Exxon Mobil Corporation

Please stand by. We're about to begin. Good day, everyone. Welcome to this ExxonMobil Corporation second 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 second quarter earnings call. We appreciate your participation on the call today and your continued interest in ExxonMobil. This is Neil Hansen, Vice President of Investor Relations. Joining me today is Neil Chapman. Neil is a Senior Vice President and member of the Management Committee with responsibility for the upstream. After I review financial and operating performance, Neil will provide his perspectives on the quarter and give updates on the substantial progress we've made on the major growth projects across the business. Following Neil's remarks, we'll be happy to take your questions. Our 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 two and the supplemental information at the end of this presentation. Moving to slide three, let me start first by summarizing the solid progress we've made on our major growth plans along with other noteworthy accomplishments. Neil will go into more detail after my remarks but I wanted to take a few moments to touch on some key highlights. In the first half of the year, we've made good progress on our growth plans. The fundamentals and long-term demand growth that underpin our investments remain strong. The competitive advantages we've built into our projects make them robust across commodity price cycles, including the margin environment we are currently experiencing. We reached final investment decisions for nine major strategic projects in just the first six months of the year, including projects from all three business lines. Offshore exploration success continued with four significant deepwater discoveries, three in Guyana and one in Cyprus. And we achieved key milestones in the development of two of our LNG growth projects in Papua New Guinea and Mozambique. Liquids production increased significantly from last year, with volumes up 144,000 barrels per day, or 7%, driven by strong growth in the Permian. We remain on schedule with plans to increase production in the Permian to 1 million oil-equivalent barrels per day by 2024, as we also continue to build out supporting infrastructure and takeaway capacity. In the downstream and chemical businesses, Recent project startups in North America and Europe are already making a positive contribution to results. These projects are accretive to earnings, even in the current margin environment, demonstrating the market resiliency we envisioned when making these investments. In particular, the Baytown Steam Cracker, which started up last year, has performed exceptionally well, with production exceeding design capacity by 10%. Lastly, we increased the quarterly dividend by 6%, marking the 37th consecutive year of dividend growth. Positive momentum we generated in the first half of the year is in line with the plans we laid out in 2018 and reiterated in March, and positions us very well to generate long-term shareholder value. I'll now highlight our second quarter financial performance starting on slide four. Earnings were $3.1 billion in the quarter, or 73 cents per share, including a positive 12 cent per share impact from a tax rate change in Alberta, Canada. These results were in line with our expectations, given the margin environment, seasonal impacts, and planned maintenance we experienced during the quarter. The margin environment remained challenging in the second quarter, as short-term supply and demand imbalances continued to pressure natural gas prices and industry product margins. Cash flow from operations and asset sales was $6 billion in the quarter, after adjusting for changes in working capital, which were primarily seasonal in nature and consistent. CapEx for the quarter was $8 billion, and through the first half of the year, CapEx is $15 billion, representing 50% of the full year guidance we provided in March. The free cash flow deficit in the second quarter is a result of our strategy to focus on the long term and grow shareholder value across commodity cycles, leveraging our financial capacity. I'll now go through a more detailed view of development since the first quarter on the next slide. Starting first with the upstream. Average crude oil prices were higher than the first quarter, with Brent up $5.63 and WTI up $4.93. ExxonMobil's liquids realizations increased by $5.09, in line with the increase in crude markers. Gas realizations, on the other hand, were down in the second quarter. This was consistent with the typical three to six month crude linked LNG pricing lag that we experience and a 51 cent decline in Henry Hub pricing as production growth continues to outpace demand in the U.S. Gas realizations were also impacted by weaker prices in Europe with lower seasonal demand and an increase in LNG imports. Production in the Permian averaged 274,000 oil equivalent barrels per day, an increase of 21% relative to the first quarter. Permian production is up nearly 90% from the average production we saw in the second quarter of last year. In addition to three exploration discoveries in Guyana in the first half of the year, we recently completed construction of the FPSO for Lysa Phase I, the Lysa Destiny, which is now in transit to Guyana. We also made a final investment decision for the 220,000 barrel per day Flies of Phase II project, and we updated the resource estimate to more than 6 billion oil equivalent barrels. We also progressed toward a final investment decision for the Mozambique LNG project by securing approval of the Rwumba development plan from the Mozambique government. We announced plans to expand unconventional operations in Argentina's Vaca Muerta Basin, and expanded our growing deepwater exploration portfolio, including the acquisition of 7 million deepwater exploration acres offshore Namibia. In the downstream, industry refining margins improved during the quarter, but remained near five-year lows. Unrelated reliability events at the Baytown, Sarnia, and Yambu refineries negatively impacted second quarter results. We expanded our Group 2 lubricant base stocks portfolio with increased production from the Rotterdam hydrocracker and a further expansion in Singapore. Although long-term fundamentals remain strong in the chemical business, paraxylene margins weakened during the second quarter as a result of supply length from recent industry capacity additions. We achieved another important milestone in our plans to grow high-value premium chemical product sales with the startup of the polyethylene expansion at Beaumont, which will capture integration benefits with the Baytown Steam Cracker and, once lined out, is expected to be accretive to earnings and cash flow in the current margin environment. We also announced a final investment decision for the Gulf Coast growth venture in Corpus Christi, where, with our partner, SABIC, we will construct a 1.8 million ton per year steam cracker and derivative units. We continue to progress research and development of lower emissions technologies. In the quarter, we signed a joint development agreement with Global Thermostat to advance breakthrough technology to capture and concentrate carbon dioxide emissions from industrial sources, including power plants. We also initiated a partnership with the Department of Energy's National Renewable Energy Laboratory and National Energy Technology Laboratory to research and develop a range of low-emissions technologies with a specific focus on ways to bring biofuels and carbon capture and storage to commercial scale. Both of these important efforts are aligned with our focus on leveraging fundamental science to develop breakthrough solutions that can help reduce global emissions. Let's now move to slide six for an overview of second quarter earnings relative to the first quarter of the year. Second quarter earnings of $3.1 billion were up nearly $800 million from the first quarter. Upstream earnings were up approximately $400 million, driven by higher liquids realizations and one-time tax items. partly offset by lower natural gas prices. Downstream earnings increased by more than $700 million due to improved fuels margins, wider North American crude differentials, and the absence of negative mark-to-market derivative impacts. Improvements in downstream earnings were partly offset by the previously mentioned reliability events. And finally, chemical earnings were lowered by $330 million with higher scheduled maintenance and weaker paraxylene margins. Turning to slide seven, I'll expand on the impressive year-over-year increase in upstream volumes. Production in the second quarter of 2019 was 3.9 million oil equivalent barrels per day, an increase of more than 260,000 oil equivalent barrels per day relative to the second quarter of last year, representing a 7% increase. The higher volume was driven by production growth of 129,000 oil equipment barrels per day in the Permian, which represents an 89% increase from the prior year quarter. Increased production from Hebron and Kayombo also contributed to the higher volumes. Lower maintenance in Canada and the absence of impacts from the earthquake in Papua New Guinea, combined with stronger seasonal gas demand in Europe, provided additional volume uplift. The bottom left chart highlights the strong year-over-year liquids growth of 177,000 barrels per day, an increase of 8% from the second quarter of 2018. Importantly, this marks the highest quarterly liquids production since 2016 and the highest second quarter liquids production in a decade. Moving to slide eight, I'll review the second quarter 2019 cash flow. Second quarter earnings, when adjusted for depreciation expense and changes in working capital, yielded $6 billion in cash flow from operating activities. There was a $1.2 billion draw on working capital in the quarter, driven primarily by lower seasonal payables. This impact is in line with the typical seasonal pattern of a working capital draw in the second quarter, which has been on average about $2 billion over the last decade. Other items included the impact from the Alberta tax rate change, which resulted in a non-cash benefit to earnings of approximately $500 million. While no significant asset sales have completed year-to-date, asset marketing activities are in line with our divestment plans and consistent with our expectation of generating $15 billion from asset sales by the end of 2021. Second quarter additions to PP&E and net investments and advances were $6.9 billion, driven primarily by increased activity in the Permian Basin. Gross debt increased by approximately $4 billion in the quarter, and cash ended the quarter at $4.2 billion. As I've discussed and as you can see, we are leveraging our financial capacity to invest in advantaged value accretive projects through the commodity price cycle. This is an important element of our strategy, so let me provide some additional perspective on the next slide. The chart at the top left of the page provides a view of commodity prices and margins over the past 10 years and the relative position of the environment we've seen in the first half of 2019 to that range. While margins so far this year have been on the low end of the 10-year range across many of our businesses. These levels are consistent with historical experience and, importantly, consistent with the scenarios that we anticipate when we make investment decisions. In fact, even in today's market environment, as mentioned, the recent chemical and refining project startups that I previously highlighted are contributing positive earnings and cash flow. The cyclical nature of these businesses makes it critically important to have the financial capacity to invest across commodity price cycles and grow the dividend. Over the past several years, we've taken advantage of these downturns in commodity prices to assemble the best set of opportunities that we've had in 20 years, and we are now investing consistent with our strategy to capture value from those opportunities. This combination of financial capacity to invest through the cycle and a deep portfolio of attractive investments is unique in industry. The chart on the bottom left of the page highlights our annual free cash flow generation over the past several years. Cumulative free cash flow over this time period is well in excess of our cumulative dividend. This provided a strong basis to make value accretive investments and grow the dividend over time. We view those two efforts as being closely linked together. The ability to grow the dividend requires continued investments in accretive, resilient opportunities across price cycles. During times of price volatility, we keep the long-term in mind, as there can be a number of opportunities to capture incremental value by investing when others are pulling back. With our financial strength and a competitively advantaged portfolio, we've been able to invest countercyclically in a number of key growth areas, taking advantage of attractive, low-cost environments. I'll now provide some perspective on our outlook for the third quarter, starting on slide 10. In the upstream, we expect volumes in the third quarter to be in line with the second quarter. We will also see the impact of the absence of the second quarter one-time non-U.S. tax help of approximately $500 million. In the downstream, we expect Permian crude differentials to narrow as additional takeaway capacity comes online. Industry refining margins are expected to be in line with seasonal demand patterns. Scheduled maintenance in the third quarter should be significantly lower relative to the second quarter. Chemical margins are expected to remain under pressure. as the market continues to work through supply length from recent capacity additions. Consistent with the downstream, scheduled maintenance in the chemical business in the third quarter is also expected to be lower. I'll provide some additional details on scheduled maintenance on the next slide. As we've previously discussed, scheduled maintenance in the downstream this year will be higher than normal, in part due to preparation for IMO 2020. Plan maintenance and downtime tends to be seasonal, in line with demand patterns. And consistent with this, we expect the impact from scheduled maintenance in the third quarter to be lower relative to what we experienced in the second quarter. And then in the fourth quarter, we anticipate maintenance activity to pick up as we enter into the fall maintenance season. But activity, again, should remain below second quarter levels. The estimated earnings impacts for the third and fourth quarter for the downstream are shown on the upper left chart. In the chemical business, shown on the bottom left chart, we also expect lower scheduled maintenance, with the impact in the third and fourth quarters below what we saw in the second quarter. We hope this provides you with some helpful perspectives on key drivers of anticipated market and plan factors for the upcoming quarter. And with that, at this time, I'd like to hand it over to Neil.

