Exxon Mobil Corp XOM
Q1 2013 Earnings Call Transcript
Transcript Call Date 04/25/2013

Operator: Please standby, we're about to begin. Good day and welcome to this ExxonMobil Corporation First Quarter 2013 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.

David S. Rosenthal - VP, IR and Secretary: Good morning and welcome to ExxonMobil's first quarter earnings call and webcast. The focus of this call is ExxonMobil's financial and operating results for the first quarter of 2013. I will refer to the slides that are available through the Investors section of our website. But 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 was mixed throughout the first quarter. U.S. growth was flat to moderate and economic indicators were mixed. China experienced slower growth and the European economies remained challenge.

Energy markets strengthened in the first quarter, with higher crude oil and non-U.S. natural gas prices. U.S. natural gas prices remained relatively flat compared with the fourth quarter. Industry refining margins strengthened and we experienced improved chemical commodity product margins.

Turning now to the first quarter financial results as shown on Slide 4. ExxonMobil's first quarter 2013 earnings were $9.5 billion, an increase of $50 million from the first quarter of 2012 earnings per share for the quarter were $2.12 up $0.12 or 6% from a year ago. The corporation distributed $7.6 billion to shareholders in the first quarter through dividends and share purchases to reduce shares outstanding. Of that total $5 billion was used to purchase shares.

Yesterday, the Board of Directors declared a cash dividend of $0.63 per share a 10.5% increase from the last quarter. Share purchases to reduce shares outstanding are expected to be $4 billion in the second quarter of 2013. CapEx in the first quarter was $11.8 billion, up $2.9 billion from the first quarter of 2012 primarily due to the $3.1 billion Celtic acquisition.

Cash flow from operations in asset sales was $14 billion. At the end of the first quarter 2013 cash totaled 6.6 billion and debt was $13.4 billion.

The next slides provides additional detail on first quarter sources and uses of funds. Over the quarter, cash decreased from $9.9 billion to $6.6 billion. The combined impact of strong earnings, depreciation expense and the benefit of our ongoing asset management program yielded $14 billion of cash flow from operations and asset sales. The uses included additions to plant, property, and equipment or PP&E of $7.5 billion and shareholder distributions of $7.6 billion. Additional financing and investing activities decreased cash by $2.2 billion, primarily reflecting the Celtic acquisition.

Moving on to Slide 6 and a review of our segmented results, ExxonMobil's first quarter 2013 earnings of $9.5 billion increased $50 million from the first quarter of 2012. Higher chemical earnings and lower corporate and financing expenses, due primarily to favorable tax items, were mostly offset by lower Upstream earnings. Guidance for corporate and financing expenses remain at $500 million to $700 million per quarter.

As shown on Slide 7, ExxonMobil's first quarter 2013 earnings decreased by $450 million compared with the fourth quarter of 2012. Lower Upstream and Downstream earnings were partly offset by higher chemical earnings and lower corporate and financing expenses.

Moving next to first quarter business highlights and beginning on Slide 8. We continue to advance our global portfolio of high quality upstream projects. Extraction of bitumen froth at the Kearl plant facilities began March 31 and we are beginning to process the bitumen froth. We will be filling on-site (tankers) with diluted bitumen and we'll transport the product to market with the new pipeline. Startup of an operation of this size and scope is a sequential process involving multiple integrated systems. Our first priority is completing startup activity safely which includes mitigating the impacts of abnormally cold weather on both workers and equipment. Production from the initial development is expected to reach volumes of approximately 110,000 barrels of bitumen per day later this year.

Progress also continues on the Kearl expansion project which was 32% complete at the end of the first quarter. Fabrication and assembly of pipe rack and equipment modules in Edmonton is ahead of plan and we have completed setting the main pipe rack modules in the froth treatment plant also ahead of plan. The project remains on schedule for startup in 2015.

During the quarter we also started production from the Telok gas filed located offshore Malaysia in the South China Sea. The development concept of divide one design one build multiple was utilized to efficiently develop the project and shorten construction and installation timelines, allowing Telok to be completed on schedule and on budget. The Telok A platform is the first phase of the Telok natural gas project which when completed will consist of two four-legged gas satellite platforms. A total of 14 development wells are planned for the Telok A and B platforms.

