Exxon Mobil Corp (XOM) — Q1 2018 Earnings Call Transcript

Thank you. Ladies and gentlemen, good morning, and welcome to Exxon Mobil's first quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. Consistent with our recent Analyst Meeting, you'll note additional detail in our press release and this morning's prepared comments. Our objective is to provide clarity on key business drivers in the quarter and describe progress being made to deliver on value growth potential outlined in the Analyst Meeting. In the interest of time, I’ll move through the prepared material efficiently to ensure there is sufficient time for your questions. While we go further, I’d like to draw your attention to our cautionary statement shown on Slide 2. Please also see the supplemental information included in today's presentation. Turning now to Slide 3, let me begin by summarizing the key headlines of our first quarter performance. Exxon Mobil earned $4.7 billion in the quarter. Cash flow from operations and asset sales was $10 billion, the highest since 2014. Importantly, cash flow exceeded net investments in the business, distributions, and other financing activities by almost $3 billion. In the United States, we achieved positive Upstream earnings of about $430 million. In Papua New Guinea, facility shut-in resulting from the earthquake reduced this quarter's earnings by about $80 million and volumes by 25,000 oil current barrels per day. We've since resumed production and expect to reach full capacity in early May. As I’ll discuss shortly, we made good progress during the quarter in a number of areas that will support our value growth potential. Moving to Slide 4, we provide an overview of financial results. As indicated, Exxon Mobil's first quarter earnings were $4.7 billion or $1.09 per share, up 16% from the prior year quarter. Cash flow from operations and asset sales was $10 billion, including $1.4 billion in proceeds from asset sales that I'll discuss shortly. In the quarter, the Corporation distributed $3.3 billion in dividends to our shareholders. Our CapEx was $4.9 billion, up 17% from the prior year quarter, resulting in increased activity in the Permian consistent with our growth plans. Debt was down to $40.6 billion at the end of the quarter, and cash increased to $4.1 billion. The next slide provides a high-level look at the key drivers for these business results. Upstream, we benefited from higher realizations for both liquids and natural gas. However, our liquid realizations rose less than benchmark prices due to the widening of the Canadian heavy oil discount. These higher prices resulted in lower volume entitlements. Production was also reduced by downtime in the quarter and divestment of assets. We’re continuing to progress growth initiatives as outlined in our Analyst Meeting, including increased drilling in the Permian, advancing attractive new projects, and completing maintenance activities to enhance performance over existing assets. Finally, we're actively strengthening our portfolio through the acquisition of new assets, such as exploration acreage offshore Brazil. We also captured incremental value through divestments of assets. Refining margins remain strong in the Downstream, especially in North America. However, joint product demand was seasonally lower. U.S. manufacturing reliability recovered from the fourth quarter and notably, Joliet returned to full capacity in March. We also continue to make progress in growing our chemical business. The integration of the Jurong Aromatics plant into our existing Singapore business is progressing as planned. In North America, sales are increasing with the ramp-up of the new polyethylene lines at Mont Belvieu, supplying the growing demand for petroleum products. Within our base business, we successfully completed turnarounds in the Middle East and the U.S. Gulf Coast. The next slide provides additional detail on sources of cash. Earnings adjusted for depreciation expense, changes in working capital, and other items, and our ongoing asset management program yielded $10 billion in cash flow from operations and asset sales. A positive adjustment for working capital mainly reflects favorable seasonal changes in payables, which were partly offset by an inventory build in the Downstream business, mostly due to maintenance. A negative adjustment for other balance sheet items reflects the timing of equity company distributions. Asset sales included Upstream properties, notably the Scarborough gas field, and Downstream distribution and retail assets. Note that cash flow was higher than the prior quarter largely due to the higher earnings. Moving to Slide 7, I’ll describe the uses of cash. Over the quarter, our cash balance increased from $3.2 billion to $4.1 billion. From a cash flow perspective, we made shareholder distributions of $3.3 billion and confirmed our commitment to reliably grow the dividend. Earlier this week, the Board of Directors declared a second quarter cash dividend of $0.82 per share, representing a 6.5% increase from last quarter and marking our 36th consecutive year of per share dividend growth. Net investments in the business were $3.3 billion, lower than the prior quarter due to the absence of acquisition payments. Debt and other financing items decreased cash by about $2.5 billion. This included $1.9 billion in debt repayment and $425 million used to purchase 5 million shares to offset dilution related to benefit plans and programs. In the second quarter of 2018, Exxon Mobil will limit share purchases to amounts needed to offset dilution related to our benefit plans and programs. Moving to Slide 8 for a review of our segmented results. Exxon Mobil's first quarter earnings of $4.7 billion increased $918 million from the previous quarter, excluding the fourth-quarter impacts of U.S. tax reform and impairments. Upstream earnings increased about $980 million, primarily due to higher prices. Downstream earnings decreased $12 million, driven by weaker refining margins. Chemical business increased earnings by $76 million, primarily due to lower operating expenses. These were all partly offset by higher expenses in the corporate and financing segment due to the lower U.S. corporate tax rate and higher pension expenses. Our total corporate and financing charges for the quarter were about $800 million. After further evaluation of the full impact of the U.S. tax reform, we expect these expenses to range between $700 million and $900 million per quarter for the remainder of 2018. Our effective tax rate for the quarter was 40%, reflecting a higher proportion of non-U.S. Upstream earnings. Looking at the remainder of the year, we expect the effective tax rate to range between 30% and 40% at current commodity prices and the current portfolio mix. The increase in guidance is driven by Upstream's