Please stand by. Good day, everyone, and welcome to this ExxonMobil Corporation third quarter 2017 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 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 two. Turning now to slide three. Let me begin by summarizing the key headlines of our third quarter performance. ExxonMobil earned $4 billion in the quarter, bringing year-to-date earnings to $11.3 billion. Earnings rose 50% from the prior year period as commodity prices improved and business performance strengthened. All three business segments delivered solid results, generating cash flow from operations and asset sales that exceeded dividends and net investments for the fourth consecutive quarter.
These results were achieved as the company worked to safely bring our Gulf Coast manufacturing operations back online following the devastating effects of Hurricane Harvey. In addition, we continued capturing attractive opportunities across the value chain, from securing high potential exploration acreage, to logistics investments, to expanding chemical capacity in growing markets. I'll highlight these items in more detail later. Moving to slide four, we provide an overview of some of the external factors affecting our results. Overall, global economic growth was modest in the quarter. The Eurozone and Japan experienced slower economic expansion, along with the U.S., which was negatively impacted by hurricanes. In China, economic expansion remained steady compared to the previous quarter. The commodity price environment was mixed as crude oil prices increased, natural gas prices were flat to down. Global rig count increased slightly, driven by higher activity in North America.
Refining margins improved with stronger global distillate demand, while global chemical commodity margins softened, driven by increases in feed and energy costs. Turning now to the financial results on slide five. As indicated, ExxonMobil's third-quarter earnings were $4 billion or $0.93 per share. In the quarter, the corporation distributed $3.3 billion in dividends to our shareholders. CapEx was $6 billion, reflecting increased activity and the completion of the Jurong Aromatics Plant acquisition. As previously indicated, this facility provides added value through integration with our existing world-class petrochemical facilities in Singapore, which are well-placed to meet growing regional demand. Cash flow from operations and asset sales was $8.4 billion, more than a billion higher than the last quarter. Cash totaled $4.3 billion at the end of the quarter, debt was $40.6 billion, down $1.3 billion from the prior quarter.
Next slide provides additional detail on sources and uses of cash. Over the quarter, cash balances increased from $4 billion to $4.3 billion. Earnings adjusted for depreciation expense, changes in working capital and other items in our ongoing asset management program yielded $8.4 billion of cash flow from operations and asset sales. Note this includes a working capital build of approximately $1 billion related to Hurricane Harvey. Uses of cash included shareholder distributions of $3.3 billion and net investments in the business of $3.4 billion. Debt reduction and other financing items decreased cash by $1.4 billion. In the third quarter, ExxonMobil did not make any share repurchases to offset dilution related to our benefit plans and programs, and we don't currently plan on making additional purchases to reduce shares outstanding in the fourth quarter. Moving on to slide seven for a review of our segmented results.
ExxonMobil's third-quarter earnings increased $1.3 billion from a year-ago quarter, driven by stronger upstream and downstream results and lower corporate charges from favorable tax items. Although corporate and financing charges have been trending below our guidance range in recent quarters, we expect fourth quarter corporate charges to be toward the high end of the $400 million-$600 million guidance. I'll note that our corporate effective tax rate for the quarter was 33%, up from 20% a year ago, reflecting changes in our segment earnings mix and other one-time tax items. Turning now to the upstream financial and operating results starting on slide eight. Third quarter upstream earnings were $1.6 billion, an increase of nearly $950 million from the prior year quarter, driven by higher realizations. Crude prices rose nearly $6.50 per barrel versus a year ago quarter, while gas realizations increased about $0.60 per thousand cubic feet.
Volume and mix effects increased earnings by $20 million. All other items increased earnings $70 million driven by lower operating expenses, which were partly offset by unfavorable foreign exchange impacts. Upstream unit profitability for the quarter was $4.53 per barrel, excluding the impact of non-controlling interest volumes. Moving to slide nine. Oil equivalent production in the quarter was 3.9 million barrels per day, an increase of nearly 2% compared to the third quarter of 2016. Liquids production was up 69,000 barrels per day. Favorable volume impacts from projects, work programs, and reduced downtime were partly offset by field decline and lower entitlements. Natural gas production decreased 16 million cubic feet per day as project and work program volumes were more than offset by field decline, lower demand, and regulatory impacts in the Netherlands. Moving now to the downstream financial and operating results on slide ten.
Downstream earnings for the quarter were $1.5 billion, up $300 million compared to the third quarter of 2016. Stronger refining margins, primarily distillate and gasoline, increased earnings by $1 billion. Unfavorable volume and mix effects decreased earnings by $160 million, mainly due to lower throughput from Hurricane Harvey, partly offset by improved operations. All other items reduced earnings by $550 million, reflecting the absence of favorable asset management gains of $380 million related to the sale of Canadian retail assets in the third quarter of 2016, as well as expenses related to the hurricane. Moving to chemical financial and operating results on slide eleven. Third quarter chemical earnings were $1.1 billion, down $79 million compared to the prior year quarter. Weaker commodity margins driven by increased feed and energy costs decreased earnings by $200 million.
Higher product sales driven by increased demand, new capacity, and improved operations increased earnings by $120 million. All other items in the quarter included costs associated with Hurricane Harvey and expenses from new production units in Saudi Arabia and Singapore, offset in part by favorable foreign exchange effects. Moving now to slide 12 for an update on our hurricane recovery efforts. Hurricane Harvey had devastating impacts for many of our employees, contractors, and the communities in which we live and operate. Nonetheless, our highly dedicated people and effective operations integrity systems permitted a safe shutdown of our refining and chemical operations in Baytown, Mont Belvieu, and Beaumont. Because of advanced planning and preparation, we were able to protect the infrastructure of our manufacturing plants and were well-positioned to resume operations in a timely fashion. Refining and chemical operations at these sites are now back to normal.
Following the storm, we worked closely with our partners and customers who sell our branded products to maximize fuel supplies to consumers and emergency responders. We acted quickly to bring in gasoline, diesel, and jet fuel from other regions in the U.S. and abroad to supplement our production, ensuring the return of reliable supply to our customers. Our upstream operations, fortunately, experienced limited impacts with some offshore platforms temporarily shut in. Overall, Hurricane Harvey had an estimated unfavorable impact on third quarter earnings of $160 million and a debit of $0.04 per share. ExxonMobil employees continue to dedicate their time and resources to support the communities impacted by the storm, and we are proud our employees have provided hands-on assistance with flood relief, and we continue to support them in their efforts. Moving to slide 13.
We're making good progress on further strengthening our portfolio in South America with high potential opportunities. First, in Guyana, we announced our fifth offshore discovery with the successful Turbot well. The well encountered 75 feet of high-quality oil-bearing sandstone reservoirs and is located approximately 30 miles to the southeast of the Liza Phase 1 project. Evaluation of the discovery is underway. Importantly, this success proves a new play De-risk multiple plays in the Turbot area. We plan to drill an additional well in the new year to help delineate this discovery. Rig is now moving to the Ranger prospect, which is another new play test on the Stabroek Block. In Brazil, we are pleased to have secured an attractive offshore acreage position, winning 10 blocks in the September bid round and completing a farm-in on two additional blocks. Each of these blocks is under a concession contract.
