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Exxon Mobil Corp
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Good day, everyone. Welcome to this Exxon Mobil Corporation Third Quarter 2019 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.
All right. Thank you. Good morning everyone. Welcome to our third quarter earnings call. We appreciate your participation and continued interest in ExxonMobil. I’m Neil Hansen, Vice President of Investor Relations. During today's call, I'll review our financial and operating performance and provide updates on the substantial progress we've made on our major growth projects. I'll be happy to take your questions following my prepared remarks.
My comments this morning will reference the slides available on the investor section of our website. I'd also like to draw your attention to the cautionary statement on Slide 2 and the supplemental information at the end of the presentation.
Moving to Slide 3 let me begin by summarizing the excellent progress we've made this year on plans to grow shareholder value. The long-term fundamentals that underpin our investments remain strong. We've generated nearly $9 billion in earnings through the first nine months of the year with a portfolio that is resilient to a range of commodity prices and margins.
We are investing in advantage projects that will grow the earnings and cash generation capacity of each of our businesses. Nearly $23 billion of CapEx year-to-date is in line with current year plans and reflect strong execution of key deliverables. Liquids production has increased significantly from last year with volumes up 131,000 barrels per day or 6%, driven by strong growth in the Permian. We remain on track to meet the full year outlook of producing 4 million oil equivalent barrels per day this year.
In addition, efforts to high-grade our portfolio are proceeding ahead of schedule, putting the consideration from the agreement we signed to sell non-operating upstream assets in Norway. The divestments now totaled nearly $5 billion. Exploration success has continued this year with five significant deep water discoveries, four in Guyana and one in Cyprus. And we've reached final investment decisions for 10 major strategic projects this year, including projects from all three business lines.
We also increased the quarterly dividend by 6% marking the 37th consecutive year of dividend growth. Finally, the strength of our balance sheet provides us with the capacity to invest through the cycle with leverage at just 12%. The positive momentum we've generated so far this year is in line with the plans that we laid out in 2018 and reiterated in March and positions us well to generate long-term shareholder value.
I will now highlight third quarter financial performance starting on Slide 4. Earnings were $3.2 billion in the quarter or $0.75 per share, putting a positive $0.07 per share impact from a one-time tax item. The results were consistent with expectations given the margin environment, seasonal impacts and planned maintenance experienced during the quarter. Crude oil prices declined relative to the second quarter while refining margins improved. Broader margin environment remained challenging as short-term supply and demand imbalances continued to pressure natural gas prices and industry chemical and lube based oil margins.
Cash flow from operations and asset sales was $9.5 billion in the quarter, after adjusting for changes in working capital, cash flow was $8 billion. CapEx for the quarter was $7.7 billion. PP&E adds and net investments and advances, which is a proxy for cash CapEx was $6.6 billion and that ratio is consistent with our rule of thumb, that cash CapEx is generally 85% of total reported CapEx. Free cash flow in the quarter increased to $2.9 billion reflecting higher cash generation and moderately lower investments in the quarter. I'll now go through a more detailed view of developments since the second quarter on the next slide.
In the Upstream, both liquids and gas realizations were lower in the third quarter, consistent with a decrease in liquids markers and continued gas supply length. Production was in line with our expectations with continued growth in the Permian. The Liza destiny FPSO is currently being commissioned in Guyana and we announced the fourth discovery of this year with the Tripletail exploration well. We also made considerable progress on our $15 billion divestment program reaching an agreement to sell our Norway non-operated assets.
In the Downstream refining fuels margins improved during the quarter with supply tightness and stronger distillate demand in Asia and Europe. On the other hand, North American logistics differentials narrowed, primarily driven by the addition of Permian pipeline capacity. Lower scheduled maintenance, most notably the completion of turnaround activities at our Joliet refinery and improved reliability relative to the second quarter contributed to stronger downstream financial performance.
Although long-term fundamentals remains strong in the chemical business, polyethylene and aromatics margins continue to be impacted by supply length from industry capacity additions. The recent startup of the polyethylene expansion at Beaumont is performing well and running above planned rates. Supporting efforts to grow sales of high-performance, metallocene products had delivered sustainability benefits including lighter-packaging weight, lower energy consumption, and reduced emissions. Lower scheduled maintenance across U.S. Gulf Coast sites continue – contributed to improved chemical earnings, although this was partly offset by a reliability event at Baytown.
We also progressed research and development of lower emissions technologies. We entered into an agreement with Mosaic Materials to explore a breakthrough carbon capture technology using metalorganic frameworks to separate carbon dioxide from the air. The agreement expands our carbon capture technology research portfolio and will enable evaluation of opportunities for industrial uses at scale. We also signed an agreement with the Indian – the Indian Institute of Technology. This partnership will focus on progressing research in biofuels and bioproducts, gas transport and conversion, and other low-emissions technologies for the power and industrial sectors. This expands our portfolio of research collaborations, which now stands at more than 80 universities, five energy centers, and multiple private sector partnerships.
Let's move now to Slide 6 for an overview of third quarter earnings relative to the second quarter of this year. Third quarter earnings of $3.2 billion were up $40 million from the second quarter. Upstream earnings declined by approximately $1.1 billion driven by lower liquids realizations and the absence of a favorable tax item. Downstream earnings increased by nearly $800 million with lower scheduled maintenance and stronger industry margins. Improvements in downstream earnings were partly offset by the decline in North American differentials. Chemical earnings increased by $50 million with lower scheduled maintenance, partly offset by the reliability event at Baytown.
Finally, Corp and Fin earnings increased by $300 million due to the previously mentioned favorable tax item. I'll review changes in Upstream volumes on Slide 7, production in the third quarter was 3.9 million oil equivalent barrels per day, an increase of 113,000 oil equivalent barrels per day relative to the third quarter of last year, representing a 3% increase. The higher volumes were driven by growth of 123,000 oil equivalent barrels per day in the Permian, representing a 72% increase from the prior year quarter.