higher proportion of earnings. Moving to Slide 9 for a comparison to the prior year quarter. Exxon Mobil's first quarter earnings increased $640 million from the year-ago quarter, driven by higher upstream realizations. This is partly offset by lower downstream earnings resulting from lower asset management gains and lower volumes due to higher maintenance in the U.S. Chemical earnings decreased due to lower margins, and corporate and financing charges reduced earnings by another $270 million, again due to the lower U.S. corporate tax rate and higher expenses. Moving to Slide 10, we’ll highlight some of the progress we've made over the first quarter that supports our growth plan shared at the Analyst Meeting. We made our 7th discovery on the Stabroek block, enabled by our proprietary subsurface imaging technology. The oil well encountered 65 feet of high-quality oil-bearing sandstone. Oil will be developed in conjunction with the giant Payara field along with other development phases. This will help bring Guyana's total production potential to more than 500,000 barrels per day. Common activities are on Liza Phase 1 and are progressing well. The Stena Carron is currently drilling the Liza 5 appraisal well, which will help to delineate the greater Liza resource. A well test is planned at Liza 5 and will begin shortly. After the completion of the test, the rig will return to the Turbot area to drill a delineation well named Longtail. Previously indicated, we mobilized the second rig to the basin, which drove the exploration well Suburban, in advance of the start of development drilling for Liza Phase I. The Suburban well reached total depth this week but failed to encounter commercial quantities of hydrocarbons. We have additional exploration drilling planned later this year as we continue to explore the full potential of the Stabroek block. In Papua New Guinea, resource assessment certified an 84% increase in the size of the P'nyang field, more than 4 trillion cubic feet of natural gas. These resources support our discussions with joint-venture partners regarding a three-train expansion concept for the PNG LNG facility. One train will be dedicated to gas from P'nyang and two trains will be dedicated to gas associated with the Papua LNG project. This development concept would add approximately 8 million tons per annum, doubling capacity over the existing plant. As planned, we continue to increase our U.S. tight oil activity. We currently have 27 operated horizontal rigs in the Permian and four operated rigs in the Bakken. We remain focused on maximizing capital efficiency, drilling wells that are consistently longer than the industry average. Total unconventional production in the Permian and Bakken has increased by 18% versus the first quarter of 2017, with strong well performance supported by optimized completions. With respect to our portfolio, we added 8 new blocks offshore Brazil, which I will talk about shortly, and signed agreements for deepwater blocks offshore Ghana and Namibia. As indicated, we continue to monetize assets, including a 50% interest in the Stabroek gas field. We also closed several downstream divestments, including distribution and marketing assets in South America and retail sites in Europe. Further portfolio high-grading remains a priority. In the chemical segment, we continue to be focused on increasing capacity to meet growing demand for higher-value chemical products. We began commissioning our ethylene cracker in Baytown, Texas, with startup planned midyear. This will enhance integration to lower feedstock costs for the associated polyethylene lines that started up in the fourth quarter of 2017. Turning now to the Upstream financial and operating results starting on Slide 11. First quarter Upstream earnings were $3.5 billion, an increase of about $980 million from the last quarter, excluding the fourth-quarter 2017 impacts of U.S. tax reform and impairments. Realizations increased earnings by $640 million; crude prices rose just over $3 per barrel versus last quarter but less than benchmark prices due to the widening of the Canadian heavy oil discount. Gas realizations increased $0.80 per thousand cubic feet. Volume mix effects decreased earnings by $130 million; primary drivers for this included two fewer days in the quarter, higher downtime, and lower entitlements, partly offset by project growth and seasonal gas demand. All other items increased earnings by $470 million, largely due to lower operating expenses and positive net asset sales. Upstream unit profitability for the quarter was $10.30 per barrel, excluding the impact of non-controlling interest volumes. Moving to Slide 12, oil equivalent production in the quarter was 3.9 million barrels per day, a decrease of 3% compared to the fourth quarter of 2017. Liquids production decreased 35,000 barrels per day as downtime in Canada, lower entitlements, and divestment of our Norway-operated assets more than offset growth from new projects and work programs. In particular, we were pleased with initial results at Hebron, where performance for the new wells has exceeded expectations. Natural gas production decreased about 400 million cubic feet per day due to lower entitlements and downtime, notably in Papua New Guinea. This was partly offset by higher seasonal gas demand and project growth volumes. Moving to Slide 13 for a comparison to the prior year quarter, first quarter upstream earnings increased $1.2 billion due to higher realizations. Crude prices rose $10.80 per barrel versus the year-ago quarter, and gas realizations increased $0.90 per thousand cubic feet. Volume and mix effects decreased earnings by $190 million due to lower entitlements and increased downtime, specifically in Papua New Guinea, which were partly offset by project volume growth. All other items increased earnings by $10 million as net gains from asset sales were offset by higher operating expenses. Moving to Slide 14, oil equivalent production decreased 6% compared to the first quarter of 2017. Liquid production was down 117,000 barrels per day due to field decline in the fourth quarter, divestment of our operated assets in Norway, and lower entitlements, partly offset by new project volumes. Natural gas production decreased 870 million cubic feet per day, driven by higher downtime, lower entitlements, and a decline in the U.S. This was partly offset by project and work program volumes. Turning to Slide 15, we’ll provide an update on earthquake recovery efforts in Papua New Guinea. First and foremost, on behalf of Exxon Mobil and in particular our staff in Papua New Guinea, I want to extend our thoughts and well-wishes to the people of PNG as recovery continues following the devastation brought by this powerful earthquake and its aftershocks. Following the initial earthquake, all of our production