Exxon Mobil Corp (XOM) — Q3 2016 Earnings Call Transcript

Thank you. Ladies and gentlemen, good morning and welcome to ExxonMobil’s third 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 third quarter performance. ExxonMobil earned $2.7 billion in the third quarter. The corporation continues to deliver solid cash flow despite the 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 throughout 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 show you today, the corporation continues to deliver on its operating and investment commitments. We are effectively progressing selective strategic investments while maintaining our commitment to safe, reliable operations. Moving to Slide 4, we provided an overview of some of the external factors affecting our results. We saw modest global economic growth in the third quarter, while the U.S. economy improved relative to the first half of the year; however, growth rates slowed in China and remained soft in Europe and Japan. Crude oil prices were largely flat, although volatile, whereas natural gas prices strengthened on average compared to the second quarter. Global refining margins decreased as production continued to outpace demand, and Chemical commodity product margins remain strong, while specialty margins held relatively flat. Turning now to the financial results as shown on Slide 5, ExxonMobil's third quarter earnings were $2.7 billion, or $0.63 per share. The operation distributed $3.1 billion in dividends to our shareholders. CapEx was $4.2 billion, down 45% from the third quarter last year, reflecting the corporation's capital discipline and strong project execution. Cash flow from operations and asset sales was $6.3 billion, and at the end of the quarter, cash totaled $5.1 billion, and debt was $46.2 billion. The next slide provides additional detail on sources and uses of cash. So over the quarter, cash balance increased from $4.4 billion to $5.1 billion. Earnings adjusted for depreciation expense, changes in working capital, and other items, and our ongoing asset management program yielded $6.3 billion of cash from operations and asset sales. Uses of cash include shareholder distribution of $3.1 billion and net investments in the business of $4.2 billion; debt and other financing increased cash by $1.7 billion. Moving now to Slide 7 to review our segmented results, ExxonMobil's third quarter earnings decreased $1.6 billion from the 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 million to $700 million on average over the next few years. In the sequential quarter comparison, shown on Slide 8, earnings decreased by $950 million, despite stronger results in both the Upstream and Downstream segments and lower corporate charges. Turning now to the Upstream financial and operating results, starting on Slide 9. Third quarter Upstream earnings were $620 million, down $738 million from the year-ago quarter. This result was driven primarily by lower realizations which decreased earnings by $880 million. Crude prices declined nearly $4 per barrel, and gas realizations fell by $1.13 per thousand cubic feet. Favorable sales mix effects increased earnings by $80 million. All other items added $60 million, driven by lower operating expenses. Moving to Slide 10, oil equivalent production decreased almost 3% compared to the third quarter of last year, totaling just over 3.8 million barrels per day. Liquids production decreased to 120,000 barrels per day, as growth from projects and work programs was more than offset by the impact of field decline and downtime events, most notably in Nigeria due to third-party impacts. Natural gas production, however, increased by 77 million 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 million higher than the second quarter. Improved realizations increased earnings by $240 million. Crude realizations decreased by $0.30 per barrel, while gas realizations increased about $0.55 per thousand cubic feet. Unfavorable volume and mix effects reduced earnings by $40 million. All other items increased earnings by $120 million, benefitting from reduced operating expenses and favorable foreign exchange effects. Moving now to Slide 12, sequentially, volumes decreased to 146,000 oil equivalent barrels per day, or almost 4%. Liquids production dropped to 119,000 barrels per day due to downtime events, entitlement impacts, and field decline. Natural gas production decreased to 161 million cubic feet per day as lower seasonal gas demand and reduced entitlements were partly offset by project growth and increased volumes from the U.S. work programs. So moving now to Downstream results, starting on Slide 13, Downstream earnings for the quarter were $1.2 billion, a decrease of $804 million compared to the third quarter of 2015. Weaker refining margins reduced earnings by $1.6 billion. Favorable volume and mix effects, mainly from lower maintenance activities, improved earnings by $170 million. Other items including lower operating costs, reduced maintenance expenses, and asset management gains increased earnings by $580 million. As announced in the first quarter, Imperial Oil is selling approximately 500 retail service stations in Canada. Today, more than 40% of these stations have been converted to the branded distributor model, resulting in an earnings impact of $380 million in the quarter. Turning to Slide 14, sequentially, Downstream earnings increased by $404 million. Weaker margins reduced earnings by $330 million; however, favorable volume and mix effects, mainly from lower maintenance activity, increased earnings by $240 million. All other items added a further $490 million, mostly from asset management gains and lower expenses. Moving now to Chemical results, starting on Slide 15, third quarter Chemical earnings of $1.2 billion decreased by 56 million 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 to $46 million sequentially, as stronger margins partly offset increased maintenance activity. Moving now to Slide 17. 