Earnings Call: Q1 2012

Apr 26, 2012

Summary

Q1 earnings excluding special items fell 11% YoY to $9.5B as Upstream and Chemicals weakened, partly offset by Downstream gains. Cash generation of $21.8B funded investment and shareholder distributions exceeding $7B.

Good day, everyone, and welcome to this Exxon Mobil Corporation first quarter 2012 earnings conference call. Today's call is being recorded. At this time, for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. Good morning, and welcome to Exxon Mobil's first quarter earnings call and webcast. The focus of this call is Exxon Mobil's financial and operating results for the first quarter of 2012. 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 customary 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 slowed in the first quarter, primarily due to continued contraction in the European Union. The U.S. and Japanese economies are also expected to show declines from fourth-quarter levels. China growth, while still robust, was also lower in the first quarter. Energy markets were mixed in the first quarter with higher crude oil and non-U.S. natural gas prices. Industry refining margins also improved from the fourth quarter. While U.S. chemical margins remained strong, Europe and Asia continued at near bottom of cycle conditions. Turning now to the first quarter financial results as shown on slide 4. Exxon Mobil's first quarter 2012 earnings, excluding special items, were $9.5 billion, a decrease of $1.2 billion from the first quarter of 2011. Our effective tax rate for the quarter was 49%. Earnings per share for the quarter, excluding special items, were $2, down $0.14 from a year ago. The corporation distributed more than $7 billion to shareholders in the first quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was distributed to purchase shares. Through the end of the first quarter 2012, we have repurchased the number of shares issued for XTO, and total shares outstanding are now lower than they were prior to the acquisition. Yesterday, the board of directors declared a cash dividend of $0.57 per share, a 21% increase from the last quarter. Share purchases to reduce shares outstanding are expected to be $5 billion in the second quarter of 2012, unchanged from last quarter. CapEx in the first quarter was $8.8 billion, up 13% from the first quarter of 2011. Across our diverse portfolio, we continue to invest in robust projects through the business cycle to help meet global demand for crude oil, natural gas, and finished products while supporting economic growth, including job creation. Our cash generation remained strong with $21.8 billion in cash flow from operations and asset sales. At the end of the first quarter of 2012, cash totaled $19.1 billion, and debt was $15.7 billion. The next slide provides additional detail on first-quarter sources and uses of funds. Over the quarter, cash increased from $13.1 billion to $19.1 billion, including cash on deposit associated with asset sales which have not yet closed and therefore are not yet reflected in earnings. The combined impact of strong earnings, depreciation expense, lower working capital, and the benefit of our ongoing asset management program yielded $21.8 billion of cash flow from operations and asset sales. Uses included additions to plant, property, and equipment, or PP&E, of $7.8 billion and shareholder distributions of $7.2 billion. Additional financing and investing activities decreased our cash by $0.8 billion. Moving on to slide 6 and a review of our segmented results. Exxon Mobil's first quarter 2012 earnings of $9.5 billion decreased $1.2 billion or 11% from the first quarter of 2011. Upstream earnings decreased $873 million, while downstream earnings improved by $487 million. Chemical earnings were down $815 million. Corporate and financing expenses were flat. Corporate and financing expenses remain within our continued guidance of $500 million to $700 million per quarter. As shown on slide 7, Exxon Mobil's first quarter 2012 earnings were essentially flat compared with the fourth quarter of 2011. Moving next to the first quarter business highlights beginning on slide 8. We continue to advance our global portfolio of high-quality projects. The Kearl initial development project is now 90% complete and is on schedule to start up later this year with initial gross production of approximately 110,000 barrels per day. The initial fleet of haul trucks and shovels are on-site and assembled, and all pipelines are mechanically complete. In Angola, the Kizomba Satellites project remains on schedule for a mid-2012 startup with peak capacity of 100,000 gross barrels of oil per day. The development design will optimize the capabilities of existing facilities, allowing for increased production levels without the investment in an additional floating production, storage, and offloading vessel. Onshore fabrication is complete, while FPSO modifications and sub-sea pipeline installation are expected to finish in the second quarter. In Nigeria, we completed construction of three wellhead platforms as part of the Nigeria Satellites project. The structures are currently being moved to the field site for installation. These are the first offshore platform structures to be fully constructed in Nigeria. The project is on schedule to start up in late 2012, with peak capacity of 70,000 gross barrels per day. Also in Nigeria, the Usan Deepwater Development achieved first oil in February and has a production capacity of 180,000 gross barrels per day. In Russia, construction is complete on the Arkutun-Dagi gravity-based structure, with float-out scheduled for later this year. The project remains on schedule for startup in 2014. In March, ExxonMobil, along with our partners, finalized a settlement agreement with the State of Alaska regarding the Point Thomson Unit, which enables the progression of the initial development phase of the Point Thomson project. The settlement agreement sets out the near-term development plan for the Point Thomson Field. The initial production system will include processing capacity of 200 million cubic feet of natural gas per day and 10,000 barrels of condensate per day. Detailed engineering and purchasing of long-lead equipment is currently underway. Pending approval of the draft environmental impact statement and other required permits, startup of the initial phase at Point Thomson is anticipated in the first quarter of 2016. Alaska's North Slope holds more than 35 TCF of discovered natural gas, and Point Thomson is a key component to the development of this resource. Turning now to slide 9. We continue to make progress on our strategic cooperation with Rosneft. Earlier this month, Rosneft and ExxonMobil signed a series of agreements to implement the long-term strategic cooperation agreement that our companies announced last August. The execution of these foundation agreements for our joint venture with Rosneft establishes the key terms for our cooperative exploration and