gathering pipeline and processing facilities were safely shut down. Exxon Mobil's humanitarian response to date has included the distribution of food, water, emergency shelters, and other supplies, along with the transportation of medics into affected areas. We focus support on the most impacted remote communities where we operate and have also made a donation to relief agencies. Our facilities successfully withstood the magnitude 7.5 earthquake in late February and its aftershocks, due in large part to robust design and the immediate and effective response by our people. As of its location, we accounted for a wide range of seismic activity in the original design, engineering, and construction of the PNG LNG project. In mid-April, ahead of our projected recovery timeframe, we announced a safe resumption of LNG production; the second LNG train started up this week and the facility is ramping up to full capacity. LNG exports have also resumed. During the period that production was shut down, we also brought forward and completed maintenance to our facilities that were planned for later this year, enabling more efficient operations in the months ahead. We are proud of the response of our people in managing this extreme event and importantly, the care for the community. On Slide 16, we take a closer look at Exxon Mobil's current acreage position offshore Brazil, which positions us with significant high-quality resource potential. You’ll recall that last year we captured several attractive opportunities, including a combined farm and bid round award for the discovered undeveloped Carcara field, which extends across both the BM-S-8 and North Carcara blocks. The Carcara field contains an estimated recoverable resource of more than 2 billion barrels, for which the co-venture group is progressing development planning activities. Group near-term plans include up to three wells in the field to better delineate the resource and deploying the development concept. As we shared at the Analyst Meeting, this proposed development yields attractive returns even at crude prices of $40 per barrel. At bid round 15 held last month, we were awarded an additional eight deepwater blocks containing multibillion-barrel prospects in the pre-salt play, taking our total acreage to more than 2 million acres across 24 blocks. Exxon Mobil operates more than 60% of these acreage holdings, and we will leverage our capabilities and proprietary technologies to maximize potential resource value. We will be acquiring more than 19,000 square kilometers of 3-D seismic data in 2018. As we already have 3-D seismic of some of the blocks, we’re also progressing plans for the first exploration well scheduled for the latter part of next year. Moving to Slide 17, we’ll now discuss downstream financial and operating results. Downstream earnings for the quarter were $940 million, a decrease of 12 million from the previous quarter, excluding the fourth-quarter 2017 impacts of U.S. tax reform and impairments. Global refining margins decreased earnings by $200 million; unfavorable volume and mix effects decreased earnings by $40 million, mainly due to lower seasonal demand and higher maintenance activity, partly offset by improved operations in the U.S. All other items increased earnings by $230 million, mainly driven by lower operating expenses, partly offset by the absence of last quarter's Norway retail divestment. Moving now to Slide 18, downstream earnings decreased to $176 million compared to the first quarter of 2017. Margins were down $30 million due to lower non-U.S. margins, partly offset by higher margins in the U.S. Unfavorable volume and mix effects decreased earnings by $60 million due to continued higher U.S. maintenance activity, mostly at Joliet, which resumed full capacity in March. All other items reduced earnings by $90 million, mainly due to the absence of asset management gains from last year's Canadian port credit asset sales. Moving now to chemical financial and operating results on Slide 19, first-quarter chemical earnings were about more than $1 billion, up $76 million versus the previous quarter, excluding fourth-quarter 2017 impacts from U.S. tax reform. Weaker margins and lower volumes, primarily due to turnaround activity, negatively impacted earnings by $30 million each. Lower operating expenses and favorable impacts from foreign exchange increased earnings by $140 million. Turning to Slide 20, first-quarter chemical earnings were down $160 million compared to the prior year quarter. Weaker margins resulted in a decrease in earnings of $270 million, as increased feedstock costs outpaced stronger realizations. Higher product sales from our new chemical operations in Singapore and the U.S. improved earnings by $120 million. All other items in the quarter included higher expenses related to new operations and other growth opportunities, which were mostly offset by favorable foreign exchange effects. These growth opportunities are a key component of our plans detailed at the Analyst Meeting. Now turning to our final slide, the corporation is focused on growing value across our integrated businesses. Each of our businesses contributed to solid financial performance in the quarter, together earning $4.7 billion. Cash flow from operations and asset sales of $10 billion covered our net investments and dividends with free cash flow of $6.7 billion. Upstream production volumes were 3.9 million oil equivalent barrels per day, in line with our expectations. We expect second-quarter volumes to be lower due to seasonal gas demand and then growth in the second half with project entitlement volumes, seasonal demand, and volume benefits from accelerated maintenance completed in the first quarter. Total CapEx was $4.9 billion with no change to our guidance. We strengthened the Upstream portfolio through exploration, acreage capture, and selected divestments, as well as disciplined execution of our investment program. In the Downstream, we are progressing our advantage investments, such as those in Rotterdam and Antwerp to manufacture higher-value products, capitalizing on our proprietary technology and integration. And in the chemical business, we’re focused on growing sales of our differentiated products supported by new assets that are well-positioned to meet global demand growth. Finally, we remain committed to our shareholders, as demonstrated by 36 consecutive years of dividend increases. That concludes my prepared remarks. Before we turn to your questions, I’d like to note that in the remaining quarters of this year, one of our management members will participate in the call to provide further perspective on progress and key developments relative to our plans. The Chairman and CEO will participate in the fourth quarter. With that, I would now be happy to take your questions.