In the highly prospective outer Campos pre-salt, ExxonMobil was jointly awarded six blocks with Petrobras. Each partner holds 50% working interest, with Petrobras as the operator. ExxonMobil was also awarded an additional two blocks in the Northern Campos Basin with 100% working interest. In the Sergipe-Alagoas Basin, ExxonMobil recently farmed in with Murphy on two blocks held by QGEP. We then jointly bid with this co-venture group and were awarded two additional blocks in the same basin. For all four of these blocks, ExxonMobil will operate and hold a 50% working interest. The 12 blocks combined offer promising deepwater exploration potential. The Campos Basin blocks are an extension of the pre-salt play where multiple world-class discoveries have been made. We have identified multi-billion barrel prospects on our own existing high-quality seismic data over these blocks and look forward to working with the government and our partners to progress exploration plans.
We anticipate commencing exploration activities in 2018 with 3D seismic acquisition, then drilling in 2019. Turning now to slide 14 for an update on our efforts to further enhance business integration for our growing attractive resources in the Permian Basin to our Gulf Coast manufacturing hubs. As you know, we continue to expand our acreage position in the Permian using strategic trades and acquisitions. Since the Delaware acquisition in the first quarter of this year, ExxonMobil has executed another five acreage transactions, adding a combined total of 22,000 operated acres for an implied cost of about $20,000 per acre. This acreage is contiguous to our core positions, making it ideal for capital efficient development using long lateral wells and adds more than 400 million oil equivalent barrels of low-cost resources. We are also expanding logistics access and flexibility to capture value from wellhead to premium fuels and chemical products.
Earlier this year, we completed the formation of the Permian Express Partners pipeline joint venture with Energy Transfer Partners. In addition, in July, we concluded an agreement with Summit Midstream Partners to create a new natural gas gathering and processing system servicing production from our acreage. Earlier this month, we further enhanced our logistics capabilities with the acquisition of a crude oil terminal in Wink, Texas from Genesis Energy. This acquisition marks ExxonMobil's first terminal in the Permian Basin to be anchored by the company's recently acquired Delaware acreage. The terminal is strategically positioned to handle Permian crude oil and condensate for transport to Gulf Coast refineries and marine export terminals. The facility is interconnected to the Plains Alpha Crude Connector pipeline system and is permitted for 100,000 barrels per day of throughput with the ability to expand.
The terminal provides crude producers with a full range of logistical options, including truck, rail, and inbound and outbound pipeline access, establishing ExxonMobil as a key midstream provider in the rapidly growing Permian Basin. These logistics investments support ongoing manufacturing investments to increase feed processing flexibility and capacity for higher value products in our downstream and chemical businesses. Our leading presence in the Permian from equity production through to Gulf Coast refining and chemical capacity positions us for world-class development across the value chain. Moving to slide 15, the graph on the right shows our progress to date compared to the unconventional liquids volumes forecast we provided at our Analyst Day in March. Our total unconventional production from the Delaware, Midland, and Bakken basins is now over 200,000 oil equivalent barrels per day.
We are currently operating 20% or 20 rigs in the Permian and will continue to ramp up to approximately 30 operated rigs by year-end 2018. We are leveraging our contiguous acreage position to drill long lateral wells targeting industry-leading unit development costs. The wells drilled in the Midland this year average about 10,000 lateral feet, well above the industry average. We continue to work with our dedicated innovation and technology team to improve our efficiency. We told you last quarter about drilling our first 12,500-foot lateral well in the Delaware, and this well was just brought on production. By leveraging our learnings in the Bakken, where we recently fractured the first of several three-mile laterals, we will start drilling our first three-mile lateral in the Permian before year-end.
ExxonMobil's best-in-class operational expertise allows for more efficient drilling and completions, which in turn enables us to enhance value through our operated investments. We'll continue to incorporate learnings to lower unit costs as we grow our unconventional liquids at a 20% compounded annual growth rate through 2025, underpinned by near-term annual growth in the Permian at about 45%. Turning now to slide 16. This summary of the corporation's year-to-date sources and uses of cash highlights the solid performance of our business segments, which enables the company to meet its commitments to our shareholders. As shown, year-to-date 2017 cash flow from operations and asset sales of $24.4 billion funded shareholder distributions, net investments in the business, and a reduction in debt. In addition, we continue to generate free cash flow while selectively investing in the business and maintaining capital discipline.
This quarter marks the fourth consecutive quarter where free cash flow has exceeded distributions to our shareholders since the significant drop in oil prices. Moving now to the final slide. I'll conclude today's presentation with a summary of our year-to-date performance. Simply put, we continue to remain focused on long-term value growth. Our integrated business has grown cash flow from operations and asset sales to over $20 billion, an increase of over 40% compared to the first nine months of 2016. Our business segments have collectively earned over $11 billion, an increase of over $5 billion compared to the first nine months last year. Upstream production volumes are within our guidance range at 4 million oil equivalent barrels per day. We continue investing in and capturing new high-quality opportunities across the value chain, but remain disciplined in capital allocation while delivering best-in-class execution.
This has resulted in total capital expenditures year to date of $14.1 billion. Finally, our year-to-date free cash flow of $13.5 billion more than covered our reliable and growing shareholder distributions of $9.7 billion. In short, we remain confident that our integrated business is well positioned to continue delivering long-term value for our shareholders. That concludes my prepared remarks, and we'll now open it up to 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 one on your touch-tone 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 are using a speakerphone, please make sure your mute function 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 we will take as many questions as time permits. Once again, please press star one on your touch-tone telephone to ask questions, and we will first go to Doug Leggate from Bank of America.
Thanks. Good morning, everyone. Morning, Jeff.
Good morning, Doug.
Jeff, the capital expenditure year-to-date continues to look quite light relative to your guidance. I wonder if you could just speak to whether you really expect to catch up at the back end of the year and also maybe the $25 billion indication you gave for 2018. I guess what's at the back of my mind is that the Permian is a very low-cost offset to whatever you think the portfolio decline is. It seems to us your capital flexibility is a lot better than perhaps your guidance suggests.
Yeah. Well, Doug, as you said, our year-to-date expenditures on CapEx is trending lower at this point. We still have our guidance at $22 billion. You may recall that our objective is to go ahead and close the transaction for the Mozambique Area 4 acreage before year-end. That's still the plan, and that was about $2.8 billion. At the same time, we have also ramped up some activity in our unconventional business. Of course, we've got the Brazil transactions that were just consummated. All that really leads us to the view that the guidance is appropriate.
To be honest, I didn't. Sorry.
Looking forward into 2018 and thereafter. Of course, we'll go ahead and provide an update before 2018 gets there. Our plan is still, and I would assume that our CapEx is linear over that timeframe. I think we showed $70 billion-$80 billion over 2018 to 2020. It is going to be in the general ballpark of about $25 billion ±. Like I said, we'll go ahead and provide an update here early next year.
Sorry, I didn't mean to interrupt you, Jeff. Just to be clear, first of all, I didn't realize that Mozambique had not yet closed. That explains it, perhaps. Would the $25 billion number next year also include acquisitions?
Well, Doug, we tend to leave a little flexibility in the budget to pursue opportunities that come up. We'll give you, if there's something that we believe is fairly close and certain, we typically would include it. If it's not at a point where we believe it's going to close, we typically do not.