In the Gulf of Mexico appraisal drilling at Hadrian North has been completed and the results are being integrated into development planning for the Hadrian North project. In addition the Erha North Phase 2 project in Nigeria was sanctioned during the quarter. The project is located 60 miles offshore Nigeria and consists of a subsea tieback to the existing Erha floating production, storage and offloading vessels. It is anticipated to recover approximately 175 million barrels of oil with the peak capacity of 60,000 barrels of oil per day. Startup is targeted for 2016.

Turning now to Slide 9, and an update on our conventional exploration activities. In Tanzania, we completed two successful wells during the quarter. The Tangawizi-1 well discovered gas and high-quality tertiary sandstone reservoirs confirming 4 to 6 Tcf of gas in play. This new discovery is located 10 kilometers from the Zafarani and Lavani discoveries. In addition, the Zafarani-2 well confirm gas bearing, high-quality reservoirs in the cretaceous appraisal target.

We have so far completed five successful wells on Block 2, exploration efforts continue and additional drilling is planned for later this year. In the Gulf of Mexico, the Phobos prospect encounter approximately 250 net feet of oil pay in the lower tertiary age reservoirs. As you know, we plan to drill several wildcats in the Gulf of Mexico this year. Our next prospect Thorn will begin drilling in the second quarter.

Moving now to Slide 10, also during the quarter we made several substantial additions of high-quality acreage to our exploration portfolio. We expanded the strategic cooperation agreement with Rosneft to include an additional 150 million acres from seven new blocks in the Chukchi, Laptev and Kara Sea from the Russian Arctic. We are now working with Rosneft on 180 million acres in the Russian Arctic, including the original 31 million acres in the Kara Sea. These blocks cover some the most promising and least explored acreage in the world.

In West Africa, we acquired an 80% interest in Liberia Block 13, comprising more than 625,000 acres offshore in water depths ranging from 75 meters to 3000 meters. Block 13 is located 30 km offshore Liberia's central coast. In the Gulf of Mexico we added high-quality acreage to our deepwater portfolio. The Bureau of Ocean Energy Management awarded ExxonMobil the four blocks for which we were the high bidder in the western Gulf of Mexico OCS lease sale 229. In the recent central lease sale 227 ExxonMobil was the high bidder for seven blocks. Additionally, we acquired a 33% working interest from BP (indiscernible) the Maui prospect located in the Walker Ridge area. ExxonMobil will provide a state-of-the-art deepwater drilling rig and will operate the Maui 1 exploration well expected to spud in the second half of this year.

Turning now to our unconventional activities on Slide 11, we continue to progress high-potential liquids-rich unconventional opportunities. During the quarter, we closed the Celtic acquisition, bringing 545,000 net acres of liquids-rich Montney shale, 104,000 net acres in the Duvernay shale, and additional acreage in other areas of Alberta into our unconventional portfolio. Although it's very early days, we're rapidly integrating personnel, systems, and processes, leveraging both our own extensive unconventional expertise and our long operating experience in Canada.

We are currently developing future drilling plans to focus on areas expected to deliver the highest liquids yield and to optimize both drilling and completion methodology.

In the Bakken gross operated production increased 75% year-on-year with the growth attributable to increased development and optimized completions across our core Bakken acreage. We are utilizing 10 drilling rigs in the Bakken and have fully integrated the acquired Danburry properties into our operations.

In the liquids-rich Woodford Ardmore shale play gross operated production increased 39% year-on-year. The Ardmore is our most active unconventional play, with 12 operated rigs delineating more than 270,000 acres in the Ardmore and Marietta Basin.

We have observed encouraging early results from our first well in the Marietta Basin since coming online a year ago. After the successful 2012 test of the overlying Caney shale in our core Ardmore area, we are progressing with further delineation across both the Ardmore and the Marietta areas.

We also continue well testing and execution of drilling plans in Argentina and Colombia. In Russia, we plan to begin operations in West Siberia later this year.