I guess just to start on the overall profitability spectrum. At the Analyst Day, you offered a pretty clear view that the Upstream contributions would be, you know, after the post-2020 long cycle development program is wrapping up, and in the interim, Downstream and Chemicals would carry a lot of earnings growth. I understand the slides clarified that the margin environment wasn't necessarily supportive of that in 1Q, but maybe just an update on how those two segments are performing in an apples-to-apples margin picture and sort of what the fundamental outlook looks like for the remainder of the year and into that 2020 period where Upstream starts to contribute more?

Yes Sam, good question, and thanks for taking us back to what are our plans as we detailed in the analyst meeting. As you may recall, let me take each of them separately. In the Downstream, we are making - we have been making very strategic investments in order to high-grade our products. I highlighted in my prepared comments Antwerp and Rotterdam, which is going to take us out of lower-value products into higher-value products. We’ll have Antwerp that will start up in the middle of the year and then Rotterdam will start up by the end of the year, okay? As well in the Downstream, we have continued to expand our entry into some high-growth areas such as Mexico and Indonesia. Everything is moving consistent with the plans that we laid out in the analyst meeting. On the Chemical side, same story. We laid out for you a growth plan commensurate with what we saw in terms of chemical products. Importantly, as I indicated in the prepared comments, the Baytown cracker will be starting up middle of this year. It is really the second half of the overall project, remember the first half being the two polyethylene lines in Mont Belvieu, which have started up and have been ramping up to full capacity, and that will add a significant additional component to our chemical portfolio. You also recall there are a number of other investments that we made in chemicals in Singapore. Importantly, we are making great progress on integrating our Jurong Aromatics acquisition, but we see significant value there. As the organization continues to integrate that into our big Singapore manufacturing facilities, we continue to see additional opportunity. But right now, the focus on Singapore and Jurong Aromatics is primarily the integration and capturing the synergies that we saw. I will leave it there unless you have more questions on it.

No, that’s all right. I assume there’ll be more later in the Q&A. My follow-up is on Upstream. I wonder if we could dig in a little bit on these entitlement effects, specifically they were a little bit accelerated from 4Q even though the oil price move was actually somewhat more substantial in 4Q versus 1Q. I know there are a lot of nuances in these contracts, and some of them are subject to some nondisclosures and confidentiality. But anything we could glean on the forward look for these entitlements and maybe some future impacts, maybe decelerating here considering the quarter-over-quarter increase in that piece of the production number?

Yes, I mean, you’re highlighting an important issue that has historically been a key criteria on how our overall volumes play out. I mean, if you go back and look at just sequential analysis versus last quarter, it was over 90,000 barrels a day that impacted us. And as you appropriately recognize, each of these contracts that we have that have entitlement volumes are very unique. They are really a function of the commercial structure, the expenditure level, and obviously prices. Now the good news side, just don't lose sight of the fact that if you have an acid that is not causing, that just means accelerated recovery sooner. But it's hard for us to convey specific guidance given the unique aspects of each of these contracts. But if you just think about what you’ve seen sequentially, 90,000 barrels a day, and you think about it quarter on quarter, which I believe is around 70,000 barrels a day, it can have a material impact. But remember what our fundamental objective here is to really manage the business to maximize the value proposition, and that’s what’s most important here. As I said on the volumes going forward, you can really think about our volumes contributions in 2018 coming from the areas that I mentioned, our project growth notably in places like Hebron, Odoptu, and Upper Zakum, the tight oil growth that we’ve been advertising, but we’re making great progress. We said that we’d be there at about 30 rigs by the end of this year; we’re already at 27 rigs, so we’re really ahead of schedule. The second piece that you’ve got to remember is that, as I alluded to, there have been a number of unplanned downtime events in the first quarter, and we went ahead and took advantage to accelerate scheduled downtime that we have in the latter part of this year into that first quarter to be more efficient, and the downtime on the facility, notably in Papua New Guinea, as I referenced, and the second area in Syncrude. So we took full advantage of the opportunity to optimize the business, and we’ll, as a result, have more efficient operations in the second half of the year, and we won't have those planned events, and therefore, we will get some volume recovery. The third thing that you'll recall is, as I mentioned, in the second half of the year, we'll start seeing that seasonal demand start ticking up again. And then, lastly, I'll mention, and I didn't say in my prepared comments, but we always have a very robust conventional work program, and those are fairly cheap high-value barrels that we're able to capture through the propane.

Great. Thanks. Good morning, Jeff.

Good morning, Ryan.

I would like to express my appreciation for the additional disclosures, and I believe that having more members of the management team on the call will be well-received by investors moving forward. That's excellent. My first question is about Groningen. One of your partners has written off reserves and recorded an impairment related to the recent government announcement there. Could you share your thoughts on the situation going forward, including the potential impact and whether there is a possibility for any compensation in the future?

Yeah. Well, I mean, as you can appreciate, it is a very dynamic situation. We continue in discussions with NAM, the operator, and the government. Those are confidential discussions. Really, Ryan, at this stage, we just don't want to speculate until we conclude those discussions. But we're still operating, the field is still operating under the current cap of 21.6 billion cubic meters per year.