development of the Kara Sea and the Black Sea. President-elect Putin also recently announced fiscal terms to encourage offshore development in Russia. These improved terms eliminate the export tax and lower the mineral extraction tax. The fiscal terms will be fixed at 15 years for the Kara Sea and 10 years for the Black Sea Deep Water. In addition, we commenced joint exploration activities in the Black Sea, where seismic acquisition is now nearing completion. We are also planning for seismic acquisition in the Kara Sea for later this year. We expect to begin exploration drilling in the 2014-2015 timeframe as soon as prospect mapping is complete and a rig is contracted. Additionally, Rosneft will take equity in promising exploration and development projects in the U.S. and Canada, including the La Escalera Ranch project in the Delaware Basin in West Texas and equity in the Harmattan acreage in the Cardium play of the Western Canada Basin in Alberta. Rosneft also has the opportunity to acquire a 30% interest in 20 blocks in the U.S. Gulf of Mexico. In addition, Rosneft and ExxonMobil will jointly study tight oil production technologies in Western Siberia. Turning now to deepwater exploration on slide 10. ExxonMobil maintains a diverse and robust global deepwater portfolio, which supports an active drilling program aimed at testing new play concepts, exploiting opportunities in proven basins, and drilling near-field wildcats. For example, in Romania, we drilled a successful deepwater play test on the Neptun block in the Black Sea with the Deepwater Champion drillship. Following this encouraging play test, we are planning additional 3D seismic data acquisition to support future drilling opportunities on the block. We also participated in an exploration well offshore Tanzania in the first quarter, which discovered approximately 5 TCF of recoverable gas in a high-quality reservoir. A second exploration well is planned for second quarter 2012 to test another prospect on the block. We also maintain an active global unconventional exploration drilling program, as discussed on slide 11. In North America, we hold a material position in multiple unconventional plays across 8 million acres, and we continue to increase our leaseholdings in emerging liquids-rich plays like the Woodford Ardmore. Our acreage position in the Woodford Ardmore play tripled in 2011 to more than 170,000 acres with acquisition costs on a per acre basis roughly 50% below major industry acquisitions in the Eagle Ford play. In the first quarter, we entered into an agreement to purchase an additional 58,000 acres through a strategic acquisition, which will increase our total acreage position to more than 230,000 acres. This will further expand our position in a play where we already hold 170,000 net acres with an estimated potential to recover 600 million oil equivalent barrels at an attractive unit development cost of approximately $10 per barrel. We continue to focus drilling activity to maximize the development of this liquids-rich play with 10 operated rigs. Current drilling is focused on delineating the acreage as well as determining optimal well spacing and drilling and completion practices. We also hold a large heritage position in tight oil plays in Western Canada, including the Cardium and Viking plays. We are actively drilling in the Cardium and achieved first oil production in the fourth quarter of 2011. We are currently drilling in the Viking and have additional drilling planned this year to further delineate this tight oil resource. Turning now to the upstream financial and operating results and starting on slide 12. Upstream earnings in the first quarter were $7.8 billion, down $873 million from the first quarter of 2011. Stronger crude oil and non-U.S. natural gas realizations increased earnings by approximately $1.3 billion as crude oil realizations increased by more than $13 a barrel, and non-U.S. average gas realizations increased $1.27 per thousand cubic feet. However, the positive effects resulting from the increase in realizations were mitigated by a higher effective tax rate. A decrease in U.S. natural gas realizations of $1.25 per thousand cubic feet also negatively impacted earnings by more than $300 million. Production mix and volume effects decreased earnings by $850 million, due mainly to the impact of lower entitlement volumes in West Africa, base decline and divestments, partly offset by the ramp-up of Angola and Iraq projects. Earnings were also negatively impacted by the unfavorable timing of liftings, as we were under-lifted in higher margin areas such as the North Sea and West Africa. All other items, primarily the absence of gains from asset divestments, combined with higher exploration and operating expenses, decreased earnings by $1 billion. Upstream after-tax earnings per barrel for the first quarter of 2012 were $18.83, reflecting the unfavorable mix impacts and higher effective tax rate. Moving to slide 13. Oil equivalent volumes decreased by more than 5% from the first quarter of last year, mainly due to the impact of lower entitlement volumes in West Africa, decline, and divestments. Volumes were positively impacted by the ramp-up of projects in Angola and Iraq and less downtime. Excluding the impact of higher prices on entitlement volumes, OPEC quota effects, and divestments, production was down about 1%. Turning now to slide 14. First quarter operational performance was consistent with plans, including the successful start-up of the Nigeria Usan development. Additional project start-ups expected in the second half of the year, including Angola satellites, Nigeria satellites, and the Kearl initial development project are key to achieving our 2012 volumes outlook. Although seasonal factors, including demand and the timing of planned maintenance activities, will impact volume profiles during the year, we expect full year volume performance to be consistent with our March outlook. Turning now to the sequential comparison, starting on slide 15. Upstream earnings decreased by $1 billion versus the fourth quarter of 2011. Stronger crude oil realizations and non-U.S. natural gas realizations positively impacted earnings by more than $300 million, as crude oil realizations increased by more than $7 per barrel, and non-U.S. average gas realizations increased $0.26 per thousand cubic feet. However, the positive effects resulting from the increase in realizations were mitigated by a higher effective tax rate. A decrease in U.S. natural gas realizations of $0.70 per thousand cubic feet also negatively impacted earnings by $170 million. Production and mix effects, mainly higher natural gas volumes from stronger seasonal demand in Europe, increased earnings by $100 million. Earnings were negatively impacted, however, by the unfavorable timing of liftings as we were under-lifted in higher margin West Africa. Other items, primarily the absence of gains from asset divestments, decreased earnings by more than $1.2 billion. Moving