Earnings Call: Q1 2014

May 1, 2014

Summary

Q1 earnings were $9.1B, supported by upstream growth, while downstream and chemical earnings declined YoY. Cash flow reached $16.2B, and FY production and capital-spending outlooks were maintained.

Good day, everyone, and welcome to this ExxonMobil Corporation first quarter 2014 earnings conference call. Today's call is being recorded. At this time, for opening remarks, I would like to turn the call over to Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. Good morning, and welcome to ExxonMobil's first quarter earnings call and webcast. The focus of this call is ExxonMobil's financial and operating results for the first quarter. I will refer to the slides that are available through the investor section of our website. Before we go further, I would like to draw your attention to our cautionary statement shown on slide 2. Moving to slide 3, we provide an overview of some of the external factors impacting our results. Global economic growth continued at a modest pace in the first quarter, with mixed performance across the regions. The U.S. economy grew moderately despite the adverse effects of severe winter weather conditions. China's growth rate has flattened, while the economies of Europe and Japan improved modestly. Energy markets delivered mixed results. WTI prices increased, narrowing the discount to Brent, as the global marker decreased in the quarter. Western Canadian Select prices increased significantly. North American natural gas prices were also significantly higher. Global industry refining margins were essentially flat, while chemical commodity product margins were stronger during the quarter. Turning now to the financial results as shown on slide 4, ExxonMobil's first quarter earnings were $9.1 billion, or $2.10 per share. The corporation distributed $5.7 billion to shareholders in the quarter through dividends and our share repurchase program. Share purchases to reduce shares outstanding were $3 billion in the quarter. CapEx was $8.4 billion. Cash flow from operations and asset sales was $16.2 billion, including proceeds associated with asset sales of $1.1 billion. At the end of the quarter, cash totaled $5.8 billion and debt was $21.4 billion. The next slide provides additional detail on first quarter sources and uses of funds. Over the quarter, cash increased by $900 million from $4.9 billion to $5.8 billion. Earnings, depreciation expense, changes in working capital and other items, and our ongoing asset management program yielded $16.2 billion of cash flow from operations and asset sales. Uses included additions to property, plant, and equipment of $7.3 billion and shareholder distributions of $5.7 billion. Additional financing and investing activities decreased cash by $2.3 billion, including a reduction in debt of just over $1 billion. Yesterday, the board of directors declared a cash dividend of $0.69 per share, a 9.5% increase from last quarter. Share purchases to reduce shares outstanding are expected to be $3 billion in the second quarter of 2014. Moving on to slide 6 and a review of our segmented results. ExxonMobil's first quarter earnings of $9.1 billion decreased by $400 million from the first quarter of 2013. Lower downstream and chemical earnings, as well as higher corporate and financing expenses, were partly offset by higher upstream earnings. In the sequential quarter comparison shown on slide seven, earnings increased by $750 million as higher upstream and chemical earnings were partly offset by lower downstream earnings and higher corporate and financing expenses. Guidance for corporate and financing expenses remains at $500 million-$700 million per quarter. Turning now to the upstream financial and operating results and starting on slide eight. Upstream earnings in the first quarter were $7.8 billion, an increase of $746 million versus the first quarter of 2013. Realizations increased earnings by $410 million, primarily driven by higher U.S. natural gas realizations. On a worldwide basis, natural gas realizations increased $0.31 per thousand cubic feet, while crude oil realizations decreased by $4.09 per barrel. Volume and mix effects increased earnings by a net $20 million. This included a favorable liquids mix effect of about $300 million, reflecting increased volumes in Canada, Russia, and West Africa, as well as the minimal financial impact related to the Abu Dhabi onshore concession expiry. A positive liquids effect was mostly offset by lower natural gas volumes, primarily due to warmer weather in Europe. All other items increased earnings by $320 million, mainly due to gains related to asset sales. Moving to slide nine. Excluding the impact of the Abu Dhabi onshore concession expiry, oil equivalent production decreased by 2.9% compared to the first quarter of last year. Liquids production was up 73,000 barrels per day, or 3.3%. As the ramp up at Kearl and lower downtime in several countries, more than offset price and spend impacts, divestments, and decline. Natural gas production was down 1.2 billion cubic feet per day, primarily due to lower weather-related demand in Europe. Turning now to the sequential comparison, starting on slide 10. Upstream earnings increased $1 billion versus the fourth quarter. Realizations had a positive impact of $540 million, as worldwide natural gas realizations increased $0.84 per thousand cubic feet, and crude realizations were essentially flat. Volume and mix effects increased earnings by $650 million. This included a substantial positive liquids mix effect associated with increased volumes in Qatar, Kearl, and West Africa, as well as a net overlift, and including the minimal financial impact related to the Abu Dhabi onshore concession expiry. The positive volumes earnings factor also reflects higher natural gas volumes in Qatar. All other items had a negative impact of $190 million. Lower gains related to asset management activities were partially offset by lower operating costs. Upstream after-tax earnings per barrel were $21.35, excluding the impact of non-controlling interest volumes. Unit profitability increased $3.40 from the fourth quarter, reflecting the benefits of our broad, diverse portfolio, including leverage to North American natural gas, our strong LNG portfolio, and the strategic choices we have made on production volumes to improve unit profitability. Moving to slide 11. Excluding the impact of the Abu Dhabi onshore concession expiry, volumes were up 45,000 oil equivalent barrels per day or about 1% sequentially. Liquids production was up 23,000 barrels per day or 1%. Lower downtime, increased production from West Africa projects, higher liquids volumes in Qatar, and ramp up at Kearl more than offset price and spend impacts, divestments and decline. Natural gas volumes