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Edited Transcript of XOM earnings conference call or presentation 1-Nov-19 1:30pm GMT

Q3 2019 Exxon Mobil Corp Earnings Call

IRVING Nov 5, 2019 (Thomson StreetEvents) -- Edited Transcript of Exxon Mobil Corp earnings conference call or presentation Friday, November 1, 2019 at 1:30:00pm GMT

TEXT version of Transcript

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Corporate Participants

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* Neil A. Hansen

Exxon Mobil Corporation - VP of IR & Secretary

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Conference Call Participants

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* Biraj Borkhataria

RBC Capital Markets, Research Division - Analyst

* Daniel Jon Boyd

BMO Capital Markets Equity Research - Oilfield Services Analyst

* Douglas George Blyth Leggate

BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research

* Douglas Todd Terreson

Evercore ISI Institutional Equities, Research Division - Senior MD & Head of Energy Research

* Jason Daniel Gabelman

Cowen and Company, LLC, Research Division - VP

* Jonathon Rigby

UBS Investment Bank, Research Division - MD, Head of Oil Research and Lead Analyst

* Neil Singhvi Mehta

Goldman Sachs Group Inc., Research Division - VP and Integrated Oil & Refining Analyst

* Paul Cheng

Scotia Howard Weil, Research Division - Research Analyst

* Philip Mulkey Gresh

JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst

* Sam Jeffrey Margolin

Wolfe Research, LLC - MD of Equity Research & Senior Analyst

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Presentation

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Operator [1]

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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.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [2]

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All right. 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.

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 Investors 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 9 months of the year with a portfolio that is resilient to a range of commodity prices and margins. We are investing in advantaged projects that will grow the earnings and cash generation capacity of each of our businesses.

The nearly $23 billion of CapEx year-to-date is in line with current year plan and reflects 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. Including the consideration from the agreement we signed to sell nonoperated upstream assets in Norway, divestments now total nearly $5 billion. Exploration success has continued this year with 5 significant deepwater discoveries, 4 in Guyana and 1 in Cyprus. And we've reached final investment decisions for 10 major strategic projects this year, including projects from all 3 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 we laid out in 2018 and reiterated in March and positions us well to generate long-term shareholder value.

I'll now highlight third quarter financial performance, starting on Slide 4. Earnings were $3.2 billion in the quarter or $0.75 per share, including a positive $0.07 per share impact from a onetime tax item. 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. The broader margin environment remained challenging as short-term supply and demand imbalances continue to pressure natural gas prices and industry chemical and lube-based stock 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 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 nonoperated 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 a stronger downstream financial performance. Although long-term fundamentals remained strong in the Chemical business, polyethylene and aromatics margins continue to be impacted by supply length from industry capacity additions. The recent start-up of the polyethylene expansion at Beaumont is performing well and running above planned rates, supporting efforts to grow sales of high-performance metallocene products that deliver sustainability benefits, including lighter packaging weight, lower energy consumption and reduced emissions. Lower scheduled maintenance across U.S. Gulf Coast sites continued to -- 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 breakthrough carbon capture technology using metal organic 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 Institute of Technology. This partnership will focus on progressing research in biofuels and bio products, 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, 5 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 onetime noncash 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 and 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, 3 new projects are online and performing well, supporting increased production of cleaner, higher-value products.

We've made final investment decisions this year for 4 additional projects, including the Beaumont light crude expansion and Wink to Webster Pipeline, both of which will support our integrated Permian strategy and growth plans. In our Chemical business, with the recent startup of the Beaumont polyethylene expansion, we now have 8 new facilities online with 4 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. Now 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 would place start-up within 5 years of initial discovery, well ahead of the typical pace for the industry of closer to 9 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 a planned start-up in 2023.

The Tripletail discovery, which we announced in September, marks 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 continue 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 the 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. 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 nonoperated Norway assets for $4.5 billion. The sale includes ownership in 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 noncontingent 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. In the Downstream, we see potential 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 an 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 -- 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 startups in Downstream and Chemical continue to perform well, and we reached final investment decisions for 8 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 risks of climate change. I'll now be more than happy to take any questions you might have.

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Questions and Answers

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Operator [1]

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(Operator Instructions) First question will come from the line of Doug Terreson with Evercore ISI.