to slide 16. Oil equivalent volumes were up slightly from the fourth quarter of 2011 as the impact of lower entitlement volumes in West Africa and divestments were more than offset by stronger seasonal gas demand in Europe. Excluding the impact of higher prices on entitlement volumes, OPEC quota effects and divestments, production was up almost 3%. For further data on regional volumes, please refer to the press release and IR supplement. Moving now to the downstream financial and operating results, and starting on slide 17. Downstream earnings in the first quarter were $1.6 billion, up $487 million from the first quarter of 2011. Margin effects decreased earnings by $40 million. Continued benefits from our refining optimization activities contributed to the positive $210 million in volume and mix effects. Other factors, primarily higher gains on asset sales, increased earnings by $320 million. Moving to slide 18. Sequentially, first quarter downstream earnings increased by $1.2 billion. Improved industry refining margins contributed increased earnings of $840 million. Volume and mix effects decreased earnings by $70 million. Other factors increased earnings by $390 million, largely due to higher gains on asset sales and favorable foreign exchange effects. Turning now to the chemical, financial, and operating results, and starting on slide 19. First quarter chemical earnings were $701 million, a decrease of $815 million versus the first quarter of 2011. Lower margins decreased earnings by $520 million, especially in Asia Pacific and Europe, while volumes and mix effects were flat. Other factors decreased earnings by $300 million, reflecting higher planned maintenance expense and the absence of favorable tax items. Moving to slide 20. Sequentially, first quarter chemical earnings increased by $158 million, driven by stronger demand for specialty products. Margin effects increased earnings by $50 million. Volume and mix increased earnings by $60 million, while all other items increased earnings a total of $50 million. While the first quarter continued to show cyclical weakness in Europe and Asia margins, ExxonMobil continues to leverage feed advantage, integration, cost discipline, and premium product offerings to strongly position us throughout the chemical business cycle. Moving to slide 21. ExxonMobil's first quarter financial and operating performance was strong and reflects the ability of our business model and competitive advantages to deliver strong results. As we continue to focus on operational excellence, deploy high-impact technologies, and leverage our unparalleled global integration, ExxonMobil remains well-positioned to maximize long-term shareholder value. That concludes my prepared remarks this morning. 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 touchtone 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'll take as many questions as time permits. Once again, that is star 1. We'll pause for just a moment. Take our first question from Doug Terreson with ISI Group. Good morning, David. Morning, Doug. How are you? I'm doing fine. My question's on the big increase in the dividend, and specifically at the analyst meeting, Rex seemed pretty clear that a more balanced approach to distributions might be forthcoming. But on this point, the size of the increase represents a fairly marked departure from the 6%-7% annualized growth rate you guys have provided over 5, 10, and I think even 15 years. So my question is whether or not you could provide some color on this change, and specifically how we should consider it in the context of overall dividend policy at ExxonMobil. Yeah, Doug, that's an excellent question given our announcement yesterday. Let me start with your last comment and move backwards from there. Okay. We've really had no change in our dividend policy. The policy remains the same, as does our total allocation of cash generated by the business. We do have a continued trend in dividend increases, as we have said before. If you go back over a long history of the company, we have in other quarters had fairly significant dividend increases. Again, no change in policy. But as we said at the analyst meeting, we are always evaluating the dividend policy and our cash distributions and studying how things are going. And the board decided yesterday to make the increase they did. But you also notice that our share repurchases remained at the $5 billion level. Yep That you saw across last year. I would say the strategy remains the same, invest in that very robust investment program we have, and you saw our first quarter CapEx very strong as those projects proceed. Have a continuously growing dividend, and then take the balance of the cash and buy the shares. And that policy and strategy, I think continues on. Okay, great. Let me just ask you one more question. There's been a lot of cross currents about the position in Iraq and specifically Exxon's current license, the strategy in Kurdistan, and eligibility and/or interest on the upcoming licensing round. Could you provide an update on that position which covers these items to the degree possible, David? I really cannot comment a lot on that other than to say the contracts that we have in place, it is our intent to honor and fulfill those contractual obligations. I will note, in the south, we reached another milestone at West Qurna, where production has reached right at 400,000 barrels a day, and we are very pleased how that effort is coming along and the progress we are making there. We continue to develop the field and do the things that we committed to do. Progress continues, but other than that, I really would not have any further comments. Okay, David. Thanks a lot. Thank you. And now we'll hear from Doug Leggate with Bank of America Merrill Lynch. Thanks. Good morning, David. Good morning, Doug. How are you? Not too bad. I have a couple also, if I may. You mentioned on your prepared remarks about the higher E&P tax rate. I'm wondering if you could just give us a little bit of color as to why that was, if it was just mix effects and what the driver was. In the context of the same issue, you also mentioned underlifts in the international portfolio. It's unusual for you to mention that, I guess, to the extent that it was material. Could you quantify that for us, either absolute or on a per barrel basis? Thanks. Sure. I'd be happy to answer both of those, Doug. First of all, let's start with the tax rate. You got the right word. You said mix. We have, and it's a number of mix effects that we saw across the first quarter. One of those that goes unmentioned is really the difference in a lot of the crude prices around the world. People tend to focus in on Brent and WTI, but there was a lot of variability. For example, the Middle East crudes tended to do better than those markers. Some of the Canadian crudes, particularly the heavier crudes, tended to do less. You also have different fiscal regimes in each of these countries. Frankly, we