Please stand by. Good day, everyone, and welcome to this Exxon Mobil Corporation first quarter 2017 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. Jeff Woodbury. Please go ahead.
Thank you. Ladies and gentlemen, good morning, and welcome to ExxonMobil's first quarter earnings call. My comments this morning will refer to the slides that are available through the Investors section of our website. Before we go further, I'd like to draw your attention to our cautionary statement shown on slide two. Turning now to slide three. Let me begin by summarizing the key headlines of our first quarter performance. ExxonMobil earned $4 billion in the quarter. Cash flow from operations and asset sales totaled $8.9 billion, more than covering both dividends and net investments in the business for the second consecutive quarter. We achieved solid results from each of our business segments and remain steadfast on managing costs and operating efficiently. In the first quarter, we continued advancing strategic opportunities to grow value through disciplined investment, portfolio acquisitions, and high impact exploration.
Moving to slide four, we provide an overview of some of the external factors affecting our results. The global economy started the year with modest growth. In the United States, expansion slowed in the first quarter. However, growth rates were stable in China and Europe and appear to have slightly improved in Japan. The commodity price environment improved in the quarter as both crude oil and natural gas prices strengthened. As a result, the global rig count increased, driven primarily by higher activity in the U.S. Refining margins also improved with global demand growth, heavier industry downtime, and seasonal product inventory draw. Further, global chemical commodity margins increased on higher realizations, with industry polyethylene capacity utilization remaining strong in advance of U.S. Gulf Coast expansions. Turning now to the financial results as shown on slide five. As indicated, ExxonMobil first quarter earnings were $4 billion or $0.95 per share.
In the quarter, the corporation distributed $3.1 billion in dividends to our shareholders. CapEx was $4.2 billion, down nearly 19% from the prior year quarter as the corporation continues disciplined execution of its investment plans. Cash flow from operations and asset sales was $8.9 billion, and at the end of the quarter, cash totaled $4.9 billion. Debt was $43.6 billion. Net debt, which is debt less cash, declined in the quarter. That was impacted by the funding of the escrow account for the contingent resource payment associated with the InterOil acquisition. These funds, which totaled $1.7 billion, were loaned back to the company from the escrow account. This impact is temporary, as ExxonMobil acquired a receivable as part of the InterOil deal, which is expected to more than cover the continued resource payment. The next slide provides additional detail on sources and uses of cash.
Over the quarter, cash balances increased from $3.7 billion to $4.9 billion. Earnings adjusted for depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $8.9 billion of cash flow from operations and asset sales. Uses of cash included shareholder distributions of $3.1 billion and net investments in the business of $4.5 billion, which included the $1.7 billion to fund the escrow account I previously mentioned. Debt and other financing items decreased cash by $100 million, which included the impact of anti-dilutive share purchases. Cash flow from operations and asset sales more than covered dividends and net investments with an excess of $1.3 billion. Earlier this week, the board of directors declared a second quarter cash dividend of $0.77 per share, representing a 2.7% increase from last quarter and marking our 35th consecutive year of per share dividend growth.
In the quarter, ExxonMobil continued to limit share purchases to amounts needed to offset dilution related to our benefit plans and programs, and we don't currently plan on making additional purchases to reduce shares outstanding in the second quarter. Moving on to slide seven for a review of our segmented results. ExxonMobil's first quarter earnings increased $2.2 billion from the year-ago quarter, driven by stronger Upstream results. Further gains in the Downstream were offset by lower Chemical results and higher corporate and financing expenses. In a sequential quarter comparison shown on slide eight, absent the fourth quarter 2016 Upstream impairment charge, earnings increased over $300 million due to stronger results from the Upstream and Chemical businesses. This was partly offset by higher corporate costs driven by the absence of last quarter's favorable one-time non-U.S. tax items.
On average, we expect corporate and financing expenses will continue to be between $400 million-$600 million per quarter in the near term. I'll note our corporate effective tax rate was 38% during the quarter, up from 19% a year ago, reflecting changes in our segment earnings mix and other one-time items. Turning now to the Upstream financial and operating results starting on slide nine. First quarter Upstream earnings were $2.3 billion, an increase of $2.3 billion from the prior quarter due to higher realizations. Crude prices increased more than $19 a barrel versus the year-ago quarter, and gas realizations increased nearly $1 per thousand cubic feet. Volume and mix effects decreased earnings by $150 million, largely because of lower entitlements and higher maintenance. All other items increased earnings $170 million, driven by lower operating costs.
Upstream unit profitability for the first quarter was $6.19 per barrel, excluding the impact of non-controlling interest volumes. Moving now to slide 10. Oil equivalent production in the quarter was 4.2 million barrels per day, a decrease of 4% compared to the first quarter of 2016. Liquids production was down 205,000 barrels per day, the result of lower entitlements and increased maintenance. New project volumes more than offset field decline. Natural gas production increased to 184 million cubic feet per day as volumes from new projects and higher demand more than offset field decline and regulatory impacts in the Netherlands. Turning now to the sequential comparison and starting on slide 11. Upstream earnings were $867 million higher than the fourth quarter of 2016, when the effect of last quarter's impairment charge is excluded. Higher realizations contributed $570 million of earnings.
Crude prices increased nearly $3 per barrel, gas realizations increased nearly $0.50 per thousand cubic feet. All other items added $300 million, again, largely the result of lower operating expenses. Moving to slide 12. Sequentially, volumes increased about 1%, or 30,000 oil equivalent barrels per day. Liquids production decreased about 50,000 barrels per day because of lower entitlements, whereas new project volumes offset higher downtime. Natural gas production increased to 484 million cubic feet per day due to ramp-up of recent project startups, increased demand, and lower downtime. Moving now to the downstream financial operating results starting on slide 13. Downstream earnings for the quarter were $1.1 billion, up $210 million compared to the first quarter of 2016. Favorable volume and mix effects improved earnings by $160 million, mainly from increased operational efficiency which resulted in higher throughput.