Good morning, everyone. It's good to be back on the call. As Neil said, before we take your questions, I'd like to share my perspective on the second quarter results. Then I'm going to provide a few updates to the plans that we laid out in our New York March discussions. I want to start by acknowledging the strong liquids growth. As I've said many times, volume is not a target. It is an outcome of our plans to grow value. Nevertheless, Our liquids growth reflects well on the organization maintaining the schedule in the early stages of executing our upstream growth plans. In terms of those growth plans, the ones we laid out in New York, I feel we're making outstanding progress. Permian growth is strong and on schedule. Guyana project plans are on or slightly ahead of schedule. And in the downstream and chemicals, 11 of the 19 projects that we laid out in New York last year are online, and we FID'd another six in the second quarter. I'm going to provide some further details on these in the following slides. We are in a unique position versus the rest of industry. We have a very attractive opportunity set. These are the advantage projects that are robust at the bottom of the cycle conditions. So we have a very attractive opportunity set, and we have the financial capacity to pursue them in a business that is very cyclical. In the second quarter, three of our major businesses were at low points in their cycles. As you heard from Neil, that's been a major factor in our quarterly results. While we obviously prefer margins to be at the top of the cycle, The current margin scenario was contemplated, and we have the financial capacity to maintain our plans. In fact, we built our growth strategies based on a full range of potential industry margins and the impact they would have on our financial results. That is why we put such importance on having a strong balance sheet to enable us to proceed with our long-term investment plans and weather through the cyclical nature of our business. On the whole, our businesses performed extremely well during the second quarter. Actually, they have in the first half of the year. Chemicals and upstream reliability has been excellent, and refining has also been strong, with the exception of the three discrete incidents, the one in Sarnia, Canada, one in Yanbu, Saudi Arabia, and the one in Baytown, Texas that Neil referenced. Although these are one-off and not systemic to our overall performance, in total, We estimate the second quarter impact from these three incidents to be of the tune of $150 million of earnings. That's the earnings impact. Of course, this is disappointing. Baytown and the Yanbu facility are now back in full production, and Sarnia will be at marginally lower rates through the fourth quarter. I want to take this opportunity to update you on the fire that occurred at our Baytown olefins plant earlier this week. First and foremost is the safety of our people and those in the surrounding community. I'm pleased to say there were no reported serious injuries. An investigation into the cause of the incident and the potential damage continues. And frankly, at this stage, it's really too early to say much more than that. On the larger point of reliability, of course, it's an important focus area for us. It has been for a long time. We benchmark extensively and our downstream facilities are ranked consistently better than the industry average. However, we must eliminate the significant one-off events as we're just not satisfied with being an above average industry performer. We're progressing a comprehensive reliability improvement program that we initiated late last year. This is leveraging insights across our upstream refining and chemical businesses and is also reaching out to leaders outside of our industry to ensure that we leave no stone unturned in our drive to lead industry reliability at all times. Slide 14 summarizes the progress of our major portfolio. Starting with the upstream, I'm going to provide some more details on Permian and Guyana on the subsequent following pages. In Brazil, our CACRA development is proceeding on schedule. We expect to spud the first exploration well on Urupuru, and that's the block that's adjacent to Kakara, with our partner Petrobras, in the second half of this year. We passed two significant milestones with host government approvals of our development plans for the Papua LNG in Papua New Guinea and Ravuma in Mozambique. In the downstream are three investments at Beaumont, Rotterdam, and Antwerp, These are all upgrading low-value streams to higher-value streams. They're lined out, and all are contributing to earnings and cash. And in the second quarter, we completed the FID of the three remaining major refinery projects that are in our growth plans. In chemicals, the new Baytown cracker and two polyethylene plants are performing well, and the expansion of the high-margin thermoplastic elastomer business at Santoprene started up in May of this year. All these investments are also accretive to current earnings. We started up the third polyethylene plant at Beaumont in July, and that was one month ahead of schedule. We also completed the FIDs of four major new world-scale plants in the first half, three of which were in the second quarter. That's a new polypropylene line at Baton Rouge, a linear alpha olefins plant at Baytown. That'll be a new product to ExxonMobil's chemical portfolio. an expansion to our industry-leading high-margin propylene plasma business at Vistamax, which is also at Baytown, and the largest steam cracker that we have ever built, plus the derivatives at Corpus Christi. On slide 15, you can see that our unconventional Permian and Bakken volumes are growing in line with plan. We increased our Permian volumes by 20% in the second quarter, which is up 90% versus the second quarter last year. We're now at 51 rigs and 12 frac crews in the Permian, and we bought 67 wells to sales in the second quarter. Our unique development plans, which are focused on maximizing long-term value of the resource and leveraging the scale of ExxonMobil to drive capital efficiency, are delivering encouraging results. The rocks and well performance is extremely strong, and as I said previously, Our approach is to understand the impact of development and operating practices on both IP rates and long-term recovery. Drilling a single well and applying a larger completion with higher intensity fracture can yield higher IPs, but it may yield lower ultimate recovery versus drilling several wells with less intense completions. Capital efficiency is critical. and it's an area where our team is constantly looking for ways to improve. It's all about balancing capital outlay, IPs, and the ultimate recovery to achieve the highest value. We've ramped up activity above surface with the ongoing construction of our Cowboy Central Delivery Point facilities in the POCOLATE region of the Delaware, and we finalized the FID to proceed with the greater than one million barrel a day liquids pipeline to the Gulf Coast. The Permian level activity is high, and we're making great progress. Page 16, our first FPSO, Lisa Destiny, is en route to Guyana. The startup is scheduled for the first quarter of next year, but I'm optimistic we'll do better than that. We completed the FID on the second FPSO, Lisa 2, which is close to double the size of Lisa 1 in the second quarter, and that will start up in 2022. The startup of the third FBSO for the Payara and Pakora development remains scheduled for a 2023 startup. We've had three further discoveries in the first half of 2019, Paimara, Tilapia, and Yellowtail. We're continuing to assess the results of these discoveries and are not yet ready to finalize their resource size. However, the Staybrook resource will be six plus billion oil equivalent barrels And again, as I've said before, this resource continues to grow. We anticipate three further exploration wells in the second half. They are likely to include Triple Tail, Uaru, and Macu, with a potential fourth one to spud before year end. We currently have three drill ships in the basin, and the fourth will be on station in the fourth quarter. On the bottom left, we've included a chart to illustrate the continuing increase in our inventory of future exploration prospects. I've included page 17 to remind you of our upstream divestment plans through 2021. We've previously communicated that we anticipate asset sales of $15 billion. As I said before, the $15 billion is a risk number and anticipates that some of the divestment candidates that we put in the market will not realize our retention value. But the marketing program is on track and includes the assets listed on the right. We're also in marketing discussions on other assets that are not public. So I have not, of course, listed them here. Again, this program is on schedule, and we anticipate delivering the $15 billion previously communicated. Finally, on slide 18, a quick update on the significant growth milestones in our integrated ethylene and polyethylene business. on the Gulf Coast. The Baytown and Montbellevue investments have been online for some time, and as I said earlier, are accretive to earnings even at the current low margins. The polyethylene units at Montbellevue started up in 2017 and are operating at capacity. The ethylene steam cracker at Baytown, which started up last year, is operating at 10% above design capacity. The third polyethylene line at Beaumont started up in July ahead of schedule. This was the first line in the world to start up on the higher value but notoriously difficult to produce in a gas phase reactor, metallosine polyethylene, and that was from the first day of operations. We're very pleased that our startup was flawless. In the second quarter, we completed the FID of the largest steam cracker we will have ever built, plus the derivatives, and they're going to be located at Corpus with our partner, Sabic. This will be highly advantaged versus the industry Gulf Coast investments, based on location and, of course, the adjacency to the Permian, lower capital cost, and higher value products. Startup is scheduled for 2022. The fundamentals supporting these chemical investments remain strong. All of this is being done to what we know will be increasing global demand, supported by population growth and a growing middle class. In summary, our organization is absolutely focused on delivering the operating performance we expect today and on delivering our growth plans. We have a high level of confidence that we will deliver, and our performance through the first half of this year demonstrates that we're on track. With that, Neil, I'll hand back to you for the Q&A.