saw some of the highest realization increases in countries with higher tax rates and some of the lower than average increases or even decreases in countries with lower tax rates. That mix there and then the corresponding mix of where your earnings were generated that uptick in this quarter on the tax rate. When we talk about the underlifts, they were a factor this quarter, so maybe I'll go ahead and give some specifics here. In the first quarter of 2012, on an absolute basis, we were underlifted about 45,000 barrels a day. Last year, in the first quarter, we were actually overlifted by about 18,000 barrels a day, so the delta quarter-on-quarter was about 63,000 barrels a day. All of that underlift was in either West Africa or the North Sea, which tend to be some of our higher margin areas. The impact was actually quarter-on-quarter a little bit bigger sequentially, and so let me provide those numbers to you. Again, on an absolute basis, we were 45,000 barrels a day underlifted in the first quarter. As I mentioned, last quarter, we were actually overlifted about 37,000 barrels a day. You might recall across last year, we talked about quarter-to-quarter we were a little underlifted, and we made a bunch of that up at the end of the year. So if you take the 45,000 we were underlifted in the first quarter, and the 37,000 we were overlifted in the fourth quarter, sequentially we were down about 82,000 barrels a day. Again, all of that was in West Africa. So it's a bit unusual that you have that level of a lifting timing effect. But it did occur in the first quarter, and as you would guess, doing the math, it did have an impact on our reported earnings. David, would you be able to quantify the net income impact, or is that not something you want to get into? No, I don't have the net income effect on that. But again, as I mentioned, those are some of our higher margin barrels, and you can probably use your own estimates and come up with a number, but I don't have one for you today. We'll figure it out. Thanks a lot, David. I appreciate it. Thanks, Doug. Moving on, we'll go to Robert Kessler with Tudor, Pickering, Holt & Co.. Morning, David. Morning, Robert. Congratulations again on the Rosneft exploration JV. I wanted to go back to that for a minute. Your recent presentation and that of Rosneft highlighted or focused extensively on the oil prospectivity of the Kara Sea. I'd say, what about gas? By that I mean estimates from, say, the USGS and others place more discoverable gas potential in the area than oil. To the extent that you discover natural gas, do the agreements contemplate and does the fiscal structure allow for economic development of the gas? Yeah, that's an excellent question, and I'm glad you highlighted to begin with the progress we made because we really have made substantial progress. I think in the meeting we had last week, the term historic was actually used, and so we're very pleased, as are our partners in Rosneft, with the progress that we've made. I know there's a number of estimates out there in terms of the prospectivity in the Kara Sea. I think I've seen some different ones. The one you've mentioned, I think WoodMac has some numbers out there. Clearly, there's oil and gas potential out there. I don't think we know yet how to assess that. Really, that process is just getting underway. But again, as we said at the meeting, we are highly encouraged by the prospectivity on the oil side because of the extension of the prolific West Siberia basin plays that are already in existence and are already producing. That is what lends that. Looking forward, it is really premature to start discussing the contract details or arrangements or fiscal terms and that sort of stuff in detail. I would just point out again, for those on the call that are not as familiar, our position in the Kara Sea is equivalent in size to basically the North Sea and all of the leased acreage in the Gulf of Mexico. Again, a huge area of land, over 30 million acres, highly prospective. But again, under some rather harsh conditions, challenging environment to work in, and will require all of the technological and operational capabilities of the two partners to explore that resource, and should it be successful, to then exploit those resources and move forward with development and production. We have a lot of experience in the Arctic, even in Russia. Again, if you just look at the parameters and the vectors, we are encouraged by the progress. We are certainly excited and looking forward to the joint venture as our partners. In particular, as I mentioned, getting the seismic activity underway and preparing to drill our first wells here in the next 2 to 3 years. Thanks, David. The scenario that was presented in terms of potential FID date and potential first production, both those were presuming this was an oil discovery that would be made. Is that right? I think that is generally correct. Again, though, I would just caution on looking forward. There is a lot of work to do, a lot of effort to be done here. I do not want to really start getting into specifics about FID dates and production and that sort of thing, other than to say the schedule that we have in front of us, which is really getting that seismic underway this year, developing that drillable prospect inventory, siting that first well, and getting that well done in what industry perspective-wise would be a fairly short timeframe. Again, we are going after it aggressively, but this is true frontier exploration, and we will certainly be disciplined and diligent in our approach. Again, it is early days. I think we will focus a little more on the prospectivity and potential and a little less on what some of those specific dates might be in the outer years. Understood. Thanks very much. Thank you very much. Morgan Stanley's Evan Calio has our next questions. Morning, David. How are you? Morning, Evan. How are you? I guess good afternoon. It's flying by here. A question on Kearl. I appreciate your comments and progress update. I know you guys have secured a transportation solution, but can you provide more color on the planned route to market so we can better understand potential relative realizations versus waterborne crudes? I know you mentioned earlier they've been quite lower than others. Yeah. If we're thinking about the initial phase, the first phase that's coming on this year, I can tell you we already have placement for that first phase. So it's not an issue. We have multiple options within our own refining circuit to begin with as well as some other options. But basically, we're looking to place those first barrels with existing infrastructure and routes. Again, the bulk of that will likely find its way within our own system. But we have some other options. I think what's important to know is that we can start up Kearl, take it up to its full initial production of 110,000 barrels a day without any concerns over logistical constraints. Okay, good. Secondly, on Argentina, have