Good day, everyone. Welcome to this Exxon Mobil Corporation third quarter 2018 earnings call. Today's call is being recorded. At this time, I'd like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. Neil Hansen. Please go ahead, sir.
Thank you. Good morning, everyone. Welcome to our third quarter earnings call. We appreciate your participation and continued interest in ExxonMobil. This is Neil Hansen, Vice President of Investor Relations. Joining me on the call today is Jack Williams. Jack is a Senior Vice President with responsibility for the downstream and chemical business lines. As we'll discuss on the call today, we are very pleased with our performance in the third quarter. It was a quarter highlighted by strong operating performance, significant growth in liquids production, and considerable value from our integrated business model. As a result, we delivered the highest level of cash flow from operating activities since 2014. In addition, we completed several advantage projects and made significant progress on investments that will generate long-term accretive value for our shareholders.
After I review the quarterly financial and operating performance, Jack will provide his perspectives on third quarter results and give an update on several key investments and strategic focus areas. Jack and I will be happy to take your questions following our prepared remarks. Our comments this morning will reference the slides available on the investor section of our website. I would also like to draw your attention to the cautionary statement on Slide two and the supplemental information at the end of the presentation. I'll move now to Slide three, which summarizes a number of developments that influenced our third quarter performance. As I mentioned previously, cash flow from operating activities was the highest it's been in four years, dating back to the third quarter of 2014. Corporate charges for the quarter were outside the $700 million to $900 million range that we typically experience.
This was due to net favorable absolute one-time items of $420 million, primarily related to tax. It's important to note that we expect fourth quarter corporate charges to be at the high end of the normal range of $700 million to $900 million. Crude oil prices increased slightly during the quarter, with Brent up $0.92 and WTI up $1.71. Permian tight oil production increased by 17% relative to the second quarter. We continue to ramp up drilling activities in the Permian, while also maximizing the value from our integrated midstream and manufacturing operations. We had lower levels of downtime in the third quarter and stronger operating performance in Canada, where Kearl delivered quarterly record net production of 230,000 barrels per day. We also achieved a number of significant milestones on long-term upstream growth plans in Guyana and Brazil. Jack will discuss this a bit later in the call.
In the downstream, tighter supply resulted in stronger fuels margins in Europe, while wider crude differentials contributed to improved margins in North America. We successfully leveraged our midstream logistics capacity to capture significant value by moving advantage crudes from the Permian and Western Canada to our manufacturing facilities. Improved utilization from lower scheduled maintenance and better reliability also contributed to stronger earnings in the quarter. In line with our strategy to grow sales of higher-value products, we successfully started up a new hydrofiner at our Beaumont, Texas facility and a delayed coker at our Antwerp refinery. The hydrofiner will increase production of ultra-low sulfur fuels by 45,000 barrels per day using a proprietary catalyst that will remove sulfur while minimizing octane loss. The Antwerp delayed coker will increase supply of distillates and marine gas oil, further strengthening our downstream portfolio ahead of IMO 2020.
While long-term demand fundamentals remain strong in the chemical business, we experienced weaker margins during the quarter. Improved realizations were more than offset by higher feedstock costs, primarily U.S. ethane. A significant scheduled turnaround at our Singapore facility also impacted quarterly results. We continue to expand chemical manufacturing on the U.S. Gulf Coast. This included startup of the one and a half million metric ton per year ethane cracker at our Baytown, Texas chemical and refining complex. I am moving to Slide 4, which provides an overview of third quarter financial results. Third quarter earnings were $6.2 billion, or $1.46 per share, up 57% from the prior year quarter. Cash flow from operations and asset sales was $12.6 billion, including $1.5 billion in proceeds from asset sales. Third quarter CapEx was $6.6 billion.
We continue to progress investments to support our long-term growth plans, including increased activity in the Permian and the acquisition of additional acreage in Brazil. CapEx through the first three quarters of the year was $18.1 billion. If you exclude the acquisition of incremental Brazil acreage of about $1 billion, we remain on pace to meet full year guidance of approximately $24 billion. Free cash flow after investments was $7.2 billion, more than enough to cover the $3.5 billion in dividends. Debt ended the quarter at $40 billion, a $1.2 billion decrease compared to the second quarter. As a result, we have reached the lowest level of debt that we have had since the end of 2015. Cash increased to $5.7 billion at the end of the quarter.
This increase, which was above our normal operating levels, was due primarily to the timing of proceeds from the Germany retail divestment, which closed in the fourth quarter. Again, we received those proceeds the day before the quarter ended, and the transaction closed on October 1st. We do not have the earnings impact in this quarter, we did receive the cash. I will start the more detailed review of our third quarter results with a reconciliation of Upstream financial and operating performance. Slide five provides a look at Upstream results relative to the second quarter. Liquids growth contributed to Upstream earnings of $4.2 billion, a $1.2 billion increase. Gas prices increased by 7%. Crude utilizations were essentially flat, impacted by wider Permian and Western Canadian differentials. However, we look at this, the estimated unfavorable impact of those wider differentials on our Upstream was $170 million.
But given our integrated logistics and manufacturing position, that value and more was captured in the Downstream. Having the takeaway capacity that we have that exceeds our Upstream production allowed us to realize a corresponding estimated benefit of approximately $280 million in the Downstream. Lower scheduled downtime and the absence of impacts from the PNG earthquake increased Upstream earnings by $130 million. An increase in production, in addition to the volume recovery we saw from lower downtime, contributed $320 million to third quarter earnings. Other items included net absolute favorable one-time tax impacts of $370 million. Now moving on to slide six and a comparison of third quarter Upstream production to the second quarter of this year. Oil equivalent production in the quarter was 3.8 million barrels per day, an increase of 139,000 oil equivalent barrels per day.
Exclude the impact of entitlements and divestments, volumes were up 5% as a result of improved operations and a continued focus on growing volumes with the highest value. Liquids increased 3%, driven by continued growth in the Permian and improved performance at Kearl. Natural gas production was up 5%, lower downtime across the LNG portfolio, including Qatar, PNG and Gorgon. Moving to slide seven, a comparison of third quarter Upstream earnings with the third quarter of 2017. Higher prices increased earnings by $2.6 billion, driven by a $19 per barrel or 41% improvement in crude realizations and a 30% increase in natural gas prices. Again, we estimate the unfavorable impact of wider Permian and Western Canadian differentials on our Upstream results relative to last year to be approximately $360 million.
The total estimated benefit that we captured in the Downstream from our fully integrated value chain was $590 million compared to the third quarter of last year. Downtime decreased earnings by $80 million. This was largely driven by carryover from the second quarter Syncrude outage. And just to give you an update, as of mid-September, all cokers at Syncrude were back online. Other volume impacts increased earnings by $130 million. Liquids growth, largely driven by U.S. unconventional and Hebron, was partly offset by the impact from lower entitlement volumes. Slide eight provides us a comparison of third quarter volumes relative to the same period as last year. Oil equivalent production declined by approximately 90,000 barrels per day. However, and this is important, if you exclude the impact of entitlements and divestments, volumes increased by more than 60,000, with liquids production up 6%, including 57% growth in the Permian.