Thank you for your comments, Neil. We'll now be more than happy to take any questions you might have.

Thank you, Mr. Chapman and Mr. Hansen. The question and answer session will be conducted electronically. If you'd like to ask a question, please do so by pressing the star key followed by the digit 1 on your touchtone telephone. We request that you limit your questions to one initial with one follow-up so that we may take as many questions as possible. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. Additionally, please lift your handset before asking your question. We'll proceed in the order that you signal us. We'll take as many questions as time permits. Once again, please press star 1 on your touch-tone telephone to ask a question. We'll take our first question from the line of Doug Leggett with Bank of America.

Thanks. Good morning, everyone. Neil, great to have you back on the call. Neil, I've got two questions, if I may. My first one, not to be terribly predictable, but is on Guyana. Clearly, the exploration program, Hammerhead, you've dedicated both assets to appraisal drilling. And now, as I understand it from your partner, you're going off to kind of fully appraise what could be a major development hub in the long-tailed turbot area. So I just wonder if I could just push you a little bit on why you have not yet chosen to revisit the likely production trajectory, because it clearly looks like you're running well ahead, not least because to have a fourth and fifth boat and still hit 750 means those would be undersized. So could you frame for us what you see the potential like today and how that would play into your 2025 outlook, which is clearly out of date?

Yeah, how about out of date, Doug? I mean, you know, what we communicated in March was this big increase, getting up to 750 KBD by that time. I would tell you... There is a tremendous amount of activity going on in the basin. I want to start at that point. You know, as we've said, we have the first boat on the way. We have the second boat in construction. We have three drill ships. We have a tremendous amount of activity going on. And, you know, all of these items, you know, we're going at great, great pace. We have to maintain alignment with our partners and with the government on each one. What I'm really focused on and the organization is focused on primarily is delivering on what we communicated to you and to the investment community. And that's the numbers that we laid out in March. Of course, as I indicated, we're very optimistic that that will be at least what we will do. We're just not ready to make another change to up either the production outlook or at this stage, anything more on the resource base. You mentioned Hammerhead. Let me just make a couple of comments on Hammerhead. I think you are aware that we drilled two more wells on Hammerhead recently, and the results were positive. I would describe them as reinforcing their high-quality reservoirs. We've now drilled three wells on Hammerhead. They're in communication. The pressure's in communication, which means there's very good connectivity, which again suggests that there's good news for development planning. You talked about appraisal drilling. You know we're going to be doing some appraisal drilling on Ranger, which we've not quantified yet. That's the large carbonate structure, of course. All of that being said, we just have a tremendous amount of activity going on. I want the organization focused on delivering what we've committed to. And, you know, frankly, the next significant update in terms of outlook for production, I don't think we'll get anything different until an update in March next year.