All other items added $40 million, mostly from minor asset management activities, partly offset by unfavorable foreign exchange impacts. Turning to slide 14. Downstream earnings decreased sequentially by $125 million. Stronger margins increased earnings by $200 million. Volume and mix effects decreased earnings by $220 million, primarily driven by higher planned maintenance. All other items reduced earnings by a further $110 million, driven by higher turnaround costs and the absence of fourth quarter asset management gains of more than $500 million from the Imperial Oil's retail network sale. This was partially offset by lower operating costs and the absence of unfavorable fourth quarter inventory impacts. Moving now to chemical financial operating results starting on slide 15. First quarter chemical earnings were $1.2 billion, down $184 million compared to the prior year quarter. Weaker margins, primarily from specialty products, decreased earnings by $70 million.
All other items decreased earnings by $110 million, largely due to increased turnaround expenses and unfavorable foreign exchange effects. Moving to slide 16. Chemical earnings improved sequentially about $300 million. Stronger commodity margins increased earnings by $170 million as higher realizations outpaced rising feed and energy costs. All other items increased earnings $140 million, primarily reflecting lower expenses in the absence of unfavorable fourth-quarter inventory effects. Turning to slide 17 and our business highlights. First, a strategic acquisition in Mozambique. ExxonMobil signed an agreement to acquire a 25% indirect interest in Area 4 offshore Mozambique for cash consideration of $2.8 billion. The deepwater Area 4 block is estimated to contain more than 85 trillion cubic feet of natural gas in place, with high expected well deliverability underpinning a world-class LNG project. We believe the project will be well-positioned to supply LNG customers in markets around the world.
ExxonMobil will lead the construction and operations of the planned onshore facilities, including liquefaction trains with a capacity of up to 40 million tons per annum. As such, ExxonMobil will contribute its expertise in project execution and operations to support the project's success in a globally competitive LNG market. The transaction is subject to regulatory approval. After it has closed, the partners will optimize development plans and determine key milestones such as FID and start-up timing accordingly. Elsewhere in Mozambique, we are evaluating three high-potential blocks for which we were awarded the right to negotiate exploration and production rights. We participated in a multi-client 3D seismic survey which was completed in November of last year. We look forward to finalizing discussions with the government of Mozambique on PSCs for these blocks. Turning now to slide 18 for an update on our project and exploration activity.
To begin with, ExxonMobil closed two significant acquisitions this quarter. The first was the InterOil deal with assets in Papua New Guinea. We are now engaging with co-ventures to assess optimal development of discovered undeveloped resources, both legacy and acquired. The Antelope-7 appraisal well is complete, and the interim resource recertification process has been initiated and will be completed later this year. The second transaction was our acquisition of companies owned by the Bass family, which more than doubled our Permian Basin resources. An integrated asset team is in place to manage these newly acquired properties. In order to fully capitalize on the advantages offered by the highly contiguous acreage position and our participation across the full value chain, the team is leveraging corporate expertise in unconventional development, research, project management, and logistics. We do expect to spud the first well on the new acreage shortly.
Next, we continue to selectively invest in projects across the value chain. We currently have 18 major projects in execution across all business segments. In the upstream, this includes projects such as Hebron and Odoptu Stage Two. Commissioning work is progressing well on both of these projects, which are expected to start up before year-end, adding a combined gross production capacity of 215,000 barrels of oil per day. In the downstream, the Antwerp Coker project will start up later this year, delivering higher-value products, including ultra-low sulfur diesel. The chemical expansion project at Baytown and Mont Belvieu will begin a phased start-up in the second half of the year. In other recent developments in Australia, train three at Gorgon LNG started up in March. All three trains are now available to ramp up to full plant capacity of 15.6 million tons per annum.
Turning to exploration, we remain focused on adding resources that are attractive in the current price environment. We recently announced the Snoek discovery in Guyana, with reservoirs similar in age to the prior discoveries at Liza and Payara. The rig has moved to the Liza-4 appraisal well, which is evaluating the east flank of the Liza field. A well test is expected to begin on this well next month. After Liza-4, the rig will drill a delineation well at Payara that will also test a deeper exploration prospect. We also continue to capture new high-potential acreage around the world. In the U.S., ExxonMobil is the apparent high bidder on 19 blocks in the central Gulf of Mexico. In Papua New Guinea, a recent farm-in to two offshore blocks was ratified by the government. These blocks are just 60 miles south of our LNG facilities.
The initial scope of work is expected to include seismic acquisition. Finally, in Cyprus, we were awarded an exploration and production sharing contract for offshore Block 10 with our long-standing partner, Qatar Petroleum. The contract includes commitments to acquire 3D seismic data and drill two exploration wells, with the first well anticipated in 2018. I'll note this block is near the recent Zohr discovery. Moving now to the final slide. The corporation remains committed to growing value across our integrated businesses. All three of our business segments contributed to solid performance in the quarter, together earning $4 billion while remaining highly focused on business fundamentals. Upstream production volumes were consistent with plants at 4.2 million oil equivalent barrels per day. Total CapEx was $4.2 billion, a decrease of 19% from the prior year or prior quarter.
Corporation has remained disciplined in its investment program, selectively advancing strategic opportunities across the value chain while maintaining focus on capital efficiencies. Cash flow from operations and asset sales totaled $8.9 billion, and free cash flow was $4.9 billion, more than covering $3.1 billion in quarterly shareholder dividends, even after funding the escrow account for the InterOil transaction. We remain committed to our shareholders as demonstrated by our reliable and growing dividend. Regardless of the business cycle, we are confident in ExxonMobil's integrated business model and our ability to create shareholder value over the long term. That concludes my prepared remarks. I would now be very happy to take your questions.
Thank you, Mr. Woodbury. The question and answer session will be conducted electronically. If you would 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 are 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 will proceed in the order that you signal us. We'll take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. We will take our first question from Brad Heffern with RBC Capital Markets.
Morning, Jeff. How are you?
Good morning, Brad. I'm doing well. How are you?
Good, thanks. A couple questions on LNG. Obviously you've added Mozambique now. That goes into a really long LNG queue. You've got PNG, Golden Pass, Scarborough, the list sort of goes on and on. I'm curious how you think about the order of priority there, and just generally how much room you think there is for more LNG in the portfolio.