Gas decline year-over-year was mostly in U.S. unconventional. Again, aligned with our focus on value and our near-term prioritization of liquids growth opportunities. Lower entitlements resulting from higher prices reduced volumes, as did continued efforts to high-grade our portfolio. And the largest impacts came from the divestments of our operated assets in Norway and a number of U.S. Rockies gas assets. Increased downtime in the quarter was driven by carryover, again, of the second quarter unplanned outage at Syncrude. Liquids growth more than offset decline from mature fields. This was led by the significant increase in unconventional Permian and Bakken production and the continued ramp-up at Hebron. Improved performance at Kearl also contributed to the increase in volumes. Moving now to slide nine. I'll review Downstream third quarter financial and operating results, starting first with a comparison to the second quarter.
Downstream earnings of $1.6 billion increased by $918 million with improved operations and the capture of significant value from our integrated business model. Refining margins strengthened in North America, supported by wider crude differentials and in Europe with tighter supply. Stronger margins contributed $150 million to earnings. As previously mentioned, our integrated logistics network that allowed us to connect barrels in the Permian and Western Canada to our manufacturing facilities enabled us to capture significant benefit from wider differentials. We estimate the favorable impact of the downstream to be approximately $280 million versus the previous quarter. Lower levels of scheduled maintenance and improved reliability increased earnings by $460 million. The absence of last quarter's unfavorable foreign exchange impacts resulted in a positive $140 million contribution to earnings. Let me tell you, the absolute impact from foreign exchange on third quarter earnings was immaterial.
In fact, it was about a $15 million help. Finally, other items included improved refining yield and mix and minor asset sales gains. All right. Now moving to slide 10, a comparison of current quarter downstream or earnings relative to the third quarter of the prior year. Downstream earnings for the quarter were up $110 million. Margins had a negative impact on earnings of slightly more than $100 million. This was mostly driven by lower lubricants and fuels margins in Europe and Asia Pacific. The absence of supply tightness that resulted from Hurricane Harvey last year also impacted our relative margins. Now, before I move on, let me give you some additional perspective on lubricants margins. With higher feedstock costs and softer market fundamentals for base stocks, the negative impact on third quarter earnings from lubricants margins was more than $200 million compared to last year.
If you look at it on a year-to-date basis, we've experienced approximately $500 million in downward pressure from lubricants margins. This was partly offset, again, by our ability to successfully capture approximately $590 million of benefit across our value chain from wider Permian and Western Canadian differentials. Downtime and maintenance resulted in a $10 million negative impact in quarter-over-quarter earnings. Higher maintenance activities were offset by the absence of the volume and expense impacts that resulted from Hurricane Harvey last year. Other items reflect the impacts of the lower U.S. tax rate, benefits from minor asset sales gains, and improved refining yield and mix. Moving now to chemical financial and operating results on slide 11, starting first with a comparison of the third quarter with the second quarter. Third quarter chemical earnings were $713 million, a $177 million decrease.
This was mainly driven by higher planned maintenance, partly offset by growth in sales of higher value products. Margins decreased by $20 million as increased ethane prices impacted polyethylene margins. This was mostly offset, though, by stronger aromatics margins. Sales volumes increased earnings by $40 million with higher polyethylene demand and contribution from our new assets in Singapore and the U.S. Downtime and maintenance negatively impacted earnings by $140 million, mainly driven by planned turnaround activities in Singapore. The other items you see there included some unfavorable foreign exchange impacts. Turning now to slide 12, a review of current quarter chemical earnings relative to the third quarter of last year. Lower margins resulted in a decrease of $140 million. Higher feed and energy costs outpacing stronger realizations. Higher product sales improved earnings by $30 million, supported by an increase in sales from new assets.
Downtime and maintenance had a negative impact of $90 million. This was driven by the Singapore turnaround. It was partly offset by the absence of last year's impacts from Hurricane Harvey. Other items included operating expenses for the new assets and upcoming projects as we continue to position our chemical portfolio for long-term accretive growth. An unfavorable ForEx also had an impact on earnings. Slide 13 provides a review of sources and uses of cash. Third quarter earnings, adjusted for depreciation expense and changes in working capital, yielded $11.1 billion in cash flow from operating activities. Asset sales contributed $1.5 billion in the quarter, including proceeds with the previously mentioned Germany retail divestment, which closed in the fourth quarter. In line with our capital allocation strategy, cash flow from operations and asset sales fully funded year-to-date investments and shareholder distributions.
We've also been able to reduce debt levels, further strengthening our industry-leading financial flexibility. Cash used to fund investments and shareholder distributions in the third quarter were $5.4 and $3.5 billion respectively. Our ending cash balance of $5.7 billion was up $2.3 billion from the prior quarter. This was driven primarily by the timing of asset sales proceeds. At this time, I'd like to turn it over to Jack. He will provide some additional perspectives on third quarter performance and discuss the progress we've made on the long-term growth strategy we outlined at the 2018 annual meeting.
Well, thank you, Neil. Glad to be here today. I'd like to thank all the folks on the line today for their interest in ExxonMobil. Let me make a couple of comments about the quarter. I'll go into some more updates on the strategic progress. We're very pleased with the business progress that's reflected in the third quarter results. First, if you look at the upstream, if you ex entitlements and divestments, the net positive volumes growth versus both sequential and year ago quarters really bodes well as it reflects a contribution from just one of the five key growth areas that we talked about back in March. That's, of course, the Permian. I'd also add that the Hebron ramp-up contributed significantly as well. It's also going very well.
In the downstream, as Neil mentioned and quantified earlier, we're seeing the benefits of this integration across the value chain. We're capturing value from low-cost crude feedstock that we purchase in Midland and Edmonton for our Gulf Coast and Midwest refineries. That's enabled by the strong logistics position that we have. Of course, in both the upstream and the downstream, we're very pleased with the improved reliability. This level of performance is much more in line with our ongoing expectations. It's continued into October as well. Now, the downstream did benefit from seasonally lower refinery turnaround activity. In the fourth quarter, you should see scheduled maintenance activity more in line with second quarter levels. In the chemicals business, we are seeing some near-term impacts of recent industry supply growth, including our own, which does not change our view of the long-term attractiveness of this business.
The fundamentals continue to remain strong. Our growth plans remain on track, and that's evidenced by the recent startup of the new Baytown steam cracker. All in all, a good quarter. Now let me cover a few slides to highlight some of the progress we're making in our downstream and chemical businesses. I'll start with a reconnect in the downstream. What we talked about was the key driver for downstream earnings growth is this yield shift to grow higher value products. It's largely through the deployment of our proprietary catalyst and process technology. Now this yield shift is accomplished primarily through six advantage refining projects. Three of these are in the near term, the Beaumont hydrofiner and Antwerp coker, both of which are now online. Then the Rotterdam advanced hydrocracker, which should start up around year-end.
