Good day, welcome to the Exxon Mobil 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, welcome to Exxon Mobil'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 two. Turning now to slide three. Let me begin by summarizing the key headlines of our third quarter performance. Exxon Mobil earned $2.7 billion in the third quarter. The 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. Exxon Mobil'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 four, we provide 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, 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, chemical commodity product margins remained strong, while specialty margins held relatively flat. Turning now to the financial results as shown on slide five. As indicated, Exxon Mobil's third-quarter earnings were $2.7 billion or $0.63 per share. Corporation 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, 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. Over the quarter, cash balances increased from $4.4 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, including shareholder distributions 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 seven to review our segmented results. ExxonMobil's third-quarter earnings decreased $1.6 billion 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 million to $700 million on average over the next few years. In a sequential quarter comparison shown on slide eight, earnings decreased by $950 million 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 nine. Third-quarter upstream earnings were $620 million, down $738 million from a 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 and sales mix effects increased earnings $80 million, and 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 impact of field decline and downtime events, most notably in Nigeria due to third-party impacts.
Natural gas production, however, increased 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, and 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, benefiting from reduced operating expenses and favorable foreign exchange effects. Moving to slide 12. Sequentially, volumes decreased to 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 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 U.S. work programs. 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. To date, 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 $404 million. Weaker margins reduced earnings by $330 million. 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 $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 $46 million sequentially, where stronger margins partly offset increased maintenance activity. Moving now to slide 17. Key to 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 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 these structural advantages while ensuring high integrity in our operations. For example, by leveraging our fast drill process and flat time reduction initiatives, we realized 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 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. 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 first 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 million oil equivalent barrels, primarily in the U.S., reflecting the change in natural gas prices, offset by liquid additions 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 of currently booked reserves, such as those associated with our Canadian oil sands, will not qualify as crude reserves at year-end 2016. In addition, if these price levels persist, reserves associated with infill-like 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. You can find further details of our reserves reporting in our 2015 10-K. Now, regarding asset impairments, we follow US 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-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 was generally consistent with long-term price forecasts published by third-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-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-life 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. Moving to slide 19, I'd like to provide an update on efforts to further enhance our development portfolio and advance major projects. First, 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 one billion 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 Carron drillship will next move to the Payara exploration prospect, located approximately 10 miles to the northwest of the Liza-1 discovery. Payara 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 Owowo-3 well, located approximately 56 miles offshore Angola, reached target depth in October and discovered significant oil resources. This well builds on our successful Owowo-2 well drilled in 2012 on the neighboring license. Together, these wells confirm a half a billion to a billion-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 sq km of 3D 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 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 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 Bull Arm fabrication site in the Canadian province of Newfoundland and Labrador. The topsides, including UPM, will next be mated with the concrete gravity base 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 $16.9 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 barrels per day, and we anticipate that full-year production volumes will be within our guidance of 4 to 4.2 million 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 $14.5 billion, and we remain committed to sharing the corporation's success directly with shareholders through the dividend. Year-to-date dividend distributions totaled $9.3 billion. 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. If you would like to ask a question, please do so by pressing the star key followed by the digit 1 on your touchtone telephone. We request that you limit your questions to one initial with one follow-up so that we may take as many questions as possible. If you're using a speakerphone, please make sure your mute button is turned off to allow your signal to reach our equipment. Additionally, please lift your handset before asking your question. We will proceed in the order that you signal us and will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. We'll go first to Phil Gresh at JP Morgan.
Good morning, Jeff.
Morning, Phil.
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. I guess my first question is, given the degree that it's lower than you'd guided, are you surprised by the degree of savings that you've been able to achieve? As we look ahead, where are we in this cycle of CapEx savings?
That's a real good question, Phil. I'd say that first I just want to recognize the organization for how focused they've been on, particularly in a low-price environment, continuing to capture benefits. We, as you've highlighted, have been below our capital guidance to you all. We've been able to capture the many capital efficiencies. We've continued to effectively respond to the market and capture market benefits. Importantly, Phil, we've continued 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-$21 billion.
$20 to $21 for the full year?
For the full year.
Okay. As you look at the M&A activity, there's been a lot of M&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.
Yeah. 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 over the recent past, picking on 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 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? Then I'll have a follow-up.
All righty. Neil, 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. When you think about a 10-year average demand growth of somewhere between 1 million-1.1 million barrels per day. Since 2014, we've seen demand growth in excess of that. 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 per day in the first half. As we anticipated, we are seeing convergence in the second half. I'll tell you that as you continue to progress that, we'll probably end up this year oversupplied by anywhere from a half million to 0.8 million barrels per day of supply.
