Earnings Call: Q2 2012

Jul 26, 2012

Summary

Q2 earnings rose to $15.9B, substantially boosted by Japan restructuring and divestment-related impacts. Downstream gains offset lower upstream realizations and volumes; cash generation supported $7.7B of shareholder distributions.

Today, and welcome to the Exxon Mobil Corporation second quarter 2012 earnings conference call. As a reminder, today's conference 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 second quarter earnings call and webcast. The focus of this call is Exxon Mobil's financial and operating results for the second 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 result. Global economic growth slowed in the second quarter, primarily due to continued weakness in Europe. The U.S. and Japanese economies are also expected to show declines from first quarter levels. China growth, while still robust, continues to weaken from prior year levels. Energy markets were mixed in the second quarter with lower crude oil and natural gas prices, while industry refining margins increased from the first quarter. Although U.S. chemical margins remain strong, Europe and Asia commodity margins continued at near bottom of cycle conditions. Turning now to the second quarter financial results as shown on slide 4. Exxon Mobil's second quarter 2012 earnings were $15.9 billion, an increase of $5.2 billion from the second quarter of 2011. Second quarter earnings included a net impact of $7.5 billion associated with divestments and one-time tax-related item. Earnings per share for the quarter were $3.41, up $1.23 from a year ago. The corporation distributed $7.7 billion to shareholders in the second quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was distributed to purchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the third quarter of 2012. CapEx in the second quarter was $9.3 billion, down 9% from the second quarter of 2011, primarily due to the absence of acquisitions made in the second quarter of last year. Our cash generation remained strong with $13.9 billion in cash flow from operations and asset sales. At the end of the second quarter of 2012, cash totaled $18 billion, and debt was $15.6 billion. The next slide provides additional detail on second quarter sources and uses of funds. Over the quarter, cash decreased from $19.1 billion to $18 billion. The combined impact of strong earnings, depreciation expense, working capital, and the benefit of our ongoing asset management program yielded $13.9 billion of cash flow from operations and asset sales. The $9.6 billion in working capital and other primarily reflects eliminations of gains on asset sales, increased working capital, and tax items. Uses included additions to plant property and equipment, or PP&E, of $8.3 billion and shareholder distributions of $7.7 billion. Additional financing and investing activities increased our cash by $1 billion. Moving on to slide 6 and a review of our segmented results. Exxon Mobil second quarter 2012 earnings of $15.9 billion increased $5.2 billion or 49% from the second quarter of 2011, primarily due to gains from asset sales, partly offset by one-time tax item. Upstream earnings decreased $183 million, while downstream earnings improved by $5.3 billion. Chemical earnings were up $128 million, and 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 second quarter 2012 earnings increased by $6.5 billion compared with the first quarter of 2012. Moving next to second quarter business highlights and beginning on slide 8. We continue to advance our global portfolio of high-quality upstream projects. In Angola, the Kizomba Satellites Phase One project achieved first oil in May ahead of schedule. The initial phase has a peak production capacity of 100,000 gross barrels of oil per day and will recover a total of approximately 250 million barrels from the Mavacola and Clochas field. The development is located 95 miles off the coast of Angola in water depths of approximately 4,500 feet. Phase one of the project includes 18 wells with subsea tiebacks to the existing Kizomba A and B floating production storage and offloading vessels, thus optimizing the capabilities of on-block facilities to increase current production levels without requiring an additional FPSO vessel. In Nigeria, we completed the installation of three wellhead platforms as part of the Nigeria Satellites project. 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. We also completed the installation of the Arkutun-Dagi gravity base structure offshore Sakhalin Island in Russia. We are currently progressing pipeline tie-ins, with topsides installation scheduled for 2013. The project will have a peak production capacity of 90,000 gross barrels per day and is on schedule to start up in 2014. Construction is also progressing at the Papua New Guinea LNG project, which remains on schedule for a 2014 startup. The entire 250-mile offshore pipeline has been installed, and over 105 miles, or approximately 60%, of the onshore portion of the main gas pipeline have been welded. At the LNG plant, pipe racks and heavy equipment are being installed on the process trains, and piling on the jetty is complete. Additionally, mobilization and commissioning of the first two new drill rigs was ongoing during the quarter. The second rig is being mobilized to Hides, with drilling expected to begin later this year. Also during the quarter, two rigs began drilling at Hadrian North in the Gulf of Mexico to further appraise the resource. The results from these wells will be incorporated into the overall development plan. Finally, the Kearl initial development project is now 94% complete. All modules have been transported from the U.S., and integration of the modules into the plant facilities is progressing. The project is on schedule to start up later this year. Turning now to slide 9, we continue to make progress on our strategic cooperation agreement with Rosneft. In June, we signed agreements with Rosneft to jointly develop tight oil reserves in Western Siberia and establish an Arctic research center for offshore development. This agreement combines the strengths of our two companies, ExxonMobil's technology leadership in tight oil and unconventional resource development, and Rosneft's direct knowledge and experience of Western Siberia's geology and