Just for completeness, the other three are the Fawley hydrofiner, Beaumont light crude expansion, and the Singapore integrated upgrade project. Just a couple of comments on that. When I say advantage, what I mean there is that either due to proprietary technology application or to integration benefits or both, these projects generate from mid-teens to mid-20s discounted cash flow returns. When I say primarily, in terms of primarily those six projects, those projects really are needle movers in that regard. There's also a few hundred other smaller optimization projects that are collectively having a big impact as well. As a matter of fact, as you think about the 2018 and 2019 turnarounds, in over 80% of those, the scope includes work on these small optimization projects.
I think this is really a great example of how our downstream teams are continually working to improve the performance of our assets. The other main strategic area for us is this integration across the value chains. In the Permian, we really have a unique position that's already generating additional value today. We're progressing a very attractive pipestill expansion at Beaumont, and we're further building our logistics position to capture the advantage feeds on the Gulf Coast integrated facilities. I'll talk more about that logistics in a second. On Beaumont, just a quick reminder on that project. We're adding a 250,000 barrel a day atmospheric pipestill and some hydrotreating conversion capacity. We're utilizing an existing gas plant and utility capacity, and we're replacing over 100,000 barrels a day of intermediate products that are purchased at Baytown and Baton Rouge. This project is highly attractive.
You're essentially getting a large-scale capacity addition for the unit cost of a debottleneck project. Very attractive project, and it significantly improves the Beaumont complex earnings profile. Okay, moving on to chemicals. In March, we spoke of 13 new chemicals manufacturing facilities, and these are all underpinned by these competitive advantage that we're talking about. Integration, proprietary technology, performance products, and global market access. Seven of the 13 are now operational with the steam cracker at Baytown that started up early in the third quarter. We're actively progressing projects to increase our chemical product manufacturing capacity by 40%. If I look forward, we have the Beaumont polyethylene expansion that should start up middle of next year. We're progressing a new ethane cracker in Corpus Christi, and we recently announced a plan to pursue a new liquids cracker in China.
I'll expand on these in a later slide, but I just want to leave you with the point that we're on track with our chemicals growth plan. Now for a couple of business updates. Start with the Antwerp delayed coker. This 50,000 barrel a day coker is now operational. The point I want to make here is that it is located at Antwerp, but I want to stress that it's a regional coker. In other words, we're planning to process residues from our entire European circuit at this coker. You can see on the chart that we're showing here that it's centrally located in the manufacturing center of Northwest Europe, and we can process third-party resid as well.
At the time of FID on this project back in 2014, it was not clear when the IMO bunker fuel spec change was going to come into effect, but the project was attractive based on just trend line industry margins. We knew the spec change provided potential upside. Of course, looking at the startup timing today, it looks very likely we're going to achieve that additional upside. Once we achieve stable operations on the coker, we'll be looking for debottleneck opportunities to further increase capacity in the unit. Typically, we're able to get about another 10% or 15% of more throughput over time. This coker positions us well in Europe for the 2020 IMO spec change, but we're in good shape in the rest of the world as well. With the most global coking capacity of any of the IOCs.
We're also going to offer a marine gas oil and a low sulfur fuel oil option to our customers. Of course, we'll continue to offer a high sulfur fuel oil product to ship owners who invested in onboard scrubbers. Moving on to the Permian. We are positioned well in the Permian across the full value chain. It starts with the upstream position, where we continue to see positive indicators on both the quality and the size of the resource in the Northern Delaware Basin acreage. You can see on the chart on the left that we're making good progress versus the growth potential communicated back in March. Our XTO Permian team is very excited with the results they're seeing out there in this new acreage. The vector's clearly up on the Permian developments. I was out there about a month ago.
In fact, the entire management committee and the board went out there. We even let Neil go out there with us. It was clear to see that the team was very energized. They're really starting to hit their stride. It was really good to see that operation. Still early days, but again, the vector's up there. Looking more downstream, today we have the ability to run 450,000 barrels a day of light crude in our Gulf Coast refining circuit. This has provided ample incentive to secure efficient transportation capacity for our refineries well in excess of equity production from the Permian. Currently, we have about 270,000 barrels a day of committed capacity, and that's likely going to grow further in the coming quarters. The 450,000 barrels a day is growing, too.
In addition to the Beaumont expansion, we're working on some other smaller debottleneck projects to add about another 50,000 barrels to ultimately take our Gulf Coast light crude processing capacity to over 750,000 barrels a day. In addition to our three Gulf Coast integrated facilities, we run Permian crude at 10 other sites outside the U.S., including our Singapore crude cracker. On the lower left of the chart is a chart from Mark showing the integrated earnings based on 2017 prices and margins. Year to date with the actual environment we're seeing, we've made well over $1.2 billion across this value chain. It's clear from the current environment, it's highlighting the value of our approach in the Permian.
The last thing I'd like to say is that given the growth plans we have in both the upstream and the downstream here, we're progressing a large 1 million barrel a day plus crude pipeline system with our JV partners that's going to provide long-term efficient transportation to our Gulf Coast refineries and also other outlets. FID's planned for next year with startup in 2021. We plan to be both an owner and an anchor shipper on the line. Moving on to Western Canada. Our position across the full Western Canada crude value chain. It's somewhat similar to the Permian, with strong upstream and downstream positions that facilitate the development of a really valuable midstream logistics position that ensure we capture the full value of West Can crude even when there's a large WTI WCS differential.
Just to clarify here, when I say we and our on this slide, I'm also including IOL. All the assets in Western Canada are fully or partially owned by IOL, and they're, of course, operating everything up there. Our upstream positions comprise primarily of interest in Cold Lake and including Kearl. This production is processed at the Strathcona and Sarnia refineries in Canada. Our Midwest Joliet and Billings refineries, and then all of our three large U.S. Gulf Coast integrated facilities, and all of these with heavy oil processing capabilities. During the early days of bringing Kearl on stream, we made the decision to invest in a 210,000 barrel a day capacity rail terminal in Edmonton.
That's to allow efficient unit rail transportation to the Midwest and U.S. Gulf Coast in case Canadian production growth outran pipeline capacity. As you can imagine, the utilization of this terminal is increasing rapidly in this current pipeline-constrained environment, which provides another transportation option down to the Midwest and Gulf Coast refineries, in addition to our committed pipeline capacity. Today, we're running about 100,000 barrels a day through this terminal. That should grow to about 170,000 barrels a day by the first quarter of next year. Our downstream logistics positions in this value chain are unique, and like the Permian, added a significant earnings contribution in this quarter. Moving to chemicals. The chart on the left here was shown back in March, it shows the market position of over 75% of our chemical product sales, where we're either number one or number two in the market.