Yeah, good question, Brad. I think I'd start first with the second question and really think about our energy outlook and our long-term view on demand, and particularly as it relates to LNG. To start off, as you know, we have gas growing from 2015 to 2040 at about 1.5% per year. In fact, becoming the second highest source of supply overtaking coal for the obvious environmental benefits. On an LNG basis, over that same time period, out to 2040, we have LNG capacity and thus demand growing by about 250%. There's the business case right there. Now obviously, like any type of supply-demand mechanics, you're going to see periods of tightness, periods where there's excess demand and it requires a supply response. As you highlighted, Brad, moving into your first question, there are a number of LNG projects that we are concurrently progressing.
I will tell you that not all of them will move at the same pace. We've got a good diverse portfolio, some that are associated with brownfield expansions to existing facilities, such as the Papua New Guinea or the Golden Pass, and then others more large greenfield developments like Mozambique. Each of them have unique characteristics that we're going to try to place into the market. It's not choosing one or the other at this point. It's a matter of moving them all forward and depending on all the different variables that have to work for a multi-billion dollar investment, some will come to maturity quicker.
Okay, thanks for that. I guess digging in slightly on Mozambique, I was curious if you foresee any changes to the development plan as it's been laid out in the past, and I'm specifically thinking about Coral and how you feel about the floating LNG plan there.
Yeah. Brad, I would tell you that obviously we've got to wait for the regulatory approvals to be concluded and then get with the co-ventures and have discussion. The current plan is that Coral will progress.
Okay, thanks, Jeff.
We will now hear from Neil Mehta with Goldman Sachs.
Good morning, Jeff.
Good morning, Neil.
Jeff, I always appreciate your perspective on the oil macro. Brent's really still trying to get some legs under it here in 2017. Where does Exxon believe we are in terms of the crude rebalancing process? Would appreciate your views on OPEC, non-OPEC and demand.
Yeah. It's a good question. Clearly I would say that the macro would still indicate from an Exxon Mobil perspective, still indicate the need to be cautious going forward. As we've talked in the past, underlying demand growth has been generally strong. We're seeing demand growth of about 1.4 million barrels a day, similar to last year, and that's above the 10-year average. As we would have expected, we're seeing a supply-side response to supply and demand coming into balance. We do see that non-OPEC volumes are growing, particularly driven by North America and specifically the unconventionals. And you think over the last recent period, unconventionals have grown, round numbers, about 800,000 barrels a day on trend and maybe a million barrels a day over a 12-month period.
I think it all indicates the importance of making sure that we are very thoughtful about the near and longer-term macro environment. On an OPEC basis, as you've seen, the OPEC has generally met their commitments. A little bit short, but they are demonstrating a level of compliance. When you step back and look at the supply side, I think is the biggest issue in front of us, and that'll be a function of so many elements, including the North American response that I talked about, but also economic growth and other variables. Remember, we still have round numbers, about 600 million barrels in storage. Depending on what near-term prices do, that's going to come out at some point. A lot of variables to think about, and that's what really underpins my comment about just being cautious.
I appreciate that, Jeff. The follow-up is, I just want to talk about your long-term growth aspirations in two regions that don't always get a ton of attention. The first would be Iraq, the second would be Russia. Any comments on either of those would be helpful.
Yeah. Let me start with Russia. As everybody clearly knows, that the sanctions remain in place, and I want to be very clear that we remain in full compliance with those sanctions. Therefore, not a whole lot is being done there other than our assets on the East Coast that are not included within the sanction restrictions. I'll tell you, that development has continued to perform exceptionally well. I mentioned in the prepared comments that we've got the next phase of development there with the Odoptu Stage 2 starting up by the end of the year, and it's moved remarkably well, and we've got a very strong co-venture there that supports our activities. In terms of Iraq, we are running generally consistent in terms of our production activities.
The key for Iraq will be ongoing investment to build up capacity for water injection to maintain reservoir pressure in these big, very large oil fields. We'll continue to invest to build that capacity commensurate with the availability of the required infrastructure. We'll just need to see how that plays out over time. We're actively involved with other co-ventures and the government to address the future requirements.
Thanks, Jeff.
You bet.
Our next participant is Phil Gresh with JPMorgan.
Hey, good morning, Jeff.
Morning, Phil.
First question, just on the capital spending, obviously was trending well below the full-year expectation in the first quarter. Maybe you could just give us a little bit of color about how you might expect that to progress through the year. Are there going to be significant ramps as we progress through the year? I guess specifically, I see that the U.S. number on E&P was actually down quarter-over-quarter. I know from the Analyst Day ramping shale is a big focus, maybe any color you could give on rig counts today and where you hope to be perhaps by year-end.
Yeah. Will do. Let me first talk about our CapEx. There really is no change right now, Phil, to our CapEx guidance. I will continue to emphasize that the organization has done a remarkable job in identifying and capturing capital efficiencies. I think that is a huge opportunity for value growth in the future. I think you saw that, if you recall, our actual spend last year was down materially versus our guidance, that was in part due to the organization's focus on this important area. $22 billion is still our guidance. If you remember in the analyst presentation, we gave a breakdown on how we plan to spend that and what key areas that we're planning to focus on. You mentioned the short cycle program, which I'll just remind is not only unconventional, but also a very significant component of the conventional work program.
If you look at our total rigs in the U.S. unconventional, they have gone from 13 in the fourth quarter, we're now up to 18 rigs. We are starting to ramp that activity. As I said in the prepared comments, in the Delaware acreage that we recently picked up, we've got a very concerted, focused effort, we should have a rig on site here soon, we'll continue to ramp up activity in that property.
Where might you hope to be in rig counts by year-end in order to achieve some of your production goals for the next one to two years?
Well, Phil Gresh, I really don't have a number to share with you on that, but I will tell you that as we signaled previously, our intent was to pick up in the order range of about 15 rigs in that Delaware acreage over time. Whether that happens by the end of the year or that happens later into the following year, I really can't go ahead and give you a more exact number. It will be a function of a number of factors. Remember, we are looking at this from a value chain perspective, and we're working all the elements to make sure that when we make the investment, that we can get that product all the way to the consumer.
Sure. Okay. Just my follow-up would be on the chemicals project. You mentioned the phase ramp as the year progresses. I guess what I'm wondering is maybe a little bit more color around when you might expect a full actual contribution from the cracker. Would you be thinking by early 2018 you might be up at a full run rate, or might it take a bit longer than that? Just any additional clarity.