conventional production. In the near future, we will develop a work program for selected Rosneft license blocks, which will include geological studies and drilling, with drilling planned as early as next year. A pilot program will be established to determine the technical feasibility of developing these reserves. The Arctic Research Center will provide a full range of services to support all stages of our joint venture oil and gas development on the Arctic shelf, including ice monitoring and management, logistics, and the design of ice-resistant offshore vessels, structures, and Arctic pipelines. Safety standards will be a priority for the center, which will have its own special marine incident warning and prevention center. In addition, we progressed joint exploration activities in the Black Sea, where seismic acquisition is now complete. We remain on schedule to commence seismic acquisition in the Kara Sea later this year. Exploration drilling is expected to begin in the 2014-2015 timeframe as soon as prospect mapping is complete and a rig is contracted. Turning now to conventional exploration on slide 10. In the quarter, we achieved continued success in our conventional exploration portfolio. In Tanzania, we drilled a second exploration well with our partner, Statoil. As indicated by the operator, this well has confirmed a discovery of approximately 2 TCF of recoverable gas. This follows our first exploration well on the block, which discovered approximately 5 TCF of recoverable gas. We also made a gas discovery on acreage in northwestern Papua New Guinea and have commenced drilling of a second well in the Highlands. This exploration activity is designed to support expansion studies for a third train at our Papua New Guinea LNG project. Also during the quarter, we drilled our third well in Vietnam, which encountered additional gas. Results from this well are being evaluated. In light of the encouraging results in Romania, planning for further exploration activity is underway. We expect to begin acquisition of a new 3D survey on the Neptun license by year-end. Finally, we were high bidder on 22 blocks in the recent central U.S. Gulf of Mexico lease sale. Moving on to slide 11. We continue to advance our growing portfolio of high-potential unconventional assets in liquids-rich plays like the Bakken, the Woodford-Ardmore, and the Neuquén Basin in Argentina. In the Bakken, we have moved into a development phase across our roughly 400,000 net acre leasehold. In the first half of 2012, we turned 40 wells to sales, nearly double the pace of 2011. In the second quarter of 2012, our gross operated Bakken production increased by 60% over the prior year quarter. Since our entry into the play, we have more than doubled gross operated production to approximately 32,000 oil equivalent barrels per day. In the Woodford Shale in the Ardmore Basin, we completed a strategic bolt-on acquisition, adding 58,000 acres of leasehold and just over 4,000 oil equivalent barrels per day of production. This brings our total Woodford Ardmore acreage to approximately 260,000 net acres and expands our resource potential beyond the 600 million oil equivalent barrels previously estimated. In the second quarter, we utilized 10 rigs to delineate our acreage, evaluate optimal well spacing, and continue development activity. Moving to South America, we have drilled two exploration wells in Argentina's Neuquén Basin. Testing of the first well is underway. The second well is scheduled to be completed and tested in the third quarter. A third exploration well is also planned to spud during the third quarter. Our efforts are currently concentrated on defining the resource potential of our more than 800,000 net acre leasehold. Turning now to slide 12 on the North American chemical growth project. During the quarter, ExxonMobil Chemical filed permit applications to progress plans for a world-scale petrochemical expansion at our integrated Baytown, Texas complex. The project includes a new ethane cracker with up to 1.5 million tons per annum of ethylene capacity, which will feed two new 650,000 tons per year premium polyethylene lines situated at the nearby Mont Belvieu plastics plant. The proposed expansion capitalizes on the abundant and growing supply of North American natural gas liquids to economically supply the rapidly growing global demand for high-performance polyethylene products. These metallocene-based premium resins deliver sustainability benefits such as lighter packaging weight, lower energy consumption, and reduced emissions. Required government reviews and approvals are expected to take about a year, after which ExxonMobil will make a final investment decision. If progressed, a 2016 startup would be anticipated. Turning now to the Saudi Elastomers project on slide 13. During the quarter, the Kemya 50/50 joint venture partners, Saudi Basic Industries Corporation and ExxonMobil, announced the decision to proceed with construction of the specialty elastomers project at Al Jubail, Saudi Arabia. This continues a long history of ExxonMobil investment in the kingdom and represents a significant broadening of Kemya's product portfolio. The facility will have the capacity to produce up to 400,000 tons per year of specialty products, including synthetic rubber, thermoplastic specialty polymers, and carbon black to serve local markets, the Middle East, and Asia. Project completion is expected in 2015. Turning now to the Upstream financial and operating results and starting on slide 14. Upstream earnings in the second quarter were $8.4 billion, down $183 million from the second quarter of 2011. Realizations decreased earnings by $870 million due primarily to lower crude oil and U.S. natural gas realizations, which declined by more than $8 per barrel and $2 per thousand cubic feet, respectively. Production mix and volume effects negatively impacted earnings by $330 million, due mainly to the impact of lower entitlement volumes, base decline, and divestments, partly offset by the ramp-up of Nigeria and Angola projects. All other items, primarily gains from asset divestments and lower exploration expense, partly offset by one-time tax items and higher production operating expenses, increased earnings by $1 billion. Upstream after-tax earnings per barrel for the second quarter of 2012 