Our seven new facilities that are now online have added about five MTA of additional manufacturing capacity. As shown in the red stars on the chart, they're focused on many of the products where we already have a leading market position. We continue to progress a new 1.8 MTA ethane steam cracker, along with an ethylene glycol and two polyethylene derivative units at a site near Corpus Christi, Texas. Construction of that project is pending completion of the environmental permitting process, and expected startup is in 2022. In September, we announced an agreement to pursue a liquid steam cracker complex in China's Guangdong Province to produce performance polyolefin products for the domestic Chinese market. The current plan is the unit will have a direct crude cracking capability similar to our Singapore operation.
We're growing all these new facilities with a significant proportion of performance products, which currently are about 30% of our overall chemical sales. They're growing at a rate about double that of the commodity chemical sales we're having. They achieve, due to superior performance characteristics, on average about a 30% higher price than commodity products. Now let me wrap up with sharing a few other highlights in our business, the milestones since the end of the second quarter. In Brazil's fifth pre-salt bid round, we're the successful bidder on the Titã offshore block, adding up more than 71,000 net acres and bringing our offshore acreage build to precisely 26 blocks, two-thirds of which we're the operator. In Guyana, we made our ninth offshore discovery and fourth year to date at the Hammerhead-1 well. This discovery reinforces the potential of the Guyana Basin.
As I think Neil highlighted last month, we've added a second exploration rig. In fact, I can verify that rig has now spudded the Pluma exploration well. We're also fast-tracking the Liza Phase 1 development, so the vector is certainly looking up in Guyana. Our Permian tight liquids production growth continued. It's up 57% quarter-on-quarter 2018 versus 2017. We're currently running 38 rigs in the Delaware and Midland basins. In Angola, the first Kaombo FPSO successfully started up in late July, with production expected to reach 115,000 barrels a day. The second FPSO is planned to start up in mid-2019. Moving to the downstream, our Indonesia lubricants acquisition's proceeding well. The transition with Federal Oil is on track. The expertise in motorcycle lubricants is complementing the Mobil lubricants offer. We think we're positioned well now to be a strong competitor in a growing market.
Mexico, our fuels market entry is progressing well. Recently, we've been streaming new sites at the rate of three new retail stations per week. In Germany, our retail divestment was completed October 1st, so we're moving to our branded wholesale model there. The Augusta refinery and terminals divestment's on track for completion at year-end. If the Augusta sale does close in the fourth quarter, we expect a combined earnings benefit in the downstream from both the Germany and the Augusta divestments of about $700 million-$1 billion, with ForEx movements being one factor that could impact the final earnings. Moving to chemical. Startup has commenced at our Newport, Wales Santoprene specialty elastomer expansion project, with the first production line now in service and the second line planned for startup in next year.
Our Beaumont polyethylene plant expansion, as I mentioned earlier, will take the remainder of the ethylene from the new Baytown cracker that's not going to Mont Belvieu. That's progressing well, and start is planned for mid-2019. Before I hand it back to Neil to start the Q&A, let me just wrap up by telling you that we're on track with our growth plans. We've seen a bit of upside in Guyana and in the Permian. We've hit a couple of important milestones with the Antwerp coker and the Baytown steam cracker startups. I feel good about where our businesses are positioned today and the underlying path we're on. We are all excited about the opportunities in front of us, and I can assure you the organization's working very hard on them. With that, I'll hand it back to Neil.
Great. Thank you for the comments, Jack, and I do appreciate you letting me go on that Permian trip. That was wonderful.
No problem.
All right. We'll now be more than happy to take any questions that you have.
Thank you, Mr. Williams and Mr. Hansen. The question and answer session will be conducted electronically. If you'd like to ask a question, please do so by pressing the star key followed by the digit 1 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're 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. Proceed in the order that you signal us, and we'll take as many questions as time permits. Once again, please press star one on your touch-tone telephone to ask a question. We'll pause for just a moment to allow everyone a chance to signal. We'll first go to the line of Neil Mehta with Goldman Sachs.
Good morning, guys, congrats on a good quarter here.
Good morning, Neil. Thank you.
Morning.
Jack and Neil, maybe you could start off by just talking about the LNG cadence of projects. You've got so many different options out there, whether that is Mozambique, Golden Pass, the potential upside of PNG, Qatar, I think we as an investor community are wondering what are the priorities in terms of most likely to sanction when, and how should we think about the cadence of that growth. If you just frame out how you're thinking about it and where you stand with some of the key projects, that'd be helpful.
Thanks, Neil. Let me start off, Neil, and you can chime in if you like. We are very happy with the portfolio of opportunities we have in the LNG market. At Papua New Guinea, we're building on success there with the foundation project that's continuing to achieve performance above expectations. Mozambique, a big new area for us. Large resource base. We think we're bringing some real unique expertise that we have from both PNG and in Qatar to bring to bear on that resource. Of course, here in the U.S., continuing to look at Golden Pass LNG with QP, and obviously very interested in any expansions in the North Field as well. I would say that given the low cost of supply of all these opportunities, they're all attractive. We see a growing LNG demand that would certainly allow all those projects to go forward.
Naturally, Mozambique is a little bit behind PNG in terms of the onshore trains. The offshore FLNG will make a little quicker. In Qatar, with the new trains, we would like to pursue that as soon as possible, but that may be a little bit longer term as well. In terms of the cadence, what I'd tell you is that there's other parties involved in all of those. We find them all attractive. We're wanting to pursue them all in our typical capital efficient, deliberate way. Very proud of where we are and the opportunities we have in front of us and very excited about pursuing all of them, Neil.
That's great. The follow-up I had is we've seen some increase in unconventional M&A. One of your peers doing a deal in the lower 48, and then some of the independents as well here over the course of the last week. Just wanted your latest thoughts on pursuing growth in the lower 48, whether to do it organically or to do it through transactions. Just what the bid ask looks like in the market, especially with some of the shale players having pulled back here decently over the last couple of months.
Thanks, Neil. You mentioned it earlier in your question. Let me just reinforce that from an organic standpoint, we have a very exciting growth plan. We talked about that earlier. A lot of running room. We had that big acquisition, Northern Delaware Basin, that we're now estimating over 5 billion barrels, 9 billion total in the basin. A lot to go after there. Having said that, we do maintain the financial strength to be able to capitalize on any environment we find ourselves in that might present an attractive opportunity. We continue to scan the market for all opportunities that play to our strengths. We think certainly unconventional does that. We're continuing to look.
I would say that as we think about those kinds of opportunities, we're certainly thinking about where we can really bring our development strengths to something that would have a large undeveloped aspect to it. We do like our organic growth plan. We feel like that's going to give us a lot, many years of substantial growth. As you may have noticed, our rig count is increasing the Permian and the vectors up there. We got a lot on our plate right now, but we continue to look.
Thanks, Jack. Thanks, Neil.