Now, of course, all this is going into commercial inventories. 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 to 600 million barrels of commercial inventory build since the end of 2013. That's got to come out of inventory at some point. 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. 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.
I 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 set you see in Nigeria, that would be appreciated.
Yeah. 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 the aerial extent, the reservoir quality, and thus our communication that we believe we are in excess of a 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 extensive 3D seismic survey. All that is being integrated into our development planning. In short, I would say we are very encouraged by not only Liza, but the prospectivity on the block. We see this as a high-quality asset for the corporation.
Pivoting over to Nigeria and the Owowo development, I 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 are thinking anywhere between a half a billion to a billion barrels of 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 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.
I think it is a great example about the value we can 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. 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. Is Kearl kind of an all or nothing thing, where it would be the full 3.6 billion barrels, or it would be nothing? If you could just comment around that.
Good question, Jason. The first point is that as I mentioned, we're seeing almost a 25% reduction in prices on an SEC basis year to date. Of course, we need to wait until we get the last two data points for that calculation. Given what we were seeing to 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 Kearl in 2015. 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?
It was really just, 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
For the most part, it is. For Kearl itself, you remember it's a very long flat plateau, it would be all or nothing.
Sure. Are you positive cash margin there right now, Jeff?
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 used proprietary technology in order to avoid that upfront capital investment and the subsequent operating cost associated with it. Just what we're really primed 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. 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.
Yeah.
We'll take our next question from Evan Calio at Morgan Stanley.
Hey, good morning.
Good morning, Evan.
Yeah, maybe my first question is it's a different slant to Phil's prior question. Just given the success you've had adding resource through the drill bit in Guyana and 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 [inaudible] always ask more for U.S., but your view on the global market and kind of perceived need and or interest.
Yeah, it's a good perspective, Evan. I would tell you it's not either/or for us. We're looking at where can we get the greatest value. 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. 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. We've continued our exploration activity, looking towards an expansion of the existing LNG facility. In addition to that, we saw the opportunity for synergies value proposition by acquiring the InterOil and specifically the Elk-Antelope resource that we could combine with our existing resources there. With the great success we've had in terms of the operating reliability and the cost structure there, it puts it right up to the top of the portfolio. Think about all of our actions, Evan, as what is the best value proposition? That may become organically or inorganically.
Okay. That's fair. A follow-up on Liza, maybe just more detail here on how success affects your 2017 well counting program across your various blocks, I mean, potentially adding another rig and any preliminary thoughts on how that affects that development plan you filed in July, potentially adding a second FPSO. Maybe just clean it up there. Just any color on Payara or what you learned from Skipjack?
Yeah. As I indicated in the earlier question that 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.
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. It's a paced 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. Very optimistic about the future in Guyana, and we think we're bringing a lot of value to the government and people of Guyana.
On the prospect?
On Payara?
Yes.
Yeah. 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.
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 the potential impacts to the business? I'm thinking specifically of Upper Zakum and some other projects that start up next year within member states.
Yeah, Sam. I'm not really good at speculating 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. Directionally, it could impact you on several ways. One, there could be restrictions, but we're going to continue to make 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 the OPEC parties.
Understood. Thanks so much. I'm curious about this evaluation you mentioned in the press release about another chemical complex in the U.S. Gulf. 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 you 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?
Yeah. Like most everything in ExxonMobil, it all starts with our view on the long-term energy supply demand picture. When you think about chemicals, the chemical demand growth based on our latest outlook has from an overall perspective, chemical growing about 1% above GDP. From an ethylene perspective, we're expecting that chemical demand will grow such that you need to add about 5 million tons per annum of new capacity per year. To put that into hardware, that would be 3 to 4 world-scale crackers per year. That sets up the value proposition. First, as you know, we're expanding the Baytown complex to add another 1.5 million tons per annum of ethylene capacity, a corresponding investment at Mont Belvieu, adding derivative units to produce ExxonMobil's high-value metallocene polyethylene.
To your question, we announced a potential joint venture with SABIC 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 1.8 million tons per annum, and corresponding derivative units that would be built alongside that. 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.
Cool. 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.
Jeff, the new CapEx guidance seems to be following a trend that you've indicated goes lower again next year. You've also said that in a recovering environment, you could quickly pivot back to unconventionals in the lower 48. I think the number I have in my head is an incremental 200,000 barrels a day net to Exxon by the end of 2018. Can you just walk us through where you stand on making that decision and whether I'm characterizing it correctly?
Yeah. If you recall back in the 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. Of course, the experiences that 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's two components to our investment program. There's a very large component being our long-cycle investments. Nothing's really slowed down in that regard and how we're working through maximizing the value proposition for those investments. As I've said earlier, we're trying to take full advantage of the cycle benefits.