Okay. Thank you. My follow-up is, not to be too predictable here, but is Guyana. Your comments on Turbot. I guess my understanding is the rig stayed on location several weeks after you disclosed the result. One wouldn't expect you to do that on a small discovery. I wonder if you could speak to what you're thinking in terms of the scale of the greater Turbot area, and maybe an update on how you're thinking about the coincident timing of multiple phases in Liza-Payara, and I'll leave it there. Thank you.
Yeah, sure. Again, as you would expect that we are very pleased with the Turbot discovery. We do plan, as I may have indicated previously, we do plan going back and drill a follow-up well in 2018. The important message on Turbot is that it did confirm a new play, a different depositional environment, and there's still a lot of work to be done. It's early days in order to assess it. There were a number of follow-up plays in this area that allows us to go ahead and better define and potentially go ahead and assess. As you go forward to your second question about the subsequent developments, what I would tell you is that obviously we're very encouraged by the results in Guyana. We had previously given you a range of about 2.3 to 2.8 billion barrels of recoverable resource.
Obviously, the Turbot result puts us towards the higher end of that. We will certainly, as we better define Turbot, we'll certainly refine our resource range. Given those results, we have had active development planning for subsequent phases in progress. I would say given the significant exploration success to date that we are considering at least 2 more phases, phase 2 and phase 3 for Guyana. We are also considering higher processing capacity for the ships. Now, of course, as we continue our parallel exploration program, that will be integrated into our development planning efforts, and things may change. Very positive progress and certainly a very important component of our portfolio going forward.
Okay, Jeff, I'll leave it there, but I just wonder if you'd give us some idea as to when you would expect to FID the subsequent phases, and I will leave it there. Sorry to extend the question.
Yeah. I certainly appreciate the interest, Doug, I really don't have a timeline at this point. We're looking at all the various options, but given the progress we've made, you can appreciate with the phase one development, that was a best-in-class five-year from discovery to startup. The extent that we can continue to capture the, if you will, design one, build many concept, we want to keep on a fairly good pace going forward. Okay?
Thanks, Jeff.
We'll now go to Doug Terreson from Evercore ISI.
Good morning, Jeff.
Good morning, Doug.
Around this time of the year, companies often reassess strategy and pay incentives to reflect changes in competitive and corporate governance environments. On this point, ExxonMobil has historically emphasized returns on capital employed and free cash flow and shareholder distributions. These metrics have very strong correlations to total shareholder return, which is obviously a good thing, especially in relation to some of the growth metrics. Simultaneously, ExxonMobil stock is flat versus a decade ago, and relative performance versus energy peers is mixed. This kind of begs the question whether a change in the mix or weightings of incentives is needed or whether a more challenging peer group, which might include S&P 500 as a peer has done, might be beneficial to shareholders, too.
Can you comment, Jeff, on how the company thinks about these issues given the performance of the stock over the past decade and how important this topic is internally in the grand scheme of things?
Yeah. Well, Doug, as we've talked in the past, I'll just reinforce for the broader group that it is very important. The fundamental principle for our executive compensation structure is to tie a large component of the compensation to the same performance that our shareholders will experience.
We have one of, if not the longest, incentive programs in terms of vesting. Again, that whole ultimate compensation is driven by how the stock will ultimately do. As you know, we're in a business that has very long cycle times on returns because of the magnitude of the investment. We want to make sure that we hold our executives to the decisions that they made over a long period of time. We have a very large part of the compensation that is performance-based that is tied directly to the share's performance. As you said, there are other parameters that the board considers. Return on capital employed and safety performance are two of the seven key criteria.
Yeah. No, you definitely seem to be using the right metrics. I just wonder if the weightings could be reset or what have you. Anyway, I also have one other question, Jeff. You guys announced a pretty meaningful asset sale, if I read this correctly. Can you talk about how it affected the published earnings number of $0.93 per share in the quarter?
You mean the overall asset proceeds of the
Yes. Yes.
It was-
Were there any gains and losses we should know about that were meaningful?
Overall from an earnings impact, it was actually a quarter-on-quarter decrease.
Okay.
A quarter-on-quarter decrease on earnings by about just over $300 million.
Okay.
On the overall proceeds in the release, it was about $850 million. A lot of that in the third quarter was really associated with the receivable that we had due in Papua New Guinea.
Okay. I see.
Okay.
Okay, Jeff. Thanks a lot.
All right. Thank you, Doug.
You're welcome.
Our next question comes from Evan Calio from Morgan Stanley.
Hey. Good morning, Jeff.
Good morning.
Yeah. Maybe another strategic question to start. Peak oil demand driven by EV penetration has increasingly captivated investor attention, and it does represent a medium to longer term challenge. I know that you expect, on your macro work, to see demand growth for decades yet. Has the risk of peak oil demand altered in any way? How is that considered in your gating process for both upstream and downstream products, projects, sorry. Especially given the depth in your portfolio?
Yeah. Evan, this is a very important question and one that probably can take a lot of time to describe, but for us, it really starts with the annual update of our energy outlook. That is fundamental to providing us the insights around our business strategy and our investment planning. If I very quickly summarize that oil demand is primarily driven by three components, light-duty vehicle consumption, heavy-duty consumption, and petrochemicals. What's really driving that growth are the latter two, petrochemicals and heavy-duty consumption. Right now, there's not a sufficient alternative to replace those energy sources because of the energy intensity requirements. Now, our energy outlook assumes on light-duty vehicles that we will reach a peak in gasoline demand and come down, and that's driven by two things. It's driven by efficiency of ICE, of internal combustion engines, as well as greater hybrid and EV penetration into the marketplace.
The bottom result of all this is that we do look at variations in the peak or in the EV penetration, and if you look at our forecast right now, we have, by 2040, the fleet is about 6% EV. If you were to increase that by 50%, that would have a liquids demand impact of about half a million barrels a day. Not substantial when you think about a overall oil demand of over 100 million barrels a day at that point. Certainly something that we keep a very close look at as we think about our research and development activities, as well as building the strategy.
A key element of all what we've been doing in this area is, and you've heard us talk about it, is how we are making strategic investments today in order to upgrade those gasoline molecules into higher value products like distillates and lubricants.
Great. I appreciate the color. Second one. On a U.S. onshore basis. Exxon is one of the fastest accelerators here of growth. You've gone from 16 to 25 rigs, added four in the Permian just since mid-year, your plan's here to add another 10 by 2018. I guess particularly as it relates to the Permian, are you seeing any deterioration in equipment or completion crew quality that is being highlighted by some smaller operators? Are you able to fully mitigate or offset some of those pressures? Given your global sourcing advantage.
Yeah. No, it's a good question because anytime you come off a very low cycle like we've just been through, you have to be very mindful of the crew qualifications and the equipment capability. Remember, Evan, that even in that low cycle, we maintained a fairly active rig program in the onshore U.S., and that is because of we want to maintain that learning curve benefit, and we want to make sure that we're taking full advantage of the market at that point. Therefore, as we ramp up, we've got a very strong fleet of service providers. As we add additional rigs, clearly the partnership that we've got with our service providers, they understand what the minimum standards are. What you want to avoid is all that rework associated with execution shortfalls and quality shortfalls and quality performance.