All right. Thank you, Neil. Our next question comes from the line of Sam Margolin with Wolfe Research.
Hey, good morning. Thanks for calling on me.
Good morning, Sam.
I guess my first question, I'm going to relay a question that I've been encountering in the investment community, and maybe you can have a better answer than I've been able to come up with. One of the fears that gets brought up occasionally is that fiscal terms internationally are sort of tightening. Renewals are challenging, especially with momentum in commodity prices, and people are afraid there's a lot of contracts that are scattered around the world that are sort of at risk, and that renewals aren't going to be as attractive.
Can you talk about how your unconventional business, if that's true, first of all, if it's not, you can just refute it, but if your unconventional business kind of functions as an offset to that, you can simply rotate capital into the U.S. where you're seeing those international headwinds and whether there's sort of a limit to that strategy, and just generally, if there's a strategic function to the U.S. unconventional business besides just short cycle volume growth at a high margin?
Okay, Sam, let me start with that, and Neil may want to chime in. On the last part of the question first around the unconventional, we do see it more than just kind of short cycle place to go invest. We do view that whole unconventional strategically and really plays to our strength with the large unconventional organization that we have. I would certainly characterize the U.S. unconventional as strategic and as a strength of our corporation. Now, getting back to the earlier part of your question around PSC extensions and terms and so forth.
What I would say is that by the time PSC extensions come up, we typically had 20, 25, 30 years of operations, and we would hope, certainly our expectation, we would hope that the resource owner recognizes the strengths that we bring at that point in time, and that we are able to progress and extend to extent the resources are required, extend those terms, obviously, with a fulsome negotiation. I wouldn't want to pre-talk about where the things are going to go and when. I would think we typically start out from a position of strength in terms of what we've delivered in terms of the value to the resource. That certainly comes into play in terms of those type decisions.
The other thing I'd like to point out is in terms of this overall comment you made around physicals starting to tighten and so forth, is when we talk about these five growth areas that we talked about back in March. Think about when those were acquired and brought into our portfolio, and the environment at the time. We basically brought all those in kind of at the bottom of the cycle where the environment was reasonable in terms of getting reasonable terms and so forth. All of those were tested hard at bottom of cycle conditions. To the extent that you think things are tightening now, it makes those resources and those projects all the more attractive.
Yeah. The only other thing, and maybe just to reiterate some of those points, Jack, we have a long history of execution. We have a good relationship with the resource owners. We tend to be a partner of choice. The diverse portfolio that Jack mentioned does give us that flexibility, Permian certainly being an example of that. The only other thing I'd say is we've successfully renegotiated multiple extensions across our portfolio in the past. I don't think there's any near-term pending concerns on fiscals. I think we continue to focus on making sure we deliver what we say we're going to deliver, that we establish those good relationships, and that certainly mitigates any of the risk you might have from deteriorating fiscals.
Thanks for all that color. My follow-up is quicker just on this theme of integration. There's obviously a lot of focus on crude takeaway from the Permian and maybe from Western Canada too. Frack has been very tight in the Gulf Coast, and you sort of highlighted it with your chemicals summary of the period. Just how you think about the full suite of integration besides just takeaway and refining, but maybe some of those intermediate stages too if you have investment plans for that.
Well, let me make a comment there. On the broader question of the takeaway capacities and these disconnects. The nice thing about being across the value chain is it doesn't really matter whether those disconnects are there or not in terms of the value we accrue to the corporation. Well, for instance, in the Permian, we'll either accrue that value with higher crude price at the wellhead, or we'll accrue that value through our midstream and downstream. We'll get that full value of those molecules all the way through the value chain to the customer. Really, I think the same thing is true in Western Canada. Now on the ethane issue and the NGL fractionation capacity. What I'd tell you on that is that that's a transitory issue, and there's more NGL fractionation capacity being built, constructed right now. We certainly see that going away.
We see plenty of ethane supply out there, and quite frankly, a lot of it's getting rejected into the methane stream right now. That's going to get resolved, and I think it's going to get resolved in a matter of over the span of 2019. I'd say that's more of a transitory sort of issue. Neil, would you comment?
Yeah. I'll just reiterate. Long-term fundamentals for the chemical business remain very strong. We look at demand over time still growing at 1% above GDP. You'll see times where you'll see cyclical pressures. We don't attempt to time when we bring these investments online. We make these investments based on those long-term fundamentals.
Thanks so much.
Thank you. Next question comes from Phil Gresh with JPMorgan.
Hey, good morning. First area I wanted to just hit was on the chemicals business, Jack. I know there were some headwinds in there from maintenance in the third quarter. We have seen some pressure for much of the year on the earnings profile in the business. It's a big area of investment for you guys. Maybe you could just elaborate a bit more on your thoughts here and just in terms of the margin outlook for the various businesses.
Sure. Neil just mentioned we do see a longer-term growing demand. Fundamentals of the business still look good. The issues have kind of shifted a bit near the year. The early part of the year, we had depressed aromatics margins. Those look much better now. Now with the U.S. ethane feedstock increases, it hurts the ethylene and polyethylene margins. There's a few near-term things going on. It doesn't change the fundamental analysis for those supporting those big investments. We still see a growing market. We think our investments are all advantaged in terms of cost of supply. We have these performance products that are unique to us that also enhance our projects as we bring them online. As we look at the fundamentals, we really still like that business a lot and like the investments that we have made and are making.
Okay. Second question, just a quick numeric one would be, you've mentioned the two asset sales in downstream and the earnings impact that you expect to see. What is the lost earnings impact from both of those assets on a go-forward basis? You guys have a lot of assets sales, and I think that's the harder part for us to figure out sometimes.
I'm not sure what the lost value is going forward. Obviously, when we look at divesting assets, we do that when someone else sees more value for the asset than we do. Again, the assumption is when we sell these divestments, we're getting more value out of them than we would if we were to keep them. I don't have a specific number on those two individual assets on what we're giving up. I can assure you that what we're getting today is worth more than what we would get if we were to keep them.
Yeah, I would concur with that.
Okay.
Yeah.
If I could just ask one last one then. On cash flows, you had a headwind from deferred taxes, and I think in the first quarter, you had a big headwind from affiliates that you expected to reverse at some point. Maybe you could just elaborate a little bit on where we would stand on that. Thanks.
Yeah, you're right. In the quarter, we did see an adjustment for the non-cash impact from those favorable one-time tax items that I mentioned. If you look full year, we will always see some timing on equity companies in terms of earnings and when the dividends come in. It's tough to predict when that will happen. I think we mentioned in the first quarter that that was the case. We have seen dividends come in from equity companies. I think another important thing to consider is these equity companies also may prioritize accretive investments over dividends. I think one of the things you're seeing and probably the biggest impact on a year-to-date basis is Tengizchevroil. Tengizchevroil is the equity company that holds our Tengiz investment, and so obviously they're prioritizing dividends over investing in that project. Tough to predict exactly when the dividends come in.