were $22.12. Moving to slide 15. Oil equivalent volumes decreased by 5.6% from the second quarter of last year, mainly due to the impact of lower entitlement volumes, decline, and divestments. Volumes were positively impacted by the ramp-up of projects in Nigeria and Angola and less downtime. Excluding the impacts of entitlement volumes, OPEC quota effects, and divestments, production was essentially flat. Turning now to the sequential comparison and starting on slide 16. Upstream earnings increased by $556 million versus the first quarter of 2012. Lower crude oil and natural gas realizations negatively impacted earnings by more than $700 million, as crude oil realizations decreased by more than $10 per barrel, and average gas realizations decreased by $0.60 per thousand cubic feet. Production mix and volume effects decreased earnings by $480 million due to a decline in seasonal gas demand in Europe, base decline, and lower entitlement volumes, partly offset by the ramp-up of projects in Nigeria and Angola. Other items, including gains from asset divestments, lower exploration expense, and favorable ForEx, partly offset by one-time tax items, increased earnings by $1.8 billion. Moving now to slide 17. Oil equivalent volumes were down 8.8% from the first quarter of 2012, resulting from a decrease in seasonal gas demand in Europe, base decline, and lower entitlement volumes, partly offset by the ramp-up of projects in Nigeria and Angola. Excluding the impacts of entitlement volumes, OPEC quota effects, and divestments, production was down 7.6%. Year-to-date, oil equivalent volumes decreased 5.5% compared to the first six months of 2011. The first half of 2012 volumes associated with the 3% full-year decline outlook provided at the analyst meeting in March are shown on slide 18. Operational performance was slightly ahead of plan, benefiting from the early startup of the Nigeria Usan and Angola Satellites projects, and strong base performance. First half of 2012 prices, most notably in February through April, were higher than our March analyst meeting outlook basis of $111 Brent, and negatively affected first half volumes due to both permanent and price-related entitlements. In the second half of 2012, successful startup of several projects and continued strong base performance will support our 2012 volumes. Moving now to the downstream financial and operating results, and starting on slide 19. Downstream earnings in the second quarter were $6.6 billion, up $5.3 billion from the second quarter of 2011. The driver for the increase was a $5.3 billion gain associated with the Japan restructuring, which was completed on June 1st. This gain was partly offset by unfavorable ForEx effects, one-time tax items, and increased maintenance activities. Improved refining margins, mainly in the U.S. and Europe, increased earnings by $650 million. Moving to slide 20. Sequentially, second quarter downstream earnings increased by $5.1 billion, primarily due to the Japan restructuring and improved refining margins, partly offset by ForEx effects, increased refinery maintenance, and one-time tax items, and the absence of first quarter gains on asset sales. Turning now to the chemical, financial, and operating results, starting on slide 21. Second quarter chemical earnings were $1.4 billion, up $130 million versus the second quarter of 2011. Margins decreased earnings by $150 million, as lower commodity margins were only partly offset by improved specialty margins. Volume and mix effects decreased earnings by $100 million, mainly reflecting weaker demand in Europe. Other factors increased earnings by $380 million, which includes $630 million associated with the Japan restructuring, partly offset by unfavorable ForEx effects. Moving to slide 22. Sequentially, second quarter chemical earnings increased by $750 million, mainly associated with the Japan restructuring. Stronger margins increased earnings by $160 million, primarily due to lower feedstock costs. Volume and mix effects decreased earnings by $70 million, mainly due to weaker demand in Europe. Finally, moving to slide 23, ExxonMobil's second quarter financial and operating performance 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. 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 one on your touchtone telephone. We request that you limit your number of questions to two, so that as many may have an 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 one on your touchtone telephone to ask a question. We will take our first question from Doug Terreson with ISI. Good morning, David. Morning, Doug. How are you? I'm doing fine. My question's on foreign exchange effects, asset sales, and tax items, and specifically whether or not you have functional and geographical quantification on those items in Q2. I mean, there was a pretty large lump in the quarter, and just wanted to see if we could get a little color and segmentation. Why don't I start with the items in the $7.5 million? Okay. $7.5 billion. Yep. I'm sorry. The primary item in there was $6.5 billion associated with the Japan restructuring. Right. Okay. The segmentation of that $6.5 billion was $5.3 billion in the downstream, $600 million in chemical, $400 million in corporate fin, and about $100 million in the upstream. The balance of the $7.5 billion really related to gains on asset sales in the upstream, primarily Angola Block 31, and a number of tax-related items. Okay. Okay? Also in E&P business, there is commentary that several of the major integrated gas projects in Australia face cost overruns, that is, unless budget contingencies were appropriate at the time. So I wanted to get your insight into trends and investment performance versus budget in Australia, because ExxonMobil has been in the country for many years, and given that you have significant holdings besides integrated gas, you obviously hold a unique perspective. So any trends that you could highlight or provide insight into would be appreciated. Yeah. I will make a general comment and then for specific project updates, I would recommend that you Sure talk to the operator of any specific project. But in general, over the last couple of years, we have seen some foreign exchange issues with the Australian dollar as well as across the board, there have been upward cost pressures on