There is nothing material that I would point to at this stage, but it's something you got to watch very carefully as you go into a ramp-up phase, especially in areas where there's a lot of activity.
Great. Makes sense. Thank you.
We'll now go to Phil Gresh from JPMorgan.
Yeah. Hi, good morning, Jeff. Just first question, I just wanted to clarify the comment on the asset sale gains and earnings. You mentioned the quarter-over-quarter, but could you give us the absolute number? I know downstream, we didn't have the gains from last quarter, but what was the absolute upstream gain?
You're asking for in the quarter or quarter-on-quarter?
In the quarter on an absolute basis.
The absolute gain was almost $80 million in the quarter. Most of that was in the upstream.
Okay. Got it. Thank you. Second question is on the CapEx that was asked about before, looking towards the longer term. You were talking about $25 billion ± in a given year. I think when I asked about this last quarter, you did seem to suggest maybe it'd be a bit more of a linear path, lower and then kind of ramping in the out years. Is that still how you think about it, or would 2018 be more in that $25 billion ±?
Yeah, Phil, I think it's probably best to wait until we get to the next phase of communication around our forward investment plans. It's going to be in where we are in 2017 to around that ballpark. As you know, we've picked up a number of very attractive new assets that we're going to get after right away. That needs to be integrated into our forward investment plans.
Okay. Got it. You made a comment that you will not be doing buybacks to offset dilution. I think in the third quarter, it tends to be lumpy, it appears. Maybe you can just comment on that and the decision not to do that.
Yeah. There's two components. One is the purchase of shares to offset dilution for our benefits plans and programs, and that is lumpy. That happens usually, I believe, in the first quarter timeframe. The second component of that is our buyback program. As we've talked previously in our capital allocation, the way we think about it from our sources of funds, the first things that they're being funded are our dividends and our investment program. If there's any cash left at that point, given that the corporation does not want to hold large cash reserves, it's at that point that we will look for what the next best thing is. It may be if we have some debt maturing, we'll pay that debt down. On a quarterly basis, we'll make a decision on whether we go ahead and buy back some shares.
I'll say, Phil, that decision is a function of number of factors. One being the current financial position of the corporation. As I said, both our CapEx and dividend requirements, as well as what we see in the near term in terms of the business outlook. It's a decision that ultimately is made on a quarterly basis.
Okay. I'll leave it there. Thanks.
Thank you.
I will now go to Roger Read from Wells Fargo.
Yeah, thanks. Good morning.
Good morning, Roger.
If we could come back to the Permian, the comment about 10,000 foot average laterals now going to 12.5 or at 12.5, then the idea of 15. Can you give us an idea of maybe what you've done pilot-wise to this point that gives you confidence that's the right direction to go? Just because as you go longer laterals, more things can go wrong. Since you do have the acreage, maybe an idea of the performance you're seeing out of those longer wells relative to, say, 10,000 or less.
Yeah. It's a good question. You're really honing in on a key element of our overall strategy. I'll start with, it's probably becoming much clearer to the group what the value chain strategy that we've put in place for the Permian. We've built up a very large contiguous acreage position that really allows us to leverage the strength of our technology capability. For us, I'll be real clear, it's not about just how we execute. It's all about how do we extend best-in-class performance. Clearly, what we're trying to do is leverage our full technological capability to go ahead and achieve the lowest unit cost, and then capturing the highest value from the barrels through the full value chain, ultimately to the customer. Okay? What have we done is, we have recently drilled several wells in the Bakken on a three-mile laterals.
The first one has been completed now. These are very long wells. We want to make sure that we get good inflow performance across the full lateral length. We drilled the first well in Delaware at 12,500 feet. That well's just coming on right now, and we're getting ready to drill a three-mile lateral in the Permian as well. We got a very focused research effort on this from the reservoir all the way to the hardware, and we're really looking at how do we make a step change in the ultimate development here.
Okay, great. Thanks. Just as a follow-up back to the earlier question on CapEx, if we make the adjustment for the, let's just assume the Permian acreage was the big change Q2 to Q3, it implies that your overall CapEx was fairly stable Q2 to Q3, and then you have the Mozambique in front of you. Is there any other than the comments about higher drilling in the lower 48, anything else that we should think about that steps up as we go into year-end, first part of 2018?
Yeah, let me just correct you. On the increase in the third quarter, that was primarily driven by closing the acquisition for Jurong Aromatics. Okay?
Oh, I'm sorry. I was talking upstream CapEx only.
Oh, okay.
$2.8 went to roughly $3.2, and the math works out that that's the Permian. Obviously, you've got plenty of things moving around, but I was just trying to understand, if that is the case, then the step-up, even if we adjust for Mozambique, still has to be fairly significant in the latter part of this year. I was just wondering what else was going on as we walk our way into 2018 other than an increase in lower 48 activity.
Yeah. Well, probably the biggest piece is the increase in the lower 48 drilling, predominantly in the unconventional. Just to remind you, we also have four major projects underway that a couple of them are getting close to a startup stage. It's primarily project spending, it's the ramp-up in unconventional, and then our base four program in the upstream.
Okay. Thank you.
We'll now go to Sam Margolin from Cowen and Company.
Hey, good morning.
Good morning, Sam.
Would love to get your assessment of the LNG market right now, considering it ties back to a couple of the acquisitions you made over the past year plus, and you did mention that some of the capital ramp is going into those new assets. The market's been really quiet over the course of all of 2017. Not a lot of new FID activity or reports of buyers really looking to accelerate of commitments. I wonder how much of that is due to the wall of supply that's coming on between now and 2018, and if you think that can pick up as the second half of next year emerges, or if this quiet period might last a little bit longer, and how that might affect some of your timing around those new big global gas assets you have.
Well, Sam, again, I'd start with our energy outlook, where we've got gas growing from 2015 to 2040 at about 1.5% per year. A pretty sizable component is our LNG business, and that's growing probably about two and a half times over that timeframe. Just like any type of commodity, we're going to have periods of oversupply and periods where there'll be insufficient supply. I think everybody's well aware there's a number of projects that have come on that are ramping up. Others will be starting up, and that's likely going to provide a period where we'll have oversupply to, say, the mid 2020s. As we think about the very large, very diverse portfolio we have that potentially could be LNG projects, we're moving all of them forward at the pace consistent with where the project is in its maturation timeline.
The objective is to move all of them into a final investment decision. We recognize they're not all going to go at that same pace. The key here, the very important message here is we've got to be on the far left side of the cost of supply curve. We have got to be the most cost competitive out there in the market in order to attract that demand growth that I was talking about.
The follow-up then, I guess, because this hasn't been apparent, by the way the market has progressed over the past year or so is, do you think that there'll be opportunities for you to get commitments from buyers at the scale that you might need to FID some of these projects, even if the market at that time is oversupplied? Are you seeing from your customers a look out into that post-2022 timeframe when the market's more balanced and they can sign up commitments out in the future, or do they need to see more near-term evidence of tightness before they move?
Well, I think it's a mix of both. I think, the buyers are looking far out. Obviously they need that supply. They need to make sure that they are well-positioned, for their standpoint, to competitively capture that supply. I would just remind everybody that we have underpinned our past LNG project funding decisions with long-term firm contracts, and we all know that the market continues to evolve, adding more flexibility in commercial terms on shorter durations. While our objective remains to secure commercial certainty to underpin these large funding decisions, it's more likely that projects in the near future will be based on a hybrid of sales. Although that doesn't diminish our interest in locking in long-term firm contracts.