The third quarter cash profile is shown on Slide 8, third quarter earnings when adjusted for depreciation expense and changes in working capital yielded $9.1 billion in cash flow from operating activities. There was a $1.6 billion release of working capital in the quarter, driven primarily by inventory effects related to maintenance activities. Other items included the favorable one-time non-cash tax item. Our divestment program is progressing well and ahead of schedule. Third quarter proceeds from asset sales includes a deposit for the $4.5 billion Norway asset sale and the cash received for the sale of our Mobile Bay asset. Third quarter additions to PP&E and net investments in advances were $6.6 billion. Gross debt increased by approximately $2 billion and cash ended the quarter at $5.4 billion.
I’ll now provide an update on the excellent progress we are making on key investments across all of our businesses, a summary is provided on Slide 9. Starting with the upstream, growth plans in the Permian and Guyana remain on track and I'll provide some additional details on these projects in the coming slides. In Brazil, we expect the Petrobras operated Uirapuru well to commence drilling in the fourth quarter.
In the downstream, three new projects are online and performing well, supporting increased production of cleaner, higher-value products. We've made final investment decisions this year for four additional projects including the Beaumont light crude expansion and the Wink to Webster pipeline, both of which will support our integrated Permian strategy and growth plans. In our chemical business, with the recent start-up of the Beaumont polyethylene expansion, we now have eight new facilities online with four additional projects receiving final investment decisions this year.
Moving to Slide 10. I'll provide an update on our unconventional business. Permian growth remains on track with production averaging 293,000 oil equivalent barrels per day in the third quarter. Although, we are in the early stages in the development of this significant resource, results are encouraging, including continued strong well performance. Construction of processing and takeaway capacity also continues. An important milestone this quarter was the completion of the Phase 1 of the Delaware central delivery point and the pipeline to the Wink terminal.
I'll provide an update on Guyana on Slide 11. Commissioning of the Liza Phase 1 FPSO is underway and on schedule. The target for achieving first oil is December, dependent on favorable weather conditions. This was placed start-up within five years of initial discovery, well ahead of the typical pace for the industry of closer to nine years. Liza Phase 2 engineering and construction is progressing well, following FID earlier this year. And we're also working with the government to receive necessary project approvals for Payara with the plan start-up in 2023.
The Tripletail discovery which we announced in September, marked the fourth exploration success of 2019, the well encountered 108 feet of high quality oil-bearing sandstone and we are also pleased to highlight that with deeper drilling on the well, additional hydrocarbon reservoirs were encountered, providing potential upside to this – to the initial discovery. We continued to progress considerable undrilled potential in Guyana with a fourth drilling ship, which will commence exploration activity in the fourth quarter. Three upcoming wells, Uaru, Mako, and Hassa are planned to spud in the upcoming months. Locations of those Wells are highlighted here on the map.
I’ll now provide some perspectives on the upcoming IMO 2020 implementation on Slide 13. The chart on the left highlights the coking capacity advantage we have relative to our integrated peer group. A position we recently strengthened with a start-up of the Antwerp coker. This new facility upgrades bunker fuel oil, currently produced in our Northern European refineries to higher value products, including ultra-low sulfur diesel.
The middle chart shows the clean/dirty spread using Asia gas oil and high sulfur fuel oil. As you can see, the spread is expanding with the forward curve and third-party estimate ranges showing further widening, which will favor more complex refiners with the capacity to upgrade heavier sour crudes to cleaner products. And just to give you some additional perspective, a general rule of thumb for our portfolio is that for every dollar per barrel change in the clean/dirty spread, downstream annual earnings will increase by approximately $150 million. Now a large portion of the benefit comes from the associated widening of the light-sweet and heavy-sour crude spreads, and our ability to leverage coking capacity to run higher quantities of discounted crudes.
Now turning to Slide 14, I'll provide additional details on our portfolio management activities. We've made considerable progress on our 2021 divestment objective of $15 billion, reaching an agreement to sell our non-operated Norway assets for $4.5 billion. The sale includes ownership and more than 20 fields and is expected to close in the fourth quarter, pending regulatory approvals.
The sales price of $4.5 billion is subject to interim period adjustments with an effective date of January 1, 2019. Estimated total cash flow from the divestment is approximately $3.5 billion after closing adjustments, with expected 2019 cash proceeds of $2.6 billion. And we will receive another $0.9 billion of non-contingent consideration and tax refunds over the next few years. We are also progressing marketing activities involving, but not limited to, assets in the Gulf of Mexico, Azerbaijan and Malaysia.
I'll now provide some perspective on our outlook for the fourth quarter starting on Slide 15. In the Upstream, we expect production to increase in the fourth quarter, largely driven by seasonal gas demand, and I'll provide some additional detail on the seasonality of gas demand on a following chart. With regards to the Norway divestment, again, assuming regulatory approvals are received, we anticipate the sale will close in December and that we will recognize an earnings gain of approximately $3.5 billion.
[Technical Difficulty] potential for further expansion of clean/dirty and sweet/sour spreads as preparations for the IMO spec change continue. Higher scheduled maintenance in the fourth quarter relative to the third quarter is also expected to impact results
Chemical margins will likely remain under pressure in the fourth quarter as the market continues to work through supply length from recent industry capacity additions. Scheduled maintenance in the Chemical business in the fourth quarter should be generally in line with third quarter levels, and we expect continued recovery from the third quarter reliability event at Baytown. I'll provide some additional details on scheduled maintenance on a subsequent slide.
The chart on Slide 16, shows the increase in volumes on oil equivalent basis that we typically experience from higher gas demand in Europe in the fourth quarter. And as you know, gas demand is highly seasonal and driven by weather conditions. Fourth quarter gas demand has been on average 150,000 oil equivalent barrels per day higher than the third quarter, and we expect a similar trend to occur this year.
Turning to Slide 17, I'll provide some perspectives on our fourth quarter outlook for Downstream and Chemical scheduled maintenance. As previously mentioned, scheduled maintenance in the Downstream this year is higher than normal, again, in part due to preparation for IMO 2020. Planned maintenance tends to be seasonal, in line with demand patterns. We expect the impact from scheduled maintenance in the fourth quarter to be higher relative to what we experienced in the fourth quarter – in the third quarter. The estimated earnings impacts for the fourth quarter and first quarter 2020 for the Downstream are shown on the upper left chart.
In the Chemical business, shown on the bottom left chart, we expect scheduled maintenance levels to be generally in line with the third quarter and significantly below the peak we saw in the second quarter of this year.