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 capital spending and operating costs lower by a further $12 billion 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 the structural advantages while ensuring high integrity in our operations. For example, by leveraging our fast-drill process and flat-time reduction initiatives, we realize cumulative drilling savings of $5 billion 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 the proved 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, our reporting is consistent with SEC rules, which prescribe technical standards as well as a pricing basis for the calculation of the reported reserves. This pricing basis is a historical 12-month average of the first day of the month prices in a given year. As such, the low price environment impacted our 2015 reserve replacement, resulting in a 67% replacement ratio. This was the net result of natural gas reserves being reduced by 834 million oil-equivalent barrels primarily in the U.S., reflecting the change in natural gas prices, offset by liquidations of 1.9 billion 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 currently booked as reserves, such as those associated with our Canadian oil sands, will not qualify as proved reserves at year-end 2016. If these price levels persist, reserves associated with inter-field production or certain other liquids and natural gas operations in North America also may not qualify. However, the amounts required to be de-booked on an SEC basis are subject to being rebooked into 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. You can find further details of our reserves reporting in our 2015 10-K. Now regarding asset impairments, we follow U.S. GAAP successful efforts, and under these standards, assessments are made using crude and natural gas price outlooks consistent with those that management uses to evaluate investment opportunities. This is different from the price basis for reserves that I just described. As detailed in our 2015 10-K, last year, we undertook an effort to assess our major long-life assets, most at risk for potential impact. The price basis used in this assessment generally consisted of long-term price forecasts published by third-party industry and government experts. The results of this analysis indicated that future undiscounted cash flows associated with these assets exceeded their carrying value; again, this is detailed in our 2015 10-K. 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-lived assets, similar to the exercise undertaken in 2015. We will complete this assessment in the fourth quarter and report any impacts in our year-end financial statements. ExxonMobil continues to invest in exploration activity to grow our prospect inventory across the globe. Recognizing the opportunity presented by current market conditions, we are investing counter-cyclically in large-scale seismic acquisition programs. Through 2016, we have acquired over 60,000 square kilometers of 3D seismic survey covering a diversity of geological basins around the world, including Eastern Canada, Mexico, Guyana, Irving, South Africa, and Mozambique. These new seismic data will enable us to evaluate recently captured acreage and ultimately identify new potential drilling 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 four LNG cargoes from Gorgon since August, and the second LNG train has now started. In Eastern Canada, after transportation from the fabrication yard in South Korea, the Hebron utilities and process module was safely offloaded at the Bull Arm fabrication site in the Canadian province of Newfoundland and Labrador. The top sides, including the utilities and process module, will next be mated with the concrete gravity-based structure involved in the project. Hebron remains on track to startup by year-end 2017. Moving to Slide 20, this 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 $16.9 billion 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 billion of free cash flow year-to-date, reflecting capital discipline and the strength of our business. 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 third quarter of 2015. Moving now to Slide 21, in conclusion, ExxonMobil remains focused on creating long-term value through the cycle. Year-to-date, the corporation has earned $6.2 billion and generated $16.9 billion of cash flow from operations and asset sales, benefiting from the resilience of the integrated business. Upstream volumes were 4 million oil-equivalent barrels per day, and we anticipate that full-year production volumes will be within our guidance of 4 million to 4.2 million barrels per day, driven by our value-based choices. ExxonMobil remains dedicated to capital and cost discipline regardless of business environment. Year-to-date, capital spending is down 39% to $14.5 billion, and we remain committed to sharing the corporation's success directly with shareholders through dividends. Year-to-date dividend distributions totaled $9.3 billion. That concludes my prepared remarks, and I would now be happy to take your questions.