labor, and I think those have been well documented in the industry. Other than that is all part of normal project management for us, and you have to find ways to offset those. I think the important thing on some of these large projects, in addition to cost management, is to ensure that the project stays on schedule and comes up on time and that generally is the focus. But again, if you had a specific project in mind, I would recommend you ask the operator for any specific update. Sure. Thanks a lot. We'll take our next question from Edward Westlake with Credit Suisse. Hey. Good morning, David. Morning, Ed. Just two quick questions. Firstly, buybacks. Obviously, you are still maintaining the $5 billion. You did get good sources and uses of cash from acquisitions. Draghi in Europe is making comments, which is helping the oil price. If we do see a slowdown, how do you think about the rate of buybacks being appropriate? If the earnings don't support the buybacks, do you see enough disposals in the pipeline to compensate? Ed, I really wouldn't want to comment or provide any guidance on forward expectations with regard to allocation of funds other than to say there's no change in our ongoing view of that. As you know, our first priority is fund all of our attractive investment opportunities. After that is to pay a growing dividend, and you will recall we did raise the dividend 21% earlier this year. After that, it's the share buyback to maintain our capital structure and return excess cash to the shareholder. So no change in our approach and we will see as the year goes along to how the cash flows turn out given the conditions in the market, but no change in our approach. Thanks. Just a specific one on the operations. Asia gas volumes have been pretty steady for a number of quarters until the second quarter of 2012. Was that maintenance or is that a PSC effect in terms of a tranche kicking in somewhere? Let me provide a little more clarity on that, because your question also gets to the main factor if you look at our volume recs and you look at the entitlement effects that you saw there. Really the impact is seen in Qatar. I want you to know that unlike the RasGas and Qatargas LNG trains, the AKG project, which as you know supports domestic gas sales, does operate under a development and production sharing agreement. During the quarter, that project became cost current, and that did impact both the volumes that you see in the region that we noted as well as the entitlement volumes that we talked about. As far as performance is expected in the region and all the countries there and the assets that we operate. Again, the real impact is AKG becoming cost current. And it is fair to think about domestic prices being lower than the other projects, so that would have a lesser impact on cash flow than the headline production? Yes, that would be a correct assumption. Thanks very much, David. All right. Thank you, Ed. I will now go to Doug Leggate with Bank of America Merrill Lynch. Thanks. Hi, David. Hi, Doug. How are you today? Not too bad, thank you. I wanted to go back to one of the events during the quarter, which was, I guess, your official exit from Poland, and I really just wanted to get your updated prognosis on shale gas in Europe generally, and where I'm going with this is, as one of the biggest producers obviously in Northwest Europe, what are the implications for you gravitating back towards exports of LNG in the Lower 48? I have a follow-up, please. Those are two distinctly different questions. When we look at Poland, we did drill and complete and test two wells, one in each of the two basins that we were in there. We did not have any demonstrated sustained commercial hydrocarbon flow from either of those two wells. So we have decided to end our exploration activities in Poland at this time. Now, as you look across Europe, there are a number of other opportunities and a number of other countries that people are looking at, including ourselves. So I wouldn't draw any conclusions in any one country or across Europe. It's early days. We have said often, as you look around the world at all the unconventional resource opportunities, they're all different. They're all in the early stages of evaluation, and it's going to take some time to figure that out. Now, I will mention, because we haven't talked about it in a little while, our holdings in Germany. As you know, we have a very large acreage position in Germany, and we continue to want to actively explore that. As you know, we've had some permitting issues there over the last year or so that has held that program up. I can tell you that the expert dialogue group that has been studying this issue for a while has reported their findings. Like many other similar studies and findings across the world, including the U.S., this group did not see any fundamental environmental or other risk aspects that would argue against the exploration and production of natural gas from unconventional reservoirs. So with that study out, we are in the process now of working with the regulators, particularly in the local areas, and the community at large, to progress our exploration plans and get the permits necessary to progress. So again, I think every country is different. Every unconventional resource opportunity is different, and it'd be tough to make any geographic conclusions at this time. Now, if we switch over to the potential for LNG exports out of North America, we are continuing to study those options, both in the U.S. and in Canada. As you know, we have vast unconventional holdings in both of those locations. We have a lot of optionality, a lot of flexibility. We do have some assets in the ground already to import LNG. We're continuing to study all that and look at our options and the economics, and more on that as time goes on. Thanks, David. I guess I was thinking that an outlook for European gas would impact your U.S. decision. That's why I thought it was one question. If I could try a second, it's a very quick follow-up. Sure On Doug Terreson's second half of his question, you didn't give the FX or the tax impacts by division. If you could, that would be really helpful, and I'll leave it there. Thanks. Sure. Let me first give you the foreign exchange impacts. If you're looking at the second quarter of 