I'll conclude my prepared remarks with a few key messages on Slide 18. In the Upstream, we are delivering on plans to grow liquids production and high-grade the portfolio. Recent project start-ups in Downstream and Chemical, continue to perform well, and we reached final investment decisions for eight key projects so far this year.
We are also leveraging our significant financial capacity to progress advantaged investments through the cycle, maintaining constancy of purpose on our commitment to grow long-term shareholder value across a range of market environments. Finally, but importantly, we are building on our extensive network of partnerships to develop new technologies to address the dual challenge of providing reliable and affordable energy, while mitigating impacts to the environment, including the risk of climate change.
And I'll be more than happy to take any questions you might have.
Thank you, Mr. Hansen. [Operator Instructions] First question will come from the line of Doug Terreson with Evercore ISI.
Good morning, everybody.
Hi, good morning, Doug.
Neil, in U.S. Upstream, you mentioned that the key factors this period were realizations, divestitures, output gains, but also higher growth expenses. And on this point, I want to see if we could get more color on the last item, since we can gauge the others to some degree and specifically are these higher growth expenses primarily the Permian? If so, do you consider them to be transitional in nature and when will they become less significant? And then thirdly, are they tracking with your expectations? So three questions on the higher growth expenses item in U.S. Upstream.
Yes. I appreciate the question, Doug. So just focusing on U.S. Upstream, so if you look at the change in the third quarter relative to the second quarter, earnings declined by roughly $300 million. Most of that was price, so it was about $190 million impact on price in the Upstream. We did have a few other factors, including some downtime and maintenance in non or unconventional assets, including La Barge and Prudhoe Bay, that had an impact as well, and then we did have some higher growth expenses. Most of that does it relate to the progress that we're making in the Permian.
And maybe I can just touch on that really quick. I mean I think obviously, we feel really good about the volume growth that we see out there. The resource continues to respond very well. We're making good progress on the development plan that we have in place, including making sure that we capture the full value of the resource.
If you're using our logistics position to bring barrels to our refineries and chemical plants, the pace of development is consistent with the plans that we laid out. I think we finished the third quarter with 55 rigs and roughly 10 frac crews, and as I mentioned, volume growth relative to last year in the same quarter was 72%. But we're early in the development. We've only drilled, I think a few hundred wells and that's on a well inventory in excess of 8,000.
So it's pretty early days, but we feel like we're making really good progress, we're leveraging the full strength of the corporation and bringing our unique competitive advantages, the scale, the technology. We're leveraging sophistication in the sub-surface using reservoir modeling, we're bringing drilling engineers from all of the world that have expertise in dealing with some of these environments, and of course, our project management capability.
So I think in terms of pace, I think, the OpEx is where we would expect it to be. Now when we think about the development, we're trying to balance certainly well productivity. We want to do well there, but we're balancing that with ensuring we excel in terms of ultimate recovery and then, of course, capital efficiency. So that – those are the three elements we're trying to balance.
I think we feel good about where we are. I think we've said that this is a very resilient asset. Even at $35 a barrel, we expect to generate a 10% return. So I would expect, even though we feel like we're where we should be at this point, you can fully anticipate as we bring technology to this, as we bring expertise and drilling in the sub-surface, our project management capabilities, we will only become more efficient over time and drive down those costs. I mean we're never satisfied with where we are, and we always can feel like we can get even better. So really good progress, but also very high expectations in the organization that will only get better in developing the resource.
Okay, and so it seems like if the production curve steepens in 2020 and beyond, then we'll see pretty strong results from that asset. So, okay well, thanks a lot, Neil.
Yes. Thanks, Doug. I appreciate the question.
You're welcome.
Next we'll go to Sam Margolin with Wolfe Research.
Hey, good morning.
Hey, Sam. How are you?
I'm good, thanks. So thanks for the color on the Norway sale. I mean, based on the gain there, it looks like this asset was pretty much fully depreciated and it sort of stimulates a question about maintenance spending around some of these longer-tail assets, whether or not the whole industry has kind of deferred that activity and these assets that are mature, sort of, changing hands into more local entities that are incentivized differently to spend. So is that sort of the right read on the overall landscape for divestitures, and if so, what does that mean for your baseline spending irrespective of the growth columns that you have, and maybe even a macro tangent, if you have time to?
Yes. I appreciate the question, Sam. Again we feel really good about the progress we're making on that divestment program and the fact Norway was accelerated. So that's why we feel we're ahead of schedule. We didn't anticipate being able to execute that divestment this year. So I think the organization has done a nice job of progressing that objective. But I think you all should recognize the reason we're pursuing the divestment program primarily is given the fact that we have brought so many attractive assets into the portfolio, you think about Permian and the Guyana, the LNG projects, that has placed pressure on the organization to high grade even more so, than we have in the past.
When we look at asset sales and what assets we might consider high-grading, Sam, it's generally going to be driven by strategic fit, it's going to be driven by the materiality of the asset, its growth potential. We also take into account things like whether or not we operate and have control afford investment plans, I don't want to convey, certainly from our perspective or from an industry perspective that their forgoing needed maintenance to ensure that these facilities are running well and that we're maximizing production from them.
So I think it's probably more so for us, Sam. It's more a factor of this pressure that we feel because the portfolio has really increased in terms of attractiveness and value. We feel like there is an opportunity for us to high grade the portfolio, and even – having this opportunity to even grow more, the overall value by high-grading out our assets.
Okay, thanks so much. And then my follow-up, sort of, on the other side, on the acquisition front. Bearing in mind the comment about resilient returns in the Permian, double digit down to $35 oil, I think that has more to do with your development plan than necessarily prevailing trends in the industry, because certainly it doesn't look like the independents can make similar claims. So what does that mean in terms of where we're at in the cycle for you too if you think about bolting on some assets here? It seems like you can add value to some distressed situations. Thank you.
Yes. I appreciate it, Sam. So I think if I step back with what we're trying to do, we're managing a portfolio, and as good as we feel about the opportunities that have come in – and you mentioned Permian, Guyana and some of the other assets we've been able to bring in, as good we feel about that, the objective remains trying to grow the overall value of that portfolio. We're trying to increase the pie. And so we never sit still.