your plans, pace of activity, or thoughts changed at all in Argentina following the YPF nationalization? I know you have almost a 900,000 acre position and curious to see how you're thinking or accounting for any potential investment risk there. Sure. Let me start out by saying that our position, ExxonMobil, and our activity down there has not been affected by some of the recent activities that you mentioned that have occurred down there. Our exploration activity is continuing. In fact, I can tell you in the first quarter, we did complete our first two wells and get those down. We're in the process here in the second quarter of fracking those wells, and we'll be testing them in the second quarter. So those plans continue and the objectives are being met. As you mentioned, we have a very large acreage position there. We're encouraged by the early results that we're seeing down there and look forward to profitably moving on with that venture. Having said that, of course, we are monitoring events that are occurring down there and what's happening, and we'll take all of that into consideration. But as we sit here today, we're meeting the objectives we set for the year, and plans are continuing. Again, we have a very long, successful history in Argentina, and going forward, got a great set of acreage down there. Again, we continue to work on that per our plan coming into the year. Mm-hmm. Have you had contact with the government and have some confirmation and, or is there any update on dialogue going there of your importance to the development of that resource? No, I don't have anything specific to identify. Obviously, in any country where we have a lot of activity going on and investments, we're always in contact and dialogue with the appropriate government agencies, as well as our partners. I wouldn't look for anything specific out of any meetings or contacts. Those are ongoing, just as they always have been. But wouldn't have any specifics to offer other than normal conversations that go on as we continue to really look at what we have down there and put together our plans and move forward. All right. I appreciate it. Thank you. Thank you. Now we'll hear from Arjun Murti with Goldman Sachs. Thank you. David, a couple questions regarding North America gas potential. ExxonMobil has a successful and large global petrochemicals business, global LNG business. The petrochemicals is focused on Asia and some of the Middle East growth. Can you comment on whether you see your now large domestic gas position is creating opportunities on both the export of LNG from the U.S. or potentially the Western Canada, and/or coming back to the U.S. in terms of some of the petrochemical expansions which you guys have otherwise focused on in the rest of the world? Do you see that as more of an opportunity going forward for you, and/or how do you plan to take advantage of that? Thank you. Arjun, that's a good question. Of course, behind that, it all starts with some of the obvious competitive advantages that we have across the entire space that you covered. Our large prolific gas acreage that we have in the U.S., the advantages we have certainly and have already demonstrated and you're seeing in our U.S.-based chemical business and of course our global position in LNG. So given that competitive advantage background, I don't think it'll come as any surprise to you that we're studying and assessing the very opportunities that you referred to. I don't have any specifics to offer you again other than to say we do have some advantages from all the way through the integration of resources into products. As we're always doing, we're thinking about how to optimally develop those, take advantage of the acreage position we have, the resource potential we have, the technology, the marketing advantages, et cetera, to again on an integrated basis exploit those resources. So any ideas you have and are thinking about and the things you read others are doing, you can rest assured we got folks looking at that and studying that as well. Maybe just a related question, can you talk about any update on your activities in the Marcellus and Utica as well as the Bakken in terms of maybe how the rig counts are trending and what you're expecting to do here over the rest of this year? Thank you. Sure. I would be happy to. Let me start with the Bakken and back up a little bit because that is an area where we have been over the last many months increasing rigs, and we have continued to increase our rigs. We have now got eight operated rigs running in the Bakken, and that is progressing very well, and we are encouraged by that. In the Marcellus, we have got five rigs operating. Actually, we got four rigs operating, and as you know, we have got just under 700,000 acres in the Marcellus and another 87,000 in the Utica, and we continue to progress there. But I can tell you overall, when you are looking at our rig count and what we are doing, I think it is important to kind of step back and think about what we are doing overall. You might recall across most of last year or so, we tended to have, I recall, 70, 72 rigs running in total. We have got about 64 on average in the first quarter. We are running 61 rigs today, and we have continued to shift those to the liquids rich plays that I mentioned, really focusing on the Bakken, the Permian, the Ardmore that I mentioned there. We are looking at and getting ready to plan some wells, get some wells down in the Utica. All of that is going well, and again continuing to acquire liquids-rich acreage at attractive prices and shift our rig fleet over to those areas while minimizing the incremental exposure to dry gas wells. That is great. Thank you so much. Thank you. Now we will hear from Iain Reid with Jefferies. Hi, David. Good morning. Hi, Iain. Good morning. Can I come back on the production in Africa? You talked about the underlift, but if you add that back, you still got a fairly substantial fall from the first quarter of last year in your African production. I think you said PSC effects, you have been through some threshold effects. Is that right to say that the kind of 50,000, 60,000 barrel a day decline ex the underlifts is due to threshold effects, profit oil or cost oil? Yeah, let me come at it a different way. Remember, the production that we list is the production, and the underlift is really just the sales. If you come back to just the Africa production decline that you saw in the supplement between the first quarter of last year and the first quarter this year, the bulk of that is accounted for by the entitlement effects that I mentioned, mostly the price and spend, but a little on the net interest side. Everything else kind of washed out. Okay. This is production, not liftings? Yeah. Yeah, thank you. Let me clarify that. What we show you in the supplement, that's a production number. Okay. Again, we had some project ramp-up that I mentioned, and we also had some better downtime performance, I'm pleased