Turning now to the Upstream financial and operating results, starting on Slide 12. Upstream earnings in the first quarter were just over $7 billion, down $765 million from the first quarter of 2012. Lower crude oil realizations, partly offset by improved natural gas realizations, negatively impacted earnings by $230 million as crude oil realizations declined $8.66 per barrel, while gas realizations increased $0.97 per 1,000 cubic feet.

Production volume and mix effects negatively impacted earnings by $280 million. All other items including higher expenses related to new project activity decreased earnings by $250 million. Upstream after-tax earnings per barrel for the first quarter of 2013 was $17.79.

Moving to Slide 13, our first quarter volume performance is in line with the projection presented at the analyst meeting in March. Oil equivalent volumes decreased by 3.5% from the first quarter of last year, excluding the impacts of entitlement volumes, OPEC quarter effects and divestment, production was down about 1%.

Liquids production was down 21,000 barrels per day or just below 1% from the first quarter of 2012 as fuel decline was mostly offset by project ramp up in West Africa and increased production from liquids rich plays in the United States. Natural gas production was down 823 million cubic feet per day or just under 6% quarter-on-quarter at lower entitlement volumes, primarily reflecting cutter AKG becoming cost current in 2012 and fuel decline are partially offset by lower downtime and higher seasonal demand in Europe.

Turning now to the sequential comparison and starting on Slide 14. Upstream earnings decreased by $725 million versus the fourth quarter of 2012. Realizations positively impacted earnings by $340 million as crude oil and natural gas realizations increased by $1.68 per barrel and $0.94 per thousand cubic feet, respectively. Volume and mix effects decreased earnings by $80 million as the unfavorable timing of lifting and two fewer days in the quarter were mostly offset by higher natural gas volumes in Europe and Asia. Other items, including the absence of gains from asset sales and favorable tax items realized in the fourth quarter decreased earnings by $980 million.

Moving to Slide 15, oil equivalent volumes were up 2.4% from the fourth quarter of 2012. Excluding the impacts of entitlement volumes, OPEC quota effects, and divestments, production was up more than 4%. Liquids production was down 10,000 barrels per day from the fourth quarter as unfavorable entitlement volumes were mostly offset by lower downtime. Natural gas production was up 672 million cubic feet per day versus last quarter, primarily reflecting higher seasonal demand in Europe.

Moving now to the Downstream financial and operating results and starting on Slide 16. Downstream earnings for the quarter were $1.5 billion, down $41 million from the first quarter of 2012. Improved margins, mainly in refining, increased earnings by $780 million. Volume and mix effects decreased earnings by $290 million, mainly due to increased refinery maintenance activity. All other items decreased earnings by $530 million, including lower gains on asset sales outside of United States, increased operating expenses associated with refinery maintenance activity, and unfavorable foreign exchange effects.

Turning to Slide 17, sequentially, first quarter Downstream earnings declined by $223 million. Improved margins, mainly in refining increased earnings by $470 million. Volume mix effects decreased earnings by $430 million, mainly driven by increased refinery maintenance activity. Other items reduced earnings by $260 million, due primarily to the absence of a fourth quarter LIFO gain.

Moving now to the Chemical, financial and operating results, starting on Slide 18. First quarter Chemical earnings were $1.1 billion, up $436 million versus the first quarter of 2012. Stronger commodity margins increased earnings by $320 million, reflecting improved U.S. steam cracking margins on lower ethane feed costs. All other items increased earnings by $120 million, mainly due to increase gains on asset sales.

Moving to Slide 19, sequentially, first quarter Chemical earnings increased by $179 million. Stronger margins mainly in U.S. commodity increased earnings by $80 million. Lower operating expenses and higher gains from asset sales, partly offset by the absence of a prior quarter LIFO gain increased earnings by a net $90 million.

In conclusion, Exxon Mobil's first quarter financial and operating performance reflects the value of our strong integrated business model. In the first quarter, we earned $9.5 billion, generated $14 billion in cash flow, invested $11.8 billion in the business, and distributed $7.6 billion to our shareholders. As we continue to focus on operational excellence, deploy high-impact technologies, and leverage our unmatched global integration, Exxon Mobil remains well positioned to maximize long-term shareholder value.

That concludes my prepared remarks and I would be happy to take your questions.

Transcript Call Date 04/25/2013

Operator: Doug Leggate, Bank of America Merrill Lynch.