The first question is on capital spending. You continue to see reductions sequentially in 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’s lower than your guidance, are you surprised by the degree of savings you have been able to achieve? And as we look ahead, where are we in this cycle of CapEx savings?

Yes, it's a really good question, Phil, and I’d say that first, I just want to recognize the organization for how focused they’ve been on in particularly the lower price environment, continuing to capture benefits. We, as you highlighted, have been below our capital guidance yield; we’ll be able to capture many capital efficiencies as we continue to effectively respond to the market and capture market benefits. Importantly, Phil, we continue to deliver the projects on budget and on schedule. 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 the business cycle. If you look at our spending pattern, I would tell you that it is trending towards an outlook of between $20 billion to $21 billion.

20 to 21 for the full year?

For the full year.

Okay. And then as you look at the M&A activity, there has been a lot of M&A activity in the U.S. shale space lately, some of which has been acreage that's been contiguous for years. Maybe if you could just comment about how you’re thinking about valuations in the U.S. shale today?

Yes. As we’ve talked in the past, Phil, we continue to be very alert toward there being 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 recently in picking up bolt-on acquisitions, particularly in the 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 need to add incremental value versus the portfolio that we currently have.

Jeff, I always appreciated your views on the near-term well macro. I know Rex had made some comments on London, talking about a more subdued market over the next couple of years. Can you just talk about how you see the balance over the next couple of years both from the supply and demand perspective? And then I'll have a follow-up.

So, Neil, if you think back and look at where we have been here in the recent past, I’ll start with demand. Demand has been generally reasonably strong—when you think about a 10-year average demand growth of somewhere between 1 million to 1.1 million barrels per day. Since 2014, we've seen demand growth in excess of that. So, fairly reasonable demand growth in the recent past. If you focus now on the first part of 2016, we still continue to be in an oversupply situation with production exceeding demand by about 1.1 million barrels a day in the first half. As we anticipated, we are seeing conversions in the second half. But I’ll tell you that as we continue to progress that we will probably end up this year oversupplied by anywhere from 0.5 million to 0.8 million 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 be slightly oversupplied in the year. But I had cautioned that we got to recognize that if there are still anywhere from 500 million to 600 million barrels of commercial inventory build since the end of 2013, that’s got to come out of inventories at some point. There are still uncertainties in the supply trend—some of the OPEC countries, as well as U.S. and conventional producers, will influence the supply-demand balance. So, I think when you heard Rex's comment, he was reflecting on all these factors as to how that will impact price in the near-term or medium-term.

Appreciate that, Jeff. The follow-up is related to exploration; if you could provide some additional color on both Guyana, where there has been some exploration success with Liza-3, and the opportunity that you see in Nigeria, that would be appreciated?

So, as I said in my prepared comments on Guyana, we were very pleased with the outcome of the Liza-3 well. The well is located just north of Liza-1. It has given us confidence in terms of areal extent, the reservoir quality, and thus our communication that we believe we're in excess of 1 billion barrels now. We are completing the Liza-3 well as I indicated; we will 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 expensive 3D seismic survey, and all that’s being integrated into our development planning. In short, I would say we are very encouraged not only by Liza but by the prospectivity on the block, and we see this as a high-quality asset for the corporation. Pivoting over to Nigeria and the Owowo development, I’ll tell you that this is a continuation of initial discovery. The Owowo-3 well appraised part of that initial discovery but also discovered new hydrocarbon columns in a deeper objective. Again, very encouraging, as I said in my prepared comments, we're thinking anywhere between 0.5 billion to 1 billion oil discovery, and we will clearly integrate that into our development planning. I think I will also note that the Owowo-3 well is a good indication of how the organization and its integration can continue to enhance the value proposition. We saw the potential to add additional resources, we drilled this deeper exploration objective, and added significant more resource to the potential development here. So, I think it's a great example of the value that our general interest integration can bring to the corporation.

I had two questions for you actually. The first was around the impact of the forward statement that you have in the comments you've 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 crude kind of an all or nothing thing? Where would be the full 3.6 million barrels would be nothing? If you could just comment on that?