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Douglas Todd Terreson, Evercore ISI Institutional Equities, Research Division - Senior MD & Head of Energy Research [2]

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Neil, in U.S. Upstream, you mentioned that the key factors this period were realization, 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 3 questions on the higher growth expenses item in U.S. Upstream.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [3]

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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, 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-unconventional assets, including LaBarge and Prudhoe Bay, that had an impact as well. And then we did have some higher growth expenses, most of that does 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, using our logistics position to bring barrels to our refineries and chemical plants.

The pace of development is consistent with the plans that we've 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 subsurface using reservoir modeling. We're bringing drilling engineers from all over 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. 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 3 elements we're trying to balance.

I think we feel good about where we are. I think we 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, that you can fully anticipate as we bring technology to this, as we bring expertise and drilling in the subsurface, 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 a very high expectation from the organization that will only get better in developing the resource.

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Douglas Todd Terreson, Evercore ISI Institutional Equities, Research Division - Senior MD & Head of Energy Research [4]

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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.

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Operator [5]

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Next, we'll go to Sam Margolin with Wolfe Research.

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Sam Jeffrey Margolin, Wolfe Research, LLC - MD of Equity Research & Senior Analyst [6]

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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?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [7]

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Yes. I appreciate the question, Sam. Yes, again, we feel really good about the progress we're making on that divestment program. And in fact, Norway was accelerated, so that's why we felt 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 at progressing that objective. But I think also recognize that the reason we're pursuing a divestment program, primarily, is given the fact that we have brought so many attractive assets into the portfolio. Think about Permian and 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're also taking into account things like whether or not we operate and have control of forward invest plans. I don't want to convey, certainly, from our perspective or from an industry perspective, that they're foregoing 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's an opportunity for us to high grade the portfolio and even have this opportunity to even grow more the overall value by high grading our assets.

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Sam Jeffrey Margolin, Wolfe Research, LLC - MD of Equity Research & Senior Analyst [8]

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Okay. 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 to think about bolting on some assets here? It seems like you can add value to some distressed situations.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [9]

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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 as 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't deliver.

And so it's something we're looking at very closely. We're in a fortunate position, given the portfolio that we have, that we can be very choosy. We're very fortunate in that we have the financial strength, the balance sheet capacity to transact at any level in any cycle. And so that gives you a nice spot to be in to be very, very selective in what you're pursuing and 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 of 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 and 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.

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Operator [10]

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The next question comes from the line of Neil Mehta with Goldman Sachs.

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Neil Singhvi Mehta, Goldman Sachs Group Inc., Research Division - VP and Integrated Oil & Refining Analyst [11]

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I guess the first question I have is just around IMO 2020. We've seen -- certainly seen a lot of other companies, including yourself, pulling 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's standpoint about how this is playing out?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [12]

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Yes. I appreciate the question, Neil. I'll maybe step back a little bit and talk about what we're seeing. We mentioned it 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 fall significantly, the clean/dirty spreads, I think, recently 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, 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'll 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 2 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's 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 -- 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 the industry.

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Neil Singhvi Mehta, Goldman Sachs Group Inc., Research Division - VP and Integrated Oil & Refining Analyst [13]

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And the follow-up is one of your capabilities as a company is managing regulatory and political risk. As we go into election season here in the United States, how do you think about risks around federal public lands and what that means for your exposure? I'm thinking about that in the context of New Mexico, Alaska and the Gulf of Mexico.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [14]

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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 efforts, obviously, to ban fracking, would have a negative impact on industry efforts to develop resources like the Permian. There's no doubt in 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 there 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. And 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, 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 policymakers 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 effective.

The other thing we try and do, Neil, is help policymakers understand the tremendous benefit that resource development brings to economies, it 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 net 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's political risks almost everywhere where we operate, and having a global portfolio like we have helps us mitigate risk in any potential or specific jurisdictions. So I think -- I certainly can understand if all your eggs are in one basket, and you 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.

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Operator [15]

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And next, we'll go to Phil Gresh with JPMorgan.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [16]

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So first question, you're talking earlier about execution on the existing portfolio and 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?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [17]

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Yes. 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'll provide an update on where that stands at the Investor Day in March.

I think -- you talk about inflationary pressures. I think it's dependent on where you're operating. I think we've generally seen a fairly good cost environment in the deepwater, for example. Out in the Permian and 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 and 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 hot cost environment is you build modulars in 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 undermine the value of any given investment if you're not executing well and not delivering it on time and on schedule.