On the short cycle side, you may recall, 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. We've got a lot of flexibility in our short cycle program. 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. I think we're very well positioned.
If you recall in the second quarter 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.
I appreciate the detailed answer, Jeff. My follow-up, if I may, I'm afraid it 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. Really about next steps on timing. My understanding is that you're still on location in Liza-3 looking for deeper objectives. My question is, are you done there? Have you found lowest known oil or an oil water contact? Maybe comment on your partner's suggestion that the range of Liza is now at the top end of your priority scores range.
Yeah. I'll start with the second half of the question, and that is that right now our guidance is that we're likely above a billion barrels, and really no more detail beyond that at this point, Doug. On the Liza-3 well, we did go ahead and deepen 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 the 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 the Liza but also in the rest of our exploration.
Did you find the oil water contact, or is it another appraisal well required?
Did we find an oil water contact in the deeper interval?
No, in the original section.
Well, it goes back to the objective of the Liza-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 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 billion-plus barrel resource range?
Well, to the extent that I 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 at all what happened there geologically and why it was ultimately a dry hole? How did it inform the future drilling plans? Were prospects eliminated based on that result, or was the drilling schedule changed?
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've been saying, we have numerous additional prospects as well as different play types on the block. 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. 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, or at least reportedly, recently lifted the force majeure there.
Yeah. When you think about our liquid shortfall versus the third quarter of last year as well as sequentially, it was all primarily driven to the downtime in Nigeria. There were 2 third-party impacts. The first one, I think I may have mentioned it in the second quarter earnings call. The first one had to do with the third-party rig that was transiting that impacted our export line, which had an impact on our production. 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 Eni, I'm just wondering if there's any comments that you can make in public on that.
Yeah. 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 Exxon Mobil and Rosneft were given the rights to negotiate for a PSC on three offshore blocks in Mozambique. We're actively working that opportunity. In fact, we're participating in a 3D survey right now that started up in January and is still underway.
Okay. Second question, I see a lot of ways that you can get on the offense. We've spoken about a lot of them on the call. Maybe we haven't spoken enough about integrated value growth in the downstream. There is this issue around impairments. 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 obviously the U.S. has been in an operating loss for much of 2015 and 2016. Oil Sands may or may not be in an operating loss, we don't get the disclosure, but let's say it is. I'm just looking in your accounts, your net capitalized costs for consolidated subsidiaries in the U.S. is $83 billion, and in Canada is $36 billion.
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.
Yeah. As I said in my prepared comments, Ed, we did an assessment in 2015. 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 we did in 2015, and we'll report on any results. You can see some pretty good detail of what we go through. In fact, maybe you've already looked at, given your comments in our 10-K, that really defines the process pretty clearly. I really don't have any more to share on the specifics of the mechanics that we go through. Rest assured, we're 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 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.
Yeah. 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 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.
Yeah. Okay.
We'll go next to Asit Sen at CLSA.
Good morning, Asit. How are you?
Good. Two unrelated question. First, on global gas, could you remind us what % of your LNG volume is not under long-term contract? Given slowdown in traditional Asian markets, particularly Japan, Korea, and Taiwan, are you seeing more near-term opportunities, other regional markets? Just wondering if you have any incremental thoughts on European gas picture. I have a follow-up.
Yeah. Well, on the global gas, first, let me remind everybody that from our energy outlook, we have gas growing about 1.6% and LNG growth Just under three times where we are in current LNG capacity. As you go forward, 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. 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. 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 an LNG project to a final investment decision, that we will lock in a majority of those volumes on a long-term contract. We've 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. My second question is on Brazil. It appears Brazil is opening up in the area where Exxon is not really involved. Given Guyana traction that you have now, could you update us on your latest views in Brazil?
Brazil is a country that's really blessed with a large endowment of resources, and it's really high-quality resource. Remember that how we approach our investment activities is, one, in 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. 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, Asit.
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 was highlighted before, your CapEx year-to-date is trending well below official guidance. Even at $20 billion to $21 billion for the year is still relatively low and impressive to the point where you actually covered CapEx and dividend here in the quarter. I guess first, with you effectively breaking even in the current environment, I know that it's just one quarter, but how should we think about how you manage additional cash flow into 2017 as oil and gas price recovers? How do you prioritize an increase in activity levels versus growth in distributions versus reduction in leverage?
No, 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. 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 to an 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, the remaining cash will either be put forward to either stock buybacks, share buybacks, or paying down our debt.
If we don't have enough cash, as you've seen us do in the recent past, is we'll go ahead and 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 benefited by the return we get from these investments. 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. We do that in a very measured way that we're not leaving any value on the table. 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 in the call how you guys have done a good job. You've generally maintained a decent amount of investment level on your long cycle type projects. When you're looking at this point at your 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 go and kick off investment to continue new investment in that part of the portfolio? Or is there more that you need to see at this point?