2012 versus the second quarter of 2011, we had about a negative $200 million delta on ForEx in the downstream and another two. David, I apologize for interrupting. Could you give us the absolute as opposed to the deltas? Is that possible? I don't actually have the absolute number, Ed. Doug, I'm sorry. The deltas, again, I think, if you're just looking in the recs, it's $200 million negative in the downstream. Okay and 200 in chemical, but I don't have the absolutes. All right. Thanks very much. Okay. Thank you. I will now go to Evan Calio with Morgan Stanley. Morning, David. Morning, Evan. How you doing? A question on Kearl. I know you mentioned the project start-up in the back half of the year. How should we expect volumes in 3Q and 4Q, and what's the volumetric ramp there in the start-up? Then somewhat related, I guess, I believe that the 50% goes to Exxon Mobil's refiners and then 50% into the market. I guess we should assume that you'll feed your own refiners first, and is there any feedstock change in your system as a result of that? Sure. Let me hit the status of the project first. It is progressing very well. As I mentioned, we are 94% complete. Got the modules in place that were in the U.S., and we are progressing towards a late start-up. That start-up is probably a December start-up, and our intention is to ramp up to 110,000 barrels per day of production from that. But to give you a quarterly number or a specific timing would be real difficult because, again, if you are not going to start up till December, it will not have a huge impact. What is the expected maybe trajectory to either kind of gross, that 110 gross? We will be ramping that up, obviously, from the time we start up into the next year. I do not have a specific ramp-up profile other than to say as safely as possible and with the operations running, we will ramp up to that 110 as quickly as possible. But I do not have a specific timeline for you right now. Great. On the feedstock? Oh, I'm sorry. The- Oh, I'm sorry. On the feedstock question, yeah. Yeah. The first thing I'd say is I wouldn't necessarily say we have a 50/50 mix of what's going to our refineries versus what's going to go into the market. The other part of your comment is correct. We will optimize, in general, the placement of those barrels. But certainly having the flexibility of our own refineries in Canada as well in the Midwest, we'll be able to optimize those first and then put the balance in the barrels. But that'll change depending on the market, which, as you know, has been fairly volatile recently. So if I gave you a split today, that may or may not be the split six months ago. But you're certainly spot on with your comment about us optimizing first into our refineries and then the balance going in the market so that we can maximize the value of all the barrels really across the whole refining circuit. Great. Thank you. If I may, just one other question. Sure. Thanks for the update on the PNG LNG project, and it sounds like you're really moving along well there. Can you remind us of how much gas, excluding, I guess, these recent discoveries, is behind that development? And are further discoveries necessary for potential expansion opportunities there? First, if you look at the trains, those are two trains with startup in 2014. As I recall, the total resource backing that up is about 9 TCF. Mm-hmm. Right. So you need additional discoveries likely to expand, right? Yeah. That's what I said earlier, that two things are going on. We are certainly studying the opportunity for a third train, and the positive news is we're having exploration success this year in drilling some wells, and we have an active exploration program ongoing with a lot of additional acreage that we have available to us. Sure. It's a positive story with the steel we got going in the ground now. It's a positive story on the exploration front. So we'll continue to focus on getting what we have up and running while studying for further expansion and optimization. Great. Thank you. Thanks for taking my question. Thank you for the question. We'll now go to Paul Cheng with Barclays. Hey, Dave, and good morning. Hello, Paul. How are you? Very good. Two quick questions. You've been quite active in the drilling in the Gulf of Mexico and have good success. Are you now all set with all your rig requirements for the next, say, one or two years, or that you may need additional equipment there? Well, if you look at what we're doing now in the Gulf of Mexico, probably the biggest thing we got going right now is the two wells that we're drilling simultaneously at Hadrian North as we continue to look at that resource. As we go on through the year, we are looking at the possibility of another well in the Gulf before year-end. But without talking about a specific rig line or what's contracted and what's not, what I could tell you is we do have flexibility around the rig fleet. We are planning for a sustained exploration program. And when we look at the opportunities and rig availabilities and the assets that we have under contract, I think we're well positioned to progress the program. I don't see any constraints or any hold-ups in terms of equipment availability. Dave, your current rig, the contract extend into, say, 2013 and 2014, or that is expiring this year? Paul, I really wouldn't want to comment specifically on rigs and lease arrangements and that sort of thing. Those are all part of the commercial nature of the business, and so really wouldn't want to get into any specifics on that. Okay, sure. The second question that I have to apologize, it's probably due to my ignorance. Given the low natural gas price over the last 12 months in the U.S., if the natural gas price stay at, say, the $2 to $3 per Mcf range, is there a circumstance that would force you guys to look at your proven reserve booking from the XTO, and also any write down possibility, or how's the accounting work from that standpoint? Paul, if we step back just a little, obviously that is a very large resource that we acquired in the XTO acquisition. Some of it is booked to proved reserves, but a whole lot of it is really in the resource base. When you look at prices and the volatility of those prices and what is going on, I do not think when you look at our outlook going forward, that