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Philip Mulkey Gresh, JP Morgan Chase & Co, Research Division - Senior Equity Research Analyst [18]

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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, Neil, as we look out into 2020? And considering the $200 million or so of earnings each of the past 2 quarters, there's -- looks like there's some higher maintenance in the next 2 quarters. But just generally, what's your kind of view of 2020 relative to the run rate of recent quarters?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [19]

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Yes. I appreciate it, Phil. Yes, I think that if you look at polyethylene industry margins, they were 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 barriers, some sort of unique application for our customers where we can garner 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.

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Operator [20]

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And now we'll go to Jon Rigby with UBS.

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Jonathon Rigby, UBS Investment Bank, Research Division - MD, Head of Oil Research and Lead Analyst [21]

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I have 2 questions. A 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, so 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 what if we revisited 4Q and look at it across '19 versus '18, would we start to see the effect of those start-ups within your earnings?

And then maybe if I could ask you a second question as well. Just on the guidance on disposal proceeds, is that a figure -- the $15 billion that you will receive? Or is that gross of selling costs, taxes, et cetera?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [22]

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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, into 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 think it's relatively early days in some of these major projects that have come along. They're 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 projects. So the fact that we've been able to execute that project well, execute it with new technology is pretty impressive. And we feel very good about that. And we fully expect over time, especially as 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'll continue to see good progress, and we'll 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 risked number. So certainly, in terms of the level of activity should we succeed in transacting on everything, it would bring in a lot more consideration than that $15 billion. It is progressing well. To be at $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.

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Operator [23]

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And now we'll go to Doug Leggate with Bank of America.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [24]

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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?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [25]

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Okay. Thanks, Doug. Appreciate the question. Maybe let me just 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 in NAM, that would accelerate the end of production, I think, by 2030 at the latest is the initial -- that was the initial time frame. 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 0 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 and the state, have agreed for the need to put in place an addendum to that agreement, and we'll work responsibly to accelerate the lowering of the production. And we think we'll come to a final agreement on compensation, but that's something that's underway, 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 specifics, 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.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [26]

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I appreciate a lengthy answer, Neil. My second one is probably a quick one given your history in being able to answer these. But I just wonder if there's any updates 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 would 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 time line. And I'll leave it at that.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [27]

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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'll 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 and 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, sometime in 2023. So really good project -- or progress on those first 3 phases.

We've said that by 2025, we'd have at least 5 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 -- Southeastern area, which includes all the discoveries we've had around that Turbot area, and I think there's been roughly 5 discoveries. And then if you move further east, you have Haimara and then west, you have Hammerhead. And 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 that we might regret down the future. And 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. But again, Doug, I would imagine we'll continue to provide clarity sometime in the next several months.

On Ranger, I don't have as much on Ranger only because we're still on the well location. I think coring operations have started. And 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.

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Douglas George Blyth Leggate, BofA Merrill Lynch, Research Division - MD and Head of US Oil and Gas Equity Research [28]

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Neil, I appreciate the long answer. Just to be clear, you're still holding 750,000 in your 2025 targets as a company, right?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [29]

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For production? Yes, Doug, that is -- today, that is the number we're still using. But again, that's production, that's not capacity of FPSO. That's production in 2025.

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Operator [30]

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Next, we'll go to Biraj Borkhataria with Royal Bank of Canada.

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Biraj Borkhataria, RBC Capital Markets, Research Division - Analyst [31]

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I had a few on your divestment plan and 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 that a repayment from the government? And then also I have one follow-up in addition to that.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [32]

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Yes. Good. Thanks, Biraj. So again, really good progress in the development -- divestment program with Norway. In terms of -- I mean, you're thinking about it right in terms of the impact. Certainly, there'll be an impact to volumes, and I think we've 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.

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Biraj Borkhataria, RBC Capital Markets, Research Division - Analyst [33]

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Okay. That's very clear. And just a follow-up, are you able to disclose what long-term oil and gas prices you use to test for impairments on your balance sheet?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [34]

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I think like we do with anything -- you're talking about impairments, is that what you said?

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Biraj Borkhataria, RBC Capital Markets, Research Division - Analyst [35]

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Impairment testing, yes.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [36]

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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 disclosed 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 in 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 in the underlying commodities, natural gas, crude, et cetera. And then certainly, if through those processes that we have we determine that there's some question about asset recoverability, an impairment might be required. But again, it's very strictly controlled. Certainly, we follow U.S. GAAP very closely in doing that.