We're always looking at additional opportunities that we think we can bring in into the portfolio. And so I think that certainly would include M&A, it includes looking at any other additional opportunity that's out there. Now for it to come into the portfolio, obviously, it's going to have to compete with what already is in our portfolio. That's certainly one measure of consideration. And the other thing is for us, we have to see an opportunity where we can bring a unique value where we can leverage our competitive strengths to offer something that the industry can't provide or can deliver, and so it's something we're looking at very closely.
We are in a fortunate position given the portfolio that we have, that we can be very choosy. We're very fortunate, and that we have the financial strength, the balance sheet capacity to transact at any level and any cycle. And so that gives you a nice – a nice spot to be in and to be very, very selective in what you're pursuing, very selective in what you're trying to do, because whatever we bring in, is going to have to compete with what's already in the portfolio.
So Sam, I think the environment is generally pretty good. There are a lot of things to look at, there's a lot of things to consider. I think for us it's just a question whether or not we can transact at the right value, whether or not we can add unique value to the asset given our competitive advantages and our strengths.
But have no doubt, the objective is that we want to continue to find ways to grow the overall value of what we have, including bringing things in that also includes high-grading the portfolio as we talked about. And the other thing we may not talk enough about, it also includes making sure that you execute the investments in the projects that you have well, that you bring them on budget, on schedule and that you run your existing base well. That is what we see as the objectives in terms of being able to grow that overall value.
Thanks so much.
Next question comes from the line of Neil Mehta with Goldman Sachs.
Good morning, Neil. Thanks for taking the time.
Hey, Neil.
I guess, the first question I have is just around IMO 2020. We've seen – certainly seen a lot of other companies, including yourself point forward maintenance into 2019, so you can maximize the upside to IMO. So do you ultimately think that will cap the upside, that return of throughput as you go into 2020? And just any early thoughts from Exxon standpoint about how this playing out.
Yes, I appreciate the question. I'll maybe step back a little bit and talk about what we're seeing. We mentioned in our prepared remarks. But you are starting to see certainly early transition with IMO on the product side. We've seen high sulfur fuel oil cracks, or significantly the clean/dirty spreads, I think recently we reached near 10-year highs. And so I think the market will be dynamic in the early stages of this transition, but certainly on the product side, you're already seeing some of that widening of that spread and the forward curves are indicating that as well.
On the crude differentials, this difference between heavy-sour and light-sweet, we will also follow those same trends, right. I mean, low conversion refineries are going to be incentivized to run those sweet crudes, which will obviously widen out that spread and the futures curve is showing that. But again, we anticipate you'll see some choppiness, some volatility. There are a lot of variables at play here. It's a global market, but I don't think that we have any expectation that you wouldn't see those two key factors, that – widening of that clean/dirty spread, the widening of the heavy-sour and light-sweet.
I don't – I think over time, the response to that will be the refining industry will have to add coking capacity. That's certainly something that we've done, I don't know if there is any level of maintenance that could be done that would minimize the impact of this. I think the market impact is too big to be able to respond to it with just pure maintenance. I think ultimately, the industry will have to add coking capacity, and that's why we feel really good about where we are, Neil.
I mean, we've got more coking capacity than any of our peers, we've done the maintenance, we've added Antwerp. So we feel like we're very well positioned. Our conversion capacity in the U.S. Gulf Coast is very high. I mentioned the coker in Europe, and we're also looking at upgrading resid in Singapore as well. So I think ultimately, that is what is going to have to be the response from industry.
Thanks, Neil. And the follow-up is, one of your capabilities as a company is managing regulatory and political risk. As we go into the election season here in the United States, how do you think about risks around federal public lands and what that means for your exposure, and thinking about that in the context of New Mexico, Alaska and the Gulf of Mexico?
Yes. Thanks, Neil. Appreciate the question. I think it's difficult to speculate on the impact of a policy without details on implementation. I think any effort obviously to ban fracking would have a negative impact on industry efforts to develop resources like the Permian. There is no doubt on that, but when you look at the motivation of those policies, I mean if the underlying concern is about risk of climate change and emissions reduction, we certainly share similar concerns. But we think they are more effective policies and we also think there are technology advances that are required.
For example, we've been a very long-term vocal advocate of a revenue-neutral carbon tax. It's uniform it's transparent, it will incentivize the market to find solutions. I think any efforts to ban fracking or restrict supply will not remove demand for the resource. If anything, it will shift the economic benefit away from the U.S. to another country and potentially impact the price of that commodity here and globally.
So we think there are better policies that policymakers can put in place, and we certainly spend a lot of time advocating for those policies. If it's a concern about responsible resource development, and – we share that same interest. We hold ourselves to a high standard, we work with regulators to improve industry standards, and we advocate for policies that will be effective in that space as well.
I think when you think about political risk, one of the ways we approach that is working with policy makers to help them understand the policy decisions and help them understand the potential consequences of those. We've been in the business for a long time and I think with our experience in the industry, we have a good line of sight on what policies we think would be would be effective.
The other thing we're trying to do Neil is, is help policymakers understand the tremendous benefits that resource development brings to economies, that brings to employment and to society. In fact, a recent study was done. I don't know if you saw this, but the development in the Permian, our development in the Permian Basin for New Mexico, will generate approximately $64 billion in economic benefits over the next 40 years.
So I think helping policymakers understand what policies are more effective to address some of these concerns is important. And then I think also helping them recognize the economic benefit from responsible development of the resource. The other thing though, I think it highlights, there is political risk almost everywhere where we operate. And having a global portfolio like we have, helps us mitigate risk in any potential or specific jurisdiction. So I think – I certainly can understand if all your eggs are in one basket and we have a lot of political risk there, that there would be concern, but we feel like we can mitigate it with our portfolio, and then having this approach by working with policymakers.
Thanks, Neil.
Thank you, Neil.
And next we'll go to Phil Gresh with J.P. Morgan.
Hey, good morning, Neil.
Hey, good morning, Phil. How are you?
Good. So first question, you were talking earlier about execution on the existing portfolio, an opportunity set. One of your peers today , just highlighted a 25% increase in capital spending cost at Tengiz, and obviously you are on that project. But just wondering how you view general inflation risks in – across the portfolio from a capital spending perspective. or would you characterize Tengiz as more of a one-off? Thank you.