Doug Leggate - Bank of America Merrill Lynch: Two quick questions please. Unit profitability, David, on the Upstream continues to like the historical capture rate. Can you comment as to whether something that material has changed there, I guess a couple of years ago we talked about the start of LNG trends, is there anything specific you can point to, but could lead us back on track to where we have been historical.

David S. Rosenthal - VP, IR and Secretary: I think if you look at what's happened over the last couple years as you noted, the change in the mix in particular, the addition of the U.S. gas volumes particularly over the period when prices were down in the $2 and some range, you saw the next impacting the unit profitability relative to the historical trend. As we go forward when you look at the longer-term and you look at the liquids increases that we have coming on and the higher gas prices that we have seen, you can reasonably expect the profitability to reflect those increases in both the production as well as the margin. And one of the other things to keep in mind as we crank up these new projects again is going to be the addition of long-term plateau volumes and the lower decline rate, so as the decline rate levels out (Indiscernible) you're not chasing the decline that we had in prior years, you won't be investing this much money to keep the production levels where they are. I think the other thing that's positive as we look down the road again in addition to the liquids increase that we've talked about in the analyst meeting and the increase we're projecting this year and going forward, the LNG projects that we have coming on stream in the next few years are all sold out with the gas linked under long-term contracts to crude oil prices. So again it gets back to the longer-term looking at the projects that we have coming on this year and in the next few years and the relative profitability of those projects and again over the long-term very confident in the robustness of those projects and our ability to bring them on stream and get those barrels to market.

Doug Leggate - Bank of America Merrill Lynch: My follow-up hopefully a quick one, (somebody is got to ask you) David the share buybacks, $14 billion of cash flow, you're not covering the cash outflow. Can you just talk about what you're signaling to – is this – oil spilled over to $100 and you're cutting the buyback program. My recollection is you're not using the planning assumption. So any color you can give us would be appreciated.

David S. Rosenthal - VP, IR and Secretary: Doug, let me hit that comment from a couple of perspectives. First, when you look at the cash flow in the quarter as you saw from the sources and uses of funds, we had basically a zero impact on working capital and in prior quarters we had positive impacts there. We did close and pay the $3 billion for the Celtic acquisition and we also had some timing of tax payments and that sort of thing. So, but the cash flow again is just an outcome of the earnings give or take this timing effects. As we've said in terms of the buyback, I have to tell you, there's no change in our approach to capital allocation and in the use of our cash flow as you saw, we once again raised the dividend here and board announced that yesterday 10.5% this year following on the 21% increase last year. So, we continue to raise the dividend on a consistent basis. And in the share buyback is strictly a function of cash flows in the quarter and expectations going forward in the quarters, but no change in terms of signal or the way that we approach the allocation of the funds.

Operator: Doug Terreson, ISI.

Doug Terreson - ISI: So, my question is also on Upstream profitability. I'm just going to ask a little bit a different way and specifically international side meaning your point is taken on U.S. natural gas the benefits of some of these large LNG projects over the longer-term. But internationally between flat realizations versus last year plus or minus and Rex's, comments on declining drilling and completion costs to March. I just want to see if you could maybe provide a little bit more color on some of the volume and mix effects components on the international side that you highlighted and exhibited '12, and maybe also whether or not there's a geographical aspect of the mix affect that's at work here?

David S. Rosenthal - VP, IR and Secretary: If you look at on the international side and you take a look at the profitability, one other things that we're seeing there is a mix impact with some of the loss of some of the higher margin barrels from the production Syrian contracts that we've seen over the last couple of years and then the mix certainly when you get into in this part of the year of European gas sales. So, nothing structural and nothing really deployed out other than some mix effect. But again, if you look over a longer period of time at the projects we have coming online and the earnings contribution that those will make I don't think you'll see any major change to talk about relative to prior history.

Operator: Paul Cheng, Barclays.

Paul Cheng - Barclays: Two questions. One, can you give us what is in your 2013 CapEx on the North American (shale water) play and versus that if not an absolute but versus the 2012 and what's the expectation for 2014?

David S. Rosenthal - VP, IR and Secretary: Paul, I couldn't hear your – could you just repeat the question on the U.S. CapEx?