were up 129 million cubic feet per day, reflecting higher volumes in Qatar, partly offset by lower production in the United States and Europe. Moving now to the downstream financial and operating results and starting on slide 12. Downstream earnings for the quarter were $813 million, down $732 million from the first quarter of 2013, mainly due to lower refining margins across all regions. Volume and mix effects increased earnings by $80 million, offset by other items for a net $70 million. Turning to slide 13. Sequentially, first quarter downstream earnings decreased by $103 million, primarily due to unfavorable volume and mix effects reflecting higher U.S. refining maintenance activities. Moving now to the chemical financial and operating results, starting on slide 14. First quarter chemical earnings were just over $1 billion, down $90 million versus the prior year quarter, mainly due to lower margins. Positive volume and mix effects were offset by other items. Moving to slide 15. Sequentially, chemical earnings increased by $137 million, primarily due to higher commodity product margins and lower expenses. Moving next to the first quarter business highlights, beginning on slide 16. As we discussed in our March analyst meeting, we are starting up a number of major projects that will deliver profitable volume growth. Our world-class project execution capabilities are enabling significant progress on several of these projects. At PNG, we continue to achieve milestones that will result in the first LNG cargo being loaded ahead of schedule. We have completed the onshore and offshore sections of the pipeline, which transports natural gas from the Hides gas conditioning plant up in the mountains to the LNG plant near Port Moresby. The first LNG train is now operational, and the second train is mechanically complete with final commissioning underway. Over recent weeks, we started flowing the first gas from Hides, and in the past few days, initiated LNG production. We produced the first condensate and liquids recovered through the liquefaction process. We expect the first LNG cargo delivery in the coming weeks. These are exciting milestones for the PNG LNG project and a great achievement for our project partners, contractors, and the people of Papua New Guinea. As we mentioned in our analyst meeting, we had to overcome a number of challenges during the construction phase, such as very steep slopes, flooding, and lack of infrastructure. Despite these challenges, we are starting up several months ahead of plan and delivering a project with one of the lowest costs per MTA relative to other LNG projects being built and in close proximity to the growing Asian market. This is also an excellent example of how ExxonMobil creates value through our leading project execution capabilities. In Malaysia, we have started up production in the Damar gas field from the first two of a total 16 wells. The Damar field has a projected capacity of 200 million cubic feet of gas per day and follows the Telok gas development, which began production in 2013. These projects provide additional gas supplies to help meet Malaysia's power and industrial needs, promote growth of the country's natural gas industry, and drive profitable volume growth for ExxonMobil. The Hibernia southern expansion in Canada, a project that will deliver 170 million barrels of oil, is progressing per plan and is now nearing completion. Installation of subsea infrastructure for the water injection facility has now been completed. Three of five platform production wells have been drilled, and top side modifications to the Hibernia gravity base structure platform are 97% complete. Startup is expected later this quarter. At Arkutun-Dagi in Russia, we are commissioning the last few top side systems at the fabrication yard. The platform drilling rig will be tested over the coming weeks before the 42,000-ton top side structure is loaded out later this summer. The top side will then be floated over the gravity base structure already installed offshore Sakhalin Island. Drilling will then start, and first production is expected later this year. The Banyu Urip project in Indonesia is now 87% complete. The project will deliver 450 million barrels of oil through an onshore central processing facility with 165,000 barrels per day of production capacity. Pipe rack construction is complete, equipment installation at the central processing facility is progressing, and the onshore and offshore pipelines are installed. Conversion of the floating storage and offloading vessel is nearing completion, with major equipment installed and commissioning ongoing. Two rigs are in operation, and the first 20 wells have been drilled. Startup is expected around year-end. The Kearl expansion project in Canada remains slightly ahead of plan and is now more than 80% complete. We continue to ramp up production from the Kearl initial development, with 66,000 barrels per day produced during the first quarter, up from 47,000 barrels per day in the fourth quarter of last year. Facility uptime performance is improving, and we are achieving many days with production above 100,000 barrels per day. Turning now to slide 17 for an update on our North American activities. We continue our commitment to deliver profitable volume growth, as underscored by our efforts to increase high-margin liquids production in the Permian. We had eight operated rigs running in the Permian in the first quarter and recently picked up two more in early April to continue to ramp up drilling activity. Our current net production in the Permian is over 90,000 oil equivalent barrels per day. Through an agreement with Endeavor Energy Resources, XTO will gain substantial operating equity in approximately 34,000 gross acres in the prolific liquids-rich Wolfcamp formation. The presence of multiple stacked pay zones creates the potential for capital-efficient horizontal development, and the proximity to XTO's ongoing Wolfcamp operations will offer operating cost efficiencies. The agreement increases XTO's holdings in the Permian Basin to just over 1.5 million net acres, enhancing the company's significant presence in one of the major growth areas for onshore liquids production in the U.S. Also during the quarter, we signed an agreement with American Energy Utica, or AEU, that will enable XTO to optimize funding of development costs in the Utica. As part of the agreement, XTO will continue to operate in a core area of approximately 55,000 net acres in this emerging play, and AEU will fund near-term development costs to earn acreage. This transaction is an example of an innovative solution to develop our extensive natural gas resources in the U.S. in a capital-efficient manner. Turning now to slide 18 for an update on our exploration activities. We