we see ourselves really getting into the issues that you are talking about. Without getting into any specifics on accounting and reserve reporting, I am confident that if you look at that resource and what we have got booked now, and the conservative nature with which we tend to book proved reserves, I am not expecting there to be any issues in that area. Should we assume that the ceiling test, you will be allowed to use your own internal long-term price stack? Yes. If you look at that ceiling test, as far as I know, you do use your own long-term expectation for those prices. Is that okay? Thank you. I will now go to Blake Fernandez with Howard Weil. David, good morning. I had a couple of questions for you on two different projects. One is back to the Gulf of Mexico on Julia. I know there were some issues with the government a while back, and as I understand, you have worked that out and you have now retained the block. Can you just give us an update on, if I recall, it seemed to be a fairly large discovery. Any update on timing and activity out there? Sure. I would be happy to give you an update on that. As you know, we did drill that first exploration well in 2007. It was successful. We did have some issues with the Department of Interior around that license. I can confirm the comment that you made. Yes, those issues have been resolved. In fact, if I look across the second quarter, we are working on the development plans for that. In fact, we are really progressing the technical validation program at this time and front-end engineering and development. Late in the quarter, we did place some initial long lead equipment items. If you look at the whole broader schedule, we are progressing as rapidly as is appropriate. Again, we are already in the process of ordering long lead programs, working on the development plan, and the evacuation plan. That project is progressing. Okay, great. Thank you. The other one was actually on Tanzania. It sounds like you have got about 7 TCF discovered to date. I am wondering, for one, how much you need in order to justify development? Secondly, my understanding is the government will not approve multiple developments, so it is almost a bit of a race to see who is going to have the first-mover advantage. I am just curious if there is any update on your activity there. Yeah, let me hit the first question on the results in Tanzania. That has been, to date, a very successful exploration effort for us. We have said that the first well looks like we got about 5 TCF of developable reserves there, and then the second well looks like we got about 2, so for a total of 7 TCF. I can tell you we are continuing with our exploration activities. We got some additional seismic going on this year and may even put another well down before the end of the year. So that's all going very well. I wouldn't want to give a specific number in terms of what's required for an LNG project, because it could have multiple aspects to developing that, and so I wouldn't want to give a specific number there. In terms of the race to get a project underway, I'm not aware of any constraints on that program. It's still early days in that whole area of East Africa. As you know, there's been a tremendous amount of activity and some successful discoveries. But to start discussing order of projects and who gets there first and that sort of thing, I think it'd probably be premature to talk about that. Fair enough. Thank you, David. Thank you. Then I will go to Faisal Khan with Citi. Thank you, David. Good morning. Good morning, Faisal. How are you? Good. Hanging in there. All right. I wonder if you could elaborate a little bit more on what is going on with U.S. natural gas production. It looks like it peaked at about 4 BCF a day in the fourth quarter of last year, and it has been coming down steadily. I am wondering if that is a function of your shift in rig count in the lower 48. It is a number of factors. You have to start at the top of that with base decline across the conventional resources and decline that we are seeing there. That is going to be partly offset by the increases in unconventional gas production. But as you pointed out, we have seen a shift, and that shift continues in our rig count to the liquids-rich plays. The program itself is as I have described before. We are managing across the entire portfolio, which does include continuing to delineate, appraise, and evaluate the dry gas areas, while at the same time focusing the drilling on the liquids-rich plays. The other thing that we have had in there, we have had some divestments. You might recall we had one in the Gulf of Mexico a year or so ago, and that decline would have an impact there. It is really a combination of decline, divestments, some shifting of rigs, and then offset by the production increase that we have seen in the unconventional resources at XTO. Okay. I believe at the analyst meeting, you guys talked about how you were running maybe just under 70 rigs. I am not sure if that is still the right number or not, but it seemed like you had shifted to 50% of those rigs were now drilling in liquids-rich plays. Can you give us an update on where you are with that sort of mix and rig count? Yeah, sure. We have continued to both reduce the absolute number of rigs running. I think we averaged about 57 across the quarter. We are currently at about 51 rigs in total. Without giving a specific percentage, I can tell you the majority of those rigs are working on liquids and liquids-rich plays. That obviously would be a continuation of the trend that you have seen over the last few quarters. Thanks, David. Last question from me. On slide 16, where you talk about the first quarter to second quarter progression of earnings for upstream, the $1.76 billion other, I believe you said part of that was Angola and a part of it was favorable FX. Was the FX movement, was that an absolute number, or was there a big change quarter to quarter because of something in the first quarter? No. Again, it was kind of small. It was less than $100 million. That would be the change quarter on quarter. So within that bar, it is not a big effect either way. Okay, great. Thanks for the time. Appreciate it. All right, thank you. I will now go to Pavel Molchanov with Raymond James. Thanks very much. Two related