Yeah, I kind of... Well, I didn't want to be impertinent by saying out of date, so let me just clarify what I meant. When you first gave the 2025 target, the guidance was 500,000 barrels a day. It's now more than 750, and you still haven't changed the 2020. I know it's a long way away, but that was my point. My follow-up, Neil, is probably a little bit of an off-the-ball question, kind of related to the disposal pace and the use of proceeds. My understanding is that you recently conducted a study with a buy side on opinions on share buybacks, return of cash to shareholders, and how you might consider that in the future, perhaps even with a potential to lean on the balance sheet. I'm just wondering if you could share your thoughts as to what was behind the reason for that survey and whether you're still comfortable with the pace of the disposal program you laid out at the analyst day. I'll leave it there. Thanks.

Yeah, again, Neil can maybe make a comment in a second on the specifics of the survey. Let me just make some comments on the disposal program. We highlighted $15 billion. I told the investment community that was a risk number. In other words, I anticipate we'll have to put more in the market to achieve that number. We're on track with that. I would tell you we communicated that in March. We're just four months into a three-month program. It's a three-year program, rather, and we're on track with the marketing. What we said at that time was, in terms of our capital allocation, that there's no change and the priority continues. Our use of cash, use of capital starts with investing in value-accretive projects. Secondly, we're going to maintain our growing dividend. We want to maintain our financial flexibility, and then we'll look at what else we do with the cash in terms of buybacks. And that's the way I think we have discussed it for many years, and we reinforced that in March. Of course, we indicated then that with the $15 billion on the planning basis, that could result in returning some cash to the shareholders. But, you know, we will look at that as that cash comes in, and we'll assess that based on the market conditions at the time. Neil, do you want to talk about this survey?

Yeah, no, again, just as Neil mentioned, the discussions we've had with a few buy-side firms, I wouldn't classify it as a survey. We certainly reached out to them to talk about how you might execute a buy-back program. It wasn't intended to... get a different perspective on our capital allocation priorities, which, as Neil mentioned, remain the same. It was more to gain a perspective from a few buy-side firms on if you execute buybacks, what's the best approach to do that? What's the philosophy you should take? But again, Doug, I wouldn't classify this as a survey. It was a discussion with a handful of the buy-side firms, some of our larger shareholders.

Understood. Appreciate the answers, guys, and thanks again for getting on, Neil.

Yeah, thanks, Doug.

Next, we'll go to Doug Tarrison with Evercore ISI.

Everybody. Neil, financial results in the first half of 2019 seem to be tracking below the plan highlighted at Analyst Day for 2020, although the company made clear at the time that those projections were predicated upon flat Brent rail and flat downstream and chemical margins, too. So my question is, when adjusting for market factors and whatever else you may deem appropriate, are you still comfortable with the 11% return on capital employed and $25 billion annual earnings figures for 2020? And if so, what factors will help bridge the gap from the first half, 19 hectares to the full year 2020 projections? Or do you think we'll get there solely from normalization of the market factors that Neil mentioned on page 9 in his opening comments?

Yeah, Neil, I'll say. Again, we've got Neil squared here, of course. But if in doubt, this is Neil Chapman. I'm going to answer the question. Doug, I would say, remember, when we laid out this plan in March 2018, what we were trying to indicate is the earnings power, the cash flow power that we're bringing into the business at constant prices and at flat margins. And at that time, we said we'd do it at a flat $60 a barrel average. and we do it for chemicals and downstream at 2017 actual margins. And that was our intention. And, of course, we go back and steward our performance. And I think that's what you're asking is how are we doing if you take away the price and margin impacts of the current earnings. I would say we're pretty much matching plan. The significant – the concern we've had, of course, has been these – reliability events particularly the ones that we have had in the downstream outside of the ones that were reported in the first and second quarter there's nothing material that's changed from our plan that we laid out last year it doesn't mean to say there aren't pluses and minuses it doesn't mean to say we have some positive surprises and some negative surprises I think that would be naive to say everything is absolutely perfect but on average I would suggest that we're pretty much tracking the plan, and there's no reason at this stage for us to adjust those outlooks that we laid out 18 months or so ago.

Okay. Now, I realize it's imperfect. We just wanted to try to get a gauge on it. So thanks a lot. Sure.

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

Good morning. Good morning. My first question is about the Permian. The industry, for a while now, but maybe coming to a head here, seems to be having some issues with spacing and its impact on productivity. We don't have a lot of precise numbers about your spacing, but we do know that your development plan sort of calls for, call it a high concentration of lateral feet per square mile. You have a lot of wells that are stacking up in your in your section so can you talk about just broadly this might be too complex a question i don't want to get too esoteric but just broadly how you're managing some of these issues we're seeing in the industry given uh the nature of your development plan in the permian yeah sam it's um you know of course i i like you i you know i read of many of the different um

results in the industry, I would tell you that in terms of our planning basis, again, it's unchanged from the detailed plan that I laid out in March. And what I said at that time, that we are driving a different approach than the industry with these really leveraging a combination of this large contiguous acreage that we've had and leveraging the scale of ExxonMobil. And, of course, you will recall that I went through all of that. I also discussed at that time that we are working on plans that will develop and drill multiple horizontal benches at one time. Our feeling is that there is communication between these horizontal benches, and if you go in and drill one bench now and expect to come back years later and drill the other benches, We do see and we do believe there's communication between the benches, energy dissipates, and our belief is that drilling up multiple benches simultaneously in the approach that I laid out appears to be the right way to go. We're at the very early stages of that. Frankly, it's too early to highlight anything new from what I said back in March of last year. I am aware that there are competitors out there who've looked at spacing and have moved along a line of having closer spacing than we have in our plans. I have heard that. I think everybody in the industry has read about that. My understanding is the company involved in that has pulled back from it. It hasn't been successful. We have not taken that approach. Our spacing is not as tight as that. So it's early days. We have... Nothing new to report versus what we said last time. As I said, we are on plan and nothing different.

Okay. Thank you. That's helpful. We'll go back to the March materials. My follow-up is on chemicals, and it's sort of a macro question. You've highlighted that there's some margin headwinds in the industry right now due to capacity, but capacity continues to get sanctioned globally. There's FIDs sort of in the face of this margin pressure. And so I was wondering, from your perspective on the demand side, are you seeing a big pull for new supply in the pet chem chain, even with some capacity-related margin headwinds now? And does that say anything about the longer-term cycle and what you're high-level views on the chem side are?