are currently drilling a number of wildcat prospects from our deep and diverse opportunity portfolio, primarily concentrated in established areas. Some of this activity includes the deepwater prospects Mica Deep in the Gulf of Mexico and the Caminos prospect in Angola Block 32. We also continue exploration drilling in the prolific Block 2 offshore Tanzania, where somewhere between 17 and 20 TCF of gas in place has already been discovered. A recent drill stem test on the Zafarani-2 well confirmed good reservoir quality and good connectivity in both of the reservoirs tested. Drilling operations are also currently underway on two blocks in the Kurdistan region of Iraq. Also, preparations are underway for near-term drilling that includes the Universitetskaya prospect in the Kara Sea, the Brugdan prospect in the Faroe Islands, follow-up drilling to the successful Domino well in the Romanian Black Sea, the Sputnik well in Gabon, and additional drilling prospects in Tanzania. Turning now to slide 19 and an update on our chemical business. During the quarter, we achieved notable investment milestones to grow high-value product sales. For example, we progressed synthetic basestocks investments to meet global demand growth for high-performance lubricant applications. We commissioned a new 50,000 tons per year manufacturing facility at our Baytown, Texas complex, and construction of our expansion project in Baton Rouge, Louisiana continued during the quarter, with startup anticipated late this year. Both projects leverage ExxonMobil's technology leadership to meet the industry's growing demand for advanced synthetic basestocks and improved finished lubricant performance. We also recently approved a world-scale grassroots specialty polymers project in Singapore to produce halobutyl rubber to support the growing tire market in the region, and premium resins for adhesive applications such as packaging, woodworking, and nonwoven fabrics. The project builds on the feedstock advantage and integration benefits of the recent steam cracking expansion and will allow us to meet rapidly growing demand in Asia. Construction will begin this year, and startup is planned for 2017. In conclusion, in the first quarter, we earned $9.1 billion, increased upstream unit profitability to $21.35 per barrel, generated $16.2 billion in cash flow from operations and asset sales, invested $8.4 billion in the business, and distributed $5.7 billion to our shareholders. ExxonMobil's strong financial and operating performance demonstrates progress in delivering profitable growth and achieving our business objectives outlined during our analyst meeting in March. We improved our production mix and increased upstream unit profitability. We are committed to maintaining our capital spending discipline and generating strong operating cash flow to deliver robust shareholder distributions and create long-term shareholder value. That concludes my prepared remarks, and I would now be happy to take your questions. Thank you, Mr. Rosenthal. 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 touch-tone telephone. We request that you limit your number of questions to 2 so that as many may have the opportunity to participate 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. We will proceed in the order that you signal us, and we will take as many questions as time permits. Once again, please press star 1 on your touch-tone telephone to ask a question. Your first question will come from Doug Terreson with ISI Group. Good morning, David. Morning, Doug. I have a couple questions on international E&P. First, both profitability and margins were very strong and pretty much the highest they have been in several quarters, even if you normalize for the exploration in Abu Dhabi. My question is whether there is any additional color on the positive liquid mix effects that you talked about a minute ago, and also whether or not there were any positive effects on the gas side that might have contributed to that result? Yeah, sure. Let me take a look at the upstream earnings. We can look quarter versus quarter where I mentioned although we had a net impact of only $20 million, we did have a significant impact on liquids. That was about $290 million, and gas was a negative $270 million on that. When you look at the production in the first quarter, we saw some nice increases in Canada, some in Russia, West Africa, much lower downtime, a little more in the North Sea. Those were benefits to us. The biggest decline in production was the Abu Dhabi onshore concession expiry, which carried little earnings of an effect. If you were to look at that same effect sequentially, where we noted we had a $650 million volume mix impact, liquids was about $400 million of that, and gas was about $250 million. Okay. As we look at going from the fourth quarter to the first quarter, similar on the liquid side we saw some increases in Qatar, increases in West Africa as well, Canada with the ramp up of Kearl, and then an offset with the decline in Abu Dhabi. On the gas side, we also saw a nice positive mix effect. Volumes, for example, in Qatar were up and volumes in Europe, which was mainly the lower margin volumes out of the Netherlands were down because of the lower demand due to the warmer weather. In both liquids and in gas sequentially, we did see a nice uplift in earnings from the positive mix effect. Okay. In your last comment about European natural gas, most of that or all of that decline was related to weather. Is that the way to think about it? Yeah. The way to think about it is it was all demand driven due to weather with the bulk of it again coming out of the Netherlands where the margins are a little lower than they are on the rest of our European sales. Great. Thanks a lot, David. Thank you. From Wolfe Research, we'll hear from Paul Sankey. Hi, David. Hey, good morning, Paul. How are you? Very good, thank you. David, could I just ask you about your CapEx and your volumes? In the former case, there is an enormous step down in your CapEx here, almost 30%, which takes you well below the run rate for the year that you indicated at the analyst meeting of around $40 billion. Is there reason to believe that we are coming in lower on CapEx for the year or is this an anomalous Q1 that we will see a catch up later, and therefore, would you stick with the 40 or could we see some downside to that? If I could follow up on volumes, David, the guidance at the meeting had been flat 2014 over 2013, allowing for all the adjustments that needed to be made. Again, your Q1 numbers are actually tracking below that. Can we expect to catch up back to flat later in the year? Final part, if you could just address Kashagan and where that is at within your volume forecast, both for this year and longer