Paul Cheng - Barclays: Two questions. First, for North American (shale water) can you share with us what is the actual CapEx for this year related to those basins, and if you cannot give us an actual for that, can you tell us what is that comparing to 2012 and also if you can give us an idea there what is the expectation for 2014 is that going to be higher or is going to be sustained at that level? Second – do you want to answer that and then I go for the second question?

David S. Rosenthal - VP, IR and Secretary: Yeah, how about I answer that one and then we'll go to your second question. As you look at – I don't have a specific actual CapEx outlook number for you, but as we talked about as you see our focus in drilling in the unconventional plays and in particular the liquids rich plays in the Bakken, in the Woodford Ardmore we are allocating an additional amount of CapEx to those areas relative to what we be allocating to dry gas. And clearly as we integrate the Denbury acquisition that we did, the Celtic acquisition that we did, it would be reasonable to expect that on a relative basis year-to-year over time we will be spending more money on those liquids rich plays. And you are starting to see some of that bear out. If you look at the improved performance in the Bakken and in the Woodford Ardmore not only in the production that's coming up, but the efficiency that we're getting improved completions, improved performance, that strategy and approach is starting to play out and you are starting to see the dividend. In terms of going forward, 2014 again, I don't have a specific outlook for you, but it would be reasonable to assume that as we continue to progress these liquid based opportunities and continue to drill wells and have the activity that we're having, and leveraging the ability we're getting now with these additional property, certainly as we ramp that up you can expect on a relative basis over time for the CapEx to go up. But I don't have a specific actual amount for you.

Paul Cheng - Barclays: Maybe just to – $3 billion or $4 billion currently is spending is a ballpark a reasonable estimate, or that you are not going to be able to comment even on that?

David S. Rosenthal - VP, IR and Secretary: Again I wouldn't want to give an actual number allocated to one particular resource type and one particular geography, other than again, Paul, to reiterate that clearly we have increased the focus on the liquids-rich plays and we continue to ramp up that activity. And in particular, as we move from the delineation and appraisal phase into the development phase and start bringing wells online and getting them to sales.

Paul Cheng - Barclays: Kearl startup portfolio that we are now really at the tail end of the Phase I, startup phase. Just want to see that, you've learned a lot – seems that you guys have never done the mining project, and so what steps then you have taken or what experience that you have learned now you apply to Phase II so that you can ensure that it's going to run with new project and startup schedule?

David S. Rosenthal - VP, IR and Secretary: Paul, let me first comment on the Kearl startup, literally the actual production is imminent, and so we will be looking forward to that here shortly, as I mentioned in my remarks. In terms of lessons learnt and applying those to the Kearl expansion project, the one thing you need to recall is we are partners in the Syncrude project and therefore have a lot of experience in that operation and are actually quite familiar with bitumen mining. I think the real carryover that you get as you move from the Kearl initial project development to the Kearl expansion project is the ability to carry over all the engineering work from the first section. I think we mentioned before about 90% of the engineering carries over. The new trains are being built adjacent to the existing ones, and so it's really the efficiency that you get in building the second set of trains right behind the original project, and I think that's where you'll see that. In fact, if you look at where we are today and progress that we've made, we are actually ahead of schedule, right now on the expansion projects. So, I think that's where you're seeing in the real efficiency. Now clearly, having said that, as we progress with the mine development it will be natural for us to find improvement opportunities as we go along and learn some things and continue to develop the mine plan and heading into the expansion. But in terms of starting from ground zero or low starting point, I don't think I'd characterize is that way. But again, as you know as will be continuously improving everything we're doing, as we start up and ramp up the current project and then head into the next phase.

Paul Cheng - Barclays: Can I just stick in with a small question for clarification, in your earlier comment for 2013 production guidance that given in March for 1% to 2% decline, is that already factored in the potential PSC impact base on $110 brand or that is not included?

David S. Rosenthal - VP, IR and Secretary: Yes, the impact of PSC effects at the $112 price that we used is in that estimates that we showed you. So, to be very specific, if you look at the 2% increase in liquids that we had, we have the PSC effects in their – at the assume price.

Operator: Iain Reid, Jefferies.