Yeah, Sam, I would tell you that, and again, in chemicals, you have to break it down to the individual products, and of course, we're heavily focused on ethylene and polyethylene, and those are the margins that we typically talk about, and Neil highlighted the paraxylene business, but let me talk about ethylene and polyethylene, because that's the major driver of our chemical business. Polyethylene demand grows at about one and a half times GDP, and as I recall, The ethylene market is about 150 million tons globally. And so what that means is you need three to four new crackers per year just to meet demand, three to four world-scale crackers per year. Actually, what we see right now is the demand remains very robust around the world. It's all driven by the growing metal class around the world. That's the driver for plastics. That's the driver for polyethylene. That middle class having a higher standard of living and that drives the consumption of polyethylene. So actually globally we see the demand remaining very robust. There's no changes at all. What's happened is there's been a glut of capacity. And so capacity is higher than demand. In the polyethylene business, unlike some of the other commodity businesses we're in, the demand sucks it up relatively quickly. Now I will tell you that there are some further increments of capacity in ethylene and polyethylene to come online in the next year or so. So we don't see any change in the fundamentals at all. The glut in supply today is all because of these new capacity increments, most of which are on the Gulf Coast. So I think the short-term margins, and if I was to try and predict short-term margins, inevitably I would get it wrong. We do. But because of this extra increments of capacity that are coming on in the next 12 months, I would anticipate it to be pretty soft during that period. Now, I've been in the chemical business for most of my career. I think most of you know. And the chemical business is notorious for coming back faster than anybody anticipates. But on a planning basis, I would expect it to remain soft at least for the coming six months.

Thank you so much. Next, we'll go to Neil Mehta with Goldman Sachs.

Hey, good morning. Good to talk to you, Neil and Neil. So the first question I had was just around European gas. Obviously, we've seen softness in global gas prices. Groningen is a smaller part of the business mix than it was a couple of years ago. But can you just frame out how big that European gas is as a part of the business on a go-forward basis? And is that a risk to profitability of the upstream group?

Yeah, I mean, I'll give you some approximate numbers here, Neil. I think, you know, in terms of volumes of gas in our portfolio, about 75% of our volumes from gas is what we call flowing gas. 25% is liquefied natural gas. And of that 75% flowing gas, about half is in the US and half is in the European markets. I'm just going to break it down for you. Of that European, about half is Groningen and half is a combination of, as I remember, roughly Germany, UK, and Norway. So it's a relatively large part in terms of volume. It's not a relatively large part in terms of the earnings of our business. What I would tell you is, The spot price, as you've seen in LNG, has dropped significantly, of course, over the last six months. Japanese JKM market price plus the NBP price in Europe. And that's what's impacting the flowing gas prices. And what we have seen is we've seen continued growth in demand for liquefied natural gas in Asia. That's been the big growth driver over many years. It's just a little – it's not as high for six months as this year as it has been in the previous two years. I mean, as I remember – don't quote me. These are approximate numbers. I believe year-to-date Asia LNG demand is up about 3%, which is lower than it has been. And the global demand or global supply of LNG is up north of 10%. So what happens there, those cargos look for a home and they – They can't find the home in Asia. They'll get directed towards Europe. That puts pressure on the European price. And if you look at the European gas business, the inventory level is quite high in Europe as well right now. That's what's putting the pressure on the spot LNG price, and that's what's putting pressure on the flowing gas price.

That's helpful, Neil. I guess the follow-up is relative to even at the analyst's day, Exxon shares have outperformed your smaller independent competitors in places like the Permian. How do you think about the environment for M&A and Exxon's role in consolidation in the lower 48?

Well, first of all, I would tell you that we're eyes wide open. We're always looking for opportunities. And I think one of the reasons you maintain a strong balance sheet, it gives you that flexibility to act if you see something of value. I always start in the upstream with this. We have the strongest portfolio of opportunities in the upstream this corporation has had since the merger of Exxon and Mobil. In other words, we don't need to do anything. I feel very, very comfortable with the growth plans that we've laid out to you and we see and we can execute through 2025 and beyond. So we have the capacity to do something. We don't need to do anything from a business. What we need to do is execute our current set of opportunities. So that's a great position to be in. But we look all the time for value-added opportunities. I think that's the great part about looking at the portfolio. It's all a question of if something is out there which is competitive in our portfolio, in other words, upgrades the portfolio, and we can bring a competitive advantage versus industry. I mean, that's the way we look at it. In the lower 48, in the Permian specifically, I hear, like you all hear, a lot of chatter about potential consolidation down the road. But the market, that will play out in the market. For us, You know, what I like to say to our organization, eyes wide open. If there's an opportunity out there, bring it forward. But I really want to make the point that we don't need to act. We don't believe we need to act right now. We have a great opportunity set as it is. Anything to add to that, Neil?

No, I guess that's absolutely right, Neil. And given the portfolio that we have, we can be patient. We can be opportunistic. And, you know, if we do see an opportunity to bring unique value with our competitive advantages, and we can bring in something that's accretive to the value of our overall portfolio, then obviously we'd be very interested in that type of an opportunity.

Yeah, I do. Just to go back to the Permian again and reinforce a point I've made many times, we are taking a different approach to the Permian. I mean, we are taking a approach which is leveraging the scale of this corporation. It's a manufacturing approach. We're doing it at scale, which obviously a lot of the small players would not have the capacity to do that, and we're going to do it through the cycles. You know, we have the capacity to do that. We believe we have a significant capital advantage by doing it that way. And, you know, as a result of that, I think if we can demonstrate, and we will, and we are demonstrating that, we can demonstrate it, it puts us in a position where we have an advantage development plan so we could apply that to other resources in the basin should we see fit to do so.

Thanks, Keith.

Sure.

Next question comes from the line of Phil Gresh with JP Morgan.

Yes. Uh, hi, good morning. Um, I guess my question, my first question it, uh, good morning. Yeah. So it's a bit of a followup, um, to a couple of the questions that have been asked, maybe slightly differently. If you look at the quarter, there was a fair amount of debt, uh, added this quarter. And you talked about, you know, kind of just investing through the cycle. Um, you have the $15 billion of asset sales that you're targeting. over the next three years and you want to keep the balance sheet ready if an M&A opportunity comes along. But if we look at it that way and think about the way the strip looks right now, does it make more sense to not think about share buybacks, to just keep the balance sheet in the best shape you can with asset sale proceeds as you invest through the cycle? Just want to kind of tie that all together. Thanks.

Well, yeah, I started that, Neil, and maybe you can add anything you want to add. But I think the strength of this balance sheet is really important, of course, but it's being demonstrated by the current market conditions because, as I said in my earlier comments, you know, we feel very strongly we have the capacity to maintain our investment plans through these low points in the commodity cycle. Actually, at the current conditions, If they were maintained, and we see these as very low as you have seen, and Neil pointed out from his chart, if they were to maintain those conditions, we still believe we have the capacity to execute our plans if these conditions were to remain through 2025 and still have some, you know, power to execute an acquisition should we want to do so. But, of course, it's something you watch closely. You know, you're constantly looking at all of the time. But today, and on a planning basis, We feel like we have the capacity to make no change at all to our plans. And even if these low margins continued, we can continue with our plans. I don't know, Neil, are you going to add to that?