Okay. And maybe a follow-up on Canada. I know you brought forward some of the turnaround there at Syncrude. But can you talk about your availability to get Canadian heavy out of there? I mean, how are you seeing when Syncrude comes back? Are you anticipating limits on your ability to get it out? Are you moving things on? How much on rail versus pipe, and how much you're able to run through your refineries to capture the benefit there?

You have addressed part of the answer already. In the first quarter, we faced some logistics constraints, amounting to about 12,000 barrels per day during that time. Looking ahead, we are currently clearing all the barrels. One of our ongoing objectives has been to maintain logistics flexibility. A few years ago, we tested the Edmonton Rail Terminal as an additional export option. We also have pipeline capacity at our disposal. Importantly, we aim to capture the full value chain benefits by integrating heavy oil into our equity processes beyond refining. We are continuously seeking the best value options to deliver these barrels to market. Our focus is on proactively identifying ways to maximize flexibility, whether that means utilizing our equity capacity within our manufacturing footprint or exporting to achieve higher value.

Thanks. Good morning, everybody. Again, Jeff, thanks for the incremental disclosure, but I think there is still some confusion out there on what's really going on in the operating cash flow. So I wonder if I could trouble you to just walk through the dynamics of the net PP&E odds, what is the timing of affiliate distributions, and reconcile that with net income plus DD&A, which is $9.2 billion. You see what I mean there is the CapEx at the affiliate level, as I understand, is reported on a net basis above the operating line. If you could confirm that and just walk through the delta, because I think folks think that your cash flow number was closer to $8.2 billion.

Yes. Our net property, plant, and equipment was $3.3 billion, excluding the cash requirements for affiliates.

Right.

And that is down versus both the prior quarter, fourth quarter of 2017, as well as the prior year quarter, primarily due to the absence of acquisition funding.

Just on that point, did you pay for Brazil in the first quarter?

In the first quarter, what’s specific to Brazil, there have been a number of transactions?

The Carcara acquisition, that was the money out door in the first quarter for Carcara?

Not yet.

Okay.

That is to come later this year.

Your net capital spend after affiliates, which is below the operating cash flow line, was $3.3 billion. Is that the figure we should focus on?

That's correct.

Okay. Great. Thanks. My follow-up is, obviously, you said in your commentary about the Sorubim-1 successful well. When we met with you a couple weeks ago, my colleagues had made a comment that in a success case there could be a third rig option because of the potentially open another play type. Has that option now gone away? Is that play type now abandoned, or does it just condemn that upside exploration case, or maybe you could just frame how these changes the rest profile of the block? And I'll leave it there. Thanks.

Yes, let me explain. Sorubim, like any exploration program, carries a significant amount of risk associated with all these exploration prospects. As I mentioned earlier, each time we drill one of these wells, we gain additional insights. I wouldn’t conclude that the well itself disqualifies the play or the prospect opportunities we have in the Stabroek Block. Regarding the potential for a third rig, that is always a possibility, but we will decide based on the technical progress of our prospects as we incorporate the real-time data from Sorubim, from Liza-5, and other analyses we are conducting using the 3D seismic data we collected. Currently, we plan to operate the two rigs simultaneously, with one primarily focusing on the development wells for Liza Phase 1 following the completion of the Liza-5 well test, while the other will follow up on some previous discoveries. We will consider how to adjust that rig lineup as we advance the technical prospects.

Yes. Hi. Good morning, Jeff.

Good morning, Phil.

First question is actually a little bit of follow-up to Doug’s question. You noted the equity affiliates headwind in the quarter of a $1 billion. Certainly, appreciate you breaking that out from the working capital. So, just wondering how you think about that number for the full year? One of your peers, for example, has said that the affiliates will be a $2 billion headwind on an annual basis. I know it’ll be lumpy quarter-to-quarter, so just any additional color you can provide there.

Yes. If you consider the equity companies, a significant portion of the $1 billion we are discussing is usually part of a seasonal pattern for us. Typically, we don't see those distributions until later in the year, if that’s what you’re trying to understand.

Yes. That was definitely part of it. It did sound seasonal for the quarter, but I was wondering on an annualized basis. Also, is it, you kind of lumped together a number of factors...?

Yeah.

...and your disclosures in your filings, I just wonder if that affiliate headwinds on an annual basis would still be a headwind.

We think, I mean, broadly speaking without giving you a specific number, Phil, I would tell you that most all the earnings are distributed throughout the year.

Okay. So more of the one-to-one, I guess, is what you’re saying?

Yeah. I mean...

...earnings to cash...

...broadly speaking, I mean, it is going to be some timing impacts depending on cash requirements from the equity companies.

Yes. Okay. Thanks. Second question would just be one of your peers have also given helpful statistics around base plus shale CapEx. So, I was wondering if there is some kind of framework with underlying your capital spending numbers that you might be able to provide around base plus shale, given that for you guys it’s essentially going to drive flat production for the long-term?

Yeah. I think from our prior discussions, Phil, what you really were looking at was capital efficiency. And we clearly pay close attention to that versus how we expect we should perform, as well as how our peers are managing this important area. And our conclusion continues to be that we lead in that area. Now we don’t think comfort in that only because we think we can always do better. But as you think about how we conclude that it’s through a number of things. One I would say that the ultimate measure of that is our return on capital employed, and not only do we lead on return on capital employed, we've laid out a very attractive investment program that shows how we’re going to continue to grow that lead out to 2025. We also have looked at what some are spending annually, and while we have a much bigger production base, our expenditure levels are comfortable on an absolute basis. And lastly, I would say, if you look at another measure, and to me, it's really a simple one. Take your total capital employed per barrel of crude reserves; in other words, the money spent developing the reserves. We have one of the lowest dollars per barrel out there. So, I mean, if the objective is to really try to qualify the capital efficiency of our business, that's what I would offer to you.