The first point is, as I mentioned, we're seeing almost a 25% reduction in prices on a SEC basis year-to-date. And of course, we need to wait until we get the last two data points for that calculation. But given what we're seeing at this point, we felt it was appropriate to signal the potential impact from the SEC pricing basis on proved reserves. Yes, we did add some reserves in crude oil in 2015, and then the drop we're potentially going to experience in 2016 is all due to the pricing basis. The second question, I’m sorry Jason, was related to what?

Well, it was really you referenced 3.6 billion 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, remember, it’s a very long flat plateau, so it would be all or nothing.

Sure. And are you positive on cash margin there right now?

We manage all of our assets to maximize cash flow. I will tell you that the organization has done a remarkable job across the board. Remember, if I step back a little bit, Kearl is an advantageous asset from the standpoint that we did not put an upgrader in place. We used proprietary technology in order to avoid that upfront capital investment and the subsequent operating costs associated with it. The organization has— what we are really planning to do is continue to improve overall reliability to mine operations as well as significantly reduce our cost structure there. They will continue to work on it like we do everywhere, and we manage these assets to maximize long-term return, and I’m very confident that will happen here at Kearl as well.

Maybe my first question, it’s a different slide to prior Phil's broad question. Just given the success you had adding resources at the drill bed in Guyana, Nigeria brownfield opportunity in places like PNG, pretty significant opportunities. Does that really contribute to your cautious stance so far on the asset market or the acquisition market? Maybe broad next time going to ask 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 would tell you it’s not either all or for us. We’re looking at where 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 defining our value proposition in our portfolio. You’ve highlighted some of the important resources. When we get to the point into an asset's life where we don’t think that there is much incremental value—that’s when we put it into our process of considering how else we can monetize that asset. But at the same time, we’re also very alert to where there may be some value propositions from acquisitions. I think the InterOil transaction is a really good example. We discovered a substantial resource base in Papua New Guinea and we continued to pursue our exploration activity, looking towards an expansion of the existing LNG facility. In addition to that, we saw opportunities for synergies and value propositions by acquiring the InterOil and specifically the Elk-Antelope resource that we could combine with our existing resources there. The great success we’ve had in terms of operating reliability and cost structure there puts it right at the top of the portfolio. So, think about all of our actions, Evan, as what is the best value proposition, which may become organically or inorganically.

Okay. That’s fair. And as a follow-up on Liza, maybe just more detail here on how success affects your 2017 program across your various blocks. I mean, potentially adding other rigs and any preliminary thoughts on how that affects the development plan that you filed in July? Perhaps adding a second FBSO and maybe just kind of cleaned up. Just any color on Payara or what you've learned from Skipjack?

Yes. 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 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 ahead of ourselves. We want to ensure that we are fully integrating the learnings into the regional geology, so that we upgrade our potential exploration program going forward. Regarding our initial phase development, it's been fairly consistent in scope as conveyed in the application we filed for environmental review with the government. I’ll tell you that in real-time, the organization is looking for ways to enhance value. As we progress that development planning and early engineering, we will learn more which will cause us to make adjustments. But I am very optimistic about the future in Guyana and we think we will bring a lot of value to the government and people of Guyana.

On the prospect?

On Payara? Yes, so I'd say it is a similar reservoir section to Liza, also a stratigraphic trap. Other than that, it's really too early to say much more.

It's been a number of years since people had to think about an OPEC cut and filtering through partners. Can you just remind us of the potential impact to the business, and I am thinking specifically of Upper Zakum and some other projects that are set to start up next year within that region?

Yes, Sam, I am not really good at speculating on what OPEC might ultimately decide to do. I think what's important for you all to consider is that rest assured, we are working to create incremental margin in the business. Directionally, it could impact you in several ways. One, there could be retractions, but we're going to continue to emphasize the value proposition. At this point, it's just too early to speculate on what we may or may not see from the agreement from OPEC parties.