term. Thanks. Okay. Sure, Paul. Let me hit CapEx first. Yeah, we did come in at $8.4 billion. That was down a little over $3 billion from the first quarter of last year. That was mainly due to the absence of the Celtic acquisition in Canada. If you take that out from last year's results, we would be pretty much flat, maybe down just a little bit. As we look out across the year, the first quarter is usually lower than the rest of the quarters, and we tend to ramp up across the year with a little extra in the back half. So I would say, as we look at where we are today and looking out over the rest of the year, the number we gave you in the analyst meeting is probably still a good one. I do not have an update. What I will say, though, is when we look at the first quarter CapEx, it came in just about right on what we had expected. So, so far this year, things are going according to plan on CapEx. On the volumes guidance, we said overall we would be flat at about 4.0 million oil equivalent barrels per day year to year ex Abu Dhabi, about a 2% increase in liquids, about a 2% decrease in gas. As we look at the first quarter and then across the rest of the year, those numbers still look good to us. We have got some additional ramp up expected at Kearl across the year. We do expect some of these other projects I mentioned come on, Papua New Guinea being one of those. So, we look at the first quarter, looks real strong, and certainly maintains our confidence in meeting that full year projection we shared with you in the analyst meeting. I think the other thing that's noteworthy, and I talked about it a little bit on the last question is we are seeing the impacts we were expecting on the volume mix as we reduced our exposure to some lower margin barrels, and we're able to increase production in some of our higher margin areas, both on the liquids and gas side. That's coming in as we were expecting, and we talked about a little bit at the analyst meeting. In terms of Kashagan in the forecast for 2014, we did not have any volumes in our outlook that we showed you in March for Kashagan for 2014. That's very helpful, David. Then a quick follow-up. Your product sales are up 11% year-over-year, quarter-to-quarter. In the recent past, that's been a number heavily affected by asset mix. Could you just address the scale of that jump? I mean, the 11% growth, obviously on a company of your size, looks like enormously strong oil demand globally. Any thoughts? Thanks. Paul, let me just clarify the question. When you say product sales, are you talking about our downstream sales or? Yeah, I should say, to use your language, exactly, petroleum product sales. If I look worldwide, they're up at 5.8 million barrels a day, up from a year ago level of 5.7. Yeah. We are up a little bit. We have seen worldwide, we actually had some higher demand in the U.S., actually some pretty good demand growth there. We have seen some growth in diesel as well with exports and actually some growth in Europe. Those are the two main areas, but a nice quarter for us operationally as well. Well, I guess my question was just the extent to which it is a comparable number year-over-year or whether there was any asset mix in that or whether we can just look. No, that is pretty comparable. Right. Okay, thanks very much. Yeah. I'm sorry, I didn't understand the question. All right. Thank you. Next we'll hear from Doug Leggate with Bank of America Merrill Lynch. Thanks. Good morning, David. Good morning, Doug. David, I wonder if I could follow up on the other Doug's question on margins. Your unit margin capture is something you have talked about periodically, and this quarter it had a fairly nice rebound. I am just wondering if you can walk us through any particular reasons behind that. Was it just a great operating quarter? In other words, how sustainable could this be? As a follow-on to that, you are going to have about 1 million barrels a day of new production by your forecast between now and 2017. Obviously, that is a fairly good churn in the portfolio. I am wondering if you could just qualitatively or quantitatively, whichever you can do, walk through the delta you see in cash margins for the newer projects relative to the existing portfolio, please. Sure. Let us start out with the margin and the margin capture. In addition to some of the volume mix items I mentioned, you actually have some fairly significant mix impacts on the realization side, which get masked by some of the markers. For example, if you look this quarter versus the same quarter last year, WTI is up over 4 bucks, Brent is down over $4. But Western Canadian Select, it was up $9 a barrel as a marker for the Canadian crudes. If you think about where we are exposed to Brent overseas, a number of production, but including the Abu Dhabi barrels would have some tie to that. Whereas in the U.S., a lot of our production, particularly in the Permian, would be closer to a WTI spot price, and then of course all of our volumes in Canada. It is not just Kearl, you are talking about Cold Lake and our other production up there. Think about it as the volumes that went up were attracting the higher margin or the higher price marker crudes. The volumes that declined happen to be the ones that were Brent based, and again a big change in those prices did not have much of an earnings impact. So you see a nice change on both the volume mix side as well as on the price side. So it is back to, again, what we have been talking about in the last couple of analyst meetings, growing the liquids and liquids linked volumes. LNG prices were also very attractive in the quarter, and we were able to capture those by having some increased volumes in Qatar. So I would say on a go forward basis, this is probably more typical than what we have seen in the past again given the mix changes I mentioned. If we look at the barrels that we are going to be adding on an equivalent basis going forward, I would not give any specific cash margins on those barrels, but if you recall back at the analyst meeting, some of the discussion I think Mark Albers provided in his comments, we did talk about that the volumes coming online were going to be generally accretive to our average unit margin. Given the fiscal regimes we would be in those projects also accretive to earnings. I think, again, as we go forward over the next year or two and we start up these projects, we expect to deliver the profitable growth that we talked about in the analyst meeting, and we certainly look forward to these projects coming online over the next three years. Thanks, David. Very quick follow-up. Could you give the absolute asset sale gain in the quarter just as a housekeeping point, and I'll leave it there? Yeah, sure. If you look at on an earnings basis, the absolute