Yeah, just, you know, thinking back to the investor day, Phil, and when we talked about this, you know, we conveyed that we felt very comfortable with the investment program that we have available to us. You know, we talked about the – the priority of doing a reliable growing dividend and that we felt comfortable with the balance sheet and that we didn't feel at that time that we needed to do any additional maintenance on the balance sheet. So to the extent we had proceeds come in from asset sales or additional cash come in from higher prices and margins, given where we were in those priorities, likely the cash would then come back through buybacks. But that was obviously given a current or an assumed price and margin environment. and we're in a different environment today, but when these proceeds come in from these asset sales, which is a target out to 2021, again, we don't know what environment we'll be in at that time. So it's difficult to predict exactly where that cash would go, but we can reaffirm what the priorities are. We're going to continue to invest in accretive projects, pay a reliable growing dividend, and ensure that we have the capacity and the financial strength to take advantage of opportunities that come available to us including when we have a downturn in margins of prices, which is, as we've said, a very attractive time to operate and invest when costs are lower and when others are pulling back. So there's no change to the priorities. What happens when that additional cash comes in from those proceeds? Again, it could occur over the next two or three years. It'll be dependent, I think, on the price and margin environment at that time. and what opportunities we see available to us.

Yeah, and Phil, I tell you, this is not something new for us. I mean, if you go back to the low crude oil prices in 15-16, that's when we lent into the business and made the acquisitions in the Permian, in Mozambique, in Papua New Guinea, and in Brazil. And again, I go back to the strength of opportunities that we have right now is because at that low point in the cycle, we have the capacity to move and pick up some very attractive resources at very competitive prices.

I appreciate that, and obviously can't time the asset sales quarter to quarter, so certainly can appreciate that. On the chemical side, I guess my follow-up to some of the questions that have been asked is that if I look at the performance of ExxonMobil specifically, Over the past five quarters, your earnings have gone down every quarter. And I know this quarter you had some maintenance, so some of that will come back here. But if I look relative to some of your other peers where you have traditionally kind of tracked their performance, I think they've seen a bit better performance recently, and yours has continued to degrade. And so just kind of sifting through the slides, I know you called out paraxylene as one factor. If you were to kind of disaggregate the performance, would you say that that is the primary factor that you think is differentiating your software performance recently, or are there other things we should be thinking about? Thanks.

Well, I think there are other things. I think what you have to start with in the chemical business is looking at the configuration of the assets that each chemical company has. Our business is heavily weighted towards steam cracking and polyethylene, order of magnitude and It's sort of 65% of our chemical business. Polyethylene and ethylene margins for us have been very strong for multiple years, and we've benefited from that. And at this stage of the cycle, the ethylene-polyethylene margins, for the reasons that we already discussed, are down. If you have a chemical company that has 25% of its business in ethylene-polyethylene and the rest of the business in other products, you probably wouldn't see that impact of ethylene and polyethylene. It's really driven... by the configuration of assets that you had. If we look across our chemical companies' performance over the last 12 months in terms of operations, in terms of delivering on their higher margin growth, it's been at or above plan. The total impact we have seen is because of industry margins being down due to overcapacity. That has been primarily driven by ethylene and polyethylene, primarily driven by these big increments of capacity coming on the Gulf Coast. Parazylene is similar. Parazylene is also a significant part of our chemical company, nowhere near the size of ethylene and polyethylene. There has been some big capacity increments of parazylene that's come online in China in the recent months, and that's put parazylene margins under pressure. These are cyclical businesses. The performance is no change. The underlying drivers of these businesses are unchanged. The underlying drivers for demand are unchanged. What's really important for us is that we continue to deliver more competitive steam crackers and polyethylene businesses than anybody else. That's why I made the comments when we were talking about the latest investment at Corpus Christi. This is significantly advantaged, we believe, versus any other Gulf Coast investment. It's a significantly lower capital cost. We're leveraging the scale of our upstream organization. We located the plant so close to the point is a cost advantage. And we're producing not commodity polyethylene, but higher value or higher margin polyethylenes. And so we don't see any change to the structure of this business. This is a margin impact driven by short-term excess in supply.

Okay, appreciate the comments.

Sure.

Next question comes from the line of John Rigby with UBS.

Good afternoon. Thanks, all. Good morning. Thanks for taking questions. Two, please. The first is I hear what you say about M&A opportunities and so on in the Permian, and I guess those will come around periodically, and you'll take a look at those when and if they arise. But we've got the surplus transfer rights opportunity coming up in Brazil in November, and you could argue that that is somewhat more singular. So I just wondered whether you could talk a little more about what your attitude is to that. Maybe if I just add my second question straight away. I was just looking at your CapEx profile in the U.S. in the upstream, and I see it bumping up both sequentially and year over year, and I guess that may... in part have something to do with your comments around infrastructure build out. So I just thought maybe it'd be a good opportunity if you could just sort of lay out the activity in a little bit more detail around infrastructure as well as the drilling activity. Thanks.

Yeah, yeah, yeah, yeah, sure. Thanks, John. Let me start with the transfer of rights in Brazil. Buzios, which, of course, is the big reservoir down there, the big resource that's in those transfer of rights, I mean, that's the largest one. There are other ones, of course, but Buzios is by far the largest. Because it's so large, I think everybody in the industry will have a look at that. I'd be very surprised if they didn't. But it is very, very large. It is singular. Those kind of sizes are what I would call discovered resources. It's relatively well delineated. The way I look at it, is we have to bring some advantage to that versus anybody else in the industry. And if I can find a way where we can bring a significant advantage, therefore we can get more value for our shareholders, and we don't just get into a bidding war versus other players, because, I mean, that's not the business. We want to be able to bring an advantage to that resource should we want to participate. We are looking at that resource as I can imagine. I'm very, very confident all the major players are in the world. It doesn't mean to say that we're going to act on it, John, but we're certainly looking at it. It is a large resource, and it will be interesting to see how that plays out. And obviously, I don't think you'd expect me to say much more than that. In terms of CapEx, actually, I'm very... proud of where we are. We're 50% as a corporation of our CapEx plan in the middle of the year. And actually, if you peel the onion back further, we're 50% of our CapEx plan in the upstream, halfway through the year as well. So we're tracking in total on plan. It doesn't mean to say there aren't some puts and takes. I mean, there are. I think in terms of the above-surface build-out, particularly in the Delaware Basin, What I laid out in March is we have to put a lot of upfront money to build out those facilities, both compression and these development corridors and all of the logistics within the basin. That's part of our plan. I would tell you, you know, there are puts and takes and all of that. Overall, we're on plan. It's well documented that... It is taking longer to drill these horizontal laterals in the Delaware right now than it is in the Midland. And you see numbers, you've all seen the numbers that are reported externally. It's key for all the players in the Delaware that we find a way to get those drilling times down closer to what we see in the Midland. We are working that. We're making decent progress. Of course, I want us to go faster, but we're making decent progress. So there's nothing... really to flag outside of what we've already said. It's within the range of what we'd expected. And today, our Permian production, our Permian production is accretive to earnings. We're making money in the Permian right now.

Thank you. Yeah, sure.

Your next question comes to the line at Barrage Borkitalia with RBC.

Hi, thanks for taking my question. Just one other question on pace. I understand the rationale for the pace of development in Guyana. Obviously, you're taking advantage of the services available at very good prices. For the Permian, are you concerned at all at the pace of your development and the impact it could have on the overall oil market? I get not all of the growth is oil, but a substantial amount of that exponential growth chart is oil. And then if you take you guys plus Chevron and a handful of your peers, it looks like the majority of the sector wants to grow volumes faster than the market is growing, which suggests prices maybe are not that positive over the medium term. So I just want to get your thoughts on that and whether you think it's a concern at all. Thanks.