Yes. I appreciate the question, Phil. Look, I'd recommend any specific questions on project cost and schedule, it's more appropriate for those to be directed to Chevron as the operator. What I can say is, we certainly expect and I mentioned this on the call, we expect to meet our CapEx outlook for this year. This increase in Tengiz cost does put upward pressure on future capital programs – future-year capital programs. We're doing everything we can, working to accommodate that within our program and we will provide an update on where that stands at the Investor Day in March.
I think you are talking about inflationary pressures, I think it's dependent on where you are operating. I think we've generally seen a fairly good cost environment in the deepwater. For example, in the Permian in the unconventional business, I think for the most part, we've seen a very good operating environment. We have seen a fairly hot market on the Gulf Coast, given all the capacity additions in the Chemical business on the refining side. And I think we foresee those cost pressures and we try and leverage our scale and our functional excellence to do everything we can to mitigate those cost pressures.
Let me just give you a couple of examples. Maybe the most relevant one, on the U.S. Gulf Coast. If you look at the steam cracker that we're putting in place down near Corpus Christi, again, recognizing the cost pressures on the Gulf Coast, that influenced the location of that steam cracker. It also allowed us to leverage our capabilities globally. For example, one of the things we often do in the Upstream to avoid a high cost environment is you build modulars and lower cost locations, and then bring them to the site. We're doing the same thing with that steam cracker on the U.S. Gulf Coast.
The result of that is that project would be 25% lower than the industry standard steam cracker. And so, I think you're always going to find different environments depending on where you operate, and I think we try to use our global procurement organization, our project expertise to make sure that we mitigate those costs. But it is something you have to watch very closely, because you can't undermine the value of any given investment if you're not executing well and not delivering it on time and on schedule.
Okay, understood. Second question on Chemicals. Obviously, you've highlighted multiple times the macro pressures that you're seeing here. Some of your peers have been highlighting this as well. What's your latest thoughts as we look out into 2020 and considering the $200 million or so of earnings each of the past two quarters, there is – it looks like there is some higher maintenance in the next few quarters, but just generally, what's your kind of view of 2020 relative to the run rate of recent quarters? Thank you.
I appreciate it, Phil. Yes, I think the – if you look at polyethylene industry margin, they are relatively steady versus the second quarter, but they absolutely remain weak due to industry supply length. And that has continued to be the issue. We don't expect that current market environment to improve certainly before the end of this year, but we are starting to see some competitors delay or cancel investment plans and that certainly could impact supply demand balances in 2020.
And the other thing we're seeing that's important is that demand remains robust. And certainly, if you have delays in capacity additions and we continue to see strong demand growth, that could impact margins going forward 2020 plus. The other thing in a cyclical business, we try to focus on the long-term fundamentals, and in the Chemical business, they remain very strong. We expect growth to remain above GDP as the middle-class continues to grow. So that's certainly a key element of it and we focus on those long-term fundamentals.
The other thing is, we recognize that in a cyclical business, in a commodity business, you win over the long term, with the lowest cost of supply. And so when we make these investments, I mentioned the steam cracker in Corpus Christi, we endeavor and do everything we can to keep those projects on the left hand side of the cost of supply curve, so that they are resilient to different price and margin environments. And that certainly is the case with our Chemical portfolio.
The other thing we try to gain an advantage is on the product side. As – our sales growth for the most part is on high-performing products that have some sort of technology barrier, some sort of unique application for our customers. But we can garner a high margin and we can have a strong portfolio of those types of products. So again, I think we feel really good about it.
The other thing I'd highlight, if you look at the recent investments that have come online, the steam cracker on the Gulf Coast, the Beaumont polyethylene expansion I just mentioned, those assets are performing really well. They're running above planned rates and they're accretive to earnings even in a challenging environment. So again, short term, certainly we continue to see pressures due to capacity additions, but long-term demand fundamentals remain strong and we feel like our portfolio is advantaged and well positioned to continue to perform well across the commodity price cycle.
Right. Thanks Neil.
Yes. Thank you, Phil.
And now we'll go to Jon Rigby with UBS.
Thank you. Hi, Neil, Two questions.
Jon?
Hi. Couple of questions. The first on the Downstream. I mean, you referenced, I mean the improving crack spreads, light-heavy spreads for products that I guess would fit exactly into the kind of profile of the new projects that you brought on for the hydrofiner, the coker, the Rotterdam hydrocracker. And I'm a little surprised we're still not really seeing significant delta in earnings over and above the sort of more generic stuff you're highlighting in the 8-K. And I wondered is that just materiality or would – if was revisited at 4Q and looked at across 2019 versus 2018, would we start to see the effect of those start-ups within your earnings?
And then maybe, if I ask a second question as well. Just on the guidance on disposal proceeds, is that a figure persisting that you will receive or is that growth of selling cost taxes, etc? Thank you.
Yes. Thanks, Jon. Let me take the Downstream question first. You're absolutely right. This – when we make investments, when we consider how we want to transact within our portfolio, we remain very grounded in the long-term fundamentals. And the long-term fundamentals in the Downstream are that you will see a shift in demand away from products like fuel oil into distillates and to base stocks and into chemical feedstocks.
So the investments we're making and have made, certainly Antwerp, Rotterdam are good examples, the Singapore resid upgrade project that I mentioned earlier, all of those are intended to capture the growth in that demand and improve the complexity of our refineries and the competitiveness of those refineries. We are absolutely investing to capture that long-term demand growth.
Again, I – it's relatively early days in some of these major projects that have come online. They are performing well. They, obviously, have been in a different – in a lower-margin environment up to this point, but operationally, they're performing well which is impressive especially in some cases, like Rotterdam where that project was reliant on new technology, new catalyst technology that allows us to upgrade again, fuel oil into higher distillate project.
So the fact that we've been able to execute their project well, execute it with new technology is pretty impressive and we feel very good about that. And we fully expect over time, especially if the margin environment improves, that we'll see significant contributions from those projects. I think beyond that – beyond the major projects, we continue to progress a lot of smaller capital projects at our refineries and we're constantly looking to optimize how we use those units. So again, I would fully anticipate as things progress, we will continue to see good progress and we will endeavor to try and highlight that more certainly in the earnings.
