at CLSA. Good morning, Jeff. Good morning, Asit. How are you? Good, good. So two unrelated questions. First, on Global Gas, could you remind us what percent of your LNG volume is not under long term contract? And given slowdown in traditional Asian markets, particularly Japan, Korea and Taiwan, are you seeing more near term opportunities other regional markets? And just wondering if you have any incremental thoughts on European gas picture? And I have a follow-up. Yes. Well, on the global gas, I mean, first, let me remind everybody that from our energy outlook, we have gas grown about 1.6% and LNG growth just under 3x where we are in current LNG capacity. As you go forward, and we've said it many times, Asit, that our LNG business is a very important part of our portfolio. I don't have a specific breakdown of our total gas production between pipeline sales and LNG contract sales, but recognize that a large part of our Asian gas coming from Qatar and Papua New Guinea is under long term contracts and a good part of them are liquids linked. So that's about all I can give you on that. In terms of the markets, clearly, the Asian Pacific market is an important market for LNG. We've got a very expansive marketing organization to go ahead and identify value opportunities. We are primarily interested in locking in long term contracts, either a point to point or a portfolio sale. You may recall that before we take a project to an LNG project to final investment decision that we will lock in a majority of those volumes on a long term contract. We've been really developed a very strong reputation and credibility with the buyers through our ability to deliver these projects on schedule and our responsiveness to managing through the contract terms. We've got a new operation center that we put in place in Asia Pacific to facilitate the transactions with our many buyers. Okay. Thanks. And my second question is on Brazil. It appears Brazil is opening up in area where Exxon is not really involved. Given Guyana traction that you have now, could you update us on your latest views in Brazil? I mean, Brazil is a country that's really blessed with a large endowment of resources. And And it's really high quality resource. Remember, how we approach our investment activities is one of making sure that we get attractive returns for our shareholders. The trends in Brazil have been encouraging. We continue to look for where there could be good value opportunities in Brazil. And certainly, if we think that we can get engaged there on resources or exploration activities that will be competitive on a global perspective to the other opportunities that we've got in front of us, we certainly will consider that. Thanks, Jeff. Thank you, Ashit. We'll go next to Ryan Todd at Deutsche Bank. Great. Thanks, Jeff. Maybe if I could follow-up on an earlier question in terms of CapEx trends and activity levels. You've seen as highlighted before, I mean your CapEx year to date is trending well below official guidance and even at $20,000,000,000 to $21,000,000,000 for the year is still relatively low and impressive to the point where you actually covered CapEx and dividend here in the quarter. So I guess first, I mean, I guess with you effectively breaking even in the current environment, I know that it's just 1 quarter, but how should we think about how you manage additional cash flow into 2017 as well when gas price recovers? How do you prioritize an increase in activity levels versus growth in distributions versus reduction in leverage? It's a good question, Ryan. And I know we've talked about it before, but it's always good to update on this issue. As you know, let me just first talk about capital allocation. It's one of from our cash flow from operations, the first thing that the corporation wants to do is go ahead and pay a reliable and growing dividend. The next thing is the remaining cash is put towards through to a investment program that has gotten to the point where we believe that we have maximized the value proposition for investments. If we've got enough cash to go ahead and invest it to fund that investment program, then the remaining cash will either put be put forward to either stock buyback share buybacks or paying down our debt. If we don't have enough cash, as you've seen us do in the recent past, we'll go ahead and further leverage our very solid balance sheet and debt capacity to take on some additional debt because the service costs associated with that debt is more than benefited by the return we get from these investments. So it's important to recognize that while we are very mindful of prudently managing our cash, we also believe it's very important for us to continue to invest through the cycle and we do that in a very measured way that we're not leaving any value on the table. And that's my and therefore my comments I made earlier about making sure that we're optimizing value in the bottom of the cycle. Great. Thanks. Sorry, maybe as a follow-up on that. You mentioned earlier on the call how you guys have done a good job. I mean, you've generally maintained a decent amount of investment level on kind of your long cycle type projects. But when you're looking at this point at pre FID inventory of projects, can you speak to the progress that you've seen on large scale conventional projects in terms of cost deflation or evolution in fiscal terms towards enhancing the competitiveness of this part of the portfolio? Or have you seen what you need to see at this point to kind of go and kick off investment in that to continue new investment in that part of the portfolio or is there more that you need to see at this point? Yes, let's break it up into a couple of components, Ryan. First, I'd say that we want to make sure that all the learnings that we're getting from our capital efficiency efforts year to date are being integrated into those projects. And we've talked about how we do this to reduce the upfront capital invested, like I've talked in the past about