Understood, thanks very much. Then I am curious about this evaluation you mentioned in the press release concerning 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. Is this new chemical complex potentially a reflection of a view 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, like most everything in ExxonMobil, all start with our view on the long-term energy demand picture. When you think about chemicals, the chemical demand growth based on our latest outlook is projected to be about 1% above GDP. From an ethylene perspective, we are expecting that chemical demand will grow—and you need to add about 5 million tons per annum of new capacity per year. To put that into perspective, that would be three to four world-scale crackers per year. So that really is an asset of the value proposition. As you know, we are expanding the Baytown complex to add another 1.5 tons per annum of ethylene capacity, and a corresponding investment at Mont Belvieu is adding the derivative units to produce ExxonMobil's high-value metallocene polyethylene. Additionally, we announced a potential joint venture with SABIC to jointly own and operate a complex in the U.S. Gulf Coast that would notionally produce ethylene of about 1.8 million tons per annum. Corresponding derivative units would also be built alongside that. The value proposition is there; we are making world-scale investments in this and it's a very strong component of our chemical business.

So, Jeff, the new CapEx guidance seems to be following a trend that suggests it goes lower again next year, but you've also said that in a recovering environment, you could quickly pivot back to unconventionals in the lower 40. I think the number I have in my head is an incremental 200,000 barrels a day net to Exxon by the end of '18. Can you just walk us through where you stand on making that decision and whether I'm characterizing it correctly?

So, if you recall back in March Analyst Meeting, we provided an outlook through the end of the decade for our capital investment program. If you remember, we had 2017 flat to down. The experience we’ve realized during 2016 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 are two components to our investment program: there’s a very large component regarding our long-cycle investments; nothing has really slowed down in that regard and how we're working through maximizing the value proposition for those investments. As I said earlier, we're trying to take full advantage of the cycle benefits. On the short-cycle side, you may recall, we talked in our unconventional program about having the ability to move fairly quickly to capture a higher price environment, on the order of about 200,000 barrels a day by 2018. We’ve got flexibility in our short-cycle program and when you think about what sets the balance between short- and long-cycle investments, it's really maintaining a program in a low price environment that allows us to continue building on our learning curve benefits. You don’t want to go much beyond that, as you want to optimize value. So, I think we're very positioned. If you recall in the second quarter of last year, during our last earnings call, we shared some statistics around our unconventional program where we continue to drop costs and have a sizeable ready inventory to move on.

My follow-up, if I may, is on Guyana again. I wonder if I could just pull a little bit to try to clear up some comments that your partner made. So really about next steps on timing. My understanding is that you’re still on location on Liza-3 looking for deeper objectives. So my question is, have you—are you done there? Have you found the water contract? And maybe comment on your partner's suggestions that the range for Liza is now at the top end of your prior disclosed range?

Yes. I’ll start with the second half of the question and that is, right now, our guidance is that we’re likely above a billion barrels, with no more detail beyond that at this point, Doug. On the Liza-3 well, we did go ahead and deepen; we were targeting a higher-risk deeper interval that had not previously been penetrated on the block. I would share with you that the results were positive and does support the presence of oil-bearing sands deeper in the section. It is still very early, and this is real-time evaluation that is ongoing, and that information will be used to integrate not only into the Liza but also into the rest of our exploration.

So, did you find your water contact or is it another appraisal well block?

We were targeting it. It goes back to the injective Liza-3 well; we were targeting water in the lower most sands, and we did encounter that water in the sand. We’re still evaluating the results from the well, Doug. But suffice it to say, we’re pleased with the results and are consistent with our earlier expectations.

Just to continue probing on the deeper interval. Is that included in the 1 billion-plus barrel resource range?

Well, to the extent that I’d say in excess of a billion barrels, yes.

Okay. I was wondering if you could just give a little more detail around Skipjack. Can you describe what happened there geologically and why it was ultimately a dry hole? And how did it inform the future drilling plan? Were prospects eliminated based on the results? 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. As we have been saying, we have numerous additional prospects as well as different play types on the block. We’re very encouraged by the success today as well as the future exploration wells. There’s really nothing more to share on Skipjack at this point. We are still completing some final evaluations 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, there was certainly a large apparent production impact in this quarter. Can you talk about what the current status is of your production there? I know you've reportedly recently lifted the force there.