In terms of the proceeds, the $15 billion objective we set out to 2021, that number is consideration. And so, to the extent we have divestments, transactions that include closing adjustments that would obviously reduce that number in terms of the actual cash flow that comes in. But the $15 billion is consideration. The other thing I'd remind you is that it was a risk number. So certainly in terms of the level of activity should we succeed and transacting on everything, it would bring in a lot more consideration than that $15 billion.
It's progressing well. To be a $5 billion already, we feel good about the assets that are being marketed in terms of interest, and we expect to continue to put more assets in the market as we get close to the end of the year.
Okay. Understood. Thank you.
And now we'll go to Doug Leggate with Bank of America.
Hi, guys. Good morning, and good morning everybody.
Hey, Doug.
Neil, I wonder if I could change tack, just a little bit and ask you what the latest update is at Groningen. Obviously, you highlighted the seasonal rebound in gas production or BOEs going into the fourth quarter. But obviously there's been a fair amount of news again in the last several months. And specifically, what I really want to get to target, if I may ask, is the make-whole provisions of the force majeure. So even though longer-term production may be curtailed earlier, what's happening to your – the net value and the net cash margin to Exxon as a consequence of that as we look longer-term?
Okay. Thanks, Doug. Appreciate the question. Maybe just to give a little bit of background on what's happened in Groningen. So first of all, we certainly understand concerns of residents that have experienced earth tremors and the related damage, and if you go back about a little more than a year ago, we signed a Heads-of-Agreement with the Dutch government and Shell our partner and NAM that would accelerate the end of production I think by 2030, at the latest is the initial. That was the initial timeframe. There was another tremor that occurred in May of this year, and after that tremor, the Dutch government informed us of their intentions to bring production to zero by 2022.
Now that change in the acceleration of the production we see as a significant departure from the Heads-of-Agreement that we signed roughly a year or so ago. So we, along with Shell in the state, have agreed for the need to put in place an addendum to that agreement, and we will work responsibly to accelerate the lowering of the production. And we think we will come to a final agreement on compensation. But that's something that's under way, Doug.
I think what this highlights certainly is the advantage of having a global portfolio that provides you with a lot of optionality, a lot of flexibility. Things are going to come in and out of the portfolio, but we anticipate certainly to be able to continue to grow the overall value of that portfolio. Just to give you some sense, I don't have specific, Doug, on earnings and cash, but the production levels are about 90,000 oil equivalent barrels per day on an annual basis. It does depend heavily in any given quarter, on demand and weather conditions. But we don't anticipate any significant impact from this accelerated production in the fourth quarter, but we'll certainly work closely with all stakeholders to wind down production in accordance with the desires of the Dutch government.
I appreciate the lengthy answer, Neil. My second one is probably a quick-one. Given your history and being able to answer these, but I just wonder if there is any update you can give on the Guyana project visibility? I mean clearly, you've got the Analyst Day coming up in March, but you've had extraordinary success again, and I'm specifically trying to see if you will give us any color on what you've learned so far on Ranger, because clearly that's a potential game changer, again, in terms of development timeline. And I'll leave with that. Thanks so much.
All right, Doug. I'll try to exceed your expectations. So the news flow out of Guyana, as you know, continues to be extremely positive. And we talked about Phase 1 and the likelihood that we will have start-up by December. It's been a tremendous success. So I think it's a good reflection on the project management capabilities that we have as an organization to be able to deliver that on time and certainly ahead of schedule.
Phase 2, well-defined FID, engineering construction is progressing well. And then we're working with the government on Phase 3, the Payara project, and expect to have early oil, first oil some time in 2023. So really good progress on those first three phases, we've said that by 2025, we would have at least five FPSOs and roughly 750,000 barrels a day of production. And if you think about where that could be, there are – certainly, you have the Payara area that we're focused on developing. You've got what we're calling the Eastern – South Eastern area, which includes all the discoveries we've had around that Turbot area, and I think there has been roughly five discoveries.
And then if you move further East, you have Haimara and then West you have Hammerhead. So those are the possibilities, if you will, around potential fourth and fifth boats. We're still working to define those. I would anticipate sometime in the near future, being able to provide more clarity on where those next boats will be.
One of the challenges that we have given all of the significant exploration success that we've had, is making sure that we take the time to optimize the development. We don't want to rush in a way where we do something we might regret down the future. So as we have all these new discoveries, we want to make sure we're optimizing the right approach to create value, not only for us, but also for all stakeholders involved. And then as you know, on top of that, it's all the undrilled potential. So we're trying to balance progressing those developments, while at the same time making sure that we progress what is becoming an even more attractive portfolio of exploration opportunities. Again, Doug, I would imagine, we will continue to provide clarity sometime in the next several months.
On the Ranger, I don't have as much on Ranger only because we're still in the well location. I think quarrying operations have started. Again, I would expect we'll take those results and we'll be able to integrate them into what we know and the data that we have and we'll be able to provide an update in the future, but I hesitate to give anything, just because we're still on the well location.
Neil, I appreciate the long answer. Just to be clear, you're still holding 750,000 in your 2025 targets as a company, right?
That for production, yes, Doug, today that is the number we are still using. Again, that's production, that's not capacity of FPSO, that's production in 2025.
Yes, I expect we will talk about it next week. Thanks a lot, Neil. I appreciate it.
Thanks, Doug.
All right. Next, we will go to Biraj Borkhataria with Royal Bank of Canada.
Hi, thanks for taking my questions. And a few on your divestment plan. Just a couple on Norway and the assets sold. Could you say how much cash flow or free cash flow you're going to lose from selling those assets? And then also just a clarification, the $600 million tax repaid as part of the sale, is that paid by the buyer or is the repayment from the government? And then I also have a one follow-up, in addition to that. Thanks.
Yeah. Good. Thanks Biraj. So really good progress with the divestment program with Norway. In terms of – I mean, you're thinking about to right in terms of the impact. Certainly there will be an impact to volumes and I think we said production in Norway is roughly 150,000 – currently 150,000 oil equivalent barrels per day. There will be an impact on earnings, cash flow, but also a reduction in CapEx, avoidance of CapEx.