Let's break it up into a couple 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. 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 in subsequent projects. Capturing the market response, capturing the capital efficiencies that we built 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 Owowo, to add additional resource to make 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. 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. The application and the growth of these technology solutions has been a key element. Sometimes some of these projects are really waiting on some of the technology work that's underway. 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.
Right. Thanks, Jeff.
Thank you, Ryan.
Our next question comes from Anish Kapadia at Tudor, Pickering, Holt & Co..
Hi, Jeff. I 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 opposing fact that you haven't done a deal over the last year or so, given that you haven't seen attractive enough assets in the market. Can you just talk about how those two things work together?
Well, from my standpoint, there's two 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. If we think that we can acquire an asset like the InterOil transaction, that 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, is detailed in our 2015 10-K, and it's a separate process. It's not informing or influencing our asset management activity.
Okay, thank you. I had a follow-up on Nigeria. You've made a number of discoveries in Nigeria, a number of things that you highlight as potential developments. Could we expect any of these to be sanctioned for development in 2017? If so, which are the ones that are most progressed?
Yeah. 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&O. 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. We continue to actively work with the co-ventures 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.
Any that could be sanctioned next year?
Well, Anish, we don't pre-communicate our FIDs, the portfolio that we share with you in the F&O, we've got various stages of development 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. We don't provide advanced guidance on our FIDs.
Okay. Thank you.
Thank you.
We'll go next to Roger Read at Wells Fargo.
Yeah. Good morning, Jeff.
Good morning, Roger.
I guess maybe coming back a little bit to broader cash flow CapEx questions here. A 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. How do you look at it in a world where prices have increased quite a bit from the beginning of the year, then balancing cash flow, CapEx, 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. I will tell you, as we discussed a little bit earlier, that our long-cycle investment plans are progressing. When we believe those investments are at a point of maturity where we have optimized on value, 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, that's what's really informing those long-cycle investments. It is not what current prices are doing. Okay? 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. It doesn't make sense to do much more beyond that if you recognize you want to optimize value. As I responded to Doug earlier, we're very well poised to go ahead and pick up activity on the short-cycle investments if supported by the business climate, we've got flexibility to do so.
Well, the correct response on prices is always just to say fluctuate, right? In terms of thinking about the share repo side of it, 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? 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 two.
Yeah. 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. All those variables that 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. To be clear, that consideration will also be mindful of the merits of going ahead and paying down debt if appropriate.
Okay, thanks. 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 think the WCS benchmark is probably reasonable.
Okay, great. Thank you.
All righty. 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 if you need to make FID on the early production system, or you will need additional appraisal wells?
At this time, I don't think we believe that additional appraisal wells are required prior to an FID decision. 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." Right now, it's not planned.
Okay. On Permian and Bakken, can you tell us what is your number of rig and what is the current production?
Yeah. For Permian and Bakken, I think we've got a total of 10 rigs going in the third quarter.
What's their production?
Production on a gross operated basis for Permian and Bakken is about 240,000 barrels a day.
One of your pretty large competitor that was talking about in the preparation [part], 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?
Yeah. Paul, as I just said a moment ago, we're very well positioned to respond if we think it's appropriate. I'm just not going to forecast whether we plan to add anything in the near term.
Okay. Will do. Thank you.
You bet, Paul.
Our next question comes from Iain Reid at Macquarie.
Hi, Jeff.
Good morning, Iain.
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 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 other mechanisms? I don't think Exxon's ever done that. You've always been a kind of point-to-point LNG player and never played in the kind of trading or diversion game. Be interested in a comment on that.
Thanks, Iain. I tell you that, by and large, we're price takers. We don't typically speculate or take 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 what is of interest to the buyers. I think I referred to being open to portfolio sales. We're still very much interested in locking in those contracts on a long-term.
Thanks, Jeff. As a follow-up, can I just ask a question about the long term on Kashagan? Obviously, you're just ramping up the initial phase now, what is the consortium thinking about in terms of going further than that? The resources obviously could support a much larger level of production. Given the fact you've already got this facility on stream, you must be thinking about the next phase now. That would be interesting.
Yeah. To be real transparent, 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. Certainly, the joint venture company and all the shareholders are very focused on, given that we've restarted production, now how do we move forward and really maximize value? That will include at the right time, looking at additional resource development.
Okay. That's clear enough. Thanks, Jeff.
Thank you, Iain.
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. I want to thank you again for your interest in ExxonMobil.
That does conclude today's conference. Again, thank you for your participation.