All right. Thank you so much.
Thanks, Sam.
We'll now go to Paul Sankey from Wolfe Research.
Hi, Jeff. There's a little bit more Permian disclosure that's being referenced. When I look at the data that you've given here, you added 22,000 operated acres, more than 400 million oil equivalent barrels. Would I be mistaken in assuming that you spent about $400 million in the quarter based on the statement that you paid about $1 an oil equivalent barrel? Would I be even more mistaken if I said that that was about $18,000 an acre, or is that-
Well-
just too much inference?
That's an implied cost. The reason I say that, Paul, is because the five transactions we're talking about were both cash and trades, so there were a number of non-cash trades that were in there as well.
Okay. All right, that's fine. It's interesting that you're talking about these much longer laterals, the 10,000 feet, then you're saying that you're going to be drilling a three-mile lateral in the Permian, but you've actually just completed one in the Bakken. I think that's what I heard, correct?
That's right. We actually drilled, I think it's four in the Bakken, and we've completed the first one.
Great. Thank you. If I look at the slide, and this is obviously slide 15, the implication of the very impressive growth forecast that you have is that you have all the acreage you need, more or less, to achieve the very aggressive volume growth that you're going for, insofar as you identify the acreage that's going to provide that. Again, is that too much inference, or is that a fair sort of?
No, Paul, that's a good clarification. The volume that we have on the slide 15 is really based on existing acreage that we have. As I said in my prepared comments, one of the things that we're doing in a lot of our transactions is they build on, they bolt on to existing acreage that we have. Directionally, I could share that one of the strategies is to continue to grow that contiguous acreage.
Got it. Okay. That's helpful. Thanks a lot. Jurong was reported in the press to be a $1.7 billion sale. I think that's public information. Is that about the number? I'm trying to get obviously to the clean underlying CapEx.
Yeah. Paul, unfortunately, we're bound by a confidentiality agreement on that with the sellers.
Understood, Jeff. Then the last one from me was that you did mention that you've been trending lower in corporate and other expenses, but there'll be a bounce in Q4. I just wondered what that was about. It's a bit of an arcane question for you, but thanks.
Yeah. Well, as you know, corporate finance costs have a lot of variables in them. I would say that probably the largest part of it, Paul, will be an absence of some of the favorable items that we're seeing in this quarter.
Fair enough. Thank you.
Thank you, Paul.
Our next question comes from Ryan Todd from Deutsche Bank.
Great. Thanks, Jeff. Maybe just a couple quick ones. On the Permian disclosure that you have there, you talk about the plan to increase from 20 Permian rigs to 30 by year-end 2018. Is the assumed pace of activity growth the same as what was implied in the 2017 Analyst Day earlier this year?
I would tell you that it's picking up a bit. I'll just make sure I want to clarify, for everybody that these are operated rigs. This does not include non-operated rigs that we participate in. The volumes itself is our total net production. The rig count, so I mean, it's comparable to what we had originally planned when we detailed out the basis for the acquisition, and thus what we shared with you in the March analyst.
How do you think when you look out over that multi-year period, how much does commodity price figure into that? I mean, you tend to I know you're executing a long-term-
Yeah
Plan which is based on value creation. As you think about potential upside and downside risks to that plan going forward, how much does the commodity figure in versus as you think of things like efficiency gains or cost deflation or inflation.
Well, certainly it's a factor, but remember, we're working on both sides of that equation. We're not only working on the realization, being mindful of it as we do the economics, but we're also working on the overall capital invested and the operating costs, driving that cost basis down. You may recall, in an earlier call, we provided a snapshot, I think it was in an analyst meeting, a snapshot of the economic resiliency of the existing portfolio. At $40 flat barrel, which is a reasonable lower end here, we had over 5,500 wells in the Permian and the Bakken that generated at least a 10% rate of return. A large part of them, I'd say about a third of them, generated actually better than a 30% rate of return.
Very good economic resiliency, but don't think of that as being static because we continue to work on dropping that cost. You remember last quarter, I was sharing with you all that while our average unit development cost is $7 per oil equivalent barrel, we are trying to push that down further to as far down as $5 per barrel.
That's great. Thanks. Maybe just one on Brazil. I appreciate the disclosure that you have in the slides on Brazil. Can you maybe talk a little bit about your thoughts on the acreage that you've acquired, how it would compare possibly to the upcoming pre-salt round, which I think is going on today, in blocks which I think you're potentially involved in, maybe what are your requirements from a drilling and seismic point of view over the next few years, and how it more broadly fits into your global exploration portfolio?
As you probably picked up from my prepared comments, we're very excited about the acreage position that we have. In fact, the bid round that's going on right now, I guess it's been announced now that ExxonMobil won the high bid on North Carcará as well. This has really allowed us to get into a very prolific basin that we've been looking at for some time. You all are very much aware that this is all about value for us, and we've been very mindful of making sure that while it's got a very strong resource endowment, we needed to do it on the terms that it was competitive with our existing inventory, and we're very pleased with that.
Obviously, when you think about how we high-grade the portfolio, it's all about, through our acquisitions and our exploration program, bringing in resources that go to the very top of the portfolio, then through our divestment program, monetizing the resources at the very bottom. Our full intent, as I said in my prepared comments, is to get right after the Brazil acreage. We've got some really strong partners that we'll be working with. We've already got some seismic that, as I said in the prepared comments, that we have some good sense of what's out there. We're going to get right out to, in 2018, 3D seismic, shortly thereafter, drilling. Very pleased with where we are, the potential that we've got, and yet another high-quality, deepwater resource that we'll bring our expertise to.
Perfect. Thank you.
Our next question comes from Alistair Syme from Citi.
Good morning, Jeff. It's topical that you mentioned the Brazil award that's just been announced. I'm going to guess Exxon shifted a lot of the deepwater focus in recent years from West Africa to South America. Do you think the focus on the other side of the Atlantic margin is geological-based or regulatory or really a combination of both?
Well, we keep a very broad brief of where there is high-value potential in the various basins. Remember, when you think about how we have structured our exploration program, it's primarily focusing in two areas. One being a focused exploration program on high-quality resources where we have existing operations that we can quickly leverage to get those discoveries on production in a very fast timeframe. The second area is new, big, high-value potential that's play opening. In Brazil, very strong geology. The government has evolved the fiscal basis, it's got good competitive fiscal terms. That's how we're focusing in on the exploration program.
My follow-up, Jeff, on the offshore is we're seeing a lot of deflation. Some of the recent deepwater rigs contracts have been getting pretty low. Are we at the stage yet that ExxonMobil is getting concerned about the financial viability of the supply chain that you see? If so, what are you trying to do about it?
Well, I think you do address an issue that this industry has had to deal with over the cycles. When you get in a low period, as I referenced earlier, the service sector starts getting down to their cost structure. We have got to continue to find those win-win solutions that allow the producer to achieve an attractive return, and at the same time keep the service sector healthy. One of the areas that I think ExxonMobil contributes is we develop very long, effective relationships with our supplier sector. They fully understand that the amount of activity that we can provide is a function of the value they add to the investment decisions. They have a tremendous amount of capability and innovative concepts that they have brought to collaborate with us in terms of providing new solutions for some of the more challenging resources.