And so what we're planning to do, I think instead of providing specifics for every divestment that we do in terms of how that's affecting the overall portfolio, we're going to wait until March and we'll give a more fulsome view of all of the divestments and the impact that's going to have on the overall portfolio. On the cash, the cash refund is a repayment from the government, that $0.6 billion that you referenced.
Okay, that's very clear. And just a follow-up. Are you able to disclose what long-term oil and gas prices you used to test for impairments on your balance sheet?
I think, like we do with anything – you're talking about impairments, is that what you said?
Impairment testing, yes.
Okay. Sorry about that. Monitoring for impairments is something that is an ongoing process, and certainly is something that we follow very closely with U.S. GAAP. I don't think we disclose any specific pricing that we use in terms of conducting those impairments.
We have very, as you would imagine, very stringent processes and controls to make sure we identify any changes and facts or circumstances that would indicate that an asset might not recover its carrying value. That includes annual planning and budgeting that we follow, it includes assessing trends and the underlying commodities, natural gas crude et cetera. And then certainly, if through those processes that we have, we determine that there is some question about asset recoverability and impairment might be required. But again, it’s very strictly controlled certainly we follow U.S. GAAP very closely in doing that.
Okay. Thank you.
You are welcome. Thank you, Biraj.
Your next question comes from the line of Paul Cheng with Scotiabank.
Hey, good morning.
Good morning, Paul.
On the Permian, can you tell us what's the rig number and the frac crew you are running right now. And also in the Delaware Basin, what percent of your position is in the federal land?
Great. Thanks for the questions, Paul. In terms of rig and fracs, again, the pace of development continues along with the plans that we laid out. I think at the end of the quarter, Paul, we were at 55 rigs and 10 frac crews. So those are the numbers.
Is that net number or just a gross number?
No, I think it's a net number, Paul.
Okay.
Yes, in terms of the Delaware, I don't think I have the percentage of the lands that are federal in the Delaware. I mean, as you know, we have a very large inventory out there, but I don't have a specific number on federal lands.
Is that something that you guys will be willing to share, and maybe then offline that you can have someone get back to me?
Potentially, I mean, obviously, we would share with everyone, but I'll take it away, Paul and certainly and have a discussion whether or not that's something we want to share. Happy to do that.
Okay. Second question. In your – you have a lot of coker and as you show in your presentation. Have you guys tried to run the high sulfur resid or the major component of that directly as a feedstock into your coker in this pacing heavy oil? If you have, and be able to do it, what is the quantity, maybe given the right economic, you will be able to run?
Yes, thanks for the question, Paul. We have roughly 450,000 barrels a day of coking capacity. But we also have a lot of flexibility to fill the capacity and we can do that, certainly through heavy crude processing, we can do straight run, resid processing and we can do direct import of Vacuum Tower Bottoms and fuel oil. But in terms of how we feed that or we determine what goes into the cokers, we try to optimize the coker feed slate based on economics, based on availability and based on quality of the feedstocks.
So we do have the capability. I think giving you a specific number wouldn't be helpful, because it will change depending on what's the appropriate – what's the most optimal crude slate to run or what the optimal slate to run through those cokers. But I will say I think – when you think about IMO 2020, the key economic drivers is likely to be crude oil differentials and our efforts to optimize the feed slate. And I think the general mechanism for that economic value will be the use of less expensive heavy-sour crudes.
So we anticipate that's likely to keep the cokers full, providing advantage for us. But we certainly have the flexibility and capability to respond to the market and use any of those different kinds of feeds slates, but again, it's hard to give you a specific number, just because it depends on what the market is telling us.
Then maybe let me ask you in another way. One of the major refined data set technology-wise that, yes, there is no problem that – to run it, but in certain – in many occasions, they are just being constrained by the logistic infrastructure arrangement. So I guess, my question to you is that in your coastal refinery, whether you its Baytown and all that, do you have the capability to receive large quantity of receipt if the economic is there?
Yes, I really would agree with that. Certainly, technology-wise and capability-wise we can do it. I think it's fair to say, you can be limited by logistics. But we are, again, that would be part of the consideration of whether or not you use fuel oil in the coker. But again, it's somewhat limited, but I wouldn't say it's completely constrained. We do have the ability and have had the opportunity to run those in the U.S. Gulf Coast and in Europe. So there is flexibility there, there may be some constraints on logistics, but not enough to say you couldn't do it if the market told you that's the right thing to do.
And final question, Corpus Christi crude export capacity. Neil, do you have a rough estimate what is the current export volume and how much in the near term we would be able to push it before the Southern Gateway Terminal stop?
You are talking about export capacity of crude?
Crude oil export capacity, yes, in Corpus Christi. With all the new pipeline from Permian going down, is there a concern that, that become a bottleneck and we couldn't export the oil?
Yes. I certainly understand the concern. Obviously, as production continues to grow in the Permian, there is only so much of that, that will be consumed by industry on the Gulf Coast with manufacturing both refining and chemical capacity. But today, including us, we've been able to export crudes outside of the Gulf Coast into our refineries in Europe and Asia. Again, I don't know if there is any view on near-term constraints. I fully expect that as you see growth coming out of the Permian, that the industry will respond to that and I think is responding to that and building out additional export capacity, but I don't think we anticipate any near-term constraints on the ability to export out of Gulf Coast.
So one of the things we have done, Paul, as you know, we're certainly investing to increase our capacity on the Gulf Coast to run more of the light crudes out of the Permian, including the Beaumont expansion that we're doing. And I think there's a few other smaller expansions at other refineries that we have to be able to run more of those light crudes. We're certainly able to take advantage of it in our facilities and export it out to our refineries, so no constraints currently. And again, we would anticipate the industry would continue to respond to the additional lines coming out of the Permian.
Thank you.
Thank you, Paul.
All right. We'll next go to Dan Boyd with BMO Capital Markets.
Hi, Neil. Good morning.
Good morning, Dan. How are you?
Doing well, thanks. I just wanted to kind of follow back on the Permian where you say you're kind of trending as according to plan. But you are at 10 frac crews and I think your plan was to go from 11 at the beginning of the year to 16 at an exit rate. So, are you seeing more efficiency on the frac crew side because your production is running ahead of plan? I'm just wondering what this signals? Are you going to be increasing completions going forward or are you able to just do more with less?