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Operator [37]

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Your next question comes from the line of Paul Cheng with Scotiabank.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [38]

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Neil, the -- in Permian, can you tell us what's the rig number and the frac crew you have working right now? And also in the Delaware Basin, what percent of your position is in the federal land?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [39]

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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, okay? So those are the numbers.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [40]

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Is that the net number or do you say gross number?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [41]

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No. I think it's a net number, Paul.

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 the specific number on federal lands.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [42]

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Is that something that you guys will be willing to share and that you may then do off the line, then you can have someone get back to me?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [43]

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Potentially. I mean, obviously, we would share it 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.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [44]

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Okay. Second question, in your -- you have a lot of coker, 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 coke plant, displacing heavy oil? If you have and be able to do it, what is the quantity that maybe, given the right economics, you will be able to run?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [45]

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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 feed slate. But again, it's hard to give you a specific number just because it depends on what the market is telling us.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [46]

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Maybe let me ask in another way. One of the major refiner, they have said technology-wise that, yes, that's no problem, that one, yet. But in certain -- in many occasions, that is just being constrained by the logistic infrastructure arrangement. So I guess my question to you is that in your coastal refinery that, whether it's Baytown and all that, do you have the capability to receive a large quantity of resid if the economic is there?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [47]

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Yes. No, I mean, I may 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's 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.

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [48]

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All right. Final question, Corpus Christi crude export capacity, Neil, that do you have a rough estimate? What is the current export volume? And how much in the near term we would be able to proceed before the Southern Gateway terminals start?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [49]

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You're talking about export capacity of crude?

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Paul Cheng, Scotia Howard Weil, Research Division - Research Analyst [50]

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Actual 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?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [51]

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I'd certainly understand the concern. Obviously, as production continues to grow in the Permian, there's 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 refineries in Europe and Asia. I don't -- again, I don't know if there's 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 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 the 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 with 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 lights coming out of the Permian.

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Operator [52]

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We'll next go to Dan Boyd with BMO Capital Markets.

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Daniel Jon Boyd, BMO Capital Markets Equity Research - Oilfield Services Analyst [53]

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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're 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 just 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?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [54]

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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 the 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 effective rigs. So I think not only for us but I think certainly in the industry, you're starting to see 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 subsurface 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, this 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.

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Daniel Jon Boyd, BMO Capital Markets Equity Research - Oilfield Services Analyst [55]

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And then we talked about this one before. But when I look at your operating cash flow year-to-date versus the plan back in March, maybe 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 a potential for the next couple of quarters to get back on track? And is there an operational catch-up that we might see?

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [56]

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Yes, appreciate the question. We're obviously in a much different market environment than the basis that we used 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, is 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.

But -- 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 reliant on market health that over time, those will begin to manifest themselves as we get into different price and margin environments.

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Operator [57]

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We'll take that question from Jason Gabelman with Cowen.

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Jason Daniel Gabelman, Cowen and Company, LLC, Research Division - VP [58]

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I want to address the Mosaic agreement. It wasn't really discussed on the call yet. I mean, you guys have talked and -- have talked about carbon capture for a little while now. And there's obviously concern in the general 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 you see that impacting the business and maybe the carbon emission profile? And I have a quick follow-up.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [59]

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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 3 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 3 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 3 sectors.

So in power generation, you mentioned carbon capture 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 a few months ago. I mentioned all the partnerships we have with universities, national labs, et cetera. So we are -- we have a very wide aperture at looking for opportunities to develop scalable economic solutions on carbon capture.

The second sector, transportation, we are aware of the advances being made on the light-duty side. But on the commercial transportation, heavy-duty aviation, we think we need an algae -- a biofuel solution. And you're, I'm sure, very familiar with our algae program. We're also looking at cellulosic biofuels.

And then on the -- in 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 policy. So again, that's why you're seeing us partner with companies like Mosaic, Global Thermostat, is 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.

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Jason Daniel Gabelman, Cowen and Company, LLC, Research Division - VP [60]

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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.

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Neil A. Hansen, Exxon Mobil Corporation - VP of IR & Secretary [61]

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Appreciate that last question, Jason. And 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's a neutral impact.

Well, we appreciate everyone allowing us the opportunity to highlight the third quarter and all 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.

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Operator [62]

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And that does conclude today's conference. We thank everyone again for their participation.