Iain Reid - Jefferies: Couple questions. Well, first question on the Downstream if I could. You had a very strong performance in U.S. Downstream relative to where the margin seem to go and also probably a weaker performance in our non-U.S. Downstream do you want to talk about the kind of drivers there like, were you accessing more advantage crude in the U.S. perhaps then we estimated and international Downstream was anything driving that one which, offset what the benefits you got in the U.S.?

David S. Rosenthal - VP, IR and Secretary: If you're looking at the Downstream and in particular if you're looking -- I'm not sure if you were actually referring to our quarter-over-quarter or sequential.

Iain Reid - Jefferies: Well both really.

David S. Rosenthal - VP, IR and Secretary: Well, if you look at both, yes we saw very strong refining margins in particular in the U.S. and in that really does reflect the advantage feeds that we're doing that we're running into those, plus the fact that we had good uptime and reliability and good performance in the operations. So that's come along as we talked about in the Analyst Meeting in March and we're seeing those benefits. I will say if you're looking at the sequential quarter-to-quarter that delta there was helped by the absence of some unfavorable price timing that we had in the fourth quarter. So, if you're looking sequentially and you look at that nice bump in the U.S. earnings a good bit of it is actual margin improvement and the other is an absence of the prior quarters' unfavorable price timing that I mentioned. If you're looking overseas and you're looking at the Downstream business, the biggest impact you see there is the significant increase in amount maintenance activity in our refineries particularly in Europe and in Canada and that's the bulk of what you're seeing both sequentially and quarter-over-quarter driving those results. We did have a little negative forex impact as well. And then, again, the absence – if you're looking sequentially the absence of the LIFO gain that we had in the non-U.S. from the fourth quarter. So, I think if you step back and look at all of this and just take out the LIFO gains and asset sales that we have talked about in the fourth quarter as well, the operations are running great, we are taking advantage of the feeds that are available particular here in the U.S. and continuing to benefit from the integration that we have across our refining and chemicals businesses. I think you're seeing all of that really come to fruition particularly in the margin area.

Iain Reid - Jefferies: Second one, you are obviously building up now significant further volumes and Canadian bitumen, we have seen the differential there widen even further in the first quarter. Can you talk about how Exxon is impacted by kind of market differentials there? I think you said at the analyst meeting that you saw you could take advantage if you like of your own pipeline systems to get around some of that. So, just wanted to kind of flex that out a bit.

David S. Rosenthal - VP, IR and Secretary: Sure, if you look at our refining footprint in what we call kind of an extended MidCon if you will. So, if you look at our refineries in the Midwest, in the Rockies and in Canada, we can process about 600,000 barrels a day of that advantage crude that you see in that part of the business. Now when you come back specifically to the Kearl project as we've said before, we are capable of sending all of the output from the initial development project into our existing refining circuit. So, to the extent that differentials continue, we will be able to capture those in our own refining circuit.

Iain Reid - Jefferies: So, actually it's a second phase, so was you going to have some problems with that?

David S. Rosenthal - VP, IR and Secretary: When you look at the second phase we will be looking at both the opportunity to run more of that crude into our existing refineries as well as obvious into third parties. So we're working those logistics now, looking at our various options and opportunities. We've got until 2015, but we're pretty confident when we look across our broad logistics capability and our refining circuit that we'll be able to place those barrels in an optimum manner and extract the maximum value from those products.

Iain Reid - Jefferies: Okay, so we should be expecting kind of lower E&P earnings from Kearl but higher Downstream earnings, so the whole mix kind of comes out in the (wash)?

David S. Rosenthal - VP, IR and Secretary: Well, I think that will all depend on the absolute level of crude prices and margins and then the differentials as well. I can't predict what either of those will be at a given time. I think the real message, though, is that whatever the absolute prices and margins are at the time we're going to get a benefit from being fully integrated, both across the refining chemicals business and in that integration into Kearl and the ability to process other crudes, including disadvantage imports like crudes in the U.S. and that sort of thing. So it is really optimizing across the entire circuit as well as geographic optimizations, but we feel pretty good about where we are and how our assets matchup and how we're managing those and look forward to benefiting more as we go forward with this integration.