gain on asset sales in total was just over $400 million, and that was all in the upstream. I'll just give you the numbers here because I know there's going to be interest. In the upstream, the absolute value of the asset sales on earnings was about $400 million in the first quarter of this year. That was lower than and compared to about $800 million in the fourth quarter of last year. And we didn't have any asset sales in the first quarter. So you got about a 400 positive delta quarter-over-quarter and almost 400 delta sequentially on the negative side. The other thing I'll mention to put the first quarter asset sales into perspective on an absolute basis, I mentioned we had 400 million in positive. We had about 200 million of negative tax items and other reserves. So if you think about outside the normal operations of the business, we probably had a net absolute value in the upstream of about $200 million. That's really helpful. Thanks a lot, David. From Jefferies, we'll hear from Jason Gammel. Thank you. Hello, David. Hey. Hello, Jason. David, I wanted to ask about the PNG LNG project, and congratulations, Exxon, for bringing the project on ahead of schedule. It's something that hasn't been achieved in that business in quite a while. Thank you. I wanted to ask about the pace of ramp up, David. You've made reference to first commercial cargoes by the end of the quarter from the first train and start of production from the second train in several weeks. Would you expect that you could potentially be achieving full production by year end from both trains from that project? Yeah. First of all, thanks for the comments on the project startup. The team is very proud of, as I mentioned, bringing that in early, and it looks like certainly within the budget that we had talked about. We do look for ahead of plan production and cargo deliveries. If we look out towards the end of the year, we'll certainly be ramping up both the first train and the second train. Assuming all of that continues to go well, we would expect to see these things ramp up pretty good across the coming months. It's a little early for me to give you a definitive answer. But I would say it's likely that by the time we get to the end of the year, we're going to be running at some pretty good operating rates. Okay, great. If I could ask a second one, David. It's obviously pretty early days just in terms of sanctions on Russia. Have you had any effect yet on your ability to invest in the multiple areas where you participate with Rosneft as a partner in Russia? With regards to Russia, of course we will comply with all sanctions. I can tell you on the latter part of your question, all of the activities that we had originally planned for this year are underway and proceeding as planned. Great. Thank you, David. Thank you. Next, we'll hear from Asit Sen with Cowen and Company. Thanks. Good morning, David. Good morning, Asit. How are you? Good, thanks. On PNG LNG, as we get closer to the start, was wondering if we could provide some early thoughts on some incremental operational items. First, wondering if you could talk about the condensate ratio. Second, any thoughts on train 3 expansion potential? Finally, any thoughts on LNG contracting strategy relative to the pricing slope and/or your spot exposure? Sure. On the condensate ratio, I really couldn't give you a specific number for the expectation there. Obviously, it's a very attractive stream. When we look at train 3, we are still evaluating a number of opportunities to expand the plant. Some of those relate to our own exploration success and other opportunities that we have on our own operated acreage, as well as potential other sources of additional gas. That planning and looking and analyzing and discussing, that process is ongoing. Don't have a definitive outcome for you, but as I mentioned in my prepared remarks, if you look at the plan as it sits today, the cost per MTA in today's market is very competitive, and of course, any additional capacity would take advantage of the existing infrastructure and even be more attractive. We're certainly looking at that. If you look at a contracting strategy, we entered into long-term oil index price contracts. About 95% of the production is already sold under those contracts, customers being in Japan, China, and Taiwan. Those contracts are locked up, and then you'll have, of course, a little bit left over for some spot sales. Thanks. Very helpful. Okay. Thank you. From Wells Fargo, we'll go to Roger Read. Yeah, thanks. Good morning. Hey, Roger. Just to come back to the margin discussion and maybe as a better way to understand some of the moving parts going forward, I gather the expansion of liquids, the shrinking of the gas, and what that should mean for margins as well as the addition of the LNG barrels. But I was wondering, underlying cost, can you give us any kind of view of what's going on there? Are we dealing with costs are going to go up, but your margins go up faster? Costs should hold flat while margins should improve from mix and price? Maybe a little more detail on that, if you could. As we look at the overall profitability, as you mentioned, margins are doing better with the mix that we talked about on both the oil and the gas side. In terms of OpEx, we are not seeing any significant upward pressure across the portfolio. If you look at on an absolute basis, of course, OpEx is up with the startup of some of our big projects. Kearl would be a good example of that as we progress from the startup phase last year into lining out production and ramping up this year. You get some benefit of that. We did see some lower exploration expense in the first quarter of this year. As you recall, in late last year, in the second half, we booked some fairly heavy exploration expense, mainly attributed to our business in Russia, and that was a little lower this quarter, but as expected. So I would say overall, you think about the margin capture and the profit capture, again, it is the mix that we have talked about, in particular as we ramp up these projects across the quarter. I think the other thing I might add is on the unconventional side, we continue to make good progress driving costs down in the areas that we are operating. As we have talked about before, the combination of Exxon Mobil's technology and XTO's operating experience, we are really starting to see the leverage we get by combining those, particularly as we continue to acquire attractive acreage, as I mentioned in the Permian, it would be a good example of that. So across that portfolio, that trend continues to be positive in terms of reducing costs and improving capital efficiency. So that part of the business is also doing well. Okay, great. Thanks. Then a follow-up question. Recent headlines indicated