There'll always be some timing impacts. Again, we've seen some cash come in, but we're certainly supportive of those companies continuing with investments that will provide value to the shareholders.
Okay, thank you.
Good. Thank you.
Next, we'll go to Doug Leggate with Bank of America Merrill Lynch.
Well, hi. Good morning, everybody.
Hey, Doug.
Jack and Neil, I wonder if I could pick up, Jack, on one of your comments about fast-tracking Liza-1. Actually, this is a broader question on Guyana generally. Hammerhead, my understanding from your partners, could potentially also be fast-tracked in addition to Liza-1. I'm wondering if you can address where you see the guidance that you laid out for Guyana at your strategy update versus to what appears to have been fairly rapid progress in the last six months.
Yeah. On Hammerhead, the rig just moved off there. In addition to drilling the well, we did some dynamic flow testing and so forth. A little bit too early to provide any EUR estimates on that one. I think that leaves us at this estimate that's out there right now of over four billion oil equivalent barrels, up to five FPSOs peaking at 750,000 barrels a day. With Liza-1 targeting early 2020 and Liza-2 coming in behind that, we're talking to the government right now about our development plan and environmental permit, and hope to start that one up in 2022. Far behind that. We're continuing to tick on along. When you look at the time between discovery and this projection of the Liza-1 startup, it's very impressive in terms of what the industry timelines typically look like.
Sorry, Jack, just to be clear, you did say fast track, has the March 2020 date changed for Liza-1?
No, I don't think we ever said March. We just said early 2020.
Oh, okay.
You know, Doug, when you go from five years from discovery to online, I view that as fast track. That is very fast movement. That's about as good as it gets in the industry. That was why I was talking fast track.
My follow-up, guys, if I may, is also, I'm afraid, Jack, it's also an upstream question. Just going through the Permian, 38 rigs, Q2, you gave us the completion cadence. You said you brought 50 wells online in Q2. Can you tell me how that completion cadence looked in Q3 and whether you've caught up now with your rig activity, because obviously it was still pretty light on the apparent completion pace? I'll leave it there. Thank you.
Yeah. No need to apologize. I don't mind talking upstream, and I don't mind talking Permian at all. I, in fact, enjoy talking Permian. Let me answer your question directly, and then I'll expand it a bit. We brought on 58 wells in the Midland Basin and only eight in the Delaware Basin in the third quarter. You'll notice the rigs are about equal between the two basins. What you're seeing is that in the Midland Basin, there's a lot more infrastructure. We had the rigs there longer. So the timing just worked out to where we have a lot more wells coming online there than the Delaware Basin. Over time, some of that's going to switch over, some of that growth's going over to the Delaware Basin, but it's just less mature.
I think it points out the issue that I think Neil Chapman said a couple of times, and I've said it as well. It's going to be fairly lumpy coming on. We are basically doing three things. Our teams out in the Permian are doing three things simultaneously. First, we're delineating this big new acreage position we have, and like I said, that looks very promising. There is further upward vector on that resource. We already increased it from three to five billion barrels, and there's further upward tailwinds on that. We're building out infrastructure in Delaware Basin. We're spending a lot of time and energy on this infrastructure build-out. There's about 200,000 barrels a day of well pad facilities under construction right now, in addition to two major central processing facilities. We had essentially a blank canvas on this 225,000 acres.
There were not a lot of facilities out there, we're building all that from scratch, which in some respect is an advantage for us because it allows us to bring other parts of our corporation, this major project expertise to bear on this. We're going to wind up with an infrastructure there that's really unlike anything else in the Delaware Basin or in the Midland Basin, for that matter, or any other unconventional development that I've ever seen. It's going to be very capital efficient and allow us long term to have a very competitively advantaged operation.
Okay.
In addition to those two things, we're also growing production. They're also having some of the rigs dedicated to just developing where we know we have mature benches, and we feel like we know it pretty well, and we're just growing production. There's all those things going on at once. It's going to be pretty lumpy. We draw a nice smooth line, but it's going to be pretty lumpy as we go up there, but as evidenced by this quarter.
Jack, may I ask for a point of clarification real quick? I know I've got to jump off here, but Neil Hansen did promise a little bit more of a look forward on some of your commentary. If you've 50 in Q2, 58 in Q3, can you give some idea as to what that's going to look like in Q4 in your current plan?
No, I can't. I really don't know. I can just tell you the rig activity we have out there. Now, I will say one thing. A lot of those rigs have been picked up in the last three, four, five months. When you think about these multi-well pads that you drill four, five, six wells at a time and then have to come back and frack all those wells, all the facilities considerations and so forth, it's seven, eight, nine months between picking up a rig and having production online. It's coming. The activity's there. We're liking what we see, but I can't give you a number for fourth quarter.
Appreciate the answers, guys. Thank you.
Thanks, Doug. The next will go to Thomas Klein with the Royal Bank of Canada.
Thank you for taking my question. With a good quarter and strong cash generation, I'm just wondering what else you guys would need to see in commodity price or in terms of the environment to prompt share buybacks, especially in light of recent rhetoric on this from peers. Thank you.
Great. Thank you, Thomas. We did have really what was an excellent quarter from a cash generation perspective. We're very pleased with it. I think nothing's changed for us in terms of our capital allocation strategy. We're in a very fortunate position to have a really impressive portfolio of attractive accretive projects, we're going to prioritize investing in those. We've talked about how the fact that in the upstream, we're going to generate a 20% return and a 15%-20% return in downstream and chemical. That's certainly a priority. We want to continue to pay a reliable growing dividend, we've paid a growing dividend for 36 years now, and we recognize that those two things are tied together. We need to continue to invest in accretive projects so we can continue to pay a reliable growing dividend.
Now, beyond that, you've seen a little bit of it this year, we want to ensure that we have the financial capability, the financial strength that we need to take advantage of investment opportunities regardless of the price cycle. Now, to the extent we can meet that objectives and there's excess cash, we will certainly distribute cash back to shareholders. It's an important part of our capital allocation strategy. We've distributed more than $220 billion since the ExxonMobil merger, it's certainly a key factor in that. I think if you look at maybe the bigger picture, what we're trying to do is we're trying to position the company for long-term sustainable distribution to our shareholders.
That's the objective, and we think the best way to do that is to ensure that we are taking advantage of, again, a portfolio of opportunities that's probably as attractive, if not more attractive, than anything we've seen since the ExxonMobil merger. We're not going to prioritize buybacks over doing that, because what we're really focused on is long-term sustainable distribution.
Anything to add to that?
I would just say that the shareholder accretion from this investment program we have, we think, is going to be very impressive. I'd just echo that point that we have a very exciting investment portfolio in front of us.
Understood. Thanks.
Thank you.
Thank you.
Okay. The next question comes from the line of Jason Gammel with Jefferies.