Good morning, Jeff.

Good morning, Neil.

Jeff, when do you think you'll be in a position for the company to make a FID decision around PNG, and then any update on Qatar, in terms of both the timeline and progress around negotiation there?

Regarding PNG, we've made significant progress. To recap, we completed the Interoil acquisition, which brings substantial resources at Elk and Antelope located along the pipeline route from the Highlands to the plants, creating clear synergies and opportunities. Total operates these assets, and we've been closely coordinating with our current co-venturers and Total, aligning on this expansion. Additionally, we're capturing substantial resources, including from P'nyang. Earlier this year, we made a noteworthy discovery at Muruk, with another well being spud there later this year, which is close to the Hides gas field. We've also acquired high-quality exploration acreage in the Highlands and offshore of the LNG plant. Overall, we've built a significant high-quality resource potential in the PNG area, positioning us well for this expansion and future opportunities. The timing is still to be determined, as it involves various stakeholders, including the PNG government aligning with the plans. However, we are well-positioned, and the project's performance, especially during earthquake recovery, highlights the quality of our people and assets. Moving forward, we're focused on ensuring PNG meets its history of best-in-class performance. When we get closer to a specific timeline, we will update you. On Qatar, we value our partnership with the Qataris and consider it a successful venture that has brought value to both parties. Looking back, Qatar has become one of the largest LNG exporters at a very low cost of supply, and we are proud of our role in that success. We have participated in 12 out of 14 trains and contributed important technologies like large LNG trains and carriers. We will continue our collaboration with the Qataris in places like Brazil and Cyprus and seek opportunities to leverage our experiences and capabilities to enhance our portfolio and create value for both Qatar and Exxon Mobil.

Jeff, a quick modeling question here; in the Analyst Day deck, you provided some cash flow levels at 60/80 Brent levels. What’s the rule of thumb for every dollar change in the price of Brent that due to the Exxon Mobil cash flow?

We have the earnings sensitivity that's in our 10-K, and for every dollar per barrel, it's about $500 million of earnings per barrel of cash per barrel.

Good morning, Jeff.

Good morning, Doug.

The dividend increase of 7%, while pretty similar to the growth rate and the median during the past 10 years and 20 years, it’s pretty significant, I think. And on this point, when considering the new financial disclosure that Darren is going to be on the call later in the year and its returns targets, there has been a lot of positive change at the company this year, at least in my opinion. So my question is, what is the company trying to convey from the size of the dividend increase, if anything? And if there is a new underlying message from this change or some of the other changes we've seen this year, what is it?

Yeah. Well, Doug, thanks for the question. I mean, simply put, remember we’re keeping very focused on our core mission, and that is to grow shareholder value. I mean, there is an intense focus by the corporation on value growth, okay? And part of, if you think about our capital allocation approach, fundamentally what we said was one of the first priorities is growing shareholder value and distributing that success to our shareholders through our dividend. And you’ve seen us for 36 consecutive years continue to grow that dividend. I think when you look at what the Board's decision was earlier this week, it was really underpinned by the confidence that we've got in our business plan. We made a decision given a number of factors that coalesce to be much clearer in terms of where we saw that value growth potential. Frankly, Doug, I would tell you, we believe that the investment community did not have a very good understanding of what our value growth potential was. And we believe it was important to go ahead and make that much clearer. I can tell you that every one of the senior leadership who are running these businesses are committed to delivering that value potential. Now a key aspect of that is making sure that we are being very thoughtful and selective in growing that investment program that is going to generate that accretive value. But ultimately, all these steps are around a simple message of value growth and making sure that that is clearly understood by the investment community as to where we’re going and that we think ultimately it's differentiated by our technology and by the integration of our businesses that add additional value that we believe is sustainable. As we go through this year and into next year, and you see us delivering on those expectations, I think, ultimately, people are going to have a much better understanding of the full scope potential this corporation has, notably from the integration of our three world-class businesses.

Okay. Well, Jeff, your tone surely underscores your enthusiasm towards the new value proposition, that's a good thing. And then I had another question: what was the earnings impact from the gains on asset sales in the quarter? And if you have specificity outside of Scarborough, which I think you mentioned, that would be appreciated too?

Yeah. So if you look at, I’ll give you a couple comparisons to give you perspective. So if you look at the quarter-on-quarter impact from earnings, it was about $180 million, and most of that was in the upstream, okay?

Okay.

Sequentially, it was a negative impact of about $130 million, and most of that negative impact was in our downstream business.

Okay. Thanks a lot, Jeff.

Yeah. The key aspects just a little bit more, Doug...

Yeah.

...is you mentioned Scarborough. And then I mentioned some marketing and distribution assets in South America and also I mentioned the European assets, primarily retail assets.

Okay. Okay. Thank you.

You're welcome.

Hey, Jeff. Good morning. I know you ran through some pretty good detail on the downstream, but I wanted to ask you more specifically on the upcoming IMO changes in 2020. There's an awful lot of optimism among your independent refining peers. And I didn't know if Exxon had any view. Do you share in the same kind of enthusiasm as far as what that’s going to do to just look demand in some of the heavy oil discounts, so just didn’t know if the company had a view?