Yeah. Let me say, first of all, just remind everybody that it's another one and a half million tons per annum of capability, and then corresponding derivative units to provide high-quality metallocene polyethylene products. The construction's been going extremely well. We expect that we'd be starting up the full facility by the end of the year into the next part of the year. There'll be some time to ramp up thereafter.
Okay, thanks, Jeff Woodbury.
You bet.
Our next question comes from Doug Terreson with Evercore ISI.
Good morning, Jeff and team.
Good morning, Doug.
I have a couple of questions on pay for performance per your new documents. First, when you consider that ExxonMobil's performance peers only posted a TSR of about a third or so of S&P 500 during the past decade, it seems like the bar could be higher for comparative purposes and that shareholders may be better served if it were. While you outperformed most of these companies, Jeff, my question is, how does the company think about the need to stretch the objective in this particular area as some of the peers have done?
Well, I think we have a very unique executive compensation program, Doug, as we've talked in the past.
Yeah.
With a large part of the compensation really at risk based on the corporation's performance, particularly on its stock performance. Just to remind everybody that our long-term performance is based on a five- and a 10-year vesting, and the 10-year is really the latter of 10 years or retirement. Therefore, some can go even beyond 10 years. It really does incentivize management to focus on our fundamental mission as a corporation, and that is to grow shareholder value.
That's right. Let's stay on that for a second because 'tis the season on pay for performance. During the past nine years, Rex was awarded, I think, around 225,000 shares every year, even though there was pretty significant variability in industry conditions, company performance, et cetera. My question on that, Jeff, is what is it in the compensation system that drives this apparent mismatch between low variability and the pay factor, or one of them that is, and high variability in industry and company outcomes? Meaning, is it as simple as following a heavy weighting in the part that align CEO pay with the compensation and performance peers, which is, I think, considered good corporate governance? Is it investment lead times or is it something else?
Either way, how do you expect this correlation between these variables to change in the future if you think that it will?
Well, Doug, I think I would just focus on ExxonMobil and the structure that we've put in place and how it has really proven over time.
Right.
If you look at the way the compensation committee considers this, there are seven key areas that we're thinking about.
They really focus on all of those areas in terms of deciding whether we have achieved first quartile performance. They're thinking about it over the investment lead times. We're not looking at the given year, we're looking at over a period of time. Particularly focused on the return on capital employed and our safety performance. That is what sets and determines whether the corporation has, or that the most senior executives have achieved first quartile performance, which then sets the award amounts. We think that that has worked extremely well, and it really does very much align the executives with that of the performance of shareholders. A very clear correlation that we have got to focus on that shareholder return as job number one.
Okay. You guys did a good job of laying it out this year, in my opinion. Thanks for that, Jeff. Thanks again.
You bet. Thank you.
Yeah.
We will now hear from Doug Leggate with Bank of America Merrill Lynch.
Thanks. Good morning, Jeff. Good morning, everybody. Jeff, I wonder if I could go back to the CapEx question. The $22 billion guidance for this year, does that include the acquisition in Mozambique?
Yes, it does.
Your actual CapEx, your organic CapEx then is obviously closer to $18.5 billion, $19 billion then. Is that right?
Yeah. It'd be the 22 minus the 2.8.
Yeah. Okay. Yeah, I can do the math. Thanks so much for that. I guess, just a related question then. Is 25% of Area 4 enough to do the things the Exxon way, meaning you typically bring in Qatargas as a partner, Golden Pass, I guess, being the most recent case in point. I guess you know where I'm going with this. Do you think Block 1 is necessary for you to move forward, or can you move forward with Area 4 as it stands? I've got a follow-up, please.
Well, listen, Doug, I understand the point of the question. Clearly, we did the deal with the expectation that we're going to move forward with co-ventures on Area 4, and we think it is an accretive opportunity to our overall value proposition given the diversity of our existing portfolio. As I mentioned, Doug, we also have what we consider is high potential exploration acreage that we're going to continue to progress. Standalone, as it is right now, the acquisition was premised on a very successful and competitive LNG development on Area 4.
Thanks for that. My follow-up is on Guyana, Jeff. If I heard you correct, you said you're planning a well test on Liza-4. I'm assuming that means Liza-4 spud 31st of March, if I understand correctly. Does that mean Liza-4, you're declaring that a success this morning? If so, can you give us an update on next steps as it relates to FID first oil? Because I think the license you applied for is second half of 2019 versus 2020. Just any color you can give on next steps would be great. Thanks.
The Liza-4 is still drilling, to be clear. Following the completion of that well, we would then go ahead and move into a test. As I said, the rig would then move over to Payara for the delineation well that will allow us to not only do the delineation of Payara, but also this deep exploration prospect. The well itself will be integrated, the results of the Liza-4 well will be integrated into our development planning activities that ultimately will inform a FID decision on the initial phase at Guyana.
No update on timing on FID?
I'm sorry. Say again, Doug.
No update on timing of a final investment decision?
Mid-year.
Mid-year. Okay. Thanks, Jeff.
Yeah.
Our next question comes from Evan Calio with Morgan Stanley.
Hi, good morning, Jeff.
Morning, Evan.
Normalizing your CapEx for the full-year run rate and taking out asset sales, you spent in line with distributed cash in the first quarter. You spent in line with cash during the first quarter when Brent averaged $54. Crude is lower. Clearly, investment sentiment is lower. You mentioned a cautious near-term crude outlook. Can you discuss the factors that the Board considered when raising the dividend, whether that's the balance sheet or the short cycle element or future margins? Just kind of give us some color to the raise against an increasingly gloomier outlook.
Well, I think the first thing I would say, Evan, is that it really does reflect the confidence that the Board and senior management has in the efficiency of the integrated business model. Recognizing that we're going to see peaks and valleys in a commodity-priced business, and that we have built the business to be durable in a low-price environment. It really talks to the business model at the start. The second point I would make is that we have clearly communicated through the years that a reliable and growing dividend is clearly the priority. Now, putting that aside as the, if you will, the backdrop to the decision, then it's looking forward and looking at the investment plans that we have and understanding how we're going to continue to grow value within the Corporation. I think it's all those factors.