questions about Rosneft, if I can. Sure. First one is as you know, Rosneft has publicly said they are talking to BP about the potential TNK acquisition. If that happens, how do you see that changing your relationship with them? And second question on the same point, has Exxon contemplated buying the TNK-BP stake? Yeah. Actually, my answer would be the same to both of those questions. I really could not provide any comment on either what others in the industry are doing or anything that we might have going on and are thinking about. Appreciate it. All right. Thank you. I will now go to John Herrlin with Societe Generale. Yes. Hi, David. Hey, John. Unconventional liquids was about 5% or 6% of U.S. oil production or liquids production. How big do you want to make that on a going forward basis? How large a ramp should we anticipate? That's a question I really couldn't answer because I have no idea what the forward projections are going to look like. Obviously, there's a lot of activity, a lot of plays. We are certainly heavily involved, both, as I mentioned, in the ramp-up of our existing fields like we have at the Bakken, but also in the pursuit and capture of a number of attractive acreage holdings, like we've mentioned in the Woodford, Ardmore, and the Utica. From an ExxonMobil perspective, I can tell you as we move out of these delineation appraisal and evaluation programs into full development, you'll continue to see the ramp-up that I mentioned in my prepared remarks, particularly in places like the Bakken and then in some of the other areas. But we don't have a target, and I couldn't give you a target for the industry. It's really just going to depend on how quickly these new opportunities that us and others are finding you can get in and get those online. Then, of course, you need the midstream infrastructure to evacuate those volumes and get them to market. To the extent that you're producing NGLs, there's other midstream infrastructure that has to be put in to process those. So there's a lot of opportunity, a lot of nice ramp-up, kind of across the board, as you mentioned. But it would certainly be hard for me to give you any indication on what kind of an ultimate target might be, either for us or the industry in general. Thanks. I was only asking about Exxon, but thanks, David. Okay. All right. I will now go to Iain Reid with Jefferies. Hey, David. Good morning. Hey, Iain. How are you doing? I am doing very well, actually. Couple of questions. Firstly, in thinking about your U.S. onshore operations at the moment, have you got an updated number for either capital employed in U.S. onshore or return on capital employed, which we are generating at the moment? No, we don't typically give that level of detail, Iain, so I wouldn't have either the capital employed number or the return on that. Okay. All right. Second question is about dividends. You've made a pretty substantial increase in your dividend payments. I just wonder when you're thinking about that, how do you factor in potential changes in dividend taxes, withholding taxes in the U.S.? Is that something you think about, or is this a kind of more fundamental change or increase you've made? A number of factors, as you would guess, go into the whole decision-making process about the allocation of cash and that sort of thing. I wouldn't want to comment on any one specific factor or even to speculate ultimately what the tax situation might look like or changes that we might see in the upcoming several months. Again, a number of factors we think about. We don't try to speculate a whole lot about the future from the standpoint that you mentioned. Really wouldn't have a specific comment on that. But was it something investors were kind of pressing you to look at rather than, or as a kind of add-on to the existing share buyback? Was that part of the rationale? We spent a lot of time talking to our investors about a number of things. Dividends are one, share buybacks are another. Not all of the investors are interested or have a weighting to any one particular disposition over another. Some have one preference, and others have another. We do spend some time looking at the competitiveness of both our total distributions and the breakout of those, and we do look at that. But in particular, on a specific input or a specific factor in the analysis, I wouldn't give any weighting to one over the other. We do spend time taking all the factors into consideration, and of course, that includes input we get directly from our shareholders. Okay. All right. Last question for me is on Vietnam. I believe you've proved up quite a substantial amount of gas now there with these three wells following on from last year's discovery. Any numbers you want to share with us about what sort of level of reserves you've proved up? You gave us obviously something on Tanzania. Maybe you can also talk about the forward program on that. Sure. I can tell you we are not as far along in assessing what we have in Vietnam as we were in Tanzania. We're still evaluating the wells there. We had one well that was not successful and two that were. So we're still in the early days of looking at that. We've got a lot of work to do, a lot of valuation to do, and to assess that. We are looking at additional seismic and other exploration activity, but little early to start giving you resource numbers at this time. All right, David, thanks for that. Thank you much. We'll now go to Paul Sankey with Deutsche Bank. Hi, David. Hey, Paul. How are you doing? Fine, thank you. Apologies, I am traveling today, so I got on the call late. But I did want to ask you about your specials and the way you declare them. I guess the question is, I completely don't understand why you declare no specials in the table of specials, but then immediately say there were a lot of specials. Paul, let's talk just a minute about the term specials, and I think I can address your question. Really, you have to think about two different considerations when you are talking about special items. The first that I would offer you is, if you look at this from an ExxonMobil perspective, both asset divestments and acquisitions have become a normal part of our ongoing operations. We talked at the analyst meeting in March about the level of divestments that we have had. If I just