Argentina is going to actually be importing some crude. Obviously, you are a major mover and shaker in the Vaca Muerta shale. I was wondering, have you seen any indications from the Argentinian government that they are willing to be, I do not know, good term, flexible in terms of helping to accelerate activity down there? I will take the last part of your question first. We continue to have ongoing discussions with the government about fiscal terms and stability, and I do not have anything definitive to report on that, but those discussions are ongoing. We have seen some positive signals out of the government recently in terms of improving export and import conditions and what we are doing there. These are certainly positive steps that could lead to an attractive business environment. But it is all part of progressing the programs and determining commerciality. Obviously, there is a huge potential resource in Argentina called the Vaca Muerta. We continue to have an active Program there. I think we have got a total of six wells down. We have been drilling vertical wells prior to this year. We are starting to drill our first operated horizontal wells. First one's down, the second one is drilling, and we'll be getting the third one down shortly. Again, without being specific, I can tell you that the data so far from our drilling and delineation is encouraging, but it's still early days to determine actual commerciality. But if you get the combination of good fiscal terms and stability and good resource development, that generally leads to a commercial resource development for you. We continue to actively pursue that. But again, for us, it's a very large resource. We got in at a very low entry cost, a very low commitment. That allows us to really go about this in a disciplined manner and really utilize some of the expertise XTO has to help us explore and delineate and appraise this resource without having to spend a whole lot of money upfront. Again, we're encouraged, and that piece of the business is moving along very well. Great. Thank you. Next we'll go to Faisal Khan with Citi. Hi. Good morning. It's Faisal from Citi. Good morning, Faisal. Thanks, David. You talked a little bit about the increase in per unit profitability in the upstream business. You also discussed LNG prices. Can you remind us how much of your total LNG volumes are exposed to the spot market? I don't have a total global number on that. I think probably what would be more indicative is if you take the U.S. aside, of course, and you look at our total LNG volumes, most of those are going at oil index prices. But the rest of them, by and large, are going into the Asia-Pacific Rim, and so the spot prices there are fairly close to the oil index prices, and so you're getting a nice benefit there. As well, the occasional cargo that goes into Europe goes in at a spot price, but those are attractive as well. So, regardless of how the cargo's going, either directly or indirectly, most of them, probably all but about 5%, are either oil indexed or getting equivalent type prices. Okay. I guess I was just trying to understand the commentary, given that oil prices haven't moved all that much sequentially quarter-to-quarter, but it sounded like that was a particularly strong point for you in the quarter. Thank you. It was, and a lot of it is the mix on where these cargoes get delivered, and whether they're going to Europe or they're going to the Asia-Pacific Rim or whether you have a little higher proportion going into your fixed contracts versus your spot. We did see a little uplift on those prices. As you know, not all those contracts are the same in terms of how they look back and what the formula is. But if we look across, for example, our LNG realizations out of Qatar, and you're just looking quarter on quarter this year to last year, we were up a little over $1 a KCF. Okay. Again, a nice piece of business. Yeah. No, thanks. I appreciate that detail. Then just back to Russia for a second. I believe you guys have some sort of asset swap arrangement with Rosneft that sort of protects you in case some of the investments get stranded in Russia. Can you just walk us through a little bit of that in case there are sanctions? Do you have recourse here in the U.S. with the assets that Rosneft has swapped into with you and that joint venture agreement you guys put together? I really can't comment on the terms and conditions of those pieces of business other than we have the projects that we have in Russia, and they farmed into some of our properties on a normal farm-in basis, just like anybody else would. But any discussion of contractual details or commercial arrangements, I really couldn't comment on. Okay. Got it. Thanks, David. I appreciate the time. Thank you. From Barclays, we'll hear from Paul Cheng. Hey, guys. Good morning. Hey, Paul. How are you doing? Very good. Dave, two quick questions. One, you talk about the overlift benefit in the first quarter. Can you give us, quantify that? What is the volume and also the dollar value? Also at the end of the first quarter, whether from an inventory standpoint, you are roughly balanced, still overlift or underneath? Sure. If you are looking in the first quarter relative to the first quarter last year- Can we look at relative to your production, actually? Oh, sure. We're about 15 KBD overlifted in the quarter. Yeah. On an absolute basis, we're about 15 KBD overlifted, and I'd estimate that to be worth about $100 million. Okay. At the end of the first quarter, are you roughly balanced at this point? If we look at where we are just at the end of the first quarter, I think we're overlifted just a little bit. So we're not completely in balance, but we're fairly close. Okay. Second question. Permian. Right now, you are running at 10 rigs. Is there any kind of insight you can provide on what the runway is going to look like over the next two or three years? You just add two. Should we assume that you will continue to ramp up the program there? Also, whether you can tell us the 90,000 barrel per day production, what is the mix between black oil, condensate, NGL, and natural gas? Yeah. Let me start with the first part. We are, of course, ramping up activity in the Permian. We are doing it like we always do, in a very disciplined approach. You do not want to get too far out in front of your headlights, so we have been building that rig count over the first last few quarters. I did mention the additional acreage that we picked up in a very attractive area in the Wolfcamp. So, as we move on, I would expect the trajectory to be the same, but I do not have any specific count for you. Again, in a lot of these areas, we are still delineating, we are still appraising, we are still experimenting with how we go about drilling