Remember, when we're thinking about our investment planning, Evan, we're thinking about it consistent with a long-term view, a constructive view on supply and demand.
It's about making sure that we're comfortable that we're going to continue to generate, from our perspective, industry-leading returns and continue to grow value.
Great. That makes sense. My second question is on Guyana. TechnipFMC earlier this week announced that it won the Liza Phase 1 contract for trees, which was subsea trees, which was for 17 trees. I guess that's more than we would have expected given flow rate of wells and high reservoir quality. Does that higher number indicate any kind of potential upsizing for Phase 1 FPSO beyond 120,000 barrels a day? Or just any color on that, if you could?
Yeah, Evan, I'd say it's probably a little bit too premature to talk about it. We are on, as you can appreciate, if we're getting close to an FID by the middle of this year, we're getting pretty close to fully defining the scope of the development. There's still more work to be done, and we'll obviously share more of the specifics when we get to an FID decision. Right now I really don't want to get into the specifics of the analysis that is actually underway.
Great. Thought I'd give it a try. Thank you.
All right.
We will now hear from Paul Sankey with Wolfe Research.
Hi, Jeff.
Morning.
Jeff, could we go back to Mozambique, if we could? I've obviously heard what you've been saying about it, but could you just clarify the development? I think Eni had talked about floating LNG. I assume, obviously, that you're leading an onshore effort means that presumably that's the direction you're going to want to head in. Could you firstly just remind us why you bought into this reserve? Secondly, how you plan to develop it, especially as we're aware that you're not involved in the existing project onshore. Thanks.
Yeah. Well, the why is really because we see it as a very competitive, low cost of supply LNG source in the market. You think about some of the big greenfield developments that we've done historically and that we've participated in upfront in the development of Qatar, and we're very proud of the role that we played in helping the State of Qatar to meet their overall objectives and has evolved into the world's leader in LNG. Papua New Guinea, another big greenfield development that has been extremely successful and is a key competitive source of LNG in the market, and we see the same type of characteristics in Mozambique. That's why we see it as a very competitive LNG source. In terms of what the plans are, remember that there was a floating LNG concept that was being progressed by the current co-venturers.
It's called the Coral Floating LNG. That is still intended to move forward. The most significant part of the Mozambique development would be an onshore development, as I said in my prepared comments, with anticipated capacity up to 40 million tons per annum for Area 4.
Is that going to be your own standalone development, then, led by Exxon?
I'm sorry, the large development?
The onshore. Yeah, the 40 million tons.
Yeah. Let's be clear what's going on. The actual ownership is by an Eni affiliate that we've bought into. The operator is Eni East Africa. The leadership will be provided by ExxonMobil on the onshore LNG facilities and Eni on the offshore facilities.
Forgive me, I looked at the financial annual that you put out recently. In the Mozambique section, I can't see. Do you have an onshore position, land or site?
It's being worked with the government concurrently.
Okay, that's not yet the case, but it's underway. Understood. What's the best guess, Jeff, for when this thing might actually be final investment decision and producing gas?
Yeah, I really have nothing to share with you at this point. I think what's important right now, Paul, is that we get the regulatory approvals and then working with the co-venturers to really optimize the development, and we'll have a better handle on that once we get past those milestones.
Great. Thank you, Jeff.
Okay.
Our next question comes from Ed Westlake with Credit Suisse.
Yeah, good morning. I think it's going to be a LNG focus this morning given that Mozambique slide. Is there any change in LNG pricing approach, or I guess, contracting approach? Obviously, Europe has got a big spot market that cargos can be put into. Are you still thinking of the conventional way, where you basically sign up heads of agreement and then contracts with long-term offtakers before launching an FID? The reason I ask is that there is a number of competing LNG schemes which will try and hit that sort of 2023, 2024 mismatch between supply and demand for LNG. Just trying to see how flexible you'll be to make sure these projects get in that first window.
Yeah, Ed, it's a really good question. First point I'd make is, given our success in Qatar and Papua New Guinea, we have built a tremendous amount of market credibility with the customers. We have an operational center that we set up in Singapore in order to provide the customers all the support they need. Fundamentally, our objective will be to enter into long-term contracts that will underpin the investment. Now, the commercial structure of that continues to evolve. I would tell you the commercial structure will be such that it will certainly underpin the substantial investments required for these LNG projects.
Okay. On Guyana, more about timing. Obviously, you have your rig, and it's going to be exciting to see how big Liza and then Payara could be with these appraisals. At the Analyst Day, you did walk through a number of other prospects that were being matured. I'm just wondering how many of those do you think would be drill ready for when the rig is freed up in a few months on Payara, say through the end of 2018. Wildcats.
Yeah. I tell you, Ed, this is job number one for our folks in exploration is making sure they're staying well ahead of the rig, maturing the prospects to get them to a drillable stage. I'll just remind you that it's not only the Stabroek Block, but it's also Kaieteur and Canje That we're real time integrating the 3D seismic. We're taking the well results that we've got from the Stabroek Block program to date, and we're real time assessing the highest potential, and by definition, they're staying well ahead of the rig line.
Good luck with the drilling time of one month. That's got to be some fast work.
Well, I tell you, I will give some credit to the drillers and the well site team and the contractor. We have had just remarkable results on the program in Guyana.
Thank you.
We will now hear from Blake Fernandez with Howard Weil.
Jeff, good morning. I had two questions for you. Maybe I can just ask both. The first is on oil sands. Many of your peers have been minimizing their footprint, and I was just curious if you could comment on your appetite to maintain your existing position there. Then the second, forgive me, it's a little bit detailed, but on the buybacks, I see that you were just repurchasing to offset dilution, but that number in the quarter struck me as fairly large, $500 million, where I think last year you did just under $1 billion for the full year. Is there anything from a timing standpoint or one-off that kind of inflated that dilution in 1Q where we should think that kind of normalize going forward? Thanks a bunch.
On the oil sands, let me step back a little bit and just remind everybody that we've been working on the oil sands for over three decades now. With that, we've maintained a very focused technology program. I'd start off on the mining side with Kearl, which was unique in its own right because of we were able, through technology application, to avoid the investment and the environmental footprint associated with an upgrader. As we said during the analyst presentation, we have continued to work on the cost side and have substantially reduced the overall cost in that operation. Remember, long life assets, a long source of cash flow for us, and like we have always done with all of our assets, we will continue to be working towards enhancing the value of it.