look across the last four or five years, I think we have had $26 billion in proceeds and about $11 billion in earnings. So this is an ongoing piece of the business for us. Some quarters, the numbers are a little larger than others. But in terms of divestments being special, they are part of the business. I think the other thing to consider is that the use of the term special items has in fact evolved over time, driven in part by updated SEC guidance on the use of non-GAAP terms. And we are certainly in compliance with that updated guidance and paying attention to it, and it has evolved over the last few years. So if you take those two factors into consideration, I think what we have reported here this quarter is consistent with both of those. So is that SEC definition a question of materiality then, or— and I think the other thing I find very odd, David, is that you continue to publish this table of zeros, which just kind of seems inefficient, quite frankly. But could you just talk a bit more about what you are saying about the SEC? I understand— Sure your argument that the divestments are an ongoing part of your business and therefore shouldn't be considered special. I think that's fine. The SEC bit? Without getting into the weeds here, I can tell you that it's not really a materiality look. It's really around the desire for the SEC for a company to not describe a charge or a gain as a non-recurring, infrequent, or unusual event, unless it meets certain criteria, and that includes a look back as well as a look forward. So if you're looking back and you've been doing this stuff in the past, and you look forward and you think that you might have these type of events in the future, the SEC guidance is to not call those non-recurring, infrequent, unusual, special, or whatever term you want to use. Again, that has happened over time. In terms of the table and efficiency, I'll tell you, it's possible. I'm not saying that we'll never report a special item because we may. I'm just saying that when we look at the guidance in our business, none of the earnings impacts that you saw in the quarter qualified to be "special items. Sure, I understand. If I could just follow up on Paul Cheng, it's kind of related. I think what you were saying that there would very unlikely be a write-down related to XTO because I guess what you're implying is that you're very conservative in booking what is essentially a very large resource. Yeah, I think it's a couple of things, Paul. It's the conservative nature for which we book things to prove reserves. It's also our outlook for natural gas prices. If you look broadly and look at our energy outlook, we don't have an outlook over the long term that prices are going to remain at current levels, and that's consistent with our investment plans, it's consistent with our energy outlook, and it's really consistent with the long-term way that we're going about developing these resources. Okay, David, thanks. I think I understand. I was just wondering if the SEC, going back to that, allows you to use your own long-term planning assumptions for net gas prices as regards bookings? Yeah, that's correct. Okay, that's good. Thank you. Thank you. I am going to now go to Allen Good with Morningstar. Good morning, David. Just one quick question on Lower 48 activity. It looks like you made pretty good progress in reducing the rig count there and moving towards liquid rich plays. But if we look back to over a year ago, you were at 70 rigs and natural gas prices were at $4. And certainly they have made quite a recovery off the lows we saw earlier this quarter. And whether that is sustainable or not is certainly a question, but is the $4 level something to think about that Exxon may potentially return to gas drilling or given the low base of rigs you are working off now, there certainly would have to be different conditions where you would revisit some of these gas plays that you have moved away from over the past six months? Yeah, I think the answer to the question and what you are seeing us doing it is really more reflective of our longer-term approach to this. We are still drilling in dry gas areas. We do continue to drill wells in order to work on our delineation and our evaluation of those plays to make sure that, again, over the long term, we want to be in a position to maximize the recovery and maximize the value generation from those resources. So that has not changed. What you have seen that we have talked about is both a reduction in the total rig count, and some of that, of course, is in response to the short-term pricing that has happened. In addition, the move of a lot of the rigs over to liquids and liquid-rich plays is really both to start to delineate and appraise and think about developing our new acreage, like the Woodford Ardmore, as well as ramping up in the Bakken. In fact, I think I heard the other day we are up to about 10 rigs in the Bakken out of those 51. We really do not have a price trigger to any big extent. You might do something a little different at the margin in any given quarter, depending on prices. When you really look at the overall plan and the overall strategy, it continues to be with a very long-term view of this very large, very high-quality resource we got. Okay. In the short term, though, do you expect that 51 rig total you are currently running, is that enough to do everything you want to do as far as evaluating those plays and driving production out of liquid-rich plays? Or would we expect during the short term to see that rig count continue to fall? I really do not have an outlook going forward for the rig count. We continue to progress the program, and we could see some variability around the number that I mentioned, but I really could not give you an outlook in terms of either direction or rig count specifically. Okay. Thank you very much. All right. Thank you very much. It appears there are no further questions at this time. Mr. Rosenthal, I would like to turn the conference back to you for any additional or closing remarks. No, I would just like to thank everybody on the call today, and thank you for your questions, and we look forward to visiting you again next quarter. Thank you very much. Ladies and gentlemen, that does conclude today's conference call. Thank you for your participation.