Iain Reid - Jefferies: Okay, and just one very quick one, if you don’t mind. You talked about an (asset) gain in chemicals. Are we talking on an absolute basis, hundreds of millions of dollars there, like how much is that in terms of improving chemical earnings?

David S. Rosenthal - VP, IR and Secretary: Kind of all in just under $100 million.

Operator: Pavel Molchanov, Raymond James.

Pavel Molchanov - Raymond James: Question on two of your exploration areas, first in Tanzania, I realize you are not the operator, but you have had a lot of success there? And is there – do you envision a point maybe in the next 12 months of sanctioning a development plan?

David S. Rosenthal - VP, IR and Secretary: I think if you step back and take a look at Tanzania, we have had significant success there with the wells that we've drilled so far, both the exploration wells and the recent appraisal well. So far, we're looking at gas resources somewhere in the range of 10 to 13 Tcf discovered to date. But as we look forward, we got a lot of work left to do. We've got a lot more seismic that we're running and processing, a lot more analysis to do, we are looking at drilling an additional well later this year, so we've got to take all of that into account before we can ever really start thinking about development plan. So, it's still early days. We know we've got a very high-quality resource. We've had a significant amount of early success. There is more exploration work ahead. Once we finish the exploration and appraisal process and know what we got and know how the commerciality looks, then we would do the natural progression into development planning and that sort of thing. But it's a little early right now. Fortunately, it's early because of all the success we've had to date. But we've got a little more work to do and once we get all that done we will be in a better position to talk about our go-forward plans.

Pavel Molchanov - Raymond James: Follow-up a little bit bigger picture question on your unconventional opportunity globally. One of your European competitors recently pulled some cold water over particularly shale gas development internationally talking about all the obstacles. And in your ethanol review you noted some of the issues in Germany and in obviously earlier in Poland. Can I get your kind of latest thoughts on how international ex-North America unconventional fits into your portfolio and what the plan is?

David S. Rosenthal - VP, IR and Secretary: I think the most important thing to think about when you look at our international portfolio is how diverse it is. So if you just kind of walk around the world we have a very active program underway in Colombia that we've talked about and we're progressing activities there and testing some wells and planning to drill some more. Argentina continues to be a very active area for us. We drilled a number of wells last year that we're testing looking at. We are planned to drill a number more wells in Argentina. As I mentioned my prepared remarks, we do still intend to get to work in West Siberia over the course of this year and get some work there. So, that's doing very well and we continue to leverage again the expertise that we have here in North America into those plays. Having said that, there is prospectivity in Europe, as we mentioned before we have a very large acreage position in unconventional prospectivity in Germany for both gas and liquids, we are working with the government there to try to get permit that would allow us to continue our exploration and appraisal process. We stand ready to ramp up activity there pending that. So, it's a long-term business. Its long-term resource development, both the oil companies and the countries that have these resources are just getting started with their evaluation program and developing policies. So, we can pace our activity based on local requirements and regulations. And again, the good news for us is we got a very large portfolio in a lot of different areas, with a lot of different resource potential. And we are able to dedicate the resources both human and financial and technology to those areas with the most promise and the most availability and accessibility and we're continuing to do that very well into this year.

Operator: Edward Westlake, Credit Suisse.

Scott Willis - Credit Suisse: This is (Scott Willis) on for Ed. I'd like to focus on U.S. natural gas for a minute if I could. I noticed that your domestic volumes were down around 4% quarter-over-quarter. And then when we look at natural gas prices, those have been stronger so far in this quarter. Should those prices go forward, I was just wondering how that would affect your decision to grow your domestic gas volumes going forward.