Thank you very much, gentlemen. I appreciate the conversation around the coker at Antwerp. I was hoping you might be able to make similar comments about the Rotterdam hydrocracker. First of all, just the size of the unit and whether you would actually be also processing your European system and potential third-party VGO through that unit. Finally, whether you have the hydrotreating capacity there to be able to handle third-party high sulfur VGO.
Let's see. I think it's primarily handling the feeds from our refinery there in Rotterdam. Let me just give you a sense. Again, this is advanced technology, advanced hydrocracker proprietary technology, and we think we're going to generate not only about 20 KBD of high-quality Group II lubes, but also some clean distillate products as well. Due to what we already had on the ground in Rotterdam and this shift to a real lubes base stocks generating machine, this is going to have substantial impact on the Rotterdam refinery profitability. Now, we talked about, and Neil talked about some weakness near term in the base stocks market, and clearly that's coming because we're adding a bunch of Group II capacity, which long term is going to be very advantaged.
Don't know what we're going to be looking at when we first come on in early 2019, but it's fundamentally a very advantaged investment. One of the best returns we have. It doubles the earnings from Rotterdam. I think, again, I think it's primarily focused on. I think most of the feeds into this unit are at the refinery today.
Okay. Thank you for that. I was just hoping that you might be able to give us where you're at in the process for that second group of three expansion projects in the downstream. Have they all reached FID? Are they in construction? Just where are they at in the process?
Yeah. We're looking at FID Beaumont probably first quarter of next year. The Fawley unit is probably going to be about the same timing as Beaumont, probably more like mid-year. We're looking for FID on that one. Singapore is a little bit behind that. We're looking more like a 2023 or so startup in Singapore. It's a bigger project. It's a very large project in Singapore. Very fundamentally shift the whole Singapore. When you take 75 KBD of resid and turn that into a lot of lubes and clean products, that's a very large project. That one's a little bit later. Beaumont, we've been looking at all opportunities to accelerate that and try to get that on as soon as possible because we see that one as just extremely attractive.
Thanks very much.
Your next question comes from the line of Paul Cheng with Barclays.
Hey, guys. Good morning.
Morning, Paul.
Yeah. Just on the Beaumont crude unit, 200,000 barrels a day, can you share a little bit more detail in terms of how you're talking about that replacing maybe 100,000 barrels a day of the feed. How's the output going to look like at the end? How that is going to change? What kind of CapEx we may be talking about, and when that is supposed to come on stream?
Yeah. We're looking at 2022, maybe perhaps 2021. Still looking at that pretty hard in terms of when it's going to come on stream. What we're looking at doing is a new atmospheric pipestill. 250,000 barrels a day coming in. We'll take the middle of that tower, hydrotreat it there on site, and get some diesel fuels coming out of Beaumont. Beaumont will net increase diesel coming out of the refinery. The bottom and the top of the tower are going to be intermediate products to Baytown and to Baton Rouge. Again, replacing products that they're buying today. Not a lot of net increase in new product coming out of those, just lower cost. Again, given the advantage, 30% less than industry cost because of all these advantages utilizing existing infrastructure I talked about and well in excess of a 20% return project.
Should we assume that the diesel or business increase in Beaumont is somewhere in the 30,000-50,000 barrels per day, based on what you described?
Probably higher.
Higher than that?
Yes. Something like 60.
60?
I mean, ballpark. I don't know the numbers.
Sure.
Something like that.
Will that be all in ULSD or that it will be a combination?
It'll all be ultra-low sulfur diesel that will be coming out, clearly.
Okay. That, in terms of the other, say, debottleneck opportunity, 150,000 barrel per day expansion, what kind of timeline we may be talking about?
Which are you talking about?
Paul, I assume you're talking about the debottlenecks at the other facilities.
That's correct. Sorry.
Please come back.
Yeah. It was not 150, Paul, it was just 50.
Only 50.
We have 450 capacity today. Beaumont will be another 250, another 50 on top of that, over 750 total. I'm rounding the numbers here, but over 750,000 barrels a day after Beaumont and these other attractive development projects.
Okay. A final short one. Neil, I think earlier that you say that you will be on track to the $24 billion CapEx if we exclude the $1 billion you spent in Brazil recently. Does that mean that we're going to be roughly, say, $25 billion for the year?
Yeah. Paul, our current outlook is, for the full year, is $25 billion. What we've seen, though, throughout the year, fortunately, is some incremental opportunities to acquire additional acreage in Brazil, and that's roughly about $1 billion above what we thought we were going to get. That's where you get to the 25. Again, that's heavily dependent on what happens in the fourth quarter.
Sure. Thank you.
You're welcome, Paul. Thank you.
Next we'll go to Alastair Syme with Citi.
Thanks for taking the questions. In the analyst day, Jack, you put out earnings expectations charts on both the downstream and chemicals. I know they were long term, but there were also numbers for 2018 and 2019. I'm just sort of aware you're run rating well behind these, both for 2018 and sort of the expected 2019 performance in both downstream and chemicals. Can you sort of help us with how much of this is macro and how much of this is unplanned downtime?
Alastair, let me just say this. The market environment is very different than what we had. We assumed 2017 flat conditions and in the chemicals business, very different. Well, actually, in chemicals and downstream both. Very different market environment. The underlying activity that we talked about on those projections is on track. That's why I was saying these milestones or these projects starting up. The underlying activity that's driving these earnings results, these earnings potential projections that we talked about in March, are all there. As a matter of fact, again, I think we're seeing a bit of upside. Don't know in terms of, can't give you any definite numbers in terms of earnings themselves, but I can tell you the activity's going well.
You would say more as macro?
Yeah.
On the follow-up, can you just talk around IMO, in particular, if you see scope for an emergence of compliant blends, particularly in the Asian region?
I don't know if I can answer that question specifically, I can just tell you that we're supportive of the timing. We think that the industry will be able to adapt. We think it's the right thing to do in terms of going from 3.5% sulfur down to 0.5%. We're going to be ready. We're going to be ready with a bunch of different options. As I mentioned, we'll still have HSFO, we'll have a low sulfur fuel oil as well, we'll have a marine gas oil, and we'll have LNG. To the extent that some ships convert to LNG, we'll have that as well. Then also, we have a lot of coking capacity that we'll be destroying that resid and churning out some high quality distillate. I think we're going to be ready, and we're looking forward to that environment.
I can't really tell you anything specific about what others are doing or what the markets are doing. It'd be hard to see what the impacts are going to be on that overall. Obviously, the clean dirty spread's going to grow, and we don't know how much and don't know for how long. I think the industry's going to deal with it just fine.
Thank you.
Next we'll go to Roger Read with Wells Fargo.
Yeah. Thank you. Good morning.
Hey, Roger. Morning.