Yeah, thanks, Baraj. I mean, again, I'll make some comments. And Neil, if you have any, feel free to jump in. I mean, I think You know, we laid out that pace and we said we're going to get to a million oil equivalent barrels in the Permian and Bakken by 2024, if I remember correctly. That's not driven by anything more than we see these as extremely competitive. We see them as left-hand side of the supply curve and we see them as high returns and within our capacity to execute them to the standards that we expect to execute them. That's the way we look at it. What really is important is in the commodity side and the commodity businesses is to make sure that we have a competitive advantage versus anyone else in terms of cost of supply. And it's really driven by cost of supply. That's why I am so keen that we maintain our capital discipline in the Permian. We must continue to work the capital cost down and to deliver on what we have laid out in our plans. Remember, this is a declined business. you have to keep replacing your capacity. And what's key for us and key to win in this business is to make sure that our portfolio is the most competitive in the industry. And that's the basis of these plans, and the Permian is a big part of that. Do you have anything to add on that?

No, I guess, you know, the only thing I'd add, globally the market, again, remains balanced. Demand growth continues to be strong. Obviously, you know, OPEC has remained committed to their cuts. You have, you know, oil that's offline in Venezuela and Iran and other locations. So you are seeing growth in the Permian, but I think overall we're still seeing a relatively balanced market.

All right.

Your next question goes to Roger Reed with Wells Fargo.

Yeah, thanks. Good morning.

Good morning, Roger. Good morning, Roger.

If we could come back to, I think it was slide nine, the one showing the margins and kind of where you are relative to the tenure. I was just curious, though, as we look particularly at the downstream and the chemicals, if you think about those margin performances, call it a lost opportunity or adjusted for your downtime, you know, kind of how much was truly margin loss versus had you run at a normal level of activity where you think those margins might have been? You know, can I help us think about maybe where cash flows should be back after this year, given maybe more normalized levels of downtime?

Yeah, well, make sure I understand the question, Roger. What would be the impact if we didn't have the reliability incidents? Is that your question?

Yeah, what if we were to isolate only the margin aspect in terms of price or, you know, let's just say net margin the industry offered versus net margin you captured?

Yeah, I think two things to bear in mind. I think in terms of our performance in the first half of the year and the second quarter in refining, You know, I highlighted in my comments that there was $150 million earnings impact from those three significant reliability events. Isolate those, and that gives you a number. There is a much larger impact from the heavier turnarounds, scheduled maintenance that we have, and Neil gave some numbers in terms of how that would manifest and how that will change in the third and fourth quarter. I don't know, Neil, have you got anything else to add?

Yeah, and Roger, again, just so I understand what you're asking, the charts on slide nine, those are industry margins. So those are not the realizations that we captured. Those are, again, somewhat reflective, obviously, of our footprint, but they are industry margins.

I think the other thing really, really important here is the industry margins manifest themselves differently in each of the refinery players. It depends on your configurations. Just to give an example, if you have no refining assets in Europe and the European margins are low, of course that will hit the European players and not hit the players who don't have that footprint in Europe. And even if you just go into one region like the United States, refineries are different. Some are high conversion refineries, some are low conversion refineries. There are different margins for high and low margin. In the U.S., there are different margins on the Gulf Coast versus the Midwest. And so when you look at these margins, you have to peel back the onion further and apply the specific margins to the individual configuration, both geographic and technical configurations of your refining assets. That differs from company to company. What has been shown on the chart that Neil showed, I think it was an average of industry or an industry market price, wasn't it?

Yeah, that's right. And, Roger, maybe just from a downtime maintenance earnings impact in the first half of the year, I think for the downstream in the second quarter, we showed on chart 11, it's roughly $500 million, $600 million. I think the first quarter was a little bit lower than that. And then for chemicals, it was a little bit below $200 million. And then we tried to show on slide 11 what that looks like in the third and fourth quarter. So again, down significantly from what we've seen in the second quarter. Hopefully that gives you some indication where we'll be in the second half of the year.

Yeah. No, that's...

That reflects an equal weighting, a third, a third, a third of markers in the U.S., Europe, and Asia. And so, you know, it's an average. It's an illustrative. But if you don't have a third, a third, a third in those three regions, then your margins could be different to that.

Yeah, for sure. No, and I appreciate the clarification because my original interpretation was that was your margins, not just industry margins. Sure. Okay. Thank you. And then just as a follow-up question on the Permian, I mean, I know we have the chart that shows the pace there, but phenomenal performance in Q2. I think we're familiar with timing of well completions and things like that. As you think about Permian growth at this particular juncture, I Is what we saw in Q2 what you believe becomes more representative, or Q2 is just kind of one of those quarters where you're zigging and zagging a little bit. This zigs above the line, and maybe over the next couple quarters we zag back towards the line. As Sam mentioned, we don't have a lot of clarity on a lot of what you're you're doing out there, or at least not contemporaneously. So I was just curious how you think about the performance in the Permian and maybe where that shakes out.

Well, you know, your vocabulary on zigging and zagging, you know, I describe it as a lumpy. And the reason I say it's lumpy is because the way we are developing the Permian is, you know, we're going to drill a lot of ducts, then we're going to frack a lot at different times. So, you know, I don't anticipate, and if you go back to the chart when you see our red actual performance, Yeah, that's kind of what you're going to see. You're not going to see the same growth every single quarter, but we're very confident that we can meet that, what's a green, famously called the green blob, but the green growth profile, Roger, I'd say that's what we're going to, you know, we will meet. You're absolutely right. It will be a zigging and zagging, but it's not necessarily the way everyone would develop. It reflects our development plan. that we're going to have, particularly in the Delaware, these long corridors of well pads. And we're going to drill up multiple benches at one time. And if you think about it, move those drilling rigs down the corridor, bring in those frack crews, frack them, and then you'll see a boost in production. So I don't think it would be the right thing to do to look at every single quarter and say that we'll repeat that growth rate every single quarter. But I'm very confident that we're going to meet the overall growth rate that we represented in that famous green production profile.

Great. Thank you. Sure.

Next we'll go to Paul Cheng with Scotia Howard Weil.

Hey, guys. Good morning.

Paul, ring.

I have one downstream, one upstream. Okay. Neil, for Permian, I think in March, you were mentioning that the rig count probably go to about 55 exit rate this year, and then next year may go to 60, 65, depends on the activity level. Is that still sort of the game plan at this point, or that has been changed based on the additional information you have seen over the last several months?

Yeah, I would say... You know, the 55 number is a number that I would still think we will be at at the year end, and we haven't got a change in plan on that. You know, I really don't get fixated on the number of rigs, quite frankly. I mean, that was sort of what we estimate we will have. If the productivity of these wells is better, you know, we could reduce. I mean, that's all about this capital efficiency that I keep coming back to. So, you know, as a planning basis, I mean, today we're at, what did I say, 51, I think, across both basins right now. That's in line with getting to sort of that 55 number, Paul, at the year end. But, you know, it could be 53, it could be 56. 55 is the best planning basis I can give you.

Right. I guess my question is that, I mean, based on what you see over the last several months in the productivity and everything, or fill in that is basically that is still the same plan that you haven't really changed. There's no material information that you have seen either improvement or deterioration compared to your current plan.