and completing wells, and that sort of thing. But I think directionally, given the quality of the acreage that we have and the results we have had to date, I think it would be a reasonable expectation that we would likely grow that rig count over the course of the year. I think that would be logical. But again, always in a manner that keeps in mind the long-term development of these resources, and not getting out too far in front and doing something that you will regret later. So it is all about assessing what we have got. We are very pleased with our acreage, and then ramping up that production as is appropriate and leaning towards that outlook we gave you in the analyst meeting that showed a nice ramp between now and 2017 in total in North America's liquid production. But the Permian will be a big part of that. In terms of the split on the liquids versus NGLs versus condensates, I do not have that split for you, Paul. I see. Okay. Thank you. Thank you. From Credit Suisse, we will hear from Edward Westlake. Hey. Yes, good morning, David. Three very quick tail end questions. Thanks, by the way, for all the helpful color on LNG and well done on the execution on some of the key projects. Some other people have shouted out a gas marketing benefit given the cold winter in the U.S. Did you guys have something there that we should think about? Well, we benefited from the higher gas prices. Other than that, we certainly don't do any trading, if that's what you were looking at. If that was the question, let me be clear. All of our earnings uplift comes from the production and sale of our gas. We don't do any trading. Okay, good. Then switching to the international chemicals, obviously Q4 was weak, and you've seen a bit of a comeback in Q1. Maybe just talk a little bit about, you shouted out lower other expenses. Maybe just a bit of a shout-out on what's happening there. Sure. As we went from the fourth quarter into the first quarter this year, we did have some significantly lower maintenance expense. You might recall in the fourth quarter it was pretty high. We had some turnaround activity going on in Singapore, and that's all behind us, and that's the biggest driver in that other bucket. So it's not a sort of a sea change in demand that you're seeing in the chemical chain globally? I wouldn't say a sea change, but I would say that we are seeing some encouraging signs. The integrated polyolefins chain is seeing some pickup in demand. Polyethylene sales have been good, and we continue to see some nice demand pickup there. We did also see some pickup, which was seasonal between the fourth quarter and the first quarter in our specialties business. But on the other hand, aromatics demand is weak, particularly in paraxylene. There are some offsets, but I think generally speaking, we have seen a little better demand. We've been able to sell the increased production out of Singapore. That part of the business is going well. I think as you go from fourth quarter to first quarter in the chemical business, lower maintenance as we move from the first quarter to the second quarter, as you're probably aware, we are heading into a higher maintenance period. The Beaumont chem plant, for example, came down in early April and is down for a couple of months turnaround. We'll see that impact. But a really nice first quarter operations on the chemical side. I think our capacity utilization, particularly in North America, where, of course, we get a nice margin benefit. I think we were running about 2% or 3% on a capacity utilization better than industry. That's not only good in total, but on the margin, those last couple of percent really ring the cash register for you on those sales. So good quarter for us in the chemical business. And just in the cash flow statement, working capital contribution in the quarter? The working capital contribution, as I recall, was just under $2 billion, about $1.8 billion, and that was just a change in payables. Right. Then one- But not a real big effect if you think about total cash flows, a number less than $2 billion in a quarter, but it was payables driven. Then one bigger picture question. We always talk about shale, but obviously you've been doing a lot of offshore exploration as well. When do you think you'll get to the point where you can update us in terms of actually getting after developing some of these deepwater fields that you've got in the portfolio? Yeah, I think as soon as we have a little better indication exactly on what we've got in some of these areas. One that I can mention is Tanzania, where we've had significant success, and planning is underway as we speak, not only with our partner in Block 2, Statoil, but also with BG and Ophir broadly across Tanzania. So we're working at evaluating potential sites for an LNG facility, and we have made a recommendation to the government, and studies are progressing to really determine what would be the optimum development plan for our block and across that area. So, I would say all of that is progressing as you would expect for a resource of that size, but I couldn't give you a definitive development plan or timing yet. Julia's another deepwater project that's well underway, and we'll start drilling there this year. We've got more drilling to do in Romania, where we've had a very nice successful initial well there. So a lot going on in some very attractive areas, but probably still just a little early to be talking definitive development plans or startups or FIDs or that sort of thing. Thank you. Next from Morgan Stanley, we'll hear from Evan Calio. Hey. Good afternoon, David. More housekeeping from me here. Exploration expense is much lower in the quarter, is it 338 versus normal? Is that just timing event, or is there any exploration spend trending lower there? I wouldn't say there's any lower trend. It's really particularly if you look quarter-on-quarter, it was really just timing of expenditures. particularly in Russia and some other areas. But the program remains on track, on schedule, and I think you'll probably see a little more normalized kind of trend as we go out into the year. Great. On the asset sale gain, you gave us color earlier that's included in income. Was that an international upstream? Can you Mark? Yes, that was an international upstream. Got it. Maybe just lastly from me with cash builds equaling asset sales here in the quarter, what was the consideration to holding the buyback flat sequentially? What do you need to see, you think, to raise it? Thank you. Yeah. No change in our strategy with regard to shareholder distributions in general. You saw we got a nice 9.5% bump in the dividend this quarter, continuing a nice trend that you've seen the last few years. Growing that dividend and making sure it's reliable and consistent