I think we have a mutual objective here, and I think most of the service sectors understand that as well.
Okay. Thank you very much.
Thanks, Alistair.
Our next question comes from Paul Cheng from Barclays.
Hey, Jeff. Good morning.
Morning, Paul.
Several really quick clarification. Earlier in your presentation, when you're looking at the Permian expected growth, say, up to 500,000, 600,000 barrel per day production by year 2025. Is that based on the rig program at 30 by the end of next year and then steady at that level, or that's based on a continuing incremental growth in the rig program?
Yeah. It's really the latter, that we would see some further growth in the rig program.
That at this point, that is too early for you to comment that what is the growth rate of the rig that you may have in mind?
No, really, it's an interesting question because remember, these rigs are getting much, much more productive. How we drill these wells are getting much more efficient. I would expect over this timeframe that we would see much greater efficiency as we continue to progress this development, as we have historically. If you look at the rig counts right now in the lower 48, while they're down more than 50%, that's not an equivalent reduction in overall activity because these rigs are much, much more productive today than they were back at the peak periods.
Sure. Second question that in the press release, you also mentioned, the Harvey impact is $160 million. Just want to clarify, is that represent only the cost associated for the repair, or this is also include the lost opportunity cost?
It includes two components. It includes the expenses as well as the lost volume. That $160 million, as we had in the press release and as I talked about previously, equates to about a $0.04 per share hit.
On Turbot, the next well you're going to drill next year, is that appraisal to the Turbot discovery itself or is going to test on the greater Turbot area, other structures?
On the existing resource, it will be a delineation of the existing resource. Anytime you drill, remember, this is a large area with a very small well bore that's gone through it. These are generally stratigraphic traps, it's about making sure that we test these multiple traps that we've seen in these accumulations. It's going to have several objectives as we go forward. In the general Turbot area, there are several other prospects that, given that we have now proven the play, we need to go ahead and integrate those learnings into our forward rig schedule.
Final one, the 22,000 net acre, the five concessions that you take. You mentioned that it's about $20,000, that's roughly about $440 million. Should we assume that the increase from the second to third quarter in the U.S. CapEx is all related to this? Because if you back out $440 million, it actually means that the CapEx in U.S. actually is slightly down sequentially.
No, actually, that's not the case, Paul, because as I responded to Paul Sankey earlier, that is a combination of both cash as well as trades that we made.
I see. Okay.
There were some non-cash transactions there.
You still have a net increase of 22,000, right? Or that the 22,000 is the five transaction.
No.
It's not a net increase.
That's a net increase of 22,000 in the Permian.
Right. If it is a net increase, even after you have the trade, you're still not. That's fine. We can get it offline. Thank you.
Yeah. Don't think that the trade involves just Permian assets.
Yep. Understand. Thank you.
Okay.
We'll now move to Blake Fernandez from Scotiabank Howard Weil.
Hey, Jeff. Good morning. It's late in the hour, I'll just keep it to one question. I wanted to just shift gears a bit to European gas. Last quarter, that came off pretty dramatically, and it looks like it's remained depressed. I didn't know if you could just help us, ways to think about modeling that going forward. I know seasonally, you would typically have an uptick in the 4Q, any thoughts on that potentially returning at some point to next year or so?
There really are two components on the European gas. Obviously, as you already pointed out, seasonal demand impacts, which would turn around in the fourth quarter or start to turn around in the fourth quarter. Then the second, I'm thinking it was about a 90 million cubic feet a day impact associated with the regulatory cap on the Netherlands.
And-
As well, I think, Blake, there was some downtime in the U.K.
Just so I'm clear on that 90 million a day, is there any outlook on that potentially changing into the future? Should we just view that as pretty much out of the volume mix going forward?
Well, NAM is in active discussion with the government. I really can't speculate on how that will play itself out over time.
Understood. Thank you.
Okay.
We'll now go to Jason Gammel from Jefferies.
Thanks. I just wanted to come back to the point that you're making about enhancing Permian across the integrated value chain. Obviously, been building a big upstream position and already have the downstream position on the Gulf Coast. Can you talk about appetite for owning midstream assets? I guess I'd put that in the context of the terminal acquisition of Wink. What would you consider strategic that you would want to own with obviously your low cost of capital, and what are you willing to contract out?
Yeah. Jason, thanks for highlighting that because that's really the key message that we wanted to convey as it relates to our Permian. It's just not a pure Permian play. It's the full value chain from resource all the way to molecules to the customers, whether it be refined products or chemical products. As you heard in my prepared comments, one of the things that we continue to look at is where is the value leakage across that value chain, and do we add value in that? If we do, that's what will play into our strategy of how we capture incremental assets along that value chain. On the Permian, we've got very strong Gulf Coast manufacturing facilities. We have a very strong Permian resource position. We've picked up the flexibility in the logistics system through the pipeline transactions that we've made.
We've now got this oil terminal that gives us control and value capture. We will continue, like we do in all of our assets, by the way. We'll continue to look at how can you further strengthen that value chain proposition that we or our shareholders are capturing a majority of the value there. Now, there may be some things along that value chain that we just don't add value to, and we're okay with someone else providing that missing piece in the value chain and getting value for it. I think you get a better line of sight of what we're doing in terms of our value chain management.
Okay. Thanks for that, Jeff. Just the second one, if I could please. Now that Jurong transaction's been completed, can you give us some idea of how to think about the incremental profitability from the chemical business? I know we've got the PX volume, and we can take that times margin, but can you talk about some of the synergistic benefits that you get from that transaction when you combine it with your existing Singapore assets?
Yeah. I think probably the best guidance we've got from a quantification is what you just said in terms of the additional aromatics that we're picking up from it. Remember, it's about 65,000 barrels a day of fuel coming from that facility as well. Of course, the value proposition for us was not only the added value we would get from what the market currently values the asset from because of the unique contributions we think we bring to it, but also the synergies between the Jurong aromatics site and our big Singapore manufacturing facilities. Probably the biggest part of that is logistics. Leveraging the logistics capability of that site for the full integrated site. We've not put numbers out there externally on that.
Okay. I guess I'll just make some guesses then. Thanks, Jeff.
Biraj Borkhataria from RBC Capital Markets has our next question.
Hi. Thanks for taking my question. I had two. The first one is on Mozambique. Could you just talk through the steps from now until closing and any significant things you need to close it by year-end and if there's any risk to that slipping into 2018? The second one is just on the Carcará acquisition that was announced just now. In the press release from one of your peers, there are some contingent payments. I was wondering if you could just detail whether these are just related to the oil price or anything else that you can highlight. Thank you.
Okay. On the first one, on Mozambique, it's fairly simple in that we need to get a number of approvals, and we're still waiting for those approvals. As to the possibility that it's spilling into 2018, there's always a possibility. Our objective right now, Biraj, is to go ahead and conclude this year. On Carcará, I'm not sure I know what you're really referring to. I'm going to have to punt on this one because I'm not sure what you're referring to.
Just the press release from Statoil says they'll get $800 million from you guys and then a contingent payment of $500 million. I was wondering what that $500 million was contingent on.