Yeah, I mean, there's nothing to flag because it's within the range of our planning basis. You know, I mentioned a few minutes ago, what's really important is to increase or improve the drilling time in the Delaware. You know, I read about numbers, and people are saying in the industry that it's taking 30% longer to drill the same length well, same length lateral in the Delaware as it is in the Midland. Actually, I think it's a little bit different than that. You know, there are some parts where that's too high, and depending on the length of the lateral, it's a change. But it is indicative that it is taking longer, and that is a key activity for us. to get that drilling time down because, you know, as is obvious, if you can't get that drilling time down to the level that you expect to in your planning basis, you know, you can do one of two things. You can cut back your volumes or you can add more rigs. We still believe in our planning basis we will get the productivity that we have and that reflects the number of rigs, the capital outlay, and the volumes that we're predicting. But it is the most important thing, Paul, I would tell you. And the way we're going about it is, We have moved the total ExxonMobil capability into this basin. We're applying all of our drilling capabilities from all around the world to this very, very important area. I feel very, very confident in our plans. I feel very comfortable with where we're heading. I wish we could close that gap faster.

And I think from a rig count standpoint, you're about 50-50 between Midland and Delaware. Should we assume that will remain to be the case for the next one or two years?

Yeah. Actually, I'm not sure we're 50-50 right now. We're still – we have more rigs in the Delaware today than we do in the Midland, but that's part of our development plans. In order of magnitude, if I remember, I think we have – Maybe, I think it's 29 in the Delaware and 22 in the Midland right now, just for the numbers. But, you know, our resource, our well inventory in the Delaware is much, much higher than it is in the Midland. I think we've been quite clear. And, again, I come back to this is such an early stage to jump to conclusions. And just to give you an indication, you know, we estimate we have a well inventory in the Delaware. something around 6,500. So 6,500 well inventory, we've drilled 100. We've drilled 100. So it's very tough to extrapolate from 100 wells where you're going to be with 6,500. And that's why I think it's so, so important that we stick to our long-term planning basis. We know what we've got to do. But to try and extrapolate and draw too many conclusions from that number of wells, I think... Yeah, I think we need to be careful about doing that.

A final question for me. Under the IMO 2020 world, what's your ability in your refinery to take the high sulfur receipt as a feed directly to the cooker within your system?

Yeah, I think, you know, as you know, if you sort of peel back the onion on IMO, With these new regulations, the ship owners have this multiple option. They can buy low-sulfur fuel oil, they can install scrubbers, or they can switch to some other feedstock like liquefied natural gas. The way that plays out is the demand for high-sulfur we would anticipate will decline and the demand for low-sulfur will increase. You would anticipate that that could lead to changing spreads, of course. I think if you have low-conversion refineries, you'll be incented to reduce sulfur by running sweet crudes. Our refineries, particularly on the Gulf Coast, are high-conversion refineries with low fuel oil production. And so we would say that we feel very well positioned in the U.S. We have high-conversion refineries. We added this big new coca in Antwerp. and we're investing in projects that reduce high-sulfur fuel oil production in Singapore. So we've been planning this for this for a long, long time. The market will do what the market will do, but directionally, we feel like we sit in a very strong and advantaged position.

Sure, and I guess my question is that, I mean, can you take the high-sulfur fuel oil and directly feed it into your cooker as a feedstock? instead of buying heavy oil. So we pace the heavy oil run in your refinery by using the high sulfur fuel oil. I guess that's my question.

I think the answer to that is yes, if we have spare capacity. I mean, I think that's the bottom line on that. That's what they're there for. You can do that. But of course, we are... you know, we're balanced across. That's why we invested in the COCA for, sized it for our facilities across Europe. So, but the answer is fundamental. Yes, you could do that if you have capacity.

Okay, Dan.

Thanks. Thank you, Paul. I think we have time for one more question.

Certainly, sir. We'll take that last question from the line of Jason Gableman with Cowan.

Yeah, hey, thanks for taking my question at the end of the call. Firstly, we didn't touch on a couple of projects, the Mozambique LNG development and what's going on in Papua New Guinea. You did put in your press release that you still expect to sanction Mozambique at the end of this year, but there's been some reporting that you're looking at maybe changing who's doing the EPC on that project, and I'm wondering if that could delay when you would sanction it, and then just any updates on what's going on at Papua New Guinea with negotiations with the government would be helpful. Thanks.

Yeah, sure, Jason. I think in Mozambique, you know, we're still proceeding on the planning basis that we had for Area 4 and the two lines that we're going to put in Ravuma. You know, there is likely to be, at least we read there will be a change in ownership on Area 1. Of course, everyone reads that. And Patrick made some comments, and I think earlier on this week publicly, that we have had some very, very preliminary discussions with Total to say, is there something more we can do between Area 1 and Area 4 to get the capital costs down? That's a very, very early stage because, of course, that – that ownership has not changed yet. But I think, as Patrick said, if there's something there, it's in the interest of both companies. So for sure, we will look at that to improve the capital efficiency. But no change right now in our current planning basis. I think Patrick's comments were more talking about if something comes down the road that is advantageous to both companies or both consortiums more, Area 1 and Area 4, then obviously we would look at it. But our planning basis is to go ahead with what we've already communicated. In terms of Papua New Guinea and the Papua LNG. You know, change of government there, President Merapi is in power and I met with him about a month ago and as he's publicly said and as Petroleum Minister has said, they want to look at the legal aspects of Papua. Our understanding is they've had that review and they're discussing the outcome of that review now. As far as we're concerned, we have an agreement with the government. Prime Minister Merapi understands that. And I don't see any change, but we'll have to wait and see what comes out of the government discussions. I have to say, Total is the operator on this block, so you really have to talk more details with them. As far as we're concerned, we have a contract. We honor our contracts, and we anticipate no change. in that agreement.

Thanks. If I could just ask a question, another one, about chems. I know it's been covered pretty in-depth today, but a peer had mentioned that they're seeing destocking in the China chemical landscape in terms of inventory, and there's been discussions kind of about an emerging NAPSA oversupply. And I'm just wondering if you're seeing, one, China kind of tapering back its feedstock cost purchases, and if that is reverberating through the supply chain, particularly for NAPTA. Thanks.

Just to make sure I understand, Jason, you're talking about destocking of polyethylene?

No, so kind of... not buying as much feedstock cost for their NAPSA crackers and using the inventory on hand.

Yeah, I mean, I think, you know, it's pretty typical in a commodity business. People raise their inventory levels and reduce their inventory levels. Sometimes people speculate in terms of where they think prices are going and margins are going. That's typically why people do that. I don't know if... if in China there's a destocking and folks believe that there is going to be some change in naphtha price. You know, naphtha is driven by, of course, fundamentally by your expectation on crude oil price, but also the differential between naphtha and crude is driven by the supply demand of naphtha. So I really, I'd hate to speculate on why they're destocking. I think what you have seen in the markets over the last 12 months is is relatively low naphtha prices versus crude oil. And I think that's primarily driven by there's more light crudes on the market, which leads more condensate, which leads more naphtha. And so you're seeing a trend in that over recent months. But I think it would be to speculate on short-term destocking in China. I don't think I can add anything to that.

But thanks, Jason.

Thanks.

Great. Thank you. We appreciate you allowing us the opportunity today to highlight the second quarter. That included, again, excellent progress in the Permian and the achievement of a number of key milestones across our portfolio. We appreciate your continued interest and hope you enjoy the rest of your day. Thank you.

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