progressing projects in parallels that we can benefit from the learning curve and subsequent projects. So capturing the market response, capturing the capital efficiencies that we built in, in a low price environment, as you've highlighted, there's times where we may want to go back and purchase some additional resources or do some exploration like in Ogolo to add additional resource to make the investment, the project investment even more robust. The last thing I'd mention is the application of technology has been fundamental, absolutely fundamental to our past success and into the future. And you think about where you're getting those benefits across the full value chain, I mean, from the downstream, our chemical business where we use proprietary technology to provide high value metallocene to our unconventional business with fracking technology. So the application and the growth of these technology solutions has been a key element. And sometimes some of these projects are really waiting on some of the technology work that's underway. So we've made great progress. I think we're very well positioned. We've got a solid diverse portfolio in which to go ahead and selectively invest into the future. And our next question comes from Manish Kapadia at Tudor, Pickering, Holt and Company. Hi, Jeff. Just wanted to had a question with regards to the way you look at your asset impairments versus the way that you look at acquisitions. Just trying to square the fact that you haven't written down assets in 2015 given you've got, I suppose, a fairly constructive view on the commodity prices with the kind of the opposing fact that you haven't done a deal over the last kind of year or so, given that you haven't seen attractive enough assets in the market. Can you just talk about how those two things kind of work together? Well, from my standpoint, there's 2 separate processes. Our asset management activity is a function of making sure that we are capturing opportunities, as I said earlier, that are competitive to our existing portfolio. The objective here is making sure that we're growing shareholder value. And if we think that we can acquire an asset like the InterOil transaction, then we can add incremental long term value, then we'll go ahead and pursue those type of opportunities. Our determination of asset impairment, which we've talked about, is a comprehensive process that we follow. And as I said, it's detailed in our 2015 10 ks and it's a separate process. It's not informing or influencing our asset management activity. Okay. Thank you. And I had a follow-up on Nigeria. You have a you've made a number of discoveries in Nigeria, kind of a number of things that you highlighted as potential developments. Could we expect any of these to be sanctioned for development in 2017? And if so, which are the ones that are most progressed? Yes. So, Anish, as you highlight, there are a number of projects that we have in our portfolio that we've shared with you all in our F and O. And several of those have gone through various stages of development planning to capture some incremental value. I would tell you that just like any project, there are a lot of variables that we have to address and some of those variables may take some time, But we continue to actively work with the co ventures and the government on the Nigeria portfolio. I think the Awolowo-three well is a good example of how we've added some additional value to our portfolio and strengthen that project opportunity. And any of it could be sanctioned next year? Well, Anish, we don't pre communicate our FIDs, but the portfolio that we share with you in the F and O, we've got various stages of planning underway in those projects. Some of them are in FEED, some of them are even more advanced like one of them, Tengiz, has been FID'd. But we don't provide advanced guidance on our FIDs. Okay. Thank you. Thank you. We'll go next to Roger Read at Wells Fargo. Yes. Good morning, Jeff. Good morning, Roger. Just maybe coming back a little bit to sort of broader cash flow, CapEx questions here. The number of people have asked the question, does CapEx, is it troughing here? Does it go up? I guess, to some extent, that's going to depend on oil price and cash flow. But how do you look at it in a world where prices have increased quite a bit from the beginning of the year and then balancing cash flow, CapEx, any sort of asset disposition plans? And then can you lay out any of the parameters for when we should anticipate a recovery in the share repurchase program? Like what do we need to see? Yes. Well, I mean, I really want to be careful not to speculate on what prices will do in the future. But I will tell you, as we discussed a little bit earlier that our investment, our long cycle investment plans are progressing. When we believe those investments are at a point of maturity where we have optimized on value, then we'll make an FID decision. Recall that we're making those decisions by our long term view on supply and demand. We're very constructive on long term energy demand and that's what's really informing those long cycle investments. It's not it is not what current prices are doing, okay? Now having said that, we balance that with other factors that we may be able to capture some incremental value in the near term and causes us to pace those investments out on a longer cycle in order to make sure that we're fully capturing the value. On the short cycle investments, as I alluded to earlier, we want to keep activity levels in the down cycle commensurate with the learning curve benefits that we've been realizing such that we are enhancing value across the full portfolio. But it doesn't make sense to do much more beyond that if you recognize that you want to optimize value. But as we as I responded to Doug earlier, we're very well poised to go ahead and pick up activity on the short cycle investments that's supported by the business climate and we've got flexibility to do so. Sure. Well, the correct response