to say. That was basically offset mostly by decline. The impact you're seeing there really is the impact of higher prices on our entitlement volumes. Are we talking about Angola mainly here? Is it possible to say which fields, blocks 15 or 17? Well, a lot of it's Angola, but it's also Nigeria and some other places. Of course, our large producing operations there are blocks 15 and 17. Okay. Just thinking more generally about second quarter production. You've got some maintenance, I believe, in Angola coming up. Maybe a little bit of field ramp-up at Usan and Pazflor. Are we looking generally around the same sort of level of production in the second quarter as we saw in the first quarter? Yeah, I really don't have any guidance to give you on second quarter production. No real specific events. We do see the projects continuing to ramp up a bit, but I really don't have a real forward outlook for you. Okay, David. Could I just ask one more? Sure. You mentioned a couple of times asset sales affecting earnings, yet there's nothing in the special items here. Is it possible you could tell us what the absolute asset sales was in the first quarter relative to the first quarter of last year in terms of the impact on earnings? Sure. If you're looking across the total corporation, as we mentioned in the press release, the absolute earnings associated with asset sales in the first quarter of 2012 was about $400 million, and that was generally all in the downstream. If you look compared to the first quarter of 2011, the number was about the same, about $500 million. But there, the bulk of that was in the upstream. You had kind of a switch there. The key variance that you see in our sequential earnings as we go from the fourth quarter of last year to the first quarter of this year, the total earnings from asset sales in the fourth quarter last year were about $1.4 billion. About $1.1 billion of that in the upstream and about $300 million of that in the downstream. The big sequential impact you see is in the upstream, and that's really the absence of that significant divestment that we had last quarter. Okay. I would also mention- Okay, thanks very much. Yeah, let me just mention just to be clear, in the downstream, the asset sales that we had in the first quarter related to the previously announced divestments in Malaysia and Central America. We have not booked anything in Japan, as we mentioned last quarter. That will be later in the year. Thanks, David. Thank you. Now we'll open the floor up to Paul Cheng with Barclays. Hey, Dave. Good morning. Paul, how are you today? I'm very good. If I could, I was looking at your cash flow statement. On the working capital and other is a positive swing of $6 billion. That seems to be a big number, even for the size of Exxon Mobil. Is that related to the timing of taxes payment or anything like that? Or maybe my question is that, should we assume that is here to stay or that at some point in the later year it's going to get reversed? The sec- Yeah. Let me answer that one first, Paul Cheng, and then I'll let you go to the second question. That's actually very straightforward. During the first quarter, that we saw a big decrease in working capital, and that was literally all due to higher payables. We have some other ins and outs, but the real net effect you're seeing there is a fairly decent increase in our payables accounts. Oh, you said related to crude purchase? Yeah, that's related primarily to crude purchases, and of course that's price driven. As you saw, the prices ramp up across the quarter such that when you got to the end of the quarter, you had some pretty high prices. But again, nothing really out of the ordinary if you look at the quarter and you look at what prices did. But I'm glad you asked the question because that is the impact you're seeing there. Great. In Woodford Ardmore, what is your current production? I know you normally don't want to go down to too much granularity in terms of what is the well production one way, that kind of thing. Can you also tell us what is the split between, say, the black oil condensate, NGL, and natural gas in that play? If there's any rough estimate on your 30-day IP that you've been seeing on those? Yeah. Paul, I'll be consistent with your expectations and just say, no, I'm not prepared to give that level of detail today. I think what's important is not necessarily the actual production that we're generating there. What's really important is the effort we have underway now to delineate that acreage, to analyze what we have, and really put together that comprehensive long-term exploitation and development plan that we have. That's what will deliver the volumes, and the rates, and the earnings down the road. As we sit here today, I think what's important, we're adding acreage. It's very attractive acreage. If you had a jigsaw puzzle of that area, you'd see that the things we're adding are plugging right in to adjacent properties that we already had. So the acreage position I mentioned isn't just an acreage position. It's a mostly contiguous acreage position, which as you would guess gives us really good opportunities to optimize around the development. We are seeing nice increases in production as the wells are coming on stream, and we're encouraged by those results. But our focus is less on what today's production is, but getting the rigs down there. I think I mentioned we added 2 more rigs this quarter to the Ardmore. So we've now got 10 running, and we're working on that area. As the actual production goes into sales later on, we'll be in a better position to give more information. Dave, can I sneak in a quick question? Sure. Poland, how many additional wells you plan to drill this year? Yeah. If you take a look at our Polish position, I think I mentioned last quarter the wells that we had drilled and how those turned out. I will tell you that during the first quarter of this year, we did acquire a fourth 3D seismic activity. The processing of that seismic is ongoing, and the analysis we get out of that compared with the learnings we got from the wells that we drilled will really give us an all-inclusive set of results that we can evaluate and then plan our go forward plan. But I got to tell you, the go forward plan is really dependent on the 3D seismic, and again, the real geoscience evaluations and evaluations that we will do are really going to drive our future plans, and those just aren't set just yet. Thank you. Thank you, Paul. Now we'll move on to Blake Fernandez with Howard Weil. Good morning, David. Hi, Blake. I wanted to go back, if I could, on two issues that you covered previously. One being the dividend, and the second Russia. On the dividend, if I look historically, it's around this time of year that the board basically sets the policy for the year. Is it fair to think that the dividend will remain at this level for the balance of the year, or do you think that we have an opportunity to reevaluate and potentially increase