Yes. When you think about our liquid shortfall versus the third quarter of last year as well as sequentially, it was all primarily driven by the downtime in Nigeria. There were two third-party impacts: the first one, I think I may have mentioned in the second quarter earnings call, had to do with a third-party rig that was trending and impacting our export line, which had an impact on our production. That issue has been addressed, and production is back on. The second one had to do with another third-party impact line. Let me just say that we are still investigating with the government; we do not believe that was accidental or due to mechanical failure.

I noticed a press release from Mozambique indicating that you've reached an agreement with a party, and I'm curious if you can share any comments about that publicly.

I know there has been a fair bit of media interest in this. There is 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 three offshore blocks in Mozambique, and we are actively working that opportunity; we're participating in a 3D survey that started up in January and is still underway.

Okay. And then my second question, I see a lot of ways that you can't get on the offense, and we've just spoken about a lot of them naturally, but maybe we haven't spoken enough about integrating 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-K for impairments is operating losses. And also, the U.S. has been an operating loss very much of 2015 and 2016. And then oil sands may or may not be an operating loss, that we didn’t get a disclosure, but let's say it is. I am just looking in your accounts; your net capitalized cost to your consolidated subsidiaries in the U.S. is $83 billion, and then in Canada is $36 billion. So maybe just walk us through the approach and how you would go through those impairments, say the trigger was there? And how would the corporation think about the type of impact you might have?

Yes. As I said in my prepared comments, we did an assessment in 2015 and in that assessment, as I was very clear in my comments, we saw that the cash flows fully covered the carrying cost of those assets. As I indicated, we are going to do another analysis, very similar to the comprehensive assessment we did in 2015, and we will report on any results. You can see some pretty good detail of what we go through and maybe look at given your comments in our 10-K that 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 are in full compliance with the rules and standards of both the SEC and the Financial Accounting Standards Board.

I guess 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. That would be at least a first approach to it. I guess I just worry that if you de-booked 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?

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's part of our normal planning and budgeting process to look at the profitability of our assets, and that sometimes causes us to step back like we did in 2015 and do a more comprehensive assessment.

So, two unrelated questions: first on global gas; could you remind us what percent of your LNG volume is not under a long-term contract? And given the slowdown in traditional Asian markets, particularly Japan, Korea, and Taiwan, are you seeing more near-term opportunities in other regional markets? And just wondering if you have any incremental thoughts on the European gas picture? And then I have a follow-up.

On the global gas side, first let me remind everybody that from our energy outlook, we have gas growing about 1.6%. LNG growth is just under three times the growth of current LNG capacity. As you go forward, we have said many times, Asit, that there are LNG businesses that are 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 Asia-Pacific market is an important market for LNG. We've got a very expansive marketing organization to go ahead and identify value opportunities. We're primarily interested in locking in long-term contracts, either point-to-point or portfolio sale. You may recall that before we take an LNG project to final investment decision, we want to lock in a majority of those volumes on a long-term contract. We’ve developed a strong reputation and credibility with 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 the Asia-Pacific to facilitate transactions with our many buyers.

And my second question is on Brazil. It appears Brazil is opening up in areas where Exxon is not really involved. Even Guyana fraction that you have now, could you update us on your latest views on Brazil?

Brazil is a country that's really blessed with large gamma resources and very high-quality resources. Remember how we approach our investment activities is 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 we can engage there on resources or exploration activities that are competitive on a global perspective to the other opportunities that we’ve got, in front of us we will certainly consider that.

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 it has been highlighted before, I mean your CapEx here is kind of well over official guidance and even at $20 billion to $21 billion for the year, it’s still relatively low and impressive at this point where you actually cover the 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 this is one quarter, but how should we think about you managing additional cash flow in 2017 in oil and gas as covers? How do you prioritize increasing activity levels versus growth and distribution and 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 first talk about capital allocation; it's one of our priorities from 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 that is prioritized for our investment program, so we can get to a point where we believe we have maximized the value proposition for investments. If we’ve got sufficient cash to invest and fund an investment program, then the remaining cash will be put forward to either stock buybacks or paying down our debt. If we don’t have enough cash, as you’ve seen us do recently, we’ll further leverage our very solid balance sheet and debt capacity to take on some additional debt because the service cost associated with that debt is more than 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 essential for us to continue investing through the cycle, and we do that in a measurable way that ensures we’re not leaving value on the table. Therefore, my comments I made earlier about optimizing value in the bottom of the cycle.