Yeah. Well, it's a good question and good morning, Blake. So if you think about our investments. They’re all really embedded in our deep understanding in the energy markets. That’s, that’s really informed by our energy outlook. I mean that’s why we do it, is to get down into the very deep insights that really guide our business strategy and our investment plans going forward. And this is one of those factors is our policy ultimately will impact the energy system and the products ultimately the society will need. We've been watching this closely for some time. You have seen that we've made a number of strategic investments notably in places like our European assets with Antwerp and Rotterdam. We are going to Coker and Antwerp. As I said, Rotterdam, we’re putting the hydro cracker in that’s going to take us out of the lower-value products like marine fuel oil into higher-value distillates like ultra-low sulfur diesel, as well as grow to lubricant-based stocks. When you think about IMO 2020 specifically, what we want to be positioned to do is to offer a suite of options for the marine industry. So we are going to be positioned to provide things like low sulfur blends. We’re going to provide also sulfur marine gas oil. We will have LNG capability to provide, but also high sulfur fuels for ships with scrubbers. So one of the advantages, in addition to these investments we’re making in Europe, is that we’ve got a fairly comprehensive refining network in the U.S. Gulf Coast that will be able to provide these products as well. So, I think in short, I just say that we are providing a lot of optionality, and we think we are very well-positioned to address this change in sulfur specs, as well as a number of other changes on the horizon.

Understood. Second question. I can’t believe buyback hasn’t come up yet, but this quarter, if I am kind of rewinding last year, I think, we went through this: first quarter seems to be fairly elevated as far as the requirement to offset dilution. I think you had $425 million. I am trying to confirm that that number should theoretically roll-off here throughout the year. And then I didn’t know if there were triggering points, I mean, debt reduced, you’ve got free cash flow, is there anything else you really kind of need to see in order to get the buyback program kind of up and running over and above this dilution?

Let me clarify the number I mentioned regarding the first quarter. The $425 million was related to an anti-dilutive purchase for our benefit plans and programs, which usually occurs in the first quarter. As for buybacks, I understand the interest surrounding them. Simply put, buybacks are still a possibility. Our top priority is to remain committed to our core mission of increasing shareholder value. If we find opportunities that offer valuable investment returns, that is where our funds will be directed. We are focused on value growth. We recognize the importance of distributing value to our shareholders, primarily through our cash dividend. We have shown our dedication to consistently increasing the dividend, demonstrating the corporation’s confidence in its business. Regarding buybacks, we evaluate them quarterly, taking into account the company's current financial position, which is very strong. We also consider our investment and dividend needs, the near-term business outlook, and our cash requirements for investments or debt maturity. All these factors influence our decision on whether to initiate a sustainable buyback program. Since the merger of Exxon Mobil, we have repurchased about 40% of the outstanding shares, making it a significant part of our total distributions. It will remain an option for us, but our primary focus is on reliably increasing the dividend first, then making accretive investments in our business, and finally considering how to utilize any extra cash. Does that clarify things for you, Blake?

Thank you.

You’re welcome.

Thanks. Good morning, Jeff.

Good morning, Guy.

I wanted to take Permian midstream and logistics strategy here a little bit, especially as such an important growth driver for you all. But we have seen differential widening out in the Permian for oil and gas, and potentially widening out again later this year for some time for oil, as those oil pipes get filled. Can you just help us to understand how your Permian crude is priced? Maybe how much exposure you have to Midland pricing, how much you move to higher price markets. And then, maybe just an update on where you stand regarding some of the midstream capital investment opportunities that you've discussed and the strategy to just maximize the value of your product there and then I have a follow-up.

I'm glad you raised this point. The core strategy we've adopted in our business revolves around a value chain perspective. The Permian Basin serves as an excellent example where we've established what we believe to be a strong position. This allows us to develop the resource while leveraging our expertise in development planning, extended-reach drilling, completion technology, reservoir management, and reducing unit costs below what we think others can achieve. Importantly, we need to extend this strategy to our advantageous manufacturing footprint in the Gulf of Mexico, highlighting the significance of the midstream segment. We've maintained a clear view of the value chain to ensure nothing is lost from a value standpoint without making informed business decisions about capturing that value ourselves. For instance, we acquired the Wink terminal, which we are considering expanding. Additionally, we formed a joint venture with a subsidiary of Energy Transfer Partners, combining our pipeline assets for greater export flexibility. It’s crucial that we have a long-term outlook and position ourselves wisely to seize the value proposition. Regarding our Permian production, we have not only set up the logistics network but also the supply chain to maximize value. Despite some challenges, we are successfully clearing all our Permian barrels and have the flexibility to either benefit from our manufacturing footprint or export them to capture that value. This integration has significantly enhanced the value for the corporation.

Yeah. Very helpful. And then I had two follow-ups here. One on the CapEx front. Understanding it’s early in the year, the CapEx was up year-on-year as you highlighted. It was actually a little bit below our model. Can you just talk about what you’re seeing globally from an inflationary or deflationary perspective, as you’re ramping up activity here in your key areas? And I am sorry if I miss this earlier, but in Guyana, Liza-5, was there anything incrementally share, at least the five at this point? And maybe how are you thinking about the size of that third FPSO as you integrate those results?