Okay. Yeah. Raj, we're bound under a confidentiality agreement. I really can't talk about the commercial terms.
Okay. No worries. Thank you very much.
Theepan Jothilingam from Exane BNP has our next question.
Good morning, Jeff. Just a couple of questions. Firstly, you have been very active in the asset market in Mozambique, Brazil. I was just wondering how you see potential offset by being a bit more active on the disposal side, particularly given some firming of prices there. That was my first question, actually. Thank you.
Theepan, a key element of our asset management program, as I said earlier, is to go ahead and monetize those assets on the bottom of the portfolio, importantly, where others see value that is incremental above what we expect that we can capture from the continued operation. We are always considering whether we can go ahead and complete that type of a transaction. If you look at, for instance, the last five years, our total proceeds from asset sales were over $20 billion. As I've said before, anywhere from $2 billion to $4 billion a year, we've historically went ahead and sold. It is very focused on making sure that we're getting the most value from each one of our assets, and if we get the right value proposition, we'll go ahead and pursue it.
It is a key element of our ongoing asset management through the various business lines.
Great. The second question I had was, coming back to the recent asset transactions, and you talked very much about having control in the Permian. I'm interested in terms of the moves both in Brazil and Mozambique to a certain degree where you've got less control. Is that a trend that we can expect more of outside U.S. onshore, that you're prepared to take more non-operated positions?
Yeah. I would say fundamentally, if we can operate, we feel like we've got the greatest value proposition to bring. That doesn't make that an exclusive criteria. If we think that there is a good value proposition and the structure of the co-venture is certainly very much willing to go ahead and allow us to contribute to the maximum extent, that's what we're going to try to go ahead and set up. The key here is the value capture proposition. The operatorship and the qualifications of those operators and our ability to make sure that we can influence the outcomes is all incorporated in that value proposition.
Okay. All right. Thanks, Jeff.
Thanks, Theepan.
We'll go to Brendan Warn from BMO Capital Markets.
Yeah. Thanks, Jeff. I'll keep this to one question, considering the timing. Just Baytown, you've obviously reiterated you haven't had too much in terms of production impacts because of Harvey, but can you just give us an update on the steam cracker and the development project there in terms of just impacts, delays, and any carryover to 2018, and just if there's going to be a slower ramp-up due to any impacts?
Yeah. Just to recap, the whole project included a new steam cracker at Baytown for 1.5 million tons per annum. Concurrently, we've invested in Mont Belvieu for the derivative units to 650,000 ton metallocene polyethylene trains. On the latter part, the first train has started up, and the second train is starting up now. We have started generating a revenue stream for that project. On the steam cracker, the site was temporarily shut down due to the hurricane. The construction activities resumed once all of our assessments were completed. Right now the plan is that we would get to mechanical completion early in the part of next year, and then production by the middle of the year.
Okay. Appreciate the update.
You bet.
Anish Kapadia from TPH has our next question.
Hi, Jeff. First question was on Golden Pass. I was just wondering, how does that fit into your U.S. integration strategy? Has the decision by Qatar to increase its LNG capacity significantly shifted your partner's focus, or I suppose your own focus in expanding production in Qatar rather than going ahead with Golden Pass?
Yeah. Anish, it's a good question. As I said earlier, we've got a number of opportunities in which we can invest in order to capture that LNG demand growth. We're progressing them all concurrently. Golden Pass obviously is another key aspect of the value chain within North American Gas. We're the largest producer in North American Gas. We continue to progress the opportunity there. As you know, after a fairly extensive period of time early this year, we received the Department of Energy's authorization for export of LNG to non-FTA countries, which is an important milestone. That happened in April of this year. We're focused on bringing together the remaining elements of the project, that being the finalizing the technical definition as well as the commercial details for a final investment decision. It is one of many opportunities that we're progressing.
Okay, thank you. I have another question. Just wanted to go back to the CapEx once again. Sorry to go back to it, but I just wanted to clarify. The way I understand the CapEx for this year, it seems like on an organic basis, if we strip out the acquisitions, it's approximately $17 billion, going up to $25 billion next year on an organic basis. Just wanted to try and bridge what that gap is. Where does the incremental $8 billion come from? The acquisition that was announced today from Statoil for approximately $1.4 billion, is that included also in the 2018 spend? Thank you.
Yeah. A couple points. One is that, remember these, when we set up a budget, there is a fair bit of flexibility. Fundamentally, what we're trying to do is live within our means. We're very focused on being selective in our investment program, maintaining our capital discipline, and there may be some things that we'll decide to slow down and replace it with an opportunity that comes in. It's not necessarily that it's 100% fixed and all of the specific budget allocations are going to be executed with whatever we came up with in our planning process. I'll give you a good example, and I think I've said it before, Jurong Aromatics specifically was not in our budget for 2017, we still believe that the budget guidance that we issued almost a year ago is still staying appropriate for sharing with you all.
There are some things that will move in and out, and as a result, there is a level of change out or dynamic change out going on in that forward projection. If you go back to the 2018 and 2020 forward look, we shared with you in the analyst presentation the key components that were driving those capital expenditures over that timeframe, that's probably the best guidance I've got for you at this point.
Okay. Thank you.
You're welcome.
We'll now go to Neil Mehta from Goldman Sachs.
Good morning, Jeff.
Good morning, Neil.
Jeff, we've talked a lot about the asset deals that you've done here, whether it's InterOil, Bass, the 22,000 acres, Jurong, Mozambique. Can you talk a little bit about the corporate M&A market? Historically, you guys have said that the U.S. E&P sector, for example, was not appropriately valued or you weren't able to identify attractive opportunities at the right price. As that sector has underperformed or other corporate deals that are out there, has that bid-ask start to close from your perspective?
I tell you, Neil, I would respond this way that we're not limiting any of our potential opportunity base. We'll keep open to where there may be attractive opportunities for us to pursue. Remember, there's two things you're trying to achieve here. One is, in anything you pick up, whether it be an asset acquisition or a corporate acquisition, you either want to get material synergy benefits or be able to add value above what the market values that asset at, or both. Ideally, both. We keep a very full look. We keep the aperture very wide on where there may be opportunities. As you've seen here in the recent past, primarily where we see the greatest value is on asset acquisitions. Now, some of those assets were held by a single company, and that's all they had.
It ended up being one and the same. Right now, what's most attractive to us has been these asset acquisitions.
No, that's great. The follow-up, Jeff, is just on your Canadian oil sands business. The ramp at Kearl has been taking a little bit longer than anticipated a few years ago. Just the latest in terms of the potential sanctioning of Aspen, recognizing that Imperial's also in a position to comment on this.
Well, clearly, I'll just say upfront, the Imperial organization has really worked Kearl very hard. They're making some really great progress. I give them a lot of credit for the progress that they're making. This is a long life asset, and we see the long-term value in it. It has not ramped up as we would've expected. We have made, as I said, very good progress in reducing the cost structure, and very focused on improving the reliability. We're bringing the full capability of the organization to bear on this. Remember, this is just not the asset. We're thinking about the full value chain benefits as well. I have the utmost confidence that the organization is going to continue to grow value on Kearl. I think job number 1 right now is to get that reliability up.