All right, thanks. Sorry, maybe the follow-up on that. You’ve mentioned earlier on the call how you’ve generally maintained a decent amount of investment level on your long-cycle type projects, but when you're looking at this point that you're pre-FID into a project, can you speak to the progress that you’ve seen on large-scale and conventional projects in terms of cost deflation or evolution of fiscal terms towards enhancing the competitiveness of this part of the portfolio? Have you seen what you needed at this point to go ahead and kick off new investment in that part of the portfolio or is that more that maybe you'll see at this plan?

Let’s bring it up from the components shown. First, I would say that we want to make sure all the learnings we get from our capital efficiency initiatives year-to-date are being integrated into those projects. We’ve talked about how we do this to reduce upfront capital investment, as I mentioned, by progressing projects in parallel so we can benefit from the learning conveniences of subsequent projects. So capturing market responses and the capital efficiencies we've built into the low price environment—as you highlighted—there comes a time when we may want to go back and pursue additional resources or reduce expression like in an Owowo, which adds additional resource to make the project investment even more robust. Lastly, technology application has been fundamental—absolutely fundamental—to our past success and into the future. If you think about where you're getting those benefits across the full value chain—from Downstream to our Chemical business, where we use proprietary technology to provide high-value metallocene to our unconventional business with fracking technology. The application of this growth in technology solutions has been a key element. Some of these projects are waiting on some of the technology work underway. So, we’ve made great progress, and I think we are very well positioned. We’ve got a solid, diverse portfolio in which we can go ahead and selectively invest into the future.

Hi, Jeff. I just wanted to—I had a question with regards to the way you look at your impairments versus the way that you look at acquisitions. Just want to square the fact that you haven't written down assets since 2015, given you've got, I suppose, a fairly constructive view on commodity prices, with the opposing side that you haven't dealt in the last year or so, given that you haven't seen attractive enough assets from the market. Can you just talk about how those two things kind of work together?

From my standpoint, there are two separate processes. Our asset management activity is a function of making sure we are capturing opportunities, as I said earlier, at a competitive charge for the existing portfolio. The objective here is to grow shareholder value, and if we think that we can acquire assets like in our oil transaction, then we can add incremental long-term value, and we will pursue those opportunities. Our determination of asset impairment, which we talked about, is a comprehensive process that we follow. As I said, there’s detail in our 2015 10-K, and it’s a separate process; it's not influencing our asset management activity.

Okay, thank you. And as a follow-up on Nigeria, you have made a number of discoveries in Nigeria and highlighted a number of things that present potential developments. Could we expect any of these to be functioned for development in 2017, and if so, which are the ones that are more progressed?

So, Anish, as you highlight, there are a number of projects in our portfolio that we've shared in our S&L. Several have gone through various stages of development planning to capture incremental value. I would tell you that just like any project, there are a lot of variables we have to address, and some of those variables may take some time. We continue to actively work with the co-venturers and the government on the Nigeria portfolio. I think the Owowo-3 well is a good example of how we've added some additional value to our portfolio and strengthened that project opportunity.

And then any of those could be sanctioned next year?

Anish, we don’t pre-communicate our FIDs, but the portfolio we share within the S&L has various stages of development planning underway. Some of them are in FEED; some are even more advanced, like Tengiz, which has been FID. But we don't provide advance guidance on our FIDs.

I guess maybe coming back a little bit on broader cash flow, CapEx questions here. People have asked the question if CapEx is troughing here. Does it go up? I guess to some extent that's going to depend on oil pricing 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, and any sort of asset disposition plans? Can you lay out any of the parameters for when we should anticipate a recovery in the share repurchase program? What do we need to see?