On the oil sand side, our long history in Cold Lake, and then looking at how we step the technology out further to not only enhance recovery, but also lower cost and lower the environmental footprint. We're looking at some new technology on SA-SAGD that we think will take us to that next step. As you may recall, Blake, we've got a very large oil sands portfolio, and we like what we've got, and we'll continue to look for ways to make it even more valuable in the future.
Okay. The buyback, the dilution?
I tell you, the buyback, clearly it varies over time. If you look over history, there's variability with respect to that dilution, and it's fairly in line with over a reasonable length of time. There's really nothing more I can share about it. It's clearly defined as our intent to avoid dilution on our shareholders.
Fair enough. Thank you.
Our next question comes from Roger Read with Wells Fargo.
Yeah, good morning, Jeff.
Morning, Roger.
To follow up a little bit on Blake's question there on the share repos and guidance not to do any more than offset dilution Q2. You did outperform on cash flow in the quarter, especially with the lower CapEx. What should we be looking for? What do you think execs on the board are looking for in terms of the confidence? Is it oil prices? Is it mostly just Exxon internally focused, a combo of the two? Just curious what would bring you back to that confidence to buy back shares.
Well, despite the macro volatility, which frankly we have lived within for over 130 years, we're going to ensure that the business model is durable regardless. It's then looking back about the value growth proposition that we've been able to put in place and how that has ultimately added back into further financial capability than what we currently have. It's the same variables that we've discussed previously about how we decide whether to move forward with a buyback or not, and that decision's made on a quarterly basis. We'll consider things like the company's current financial position, our near term CapEx requirements, our dividend requirements, as well as the near term business outlook. It's part of our capital allocation, Roger. The decision at this point will be one of deciding to put the cash to work either through a buyback or reducing our debt load.
Okay, thanks. Then you mentioned earlier the idea of a 15-rig target in the Delaware Basin, a spread between when we could expect that. What do you see as the main levers that we should be watching to get pulled or need to see in the market to reach that target sooner or later?
Well, again, we'll be thinking about it from a long term. We made a substantial acquisition, that acquisition had assumed a certain amount of activity. If we have true confidence in, one, our business model, and two, our energy outlook, we'll go ahead and deliver on that activity level and ramp up. We see unique value that we're going to bring to that Permian acreage. As we said back when we consummated the transaction, we believe that we're going to demonstrate that we are going to be industry leading in terms of overall unit development cost and overall return on investment given the unique aspects of it. That being, as I said previously, the contiguous nature of it and the ability for us to bring our value chain perspective.
Sorry, just if I could follow up real quick on that. The decision to expand the downstream along the Gulf Coast obviously was tied into that. In terms of the timing of developing the Delaware Basin, is some of the focus on supplying your downstream, or is that two separate items, two separate decisions?
Well, I'd say on a macro level, it's one and the same. We're thinking about, we participate across the full value chain. When you get into the specifics, I wouldn't necessarily say that they were connected.
Okay. Thank you.
Okay.
Our next participant is Jason Gammel with Jefferies.
Thanks. Hi, Jeff. Jeff, I just wanted to ask about how you see the role of the exploration program for the Corporation currently. Many of your peers have really cut back activity levels, and even your own spending has essentially fallen in half, at least in 2016, relative to where it had been in previous years. You're also talking about fairly significant restocking of the portfolio, and have had some pretty clear success in Guyana. Is this an area where you see Exxon perhaps being able to distinguish itself from peers in the near term?
Yeah. The short answer is yes. I would tell you that, as I said previously, a key aspect of the exploration program is to target resource opportunities that will, from a value perspective, upgrade our existing portfolio. That is exactly what we're doing. We want the exploration folks to know that whatever they discover, the objective is that gets to the top of our portfolio and brings unique value to the Corporation. Yes, we did slow down some of the exploration activities, but I'd say that we maintained a very healthy program in the down cycle. Last year, we shot the largest seismic acquisition program that we've done historically at a lower cost because of the market conditions. I think it was over 60,000 square kilometers of seismic in 2016. A very successful outcome.
You think about the Guyana discovery or discoveries and the acreage capture that we've been able to pick up here in some really high potential, unique opportunities. I think it really talks to how our exploration company and the organization, how it has really contributed to not only the current but the future success of the Corporation.
Appreciate that, Jeff. If I could just follow up. A lot of what you're doing in exploration, and indeed what you've added in Mozambique, is targeting deep water areas. Is this a function of Exxon believing that deep water can still be competitive if you have the right resource, or is this really just a function of the opportunities that were available to you at the time?
Let me start first that our program is primarily focused in two key areas. The first one is high potential unexplored areas that, as I said a moment ago, that really could compete with high grading the portfolio, like Guyana. The second area is where we see material potential near existing infrastructure, like the Gulf of Mexico, like Canada East, where we've picked up a lot of acreage by our Hebron and Hibernia facilities. That is really what sets up the framework of our exploration program. I would say that as it relates to deep water, that we do believe that given the right quality resource and given the progress that we have made on reducing the cost associated with our development programs, that we do see deep waters being competitive.
That's very helpful. Thanks, Jeff.
Okay.
We will now hear from Paul Cheng with Barclays.
Hey, guys. Good morning.
Hi.
Jeff, two quick questions. First, the asset sale proceeds is about $700 million for the quarter. Can you share with us what's the asset sales gain and how that's split between different divisions?
As you said, it's just under $700 million in gross proceeds, and the earnings impact on the quarter was about $230 million. About half of it in upstream and half in the downstream.
Okay. Secondly, that you recently joined force with SABIC on the chemical to build a new chemical site, I think in Corpus Christi. In the U.S., given that you have such a commanding and well-established operation in chemical, just curious that what's the rationale behind that you don't go ahead on your own, and that instead of using a joint venture structure, given that it's always a little bit more challenging than when you're trying to manage a joint venture over time. What exactly you expect that is going to bring it to you that you decide not to go ahead and just do it on your own?