Let me start with the last question first. In Liza-5, we’re still early in the process. The well itself met our expectations, and we are now moving into the testing program, so there’s really not much more to share at this point. We still estimate holding a recoverable resource of about 3.2 billion barrels, but I want to remind everyone that this does not include any additional contributions from Ranger and Pacora, as we need to conduct more delineation drilling before updating the resource assessment. All of this information is being integrated in real-time into our development planning for future phases in Guyana. The first phase involves a vessel with a capacity of 20,000 barrels per day, while the second phase is projected to involve a vessel of about 220,000 barrels per day, depending on the final investment decision. For the third phase, we are analyzing real-time data and haven’t made a definitive decision yet. Our goal is to implement more of these manufacturing rigs, similar to what we've successfully done in Angola, enabling us to design and deploy comparably designed facilities to maximize value. These are exciting times for Guyana with significant developments from exploration to production planning, and we will keep you updated as we make progress. Regarding your other question on the market and inflationary pressures, there are indeed certain services and geographical areas experiencing inflation. For example, the Gulf Coast and manufacturing areas are facing pressures on craft labor due to high activity levels, especially in the Permian Basin. However, we are focused on staying ahead of these challenges and positioning our business to offset any pressures while maintaining a commitment to structural reductions. In the Permian, we continue to drive down unit costs through increased drilling efficiencies, which is all about capital efficiency. As we develop or produce these assets, our aim is to do so at the lowest possible cost. We remain proactive with our contract awards, focusing on total cost of ownership to find supplier cost reduction opportunities and leveraging competitive bidding. Our strong supplier relationship management program enhances our ability to streamline equipment purchases, all aimed at reducing costs to offset inflationary pressures. While some areas may present challenges, we are primarily focused on achieving the lowest lifecycle cost for our assets.

Yeah. That's perfect. Thanks, Jeff.

Great. Thank you.

Hi, guys. Good morning.

Good morning, Paul.

Jeff, I believe I can speak for the investors in expressing appreciation that Darren and the management team will be joining the call later this year. This is a positive step forward. I have two quick questions. First, you drilled several wells that are 12,000 to 15,000 feet laterally in both the Bakken and Delaware regions a few months ago. I assume these wells have been producing for a couple of months now. Can you share any production data or insights regarding the testing results?

Yeah. Well, Paul, let me give you an update on where we are on those. First, just remind everybody, we try to give a view of what we saw the value was by extending the lateral lengths in these wells at the Analyst Meeting. You can always go back and refer to that. We have drilled a number of these 15,000-foot wells in the Bakken that are still early; they are producing. I would tell you that the results are meeting our expectations in terms of what we would expect in terms of the uplift. We have also drilled some in the Permian. They have not yet been completed at this stage. You remember a lot of these wells have been drilled by pads, so in order to optimize, again focused on capital efficiency, they're going to be coming in batches. We’re being careful. I am going to be very candid with you: we’re being very careful about what information we disclose on this, because we do think that there is a competitive advantage here. But I will tell you that we see the value uplift that we had portrayed in the Analyst Meeting.

In the second quarter, given the takeaway capacity in Western Canada, it seems that a resolution is not imminent. Additionally, it appears that the opportunities within your portfolio have diminished in terms of their priority or ranking. How should we view the development of incremental oil sands projects at this stage? Up until last year, particularly in May, it seemed you were on track to move ahead with several projects, including the Aspen project and others. Are those developments still expected to proceed, or have they been postponed?

Yeah. Good question, Paul. What I tell you is, as you know, we've been working on oil sands for over three decades, both in the mining and in-situ perspective. Fundamentally, any new investment is going to compete at the top of our investment portfolio. It’s got to generate, as we talk previously, generate an attractive return that's accretive to our financial performance and has durability in a lower-price environment. We continue to identify opportunities to enhance profitability in both in-situ and in our mining operations. Imperial just talked about what we're doing in Pacora in terms of improving reliability. The same has been true in the in-situ operations, by and large not only optimizing the steam operations but trying to leverage the fairly deep technology work that we've been doing in our research facility. Looking at how we can best apply the proprietary, as I said, deep potential that we think will not only improve recovery but also reduce costs, and importantly, the environmental impact. So I tell you that portfolio and, as you probably aware, it is a clearly sizable amount of resource that we’ve got up there, it’s getting a lot of focus around applying the right technologies and capabilities in order to ensure that it competes at the portfolio. So I wouldn’t say that it has fallen down on a rank. It’s just like every other resource we’ve got, we are working on it. If we come to a point at some stage that we think that the value proposition meets our objectives then we’ll move forward with it. Is that good, Paul?

Yeah. One just follow-up on that. Will you anyway that go ahead to sanction the project without clear sight takeaway capacity in Canada being resolved?

Yeah. It's very similar to what I mentioned about the Permian discussion, Paul. We've been focused on ensuring that we have the necessary takeaway capacity and the flexibility to process these crudes within our equity refining capabilities. This necessity is a key reason behind our investment in the Edmonton Rail Terminal. However, our primary supporters emphasize the need for investment in infrastructure, which has faced challenges in certain regions. We'll continue to ensure we're optimizing the value chain to maximize our value proposition. I want to thank everybody for their questions. I do want to clarify just one point to make sure my response was appropriate that there is a question about the earnings and cash sensitivity to the price of crude, and we have some of this in our 10-K that you can go ahead and reference. But broadly speaking for every barrel of crude price, it relates to about $425 million of earnings and about $500 million of cash for the year.