Exxon Mobil Corp (XOM) — Q1 2017 Earnings Call Transcript

Thank you. Ladies and gentlemen, good morning, and welcome to ExxonMobil's first quarter earnings call. The comments this morning will refer to the slides that are available through the Investors section of our website. So before we go further, I'd like to draw your attention to our cautionary statement shown on slide 2. Turning now to slide 3, 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 4, 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 5. 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 million. A debt of $43.6 billion net debt, which is debt less cash, declined in the quarter. Debt 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 for the escrow account. Now, this impact is temporary, as ExxonMobil acquired a receivable as part of the InterOil deal, which is expected to more than cover the contingent resource payment. The next slide provides additional detail on sources and uses of cash. So 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 repurchases 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 7 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 the sequential quarter comparison shown on slide 8, absent the fourth quarter 2016 Upstream impairment charge, earnings increased over $300 million due to strong 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 and $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 9. 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. So moving now to slide 10, oil equipment 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 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. Our realizations contributed $570 million of earnings. Crude prices increased nearly $3 per barrel and 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 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. Now this was partially offset by lower operating costs and the absence of unfavorable fourth quarter inventory impacts. Moving now to Chemical financial and 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 and 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 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 startup timing accordingly. Now 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 3-D seismic survey which was completed in November of last year. We look forward to finalizing discussions with the government of Mozambique on PSEs 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-venturers 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 2. 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, and the chemical expansion project at Baytown and Mont Belvieu will begin phased startup in the second half of the year. In other recent developments, in Australia, Train Three at Gorgon-Jansz 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 and we'll 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 current 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. And 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 3-D seismic data and drill two exploration wells, with the first well anticipated in 2018. I'll note this block is near the recent Zora 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 plans at 4.2 million oil equivalent barrels per day. Total CapEx was $4.2 billion, a decrease of 19% from the prior quarter. The 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, and I would now be very happy to take your questions.

Morning, Jeff. How are you?

Good morning, Brad. I'm doing well. How are you?

Good, good. Thanks. So a couple of questions on LNG. Obviously that and Mozambique now – that goes into a really long LNG queue, so you've got P&G, 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. So to start off, as you know, we have gas growing from 2015 to 2014 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%. So there is 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 requires a supply response. So as you highlighted, Brad, moving into your second – 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 Papua New Guinea or the Golden Pass. And then others are more large greenfield developments like Mozambique. Each of them has unique characteristics that we're going to try to place them in the market, but 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. And then 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, I'm specifically thinking about Coral and how you feel about the floating LNG plan there.

Yes. 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-venturers and have discussions. But the current plan is that coral will progress.

Okay. Thanks, Jeff.

Good morning, Jeff.

Good morning, Neil.

Jeff, 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? We appreciate your views on OPEC/non-OPEC in demand.

Yes. That's a good question. Clearly, I would say that the macro would still indicate, from an ExxonMobil 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, and 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 to round numbers about 800,000 barrels a day on trend to maybe 1 million barrels a day over a 12-month period. So 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, OPEC has generally met their commitments. A little bit short, but they are demonstrating a level of compliance. But when you step back and look at the supply side, I think is the biggest issue in front of us, and that would be a function of so many elements, including the North American response I talked about, but also economic growth and other variables. Remember, we still have round numbers about 600 million barrels in storage, and depending on what near-term prices do, that's going to come out at some point. So a lot of variables to think about, and that's what really underpins my comment about just being cautious.

I appreciate that, Jeff. And the follow-up is that, just want to talk about your long-term growth aspirations in two regions that don't always get a ton of attention. And the first would be Iraq and the second would be Russia. Any comments on either of those, it would be helpful.

Yeah, let me start with Russia. I mean, as everybody clearly knows that the sanctions remain in place, and that I want to be very clear that we remain in full compliance with those sanctions. And 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. And 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, very strong co-venturer there that supports our activities. In terms of Iraq, we are running generally consistent in terms of our production activities. I mean, 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 and we'll just need to see how that plays out over time. We're actively involved with other co-venturers and the government to address the future requirements.

Thanks, Jeff.

Hey. Good morning, Jeff.

Morning, Phil.

So, 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 for the year. Are there going to be significant ramps as we progress through the year? And I guess, specifically, I see that the U.S. number on E&P was actually down quarter-over-quarter and I know from the Analyst Day, ramping shales is a big focus; so maybe any color you can give on rig count today and where you hope to be, perhaps, by year-end.

Yes. Will do. Let me first talk about our CapEx. I mean 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 mean, 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 and that was, in part, due to the organization's focus on this important area. So $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 a conventional work program. But if you look at our total rigs in the U.S. unconventional, they have gone from 13 in the fourth quarter and we're now up to 18 rigs. So 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 focus to this effort and we should have a rig on site here soon and we'll continue to ramp up activity in that property.

And 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, I don't really 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 of magnitude, 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. But 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 on all the elements to make sure that we can, when we make the investment, that we can get that product all the way to the consumer.

Sure, okay. And just my follow-up would be on the chemicals project. You mentioned the phased 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.

Yes. Let me say, first of all, just to remind everybody that it's another 1.5 million tons per annum of capability and then corresponding derivative units to provide high-quality calcium polyethylene products. The construction has 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, so there will be some time to ramp up thereafter.

Okay. Thanks, Jeff.