David S. Rosenthal - VP, IR and Secretary: Well, I think if you step back and look at the unconventional resource in North America and particularly in the U.S. that we are working on, as we have talked about over the last few quarters, we have been allocating and dedicating more resources towards the liquid rich plays, particularly the Woodford Ardmore as I mentioned as well as the Bakken and those efforts are continuing and we are making great progress in terms of our productivity, optimizing the completion, getting the initial rates and extended rates out and so that effort continues unabated and we will continue to do that. I think the other news that's really good for is the flexibility we have across our unconventional resource. We have, as you well know, very large positions in all of the unconventional gas plays in the U.S. and we're still maintaining activity in some of the gas plays where the returns are good, and we maintain the flexibility to increase our efforts in those areas if we want to. But when you're looking at prices in any of the commodities, they move around, we don't tend to take the last two data points and draw a trend line and react in that manner. We tend to have longer-term approaches to the development of all of our resources, So I don't know what prices are going to do going forward and I wouldn't want to predict exactly what we'll be doing at any given time, other than currently our focus is on the liquids-rich plays and we're having great success there, but we do maintain the flexibility and optionality in the gas plays as well. So it's a pretty good position to be in and we'll continue to work on the long-term development and react as appropriate to changes in market factors.

Scott Willis - Credit Suisse: And then also just on the asset sales, it looks like you did around $400 million this quarter. I was just wondering if that is a decent run rate on how you think the rest of the year will go or if you look to kind of ramp up those asset sales as we go forward?

David S. Rosenthal - VP, IR and Secretary: I can't give you any expectation of a run rate. If you look back across the last few years, the asset sales have tended to be lumpy as well as different in certain quarters in the Upstream versus the Downstream. So I wouldn't want to give you a runway. We are continually looking at our portfolio as we always do, but I wouldn't want to either say any absolute number was appropriate or to give any guidance relative to future quarters and what you've seen this quarter or prior quarters it will just – it will happen when it happens.

Operator: Robert Kessler, Tudor Pickering Holt.

Robert Kessler - Tudor Pickering Holt & Co.: Couple follow-ups to some earlier points you made. One on the buybacks you were asked about the reduction and the strategy there. But I would like to ask about the cash balance and flexibility. So, the $6.6 billion of cash that you've got on the balance sheet at the end of the quarter, how much of that I guess in theory could be used for buybacks I know you got about $400 million marked in the footnote as restricted, but is that to say that full 6.2 remainder could be used again in theory for buybacks or are there any other factors to consider like taxes on repatriation of cash to the U.S. to the last extent you have got some broad or that kind of affect?

David S. Rosenthal - VP, IR and Secretary: Getting to the last part of your question and backing up. There are a number of factors that determine what our point end cash balance is in any quarter. I mentioned some of those this quarter, including closing the Celtic acquisition, some timing in tax payments working capital changes et cetera. So, we don't have a target in terms of what the cash balances or minimum that we have to have for an operating level. We manage the cash just to maintain our flexibility and meet all of our commitments and it does balance around fair amount as you've seen over time. But I wouldn't want make any specific comment on what cash would be available for what or how it might change going forward other than to say, as we've said before, the share buyback is determined on a quarterly basis and is a reflection of the cash that's available as delivered from the business given the market conditions that we have, and as I said were our expectation is we'll buy $4 billion in the second quarter. But other than that I just wouldn't have any guidance on either uses of cash or the buyback level going forward.

Robert Kessler - Tudor Pickering Holt & Co.: Can you say whether the $6 billion figure roughly is fully available for general corporate purposes in any jurisdiction or do you have any sizable amount that can only be used in a certain geography?

David S. Rosenthal - VP, IR and Secretary: Yeah, I tell you I wouldn't have a specific comment on that but I don't think, there's anything significant or material in any one region or another that's restricted for us. We manage our cash globally and I just -- I don't I wouldn't expect there to be anything significant or material to worry about or to think about what to do with.

Robert Kessler - Tudor Pickering Holt & Co.: Then a quick follow-up for me on the Chemical asset sale gain, I mean you mentioned just under $100 million I think in aggregate. Can you provide a quick split on U.S. versus non-U.S. for that gain in the first quarter?

David S. Rosenthal - VP, IR and Secretary: Yeah, it's about half and half, half in the U.S. and half overseas and I guess, I said the number was just under $100 million, it's in total at $70 million and again, half in the U.S. and half in the non-U.S.

Operator: With no further question I'd like to turn it back to Mr. Rosenthal for any additional or closing remarks.

David S. Rosenthal - VP, IR and Secretary: I just like to say in closing that I appreciate your time and your questions this morning and look forward to our call in about three months. So, thank you very much.

Operator: This concludes today's conference. Thank you for your participation.