I think – broadly and certainly for us, I think you are seeing more efficient production out in the Permian. And I think a fewer number of frac crews would be indicative of that. But I think even if you look at what's happening in industry rigs, certainly have flattened and even come down, but you see continued growth in volumes. And I think that's indicative of improved productivity, indicative of longer lateral lengths, indicative of using more and more effective rigs. So I think not only for us, but I think certainly in the industry, you're starting to see more, more efficiency.
But at the same time, it's not a heterogeneous resource and I think that's where we bring advantages by being able to apply sophisticated reservoir modeling. We're able to, I think, optimize how we're developing optimize things like spacing. Our ability to understand the sub-surface allows us to tailor the development to our understanding of the geology. And so I think still relatively early, I think you're going to see us continue to learn. I think you're going to continue to see us optimize how we're approaching the development.
So I wouldn't read too much into any specific number around frac crews or rigs. Again it isn't about volume for us. This is about what we need to do to create value for our shareholder and so we're going to respond to what we're learning, we're going to respond to the application of technology and drilling expertise and project management capabilities to make sure that over time, we're achieving that objective of creating value.
Okay, thanks. And then we talked about this one before, but we now look at your operating cash flow year-to-date versus the plan back in March. You may be running about, call it, $12 billion to $14 billion shy of that. Obviously we've been in a tough macro environment, but I was wondering, can you help us understand how much of that shortfall versus plan is purely related to price, and how much is potentially related to operations. We talked about increased maintenance, because what I'm trying to figure out here is, is there are potential for the next couple of quarters to get back on track and is there an operational catch-up that we might see?
Yes. I appreciate the question. We're obviously in a much different market environment than the basis that we use for that Investor Day, especially in Downstream and Chemical. So when we look at how we're performing relative to those numbers, if you adjust for that impact, if you adjust for the fact that we're in a very different environment, we're generally pleased with where we are. We have had as you highlighted, some operational challenges, which have been a detriment to that. But broadly speaking, we feel very pleased if you were to adjust for that environment.
Maybe more importantly, Dan, as we continue to have tremendous success on operational milestones. And we highlighted the liquids growth reaching 10 FIDs this year alone, the additional exploration discoveries. So we feel really good about the progress we're making on the underlying investments that will grow the earnings and cash flow generation capacity of the organization over time.
So, I think again, for the most part, we feel pretty good both on earnings and cash flow with the exception that we're just – we happen to be in a different environment. But we fully anticipate given that we are investing with structural advantages, we're not relying on market help that over time, those will begin to manifest themselves as we get into different price and margin environments.
All right. Thanks for taking the questions.
Thanks Dan. Operator, I think we have time for one more question.
Great. We'll take that question from Jason Gabelman with Cowen.
Yes, hey. Thanks for taking the question here, past the hour. I wanted to address the Mosaic agreement. It wasn't really discussed on the call yet. I mean, you guys have talking – have talked about carbon capture for a little while now. And there is obviously concern in the journal investment community that all the resource you own, will not be able to be developed, because of concerns around greenhouse gas. So your ability to develop a breakthrough technology, I think would go a long way. Can you just discuss the prospects of that technology and kind of where do you see that impacting the business, and maybe the carbon emission profile? And I have a quick follow-up. Thanks.
Jason, that's a good question to end the call on. Look – I mean, let me be clear. First of all, we recognize the risks from climate change and we recognize that something has to be done about it. And we are committed to providing affordable reliable energy, while minimizing the impact on the environment, and that's specifically the need to reduce CO2 emissions. If you look at that, 90% of global energy emissions come from three sectors, comes from power generation, transportation and the industrial sector. And the challenge that we face is, finding a comprehensive set of solutions that will allow us to reduce the emissions in those three sectors. But it's going to require advances in technology and it's going to require the implementation of effective policies by government.
So if you look at where we think we can participate in that solution development, is through our advantaged research and development capabilities. And so we are attacking each of those three sectors. So in power generation, you mentioned carbon capturing technology that is going to be critical to help reduce emissions in power generation. We're doing not only internal research and development, but we are also expanding the portfolio outside the company. You mentioned Mosaic. We had a similar agreement with a company called Global Thermostat few months ago. I mentioned all the partnerships we have with universities, national labs, et cetera. So we have a very wide aperture looking for opportunities to develop scalable economic solutions on carbon capture.
The second sector transportation, everyone's aware of the advances being made on the light-duty side, but on the commercial transportation, heavy-duty aviation, we think we need a biofuel solution. And you are, I'm sure, very familiar with our algae program. We're also looking at cellulosic biofuels. And then on the industrial side, that sector we're looking at new plant configurations, new processes, new catalysts. So the way we want to participate, the way we are participating in this, at a level that is much more significant than any of our peers, is leveraging our technology capabilities to come up with those solutions.
And I think we've spent $10 billion on low-emission technologies I think since the year 2000. And then as I mentioned, we continue to advocate for policies. So again, that's why you're seeing us partner with companies like Mosaic, Global Thermostat, because we recognize where those solution gaps exist and we believe new technologies are needed, and we think we have a competitive advantage to participate and find those solutions, while at the same time continuing to create value for our shareholders.
Thanks, I appreciate that answer. If I could just squeeze in a very quick follow-up, you cited the $150 million benefit to Downstream on the clean/dirty spread. Is there a corresponding impact on the Upstream, just trying to understand the impact to the entire portfolio? Thanks.
I appreciate that last question, Jason. It's something we looked at. I mean, obviously we don't want to focus just on the benefit we're getting from the Downstream. So when we look at our Upstream portfolio, this is a good example of having a very large global diverse portfolio, and there will be pluses and minuses in that portfolio as it relates to the implementation of IMO. But when we looked at it, in the end it ended up being a neutral impact. So it really does not have an impact on our Upstream. Again, like I mentioned, you'll see pluses and minuses, but on the overall portfolio, there is a neutral impact.
Well, we appreciate everyone allowing us the opportunity to highlight the third quarter and all of the key milestones that we hit, and the continued progress on our portfolio. We look forward to your participation on our fourth quarter earnings call, where I will be joined by our Chairman and CEO, Darren Woods. And we appreciate your interest and hope you enjoy the rest of your day. Thank you.
And this concludes today’s conference. We thank you everyone again for their participation.