Well, 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 plans for long-cycle investments are progressing. When we believe those investments reach maturity, we will optimize on value, making an FID decision. Recall that we're making those decisions based on our long-term view on supply and demand. We’re very constructive on long-term energy demand, which informs those long-cycle investments; it’s not just current prices. That said, we’ve balanced it with other factors to capture incremental value in the near term, which may cause us to pace those investments out longer to fully capture the value. On the short-cycle investments, as I alluded to earlier, we want to maintain activity levels in the down cycle commensurate with the learning curve benefits we’re realizing, enhancing value across the portfolio. But it doesn't make sense to do much more beyond that. If you recognize, you want to optimize value. I want to reiterate that we're well poised to pick up on short-cycle investments, supported by the business climate, and we’ve got the flexibility to do so.

Sure. Well, the correct response on prices is always to say they fluctuate, right? But in terms of thinking about the share repurchase side of it, do you need to be at a point where you’re comfortable or you can let’s say maintain roughly flat production levels and generate free cash flow? Or how should we think about balancing production return cash flow? I’m thinking about the more normalized environment, which appears to be where we’re headed over the next year or two.

Yes. So go back to my discussion on capital allocation approach with the buybacks. That’s determined each quarter considering a number of factors including the company’s current financial position, capital requirements, our dividend requirements, as well as what we see in the near-term business outlook. It is all of those variables that inform whether we believe it’s appropriate to distribute some of the corporation's benefits back to the shareholders in a buyback. Remember, we don’t believe in holding large cash reserves if we don’t have an immediate use for them, and we’ll go ahead and distribute whatever we don't need. Now, to be clear, that consideration will also be mindful of the merits of paying down debt if appropriate.

Two quick ones, hopefully. For Liza, do you have already sufficient well data from Liza and Liza-1 and Liza-2 appraisal if you need to meet FID on any production system? Or do you need additional appraisal wells?

On Liza, as of now, we don’t believe that additional appraisal wells are required prior to the FID decision. But I would tell you that, as I said earlier, we will continue to integrate the data we’ve got, and there may be a point where we step back and say given the risk profile we want to put some additional data. Right now, it’s not planned.

Okay. On Permian and Bakken, can you tell us what is your number of rigs and what is the current production?

Yes. In Permian and Bakken, I think we’ve got a total of 10 rigs running in the third quarter.

And what's their production?

On a gross operated basis, the Permian and Bakken is about 240,000 barrels a day.

And one of your pretty large competitors was talking about the preparation of in-depth studies that they’re going to add some additional weight by the vendor. Just curious if Exxon has any preparation for increasing activities at this point?

Paul, we are—as I just mentioned a moment ago—very well-positioned to respond, and we think it's appropriate, but I'm just not going to forecast whether we plan to add anything in the near term.

Just a quick question; I was intrigued to see a news report that Exxon is considering setting up a trading organization. I was listening to the answers to the questions on LNG and point-to-point deliveries and coverage by long-term contracts. Can you foresee a situation where Exxon, rather like some of your competitors, actually takes some of the equity volumes itself from LNG development and then redistributes via other mechanisms? Because other than that, Exxon has been a point-to-point LNG player and never played in the trading or diversion game. So, I'd be interested in a comment on that?

Thanks, Iain. I’ll tell you that by and large, we're price seekers. We don’t typically speculate. We are taking positions in the markets. Beyond that, in terms of the inner workings and how we manage that going forward, there is really nothing more that I can share. We continue to be very mindful from an LNG basis—very mindful of what is of interest to buyers. I think, we remain open to the portfolio sales, but we are still very much interested in locking in those contracts on a long-term basis.

Okay, thanks. Just a follow-up, I just want to ask you a question about the long-term on Kashagan. Obviously, you're just ramping up the initial phase now, but what is the consortium thinking about in terms of going further on that? Given that the results obviously could support a much larger level of production, and given that you’ve already got the facility on-stream, what are your thoughts for the next phase?

Yes, to be real transparent, I mean the joint venture company and shareholders have been very focused—and I am sure you will appreciate this—on getting the initial phase fully up on production and matching capacity. I said in my comments that will be about 370,000 barrels a day by the end of 2017, but there is a second tranche associated with that; the subsequent capacity plateaus to 370, which is with the additional gas reinjection facility that will take us to about 450. The joint venture company, along with all shareholders, is very focused on how we move forward and maximize value, and that will include, at the right time, looking at additional resource development.

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 I want to thank you again for your interest in ExxonMobil.