further in a later quarter? Yeah, Blake, that's a good question, but I really don't have a comment or wouldn't want to try to speculate or forecast what we might do going forward. I think, again, we did raise the dividend yesterday by 21%. Policy's unchanged if you look from a macro perspective, but I really wouldn't want to try to speculate or forecast anything on a go forward basis. Fair enough. The question on Russia. I'm just curious if you could talk a little bit about how you arrived at the North American assets to contribute to the JV. When you look at Exxon's portfolio in the U.S., obviously you've got quite a few options. I'm just curious on the Cardium and Delaware, was it just similar geologic characteristics, or was it more financially motivated? Any color you could give would be appreciated. Sure. I'd be happy to provide a little more color on that. If you look at the assets that we're talking about in terms of what our partners would get here in the U.S., it's actually a variety of a number of high-quality assets. I mentioned the Cardium, a very attractive tight oil play for us where we've got wells going down and we're drilling. We talked about West Texas and some of the unconventional oil plays we have going on there. And of course, the ability for Rosneft to improve their understanding of the technology that's at work out there and some of the practices we have and that we're doing to optimize the development of that is important to them. As I talked about, as we learn about the unconventional resources together, what we have in Canada, what we have in the U.S., what they have in Western Siberia, there'll be a lot of learning out of that. I also mentioned the Gulf of Mexico, where they're going to have an opportunity to farm into 20 blocks. As you know, we have been expanding our own activity in the Gulf of Mexico, have had some very nice success recently. So it would certainly not be a surprise that those would be attractive acreage opportunities for them. Again, I think you have to step back and look at this partnership. It's just the way we described it. It's a strategic agreement for both parties. It allows us to bring to the table, each of us, very high quality prospective resources, all of which rely on state-of-the-art and forward-looking technology applications, and bring together the best of both companies, and also in the interest of both companies, going forward. We are talking about other opportunities elsewhere around the world. Again, I keep coming back to the term strategic cooperation agreement, because that is really what it is all about. You will see that as we move forward. Thank you, sir. Now we will hear from Edward Westlake with Credit Suisse. Hey, good morning, David. Thanks for the question. So strong cash flow, good returns, but I guess there is still some criticism of Exxon’s overall liquids position in North America, and you are lowering rig count and shifting to some of the liquids plays you have. Can you give some color on the ability for Exxon to really move the needle in terms of acquiring acreage outside of the Woodford, Ardmore, the Cardium, and Viking that you are talking to? Yeah, I think it would be fair to say, Ed, it's really kind of both. We're obviously taking advantage of opportunities, again, to concentrate acreage where we already have a position, and those efforts are bearing fruit. Of course, as you get bigger and more concentrated positions, you've got a real opportunity to better the, again, the analysis and exploitation of those resources. Moving the needle, there's certainly opportunities, we believe, for that, however you define moving the needle. But those are really going to come, again, with a very deliberate, disciplined, analytical approach to how we go about doing this. I think as I mentioned last quarter, we're very fortunate to have the financial strength the company does and the flexibility to be able to go after these things in a disciplined, diligent way without worrying about paying the bills at the end of the month. We continue to progress in that arena. We are looking at a broad range of other opportunities that are out there. I can't give you the specifics yet because we're still in the evaluation phase, but there are a number of those out there in North America and frankly, in other areas. But I'd be remiss if I didn't also remind you of the recent success we've had with liquids in the Gulf of Mexico with the big discovery we had there last year. So when you look across North American liquids opportunities, it's not just the unconventional oil potential, but it's also the potential that we have in our attractive acreage position, in the Gulf of Mexico. Then broader speaking, I think it's important, and you raise a good point when you see the decline in our liquids production recently. I'll just reiterate one of the comments we made at the analyst meeting in March. If you look at the projects that are going to start up between now and 2016, I think the number we quoted was about 80% of that production will be liquids. So whether it's the Kearl project, whether it's the Africa projects, some of the other things we got going on, we have a strong portfolio of liquids projects in development, and also the pipeline of opportunities on the exploration side is quite robust. So I think if you continue to look a little longer term, I think we're going to be in really good shape, and we're looking forward, as I mentioned in my remarks, to getting the projects up that we have on the plate for this year. Then in particular, when you get in that 2014-2016 timeframe, bringing some of those big projects along as well. Thanks very much, David. Citigroup's Faisel Khan has our next question. Thank you and good morning. Good morning, Faisal. If I can go back to Iraq, in your prepared remarks or press release, you talked about a ramp-up in volumes in Iraq and kind of getting to your contracted volumes. Can you discuss a little bit about the infrastructure you're placing on the ground to get up to those contracted volumes that you guys have? Faisal, help me out a little bit. In particular infrastructure, what'd you have in mind? Pipelines and water injection facilities, stuff like that, processing facilities. I guess the basic midstream and infrastructure designed to deliver that oil to market. Sure. It's a couple of things. If you're looking in the field in particular, of course, it's important for us to get the flow lines in and do some of the bottlenecking that we can do and thus get some production up that way. If you look in broader at the infrastructure in terms of the Common Seawater Supply Project. Some of the lifting capabilities, particularly there was a major ramp-up in the capability to take oil out of the country last quarter. There's a number of projects going on. Again, some are local and help get the production up. Some are broader. Those are progressing as well. I really don't have any specific comments in terms of timing of