No, I think it's a good question, Paul. Each one of these transactions are unique in their own right. We have a very long, well-established, and successful partnership with SABIC, and this is something that in our broader business dealings, both parties wanted to do, and we saw that this was a good opportunity, a good means to achieving that. As you know, the current expansion on ethylene capacity and corresponding polyethylene at Baytown and Mont Belvieu is 100% ExxonMobil. As part of our long strategic relationship with SABIC, we decided to enter into a joint venture with them to pursue this possible steam cracker in the Gulf Coast.
Should we read that into that, or maybe it is just too much that in the future expansion in the U.S., that will be the path that you take, or that this is really just one-off?
It'll be dependent on the circumstances. This one, as I said, there were strategic reasons for doing it. It made good sense. We had a very good, long-established relationship in Saudi Arabia with SABIC. We think this is the right thing to do, but I wouldn't read anything specific into it.
Right. Thank you.
You're welcome.
Our next question comes from Ryan Todd with Deutsche Bank.
Great. Thanks, Jeff. Maybe just a couple of follow-ups. One on Liza. As you get ready for FID, any high-level thoughts you can share on drivers for the cost structure for the field? I think, both specific drivers that are specific to Liza in terms of driving down a lower cost structure, then maybe what you're seeing on a broader, specific things from the broader cost structure in terms of developing these types of projects, in terms of cost deflation, in terms of how we can think about the potential cost of the project.
Yeah. It's a good question when you think about the full scope of our development in Guyana. Clearly, the higher the resource density, the more profitable it's going to be. It starts with the resource, then it goes to the focus on the design. We really would like to get very much in the mode of designing one and building many, like we did in Angola. Get in a routine of really working in optimal design and then replicating that as you continue to expand resources through your exploration program.
Any thoughts in terms of as you're close here, the cost deflation that you've seen across those types of product lines in terms of relative to where we were a few years ago?
Well, that's a specific focus area for us. If you look back at our analyst presentation, if you look at a pool of projects that we've been working on and from a development planning perspective and take us to current day on those projects, we've seen about a 30% cost reduction. That's through a lot of the development planning, the design work, the scope reduction or scope optimization that we've been doing. A very substantial reduction over the last several years in terms of what we anticipate these assets are going to cost.
Okay, thanks. Then maybe just one follow-up. You've been active so far in asset acquisitions on everything ranging from international gas to domestic U.S. onshore oil. Any thoughts on where you're seeing greater value these days? International conventional style assets versus U.S. onshore, and whether you continue to see a high level of interesting opportunities globally?
Ryan, I don't think I would focus on any one asset type or geography. As I have said previously, we will keep alert to opportunities around the globe, whether it be in the upstream or the downstream or chemical business. We'll evaluate those specific opportunities on their own merits. Remember, our objective here is, once again, to acquire assets that will compete with our existing portfolio. We're looking for opportunities that we can see accretive value to. That's how I would characterize it. We've had a number of transactions, as you're aware of, and we keep our eyes open, and I think that's another indication of the strength of the corporation, that we've got the financial flexibility to pursue those opportunities when they come up.
Great. Thank you.
You're welcome.
We will now hear from Theepan Jothilingam with Exane BNP.
Yeah. Hi. Morning, Jeff Woodbury. Just a couple of follow-up questions, actually. Firstly, just a comment on sort of your investment plans. I think you talked about 2017 including Mozambique. I was just wondering, when you look at the guidance from the analyst day for 2018 to 2020 and the $70 billion-$80 billion there, I was just wondering how much in there is sort of assumed for inorganic spend. The second question, I think characteristic of these results, the Q1, has been sort of the lower operating expense from Exxon across multiple businesses. I was just wondering how much more do you think there is to go from an internal perspective through 2017, 2018? Thank you.
Yeah. Well, InterOil, I guess the first point I'd make on the investment program is that if it was not already in progress, there's really nothing in the forward investment plan. Goes back to my last comment that we've got that financial flexibility to pursue acquisitions if we think they are value accretive. There's nothing really I can highlight for you on the forward 2018 to 2020 investment program that we shared in the analyst presentation. Looking at our cost structure, the first thing I would say is that I'm always very much amazed with the success the organization is able to achieve with finding more innovative solutions. I want to be really clear. This is not just squeezing the margins on the service sector. This is working with the service sector to find lower cost, innovative alternatives to allow for this work to get done.
I think that relationship, that collaboration has been a key to success that we've been able to achieve. I will tell you that from our perspective, we believe we're never done on driving that cost structure. As I said, the organization continues to identify new opportunities to lower that cost structure while maintaining and enhancing operational integrity. I'm not going to put a specific target out there, but the role of the organization is one, to really identify and capture the lowest life cycle cost. It starts with the exploration program. It goes into our development program, getting a lower unit development cost, and then it goes into the production organization to find ways to drive that cost structure down.
Okay, great. Thank you.
You're welcome.
Our next question comes from Iain Reid with Macquarie.
Hi, Jeff. Couple of questions from me. Just firstly, philosophically, it looks like Exxon is at the sort of level in terms of oil and gas prices where your free cash flow is pretty much equivalent to your dividends. I just wonder how that makes Exxon management feel about maybe accelerating the pace of growth in terms of potentially more acquisitions or spending a bit more in terms of CapEx. Just, is this the kind of level at which we could see as somewhat of an inflection in terms of the pace of Exxon's investment plans? I've got a follow-up after that.
Iain, I guess the first point I'd make is that, as I said, our free cash flow was $4.4 billion. Our dividends were $3.1 billion. We had excess of $1.3 billion. To remind you that we also funded this escrow account for the InterOil transaction of $1.7 billion. Round numbers, about $3 billion excess cash. I think, again, it really speaks to the effectiveness of our business model. Now, going back to the point around the pace of our investment program, that pace is going to be driven by value optimization. It is going to be driven by our ability to get our portfolio to a place where we think we have the optimal value and we're ready to move forward. It's not a constraint by the balance sheet or the amount of cash that we're generating at this point.
To be transparent, we do step back and we look at the macro and we look at the near-term period to make sure that we retain that financial flexibility. We're not going to forego opportunities. If we think that we see one in terms of additional acreage to pick up or an acquisition or a unique opportunity to go ahead and progress investments in a lower cost structure or in other arrangements, then we're going to proceed with it, and we've got that capability to move when it's appropriate.