continues to be at the top of the list for shareholder distribution. The buyback continues to be after that with the cash we have. Although we do look at it on a quarter-by-quarter basis, we are always taking into account cash flow projections and business and that sort of thing. Again, on a company our size, plus or minus $1 billion- not a big number. I do think that it's noteworthy if you look at free cash flow, for example, in the quarter, particularly relative to the last few quarters, we did generate a total of $16 billion, put a bunch of that into the business, funded both the dividend and the buyback, and still had $2 billion left over. Half we paid down debt and half we increased cash. Again, if you're looking sequentially across the last few quarters, very strong quarter in cash flow consistent with the strong quarter in earnings. Got it. Thank you. Thank you. From Raymond James, we will go to Pavel Molchanov. Thanks for taking the question. One more on the cash allocation. By my math, this will be the first quarter that your dividend payout of $40 billion equals your share buyback. Is that deliberate, and do you see the two lines continuing to cross that way? I would say that was a coincidence. There is no deliberate effort to match those up or change any pay ratios or that sort of thing. Okay. Then this may be most relevant for your German acreage, but in the context of the Ukrainian crisis and a lot of rhetoric in Europe about ramping up shale development, any sense that permitting in Germany or elsewhere in Europe is starting to open up? I do not have any indication of that. There is a lot of discussion going on as we are all well aware, but nothing definitive, nothing different than what has been going on. As you know, we have a very attractive acreage position in Germany, and we have been in discussions with the regulators for a while on the potential of that resource, and those type of discussions are ongoing, but nothing specific to report on today. Okay. Appreciate it. Thank you. We have one question left in the queue, and that will come from Peter Hutton with RBC. Oh, good afternoon. Just two quick follow-ups. Kashagan, again, you said no volumes had been expected anyway in 2014, but I wonder whether you could say what you had in your plans for 2015 and what those still are. Also on the upstream, you talking about Tanzania. It has actually been quite some time since the recommendation has gone in about the location of the planned facility. Still nothing has come out. Do we have a timing as when we might get that as the next catalyst in that area? Finally, the downstream. If you could say some words on the international downstream, that was slightly lower than a number of people have expected profitability levels back to the early 2009. One of your competitors took a big impairment on their refining assets in Asia and are being very clear about the structural weakness in that market. Is that something that you are seeing reflected and expect to continue out into the medium and long term as well? Thank you. Let me take those in order here. In Kashagan, as I mentioned in the outlook we showed in March, we did not have any volumes for 2014. We did have some volumes in 2015. I do not want to give a specific number here today, but we did assume some production volumes in 2015. In Tanzania, we do not have any final determination on the site. But I will tell you, the discussions are ongoing and going well. Nothing out of the ordinary, and the plans for that are progressing at an appropriate pace. So I think all is well there. Okay. When we look at the downstream on the international side, yes, you did see some weak earnings there overall. We had a positive impact in Canada. You saw the IOL results out this morning, a very nice business there. We are running, obviously, advantage crudes into those refineries, and that piece of business is going well. Outside of Canada, the rest, particularly in Europe and the Asia Pac, were weak. The biggest driver there is the margin. You have had some surplus refining capacity come online in that area of the world the last couple of years, and the demand is a little weak, so you got some capacity expansion in excess of demand growth. You do see some weakness there. We are doing a number of things to improve our profitability there and improve our competitiveness. We have been spending some time on logistics and expanding feedstock flexibility, working to increase exposure to high-value product yields and less exposure to lower-margin products. Continuing to work on OpEx and maximizing the logistics benefits we get both from the location of our refineries, particularly in Europe, but also that full integration with the chemical business and the lubes business, which is doing quite well. I think if you look at that business, it is weak. It has been weak for a little while. These are always cyclical businesses, both in Europe and in the U.S. and in the Asia Pacific Rim. You would not want to take current results and draw a long-term trend. We are doing what we can, controlling what we can control, and really it is about making sure your refineries, and your chem plants for that matter, in any region are the most competitive in that region. That is what benefits you over the long term. When you talk about a potential impairment, we follow US GAAP with regard to impairment, and we look at that as appropriate. From our perspective, and it is different from companies that follow IFRS accounting rules, when we look at the US GAAP accounting, we do not see any exposure to that in that part of the world. Very clear. Thank you. One of the things you might recall, just quickly, when you look across both the downstream and the chemical segment, bear in mind the significant advantage we have on an ROCE basis for the rest of the industry. When you look at the denominator, when you look at the capital employed in our business, both on the chemical side and on the downstream side, our capital employed tends to be an order of magnitude lower than the others. That helps generate the ROCEs but also gives you a feel for how much capital is on the books. The other thing, of course, we benefit from is the level of integration we have. Even as refining cycles one way and chemicals another one, you get some offsets, and when they're both on an upswing, that's where you see the benefit of that integration. Across the business, we continue to do well, continue to generate the highest returns in the business and don't have any long-term concerns. Okay, thanks very much. Very clear. All right. Thank you very much. Mr. Rosenthal, there are no other questions at this time. Thank you. Ladies and gentlemen, that does conclude today's presentation. We do thank everyone for your participation.