on prices is always just to say fluctuate, right? But in terms of thinking about the share repo side of it, I mean, is that a you need to be at a point where you're comfortable, you can, let's say, maintain roughly flat production levels and generate free cash flow? Or I mean, how should we think about balancing production returns, cash flow? I'm thinking about a more normalized environment, which it appears we're headed to over the next year or 2? Yes. So going back to my discussion on the capital allocation approach, with the buybacks, that's determined each quarter considering a number of factors, including the company's current financial position, our capital requirements, our dividend requirements, as well as what we see in the near term business outlook. And it's a all those variables that are really inform the company as to whether we believe it's appropriate to go ahead and distribute some of the benefits of the corporation back to the shareholder via buybacks. Remember, the corporation does not believe we should be holding large cash reserves. If we don't have an immediate use to put it to work on, we'll go ahead and distribute it. Now to be clear, that consideration will also be mindful of the merits of going ahead and paying down debt if appropriate. Okay, thanks. And just an unrelated follow-up regarding the Kearl assets, is the indicator there best to use a bitumen price or to use a WCS price and that's just for us to do our calculations? Well, I mean, I think the bench mark is reasonable the WCS benchmark is probably reasonable. Okay, great. Thank you. All right. Thank you, Roger. We'll go next to Paul Cheng at Barclays. Hi, Jeff. Good morning. Good morning, Paul. Two quick ones, hopefully. For Liza, do you have already sufficient well data from Liza and Liza 1 and 2 appraisal, you need to make FID on the early production system or you will need additional appraisal wells? On the Liza Guyana, at this time, I don't think we believe that additional appraisal wells required prior to an FID decision. But I would tell you that, as I said earlier, Paul, that we will continue to integrate the data that we've got and there may be a point where we step back and say, given the risk profile, we may want to collect some additional data. But right now, it's not planned. Okay. And on Permian and Bakken, can you tell us what is your number of rig and what is the current production? Yes. For Permian and Bakken, I think we've got a total of 10 rigs going in the Q3. And what's the production? And production production on a gross operated basis for Permian and Bakken is about 240 1,000 barrels a day. And one of your pretty large competitor that was talking about in the preparation of indeed that they're going to add some additional rig by November. Just curious that whether Exxon have any preparation of increasing your activities at this point? Yes. Paul, we are as I just said a moment ago, we're very well positioned to respond if we think it's appropriate. But I'm just not going to forecast whether we plan to add anything in the near term. Okay. We do. Thank you. You bet. And our next question comes from Ian Read at Macquarie. Hi, Geoff. Good morning, Ian. Just a quick question. I was intrigued to see a news report that Exxon is considering setting up a trading organization. And I was listening to the answer to your question on LNG and point to point deliveries and coverage by long term contract. Can you foresee a situation where Exxon would rather like some of your competitors actually take some of the equity volumes itself from LNG Development and then kind of redistribute via kind of other mechanisms? Because I don't think Exxon has ever done that. You've always been a kind of a point to point LNG player and never kind of played in the kind of trading or diversion game. So I'd be interested in the comment on that. Yes. Thanks, Ian. I'd tell you that by and large, we're price takers. We don't typically speculate or take markets positions in markets. Beyond that, in terms of the inner workings and how we want to manage that going forward, there's really nothing more that I can share. We continue to be very mindful from an LNG basis, very mindful of what the what is of interest to the buyers. And I think I referred to being open to portfolio sales, But we're still very much interested in locking in those contracts on a long term. Okay. Thanks, Jeff. As a follow-up, can I just ask a question about the long term on Cashagon? Obviously, you're just ramping up the initial phases now. But what is the consortium thinking about in terms of going further than that? Because the resource is obviously could support a much larger level of production and given the fact you've already got the facility on stream, you must be thinking about the next phase now. So that would be interesting. Yes. To be real transparent, I mean, the joint venture company and the shareholders have been very focused, and I'm sure you'll appreciate this, on getting the initial phase fully up on production into maximum capacity. As I said in my comments, that will be about 370,000 barrels a day by the end of 2017. There is a second tranche to that subsequent to reaching 370, and that is with additional gas reinjection facilities for sour gas that will take us up to about 450. And certainly the joint venture company and all the shareholders are very focused on given that we've restarted production, how do we move forward and really maximize value and that will include at the right time looking at additional resource development. And that does conclude today's question and answer session. At this time, I'll turn it back over to Mr. Woodbury for any closing remarks. Well, once again, I want to thank everybody for your time this morning. I thought the questions were very thoughtful and insightful. We, of course, appreciate your engagement and want to thank you again for your interest in ExxonMobil. And that does conclude today's conference. Again, thank you for your participation.