That brings me on to my second question. You've used your shares for two of the major transactions which you completed in the quarter, or at least announced in the quarter. That seems to me a very obvious thing to do given the rating which your shares trade on, certainly relative to your peers. Is that your favored method of transacting when you're buying assets? What advantage do you think that gives you over using cash? And in terms of this dilution, which you talked about earlier about buying back the dilution, do you intend as a priority to buy back the dilution which you're creating by using your shares as an acquisition currency?
There's a couple elements in that. The first point I'd make is that we have the flexibility to do either. The final structure of that transaction will be a function of the dialogue between buyer and seller. As you know, the last three transactions, one was cash, two were stock. We've got the capability to do either, and I wouldn't read anything into it in terms of a preferred approach. The second point is on dilution. Since the merger of Exxon and Mobil around 2000, we have bought back about 40% of outstanding shares. It's a tremendous progress when you think about it over the years, and that is one of the things that we believe is a tax efficient way to distribute excess cash to our shareholders
Okay, thanks, Jeff.
You're welcome, Iain.
We will now hear from Anish Kapadia with TPH.
Hi, Jeff. My first question is, just thinking back over the last few years, it doesn't seem like you've FID-ed a major upstream project in the last three years through the down cycle. I suppose you haven't seen the counter-cyclical investment coming through from Exxon that maybe some would have expected. Can you just talk about the reasons behind the lack of FIDs over the last few years? Was it waiting for costs to come down? Is it the project queue that you've got? How could that change going forward?
Yeah. Anish, the first point, just make sure everybody understands that in 2016, we did have six FIDs. We had two in the upstream, two in the downstream, and two in the chemical. Probably the biggest one in the upstream was the Tengiz expansion. We have announced two FIDs in 2017, both in the downstream at this point. I would tell you that there were several factors that play into the pace of our FIDs. One obviously being the ability to make sure that we're comfortable that we've gotten all the value out of the opportunity. Particularly when you're in a down cycle, there are opportunities to step back and look at, are there other ways now in the current business climate that we can go ahead and generate more value from it? We've done exactly that.
As I said a moment ago, over the last several years, the projects that have been closer to FIDs, we've been able to get about 30% out of the cost. It's a very keen sense of have we fully optimized the value proposition for these investments? When we get to that point, we've got the financial flexibility to move forward, and we want to make sure that these investments, as we always have historically, are durable in a low price environment. I think that will really set the pace going forward.
To follow up, maybe just drilling down a little bit more into that, specifically in West Africa, because when I look at Nigeria, there's been a number of projects that you've had on the books for a long time in that pre-FID category that don't seem to have made much progress. I think in your latest financial operating review, we've seen some projects disappear out, like the Uge development. I think the satellite field development capacity has been cut down. I'm just wondering in terms of Nigeria, is it the costs that still are a problem? Is it the politics? Just wanted to get a little bit of an update on how things are going there.
Well, you're really touching on another element of pace, and that is making sure that we've got certain stability within our commercial structure and that all the partners have the capability to go move forward and fund these projects. Just to make sure the record is clear, over the last five years, we have had four startups, Erha, North Phase Twos, the satellite field development, Phase I, Usan. We've had a number of startups. There are a number, as you point out appropriately, that are on the development planning exercise, and that'll be a function of some of these variables locking up. We need to make sure that not only have we optimized the design, but that the co-ventures are all ready to move forward and that we have a very clear view of the fiscal stability.
Great. Thank you.
You're welcome.
Our next participant is Pavel Molchanov with Raymond James.
Thanks for taking the question, guys. A quick one about Guyana. Given that you're going to be one of the very few operators anywhere in the world to reach FID in 2017, can you just talk directionally about how the supplier contracting process has been as you've been approaching project sanction in terms of cost, competitiveness, et cetera?
Yeah, Pavel, as I've talked to, we work very closely with our contractors, our service providers to identify win-win outcomes to ensure that we've got the optimal development scope defined, that has continued to work extremely well. I think everybody's really excited about the opportunity at Guyana, there's a lot of enthusiasm moving forward. With that comes a lot of good thoughts and innovation. Specifically in terms of cost, I'd only point to the progress that we've made that we shared at the analyst presentation, that we've reduced the cost structure by about 30% in a suite of projects that we're progressing.
Okay. Just a quick housekeeping item about African liquids. That was the steepest decline in your portfolio year-over-year in Q1, down 25%. Is that Nigerian disruptions or other culprits behind that?
I think you're referring to, I guess, both sequentially and quarter-on-quarter, it was due to entitlements and downtime.
Okay. Any particular country?
Entitlements, they're all PSC.
Yep
the downtime, which is primarily in Nigeria.
Okay, clear enough. Thank you.
You're welcome.
We have time for one final question. We will hear from Jon Rigby with Societe Generale.
Yes, thank you. Jeff, in terms of your short cycle activity, the industry is obviously ramping up greatly. You're now more exposed in the Permian. What are you seeing in terms of cost inflation for the kind of projects you're pursuing for the short cycle time, and is it something that you feel you'll be able to manage effectively?
Good morning, Jon. I would tell you that, broadly speaking, that the inflationary pressures that we've seen year-to-date are really fully offset by the efficiencies we've been able to capture. Clearly, as the activity picks up, there are going to be some cost pressures, I can tell you that the organization is very focused on making sure that we drive those costs down. I'll refer you to a couple of presentations that we've shown on that. The last one being in the analyst presentation, where we showed the Permian cost reduction we've been able to achieve over the last couple of years of about 46% on our field and 72% on the development cost. We fully expect that the organization is going to continue to find ways to offset any type of cost pressures.
Great. Thanks. That's it for me.
I think the only other point I'd add to you, Jon, is that as you see activity pick up, the key will be also maintaining a really strong efficiency and execution.
Agreed.
That concludes our question and answer session for today. I would like to turn the call back over to Mr. Woodbury for any closing remarks.
Well, to conclude, again, I'd like to thank you for your time and the very thoughtful questions this morning. I want to say that we do appreciate the trust our shareholders place in ExxonMobil, and we look forward to talking to you all in the future. Thank you.
That concludes the call for today. Thank you for your participation. You may now disconnect.