We've got some work to be done there, and we're not shy about it. We're very optimistic about where we're heading. Around future investments in the oil sands, I think I'd characterize it this way that, Neil, you've heard me say this before, in that we are really building this business to be durable in a low-price environment. That means that we've got to get the technology to the point that it is going to get the cost of supply down. That regardless of where we are in the price cycle, that we're generating a very attractive return. I will tell you, we've made great progress in terms of in situ technology and capability, and we're very encouraged by that progress, particularly in SA-SAGD. I would say that we still got a little bit further to go.
Not only are we at a point where we're able to substantially increase the overall return, but also reduce the cost, as well as reduce the environmental footprint. That's important for us as we go forward. We've got a very large acreage position. It's important that we get this thing right, and the organization's very focused on it.
Thanks, Jeff.
We'll go to Pavel Molchanov from Raymond James.
Yeah, thanks for taking the question, guys. When you're guiding to CapEx for 2018, and you talk about the $25 billion number, what's the breakdown of that between organic and acquisitions? In other words, are you baking in credit for cash outlays on acquisition activity for next year?
Yeah. Good morning, Pavel. As we talked earlier, probably the best guidance I can give you right now would be going back and looking at how we have segmented our investment plans between 2018 to 2020 in the analyst meeting. As I said earlier, if there is a transaction that we believe is very close to reaching agreement, we will typically go ahead and include it in our forward-looking investment plans, like Mozambique was for this year. Other than that, we keep some flexibility in our budget. Remember what we're trying to do here is it's all about the value proposition. We're going to live within our means. We're going to manage our CapEx appropriately. We're going to keep our financial flexibility, but we are not going to forego opportunities.
We've got significant financial capability to go ahead and pursue opportunities when they come up. I think that is a unique attribute of this corporation is that when, particularly in a down cycle, we can go ahead and respond fairly quickly when those opportunities come up. Let me say, a lot of them come up, and they come up very quickly. You have got to be able to respond. We've got the financial capability and the expertise to go ahead and create value on a lot of these things.
Great. That's it for me. Thanks, guys.
Thanks, Pavel.
Our next question comes from Rob West from Redburn.
Hey, thanks for having me on the call. In Brazil, you talked about competitive fiscal terms. What I wanted to ask you is, are those fiscal terms competitive with something like the Permian? Really what's behind the question is, as you look at new resource opportunities now around the world, be it Mozambique or Brazil or other ones, how much do the fiscal terms there have to compete with the fiscal terms in the Permian to make you want to invest?
Yeah. Rob, think about it a couple ways. One is that I think most resource owners understand that they are competing globally for investment dollars. A key aspect of that is not only the quality of the resource endowment but also how competitive the fiscal terms are. Are they globally competitive? Are they transparent? Are they stable and predictable? Fundamentally, that's what's going to set for a very attractive investment climate. Where you have seen a significant investment is generally tied to how those fiscal terms have supported an international investment program. For us, Rob, it is not a kind of either/or, that we got to do the Permian or we got to do something else. As I said a moment ago, we've got sufficient financial flexibility.
For us, it is the full package, the resource quality, the fiscal terms, and our ability to go ahead and get to market from a value chain perspective and capture value. It's always that value proposition. We are making the trade-offs on the full value proposition to make sure that we are meeting our fundamental mission here, and that is growing shareholder value with accretive investments. Our portfolio is very geographically diverse, and there is some political aspects that we've got to tie into these investment decisions. I think that's an attribute of the corporation that, once again, is very unique.
Okay. Just the first part of that question was on whether the fiscal terms in Brazil are competitive with fiscal terms in Permian. I'm not sure if you missed that one or you can't comment on it, I just wanted to go back.
No, I really don't have anything to share on comparing and contrasting specific asset fiscal terms.
All right. Let me ask another one. One point you've made before that I think has been well made is that your scale gives you better long-termism when it comes to procurement. I was wondering, in 3Q 2017, was that the case in the area of pressure pumping? Where it's pretty well-known there's been some bottlenecks that have been constraining completion activity. I'm wondering, does your scale and long-term procurement practices in the Permian, did it help you avoid any of that bottleneck in a way you can share with us?
Well, let me respond to you in a broader perspective is that it's very similar to what I said earlier, Rob, where developing these long-term supplier relationships is really critical to make sure that we're all on the same page in terms of the quality standards, the operating standards that we adhere to. When we see cost pressures, we're very quick to react to find, okay, how are we building in the value proposition in our go-forward plans, and how do we offset those potential cost increases with more unique alternatives? It may be something as we've seen very significant in the Permian, and that's technology application.
Okay.
In 2017, by way of example, there has been some inflationary pressures, largely in the unconventional business. We have been able to offset that with these cost reductions that we're seeing in our drilling program, by way of example.
Okay. The final one I wanted to ask you is on the San Patricio cracker that I think follows Mont Belvieu. Could you just quickly give us a sense of timing on that? Should I be thinking about that as something you're going to really accelerate when Mont Belvieu finishes, or is it really longer term?
Yeah. It's independent of where the Baytown cracker is. This is, again, a part of the value chain. For the broader group on the phone, this is a proposed jointly owned petrochemical facility that would be a 1.8 million ton per annum ethylene steam cracker, derivative units, monoethylene glycol plant and a polyethylene plant. As you pointed out, we've selected a site in San Patricio County. Right now, We've been working with our partner to begin the planning for front-end engineering and design work. Once we get to that point where we think we've got a good laid out plan, we've moved into permitting phase, once we get all the ducks in a row, we'll make a decision on whether we move forward with funding.
It is very well positioned on the Gulf Coast to take full advantage of the feedstock that primarily would be coming from the Permian and the Eagle Ford.
Okay, thanks for taking my questions. That's great.
Okay, Rob. Thank you.
We'll now go to John Herrlin from Societe Generale.
Yeah, hi, just two quick ones. Regarding Guyana and phases two and three, Jeff, will this be a lot like Angola, where every two years you'll roll out another FPSO system? I know it's early days, but I'm just curious.
Yeah, no, John , good morning. Very similar. If you think about my comments, you really want to get into that manufacturing mode very quickly. If you've got the resource, obviously we'll continue our exploration program, hopefully continue to grow the resource. You want to get into that manufacturing process because that will help continue to progress that learning curve and reduce your overall costs. I keep on thinking about it like the Angola program that we did on Block 15.
Okay, great. One question on Brazil. Since you're getting a little bit further away from the initial discoveries by Petrobras and all that, are you assuming that the pay zones are going to be carbonates or clastics? That's it for me.
This is early days, and like I said, we do have some of our own seismic that we're analyzing, and it's really going to be different wherever we are with the acreage that we picked up. In the Araucarias Basin, it's primarily carbonate pre-salt.
Okay. Well, you've got a lot of experience with that. I was just curious.
Yeah.
Petrobras certainly can use the help. Thanks.
All right. Thank you, John .
There are no further questions. I'll turn it back over to you, Mr. Woodbury, for any additional or closing remarks.
Well, a lot of good questions this morning, I really do very much appreciate your time and your thought that you put behind those questions. Of course, we look forward to our ongoing communications, and we do appreciate your interest in ExxonMobil. Thank you.
This concludes today's presentation. Thank you for your participation.