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. And 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, 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 5-, and a 10-year vesting, and the 10-year is really the latter of 10 years or retirement. So therefore, some can go even beyond 10 years. So it really does incentivize management to focus on our fundamental mission as a corporation and that is to grow shareholder value.

That's right. And so let's stay on that for a second because it is the season on pay-for-performance, and during the past nine years, Rex was awarded I think around 225,000 shares every year, even though there was pretty insignificant variability in industry conditions, company performance, et cetera. So 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 the industry and company outcomes? Meaning, is it as simple as following a heavy weighting on the part that aligns 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? Or 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 mean 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. If you look at the way the Compensation Committee considers this, there are seven key areas that we're thinking about and they really focus on all of those areas in terms of deciding whether we have achieved first quartile performance. And they're thinking about it over the investment lead times, so we're not looking at the given year, we're looking at it over a period of time, and particularly focused on the return on capital employed and our safety performance. And that is what sets and determines whether the corporation is, or that the most senior executives have achieved first quartile performance, which then sets the award amounts. And we think that that is working extremely well and it really does very much align the executives with that of the performance of shareholders. I mean, a very clear correlation that we have got to focus on that shareholder return as job number one.

Okay. And you guys did a good job of laying it out this year in my opinion. So thanks for that, Jeff, and thanks again.

You bet. Thank you.

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.

So your actual CapEx, your organic CapEx then is obviously closer to $18.5 billion, $19 billion then. Is that right?

Yes. Well, it'd be the $22 billion minus the $2.8 billion.

Yes, okay. Yes, I can do the math. Thanks so much for that. Well, I guess just a related question, then. Is 25% of Block 4 enough to do things the Exxon way? Meaning, you typically bring in Qatargas as a partner, Golden Pass, I guess being the most recent case in point, and 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 Block 4 as it stands? And I've got a follow-up, please.

Yes. Well listen, I mean, Doug, I mean I understand the point of the question. Clearly, we did the deal with the expectation that we're going to move forward with co-venturers on Area 4, and we think it's 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 as high-potential exploration acreage that we're going to continue to progress. So, I mean 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 was spud 31st of March, if I understand correctly. Does that mean Liza-4, you're declaring that a success this morning? And 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? And just any color you can give on next steps would be great. Thanks.

Yes. So 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, and 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 in 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.

So, no update on timing on FID?

I'm sorry. Say again, Doug?

No updating on timing of a final investment decision?

Midyear.

Midyear. Okay. Thanks, Jeff.

Hi. Good morning, Jeff.

Morning, Evan.

So 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, sorry, in the first quarter. Went for an average $54. Crude is lower. Clearly, investment sentiment is lower. You mentioned a cautious near-term crude outlook, but 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 delays 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. So, I mean it really talks to the business model at the start. The second point I would make is that we have thoroughly communicated through the years that a reliable and growing dividend is clearly the priority. Now putting that aside as, 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. So I think it's all those factors. And 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. So 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. And my second question is on Guyana. I know Technip earlier this week announced that it won some Liza Phase I 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 I FPSO beyond 120,000 barrels a day? Just any color on that, if you could.

Yes, Evan. I'd say it's probably a little bit too premature to talk about. I mean 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, and there's still more work to be done, and we'll obviously share more of the specifics when we get to an FID decision. But 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.

Hi, Jeff. 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 that 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 that we see it as a very competitive low cost to 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. And so 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. And then 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?

Yes. Let's be clear what's going on. So the actual ownership is by a Eni affiliate that we bought into. So the operator is Eni East Africa. The leadership will be provided by ExxonMobil on the onshore LNG facilities and Eni on the onshore 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. So that's not yet the case, but it's underway. Understood. And what's the best guess, Jeff, for when this thing might actually be final investment decision and producing gas?

Yes. 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.

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 cargoes 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 off-takers before launching an FID? The reason I ask is that there is a number of competing LNG schemes which will try and hit that 2023-2024 mismatch between supply and demand for LNG. So just trying to see how flexible you'll be to make sure these projects get in that first window.

Yes, Ed. It's a really good question. I mean, first point I'd make is given our success in Qatar and Papua New Guinea, I mean, 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. So I think the first message there is one of being able to go out and interface with the customers, meet their needs, but fundamentally, our objective will be to enter into long-term contracts that will underpin the investment. And the commercial structure of that continues to evolve. But I would tell you the commercial structure will be such that it will certainly underpin the substantial investments required for these LNG projects.

Okay. And then on Guyana, more about timing. I mean, 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? Wild guess.

Yes. I mean, I'll tell you, Ed, this is job number one for our folks in exploration is making sure that they are 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 Canje and Kaieteur that we're real-time integrating the 3-D 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 they're staying, by definition, they're staying well ahead of the rig line.

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 and that has continued to work extremely well. I think everybody is really excited about the opportunity in Guyana and I think there's a lot of enthusiasm moving forward, and with that comes a lot of good thoughts and innovation. So 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 the suite of projects that we're progressing.

Okay. And then, 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?

Yeah, 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?

Well, I mean entitlements, they're all PSC, and in the downtime, it's primarily in Nigeria.

Yeah, yes, thank you. Jeff, in terms of your short cycle activity, the industry is obviously ramping up creatively. 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?

Yeah, good morning, John. 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, but I can tell you that the organization is very focused on making sure that we drive those costs down. And 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, and 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, John, is that as you see activity pick up, the key will be also maintaining really strong efficiency and execution, so.

Well, to conclude, again, I'd like to thank you for your time and the very thoughtful questions this morning. And 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.