Just the question earlier was asked about buying things or whatever. You detailed in the fourth quarter some of the asset sales coming through on the downstream side. I was wondering, in a market where oil prices have recovered, you clearly are focused on the investment side, but everything has to compete for capital. Do you see any acceleration potential in dispositions over the next couple of years? Particularly as the upstream starts to transition with a greater component from the lower 48, if that makes it an easier decision to move forward on asset sales?
Yeah. We kind of hinted at this and talked about it a little bit back in March. Certainly in any dialogue I think we've all been having, we've been saying that we are going to be more active in terms of looking at our upstream assets. As you mentioned, as we bring on all these high-quality assets and invest in these new accretive volumes, clearly we need to be looking at the other end of the portfolio and seeing what might be worth more to somebody else than it is to us, given where our portfolio is heading. We are already more active and will continue to be more active in that area. What I can't give you is any specifics right now in terms of timing, in terms of how those transactions, when those transactions may happen.
Obviously, we need to have an active buyer as well as a seller. If you think about what we've announced year to date with the Norway divestment that was last year and then Scarborough and the Rockies gas. We have been active, and that activity is going to continue to ramp up.
Thanks for that, Jack. I appreciate the greater disclosure Exxon's giving. I didn't really expect you to give me a list of projects that you were going to be unloading here. Just as a quick follow-up, a question about share repos was asked. I was wondering, since you mentioned debt had declined to $40 billion, lowest since 2015, I was just curious, is there a debt goal, debt to cap, net debt, total debt number, recapturing the top credit rating, any of that kind of drivers that we should think about in terms of where debt goes down the road?
This is Neil, Roger. I'll take that one. We don't target a specific credit rating. We don't target a specific debt level. Again, I think the aim or the goal is to ensure that we maintain financial strength, financial capacity so that we can act counter-cyclically. We can take advantage of investment opportunities regardless of the price cycle. Aiming or putting a specific target out there, we don't typically do that. Again, as you know, we have industry-leading strength on the balance sheet, we want to maintain that so we can take advantage of opportunities. We don't target any specific debt level or credit rating.
Thank you.
It is a competitive advantage, Roger. I mean, you can imagine it gives us a lot of capacity to use that balance sheet when we see accretive opportunities.
All right. Thanks.
Yeah. Thank you, Roger.
Our next question comes from the line of Rob West with Redburn.
Hi. Thank you for taking my question. I'd like to ask the first one about the comments you made earlier around your downstream investments. The question is, are you surprised how little some of your peers are investing in new capacity or complexity at their refining base? Could you just make some comments about why you think that might be if it is a trend that you are seeing?
Yeah. I would just say, oddly, yes, surprised. I don't really know why. I think that's something you'd have to ask them. One thing I would like to say, though, is if we think about refining investments, we're really not interested in kind of plain vanilla industry standard refining, added industry standard unit, that conversion capacity, that kind of thing. We're bringing proprietary technology and/or footprint advantages on all those projects we had. They are all well in excess of what others might see on their potential refining investments. I think that probably differentiates us. In addition to that, you look at some of the differentiated products we have coming out as well. I think that may be a reason why.
Okay. Thank you. Really, the question is: What is your number 1 highlight in the digital space in the last 12 months? The context for asking is, I've seen one of your peers talk about having 20 million data points a day at a new Gulf of Mexico platform. I've seen one of your other peers just signed a big new agreement with a machine learning company. Is there something you'd point to in that space, or would you say you're less active than peers there?
Well, Neil might want to weigh in on this one too, but let me just make a comment. I can assure you, we are very active in this space. We have had a lot of discussions at the management committee level around all the things we're doing in digital. We are not rushing out to do a me-too type project in digital, but we are putting in the underlying infrastructure to give us advanced analytic capabilities. We are doing things like pervasive Wi-Fi in our facilities to where we can make our operators much more productive. We have real-time data feeding in from all our major pieces of equipment that's improving our reliability. You're right, we haven't talked about it as much as some of our competitors, but we are very active in the space.
All aspects of our business have big digital organizations in them looking at all that opportunity, and that's coordinated with a central IT organization that's looking at the overall strategy. Very active, and we are seeing some bottom-line benefits for sure.
Maybe one example I can give, look at what we're doing on the subsurface. You can imagine over time how much seismic data we've collected as a company. One of the areas we're looking at is digitizing that, again, with the idea of using artificial intelligence and big data to help us continue to look for resources. That's one specific example. Again, I think it's happening across the business.
Thank you. Thank you for the perspective.
Good. Thank you, Rob. I think we have time for one more question.
Okay, we'll take our last question from Jason Gabelman with Cowen.
Thanks for squeezing me in at the end of the call.
Yeah, good morning.
Morning. Just on the Brazil acreage footprint expanding here, can you first remind us of that $1 billion, how much has been spent year to date? Secondly, on that, there haven't really been many updates on the Carcará development. Can you give us any updates that you have or how you're thinking about this project coming along given not much coming from you or your partners on that project?
Let me kind of laugh off the question, and maybe Neil could chime in on the numerics on the investments this year. On Carcará, we're working with Equinor on that as they're operating that development. Again, we see that as a recoverable resource of more than 2 billion barrels of high-quality oil. We've had another on-block discovery that could increase that further. It's looking good, continuing to progress. We're still continuing to talk about what's the optimum development plan and timing on that, we see it as very attractive. I think we both absolutely agree it's very attractive. We see that as kind of being a 2023, 2024 type startup, depending on a number of factors on the permits and when we get going there.
One thing I'd like to mention is that I talked about 26 blocks in Brazil, and all of these are blocks we went after because we saw on 3D seismic some attractive features that we wanted to look at a lot harder. The only thing we had in our outlook from Brazil that's been included in those earning projection outlooks we talked about back in March is just the one Carcará. Everything else in Brazil is complete upside to the outlook we had. We do see it as very prospective. We're very excited about the program now. We're probably going to spend the rest of this year, next year acquiring additional 3D seismic, interpreting that. Maybe 2024 out there drilling new exploration wells. We see it as very prospective, and we're very excited about the opportunities there.
All right. Maybe I can give you a little perspective on year to date. Again, with the acquisition of the Kaieteur block, which was roughly 71,000 acres, we're now up to 2.3 million net. I think year to date approximate numbers will be, I think full year will be around $2 billion, which is again, about a billion above what we had in plan. Jack mentioned the 26 blocks that we're in. I think the other thing that's attractive is we operate approximately 66% of those blocks. Most of them are under concession contracts as well. Very attractive position.
All right, great. Thanks a lot.
Great. Thank you, Jason. Thank you for your time and thoughtful questions this morning. We appreciate you allowing us the opportunity to highlight a third quarter that included strong earnings and cash flow performance, supported by improved operations and significant liquids growth. I'd also like to remind you that our Chairman and CEO, Darren Woods, will participate in our fourth quarter and full year earnings review. We appreciate your continued interest and hope you enjoy the rest of your day. Thank you.
That does conclude today's conference. We thank everyone again for their participation.