some of the other larger infrastructure projects. But those are progressing as well. Okay. This is the last question from me. On non-U.S. downstream in the quarter, if I strip out kind of the gains on asset sales and also Imperial Oil reported a pretty nice number in refining as well. If I take that out, it looks like outside of Canada and the asset sales that non-U.S. downstream reported fairly low earnings. Can you talk about what's dragging those results this quarter? If you're looking at the downstream earnings, you're really talking about quarter-over-quarter. Is that your emphasis, first quarter 2012 versus first quarter 2011? Yeah, that's right. Yeah. We had a number of things. I think the one I'd probably note, if you look at the margin impact that we showed slightly negative relative to some higher industry refining margins that you see quoted. We had a number of price timing effects on our feed slates into the refineries that had a negative impact there, and probably would've given you a little impact there that you weren't expecting. Nothing out of the ordinary. It was positive in the first quarter of last year. We had the absence of that in the second quarter. So quarter on quarter, you kind of saw that. But I'll tell you, ex those effects, things came in just about as we expected. Okay, fair enough. Thanks for the time. Appreciate it. Now we'll go to Allen Good with Morningstar. Good morning, David. Good morning. I wonder if I caught you correctly, you said 87,000 acres in the Utica. That seems to be up from the 75 you reported at the Analyst Day. I was just curious if you could confirm that. Then you talked about the acreage adds in the Ardmore. Are there any other liquid-rich plays that are currently interested in and you've been adding acreage in during the quarter? Yeah, let me just confirm, first of all, the number I gave you of 87 is correct, and that is up from the 75 that we mentioned at year-end. We have been incrementally adding some attractive acreage there as we've gone across the quarter. Okay. Then as far as the discovery in Tanzania, I just wonder, does that change Exxon's outlook there in East Africa? Would there be any potential there for additional acreage adds or maybe farm-ins with some already operators there in the region? Because it seems like it's sort of a light portion of your portfolio currently, and obviously the Tanzania discovery is a positive there. Just wonder, sort of what's the outlook for Exxon in that region? Sure. Let me first kind of hit the overall that you mentioned. There have been a number of discoveries announced by industry in that area over the last several months. We are very pleased to have the position we have in the block that we farmed into, and it's a very nice discovery. I think I mentioned about 5 TCF of recoverable gas. So that's very positive for us. We are very interested in appraising that prospect further and have some plans in place to do that. In terms of going forward and looking at other things, I wouldn't be any more specific other than to say we're always looking for good opportunities. We were looking when we found this one and pleased to have it. So without being specific or really any departure from past practice, we're always looking for good opportunities. This is one. We are pleased to have it. We will probably get our next well underway here in the second quarter to further appraise that prospect. I will tell you, in terms of additional opportunities, there are a series of additional structures on the block we have to take a look at and do some more work and appraise. So more to come from on that block with our partner, Statoil. Again, we are both very encouraged with this. Lots to do on that block, but always looking for additional opportunities. Okay. Thanks for that commentary. Thank you. Argus Research, Philip Weiss has our next questions. Thank you. Good morning, David. Morning, Philip. How are you? Good. How are you? All right. Most of my questions have been answered. I just had one small one. On your profitability per barrel was down relative to the movement in realizations. I just wondered if that was a function of the underlift or if there is something else going on there. It is a number of the things I mentioned. Certainly, the underlift would be a big component because you have the reported production that you are dividing the earnings by, and that is why I really wanted to give you the detail on the underlift. It is a big impact. Also, the tax rate impact I mentioned because of some of the mix that we saw, of course, had an impact on calculated unit profitability. Other than that, in the quarter, we did see a little higher OpEx, including some exploration expense higher that you would have seen in the supplement that we gave you. But again it is really the U.S. gas price on the North American side, and then the mix that we saw overseas and some of the other factors that were the real driver there. Okay, great. Thanks, David. Thank you. I believe we have time for one more question. Okay, and Pavel Molchanov with Raymond James has our last question. All right. Yeah, thanks for squeezing me in. Can you give an update on the status at PNG LNG? There has been some press reports about local conflict with residents, and construction, I believe, was suspended for a period of time. Sure. Let me give you a progress update on how we are doing in the first quarter. We have done some additional drilling and a number of other efforts associated with the project. Everything from the civil works to the work we are doing on the gas conditioning plant, and just a number of progress items related to the pipelines, the plant, and all of that. So that project is really progressing on schedule, and we are very pleased with how things are going there. You have seen in the press some of the issues around unrest. It is one of the challenges we have with the project. Each large project we seem to do around the world has its own unique set of challenges. So there is nothing out of the ordinary here. We are managing that situation in conjunction with the local communities and with the government. As you would guess, there has here and there been some impact at the individual work sites where some of this activity has occurred. I can tell you, if you step back and look across the whole project, and it is a complex project, we are on schedule. We're progressing as planned. There's no change to our outlook for a 2014 startup of that very attractive project. Okay. Can you just say if construction is currently ongoing at the LNG site? Oh, yeah. Construction is ongoing. Yeah. We're continuing to progress all phases of the project. Okay, very good. Okay, thank you. I want to thank everybody for your time today and the excellent set of questions. Thank you, and look forward to visiting with you again next quarter. Ladies and gentlemen, that does conclude our conference call for today. Again, thank you for your participation. You may now disconnect.