Earnings Call: Q1 2013

Apr 25, 2013

Summary

Q1 earnings reached $9.5 billion, with stronger chemicals and refining largely offsetting upstream weakness. Cash flow was $14 billion, while capital spending included the Celtic acquisition and shareholder distributions totaled $7.6 billion.

Good day, and welcome to this Exxon Mobil 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. Good morning, and welcome to Exxon Mobil's first quarter earnings call and webcast. The focus of this call is Exxon Mobil's financial and operating results for the first quarter of 2013. I will refer to the slides that are available through the investor section of our website. But before we go further, I would like to draw your attention to our cautionary statement shown on slide 2. Moving to slide 3, we provide an overview of some of the external factors impacting our results. Global economic growth 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 remain challenged. 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. Exxon Mobil'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 and asset sales was $14 billion. At the end of the first quarter of 2013, cash totaled $6.6 billion and debt was $13.4 billion. The next slide 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. 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 six and a review of our segmented results. Exxon Mobil'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 seven, Exxon Mobil'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 eight. 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 tankage with diluted bitumen and will transport the product to market with a 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 activities 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 field located offshore Malaysia in the South China Sea. The development concept of 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 within 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 sub-sea tieback to the existing Erha floating production, storage, and offloading vessels. It is anticipated to recover approximately 175 million barrels of oil with a peak capacity of 60,000 barrels of oil per day. Startup is targeted for 2016. Turning now to slide nine and an update on our conventional exploration activities. In Tanzania, we completed two successful wells during the quarter. The Tangawizi-1 well discovered gas in high-quality tertiary sandstone reservoirs, confirming four to six TCF of gas in place. This new discovery is located 10 kilometers from the Zafarani and Lavani discoveries. In addition, the Zafarani-2 well confirmed gas-bearing, high-quality reservoir 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 encountered approximately 250 net feet of oil pay in the lower tertiary aged 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 Seas of 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 of 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 to 3,000 meters. Block 13 is located 30 kilometers 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 Exxon Mobil 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, Exxon Mobil was the high bidder for seven blocks. Additionally, we acquired a 33% working interest from BP through a farm-in to the Maui prospect located in the Walker Ridge area. Exxon Mobil 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 are 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 liquid yield and to optimize both drilling and completion methodologies. 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 Denbury 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 basins. 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 thousand 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 were $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 quota effects, and divestments, 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 field decline was mostly offset by project ramp-up in West Africa and increased production from liquids-rich plays in the U.S. Natural gas production was down 823 million cubic feet per day or just under 6% quarter-on-quarter, as lower entitlement volumes, primarily reflecting Qatar AKG becoming cost current in 2012 and field decline were 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 the U.S., increased operating expenses associated with refinery maintenance activity, and unfavorable Forex 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 and 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 and 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 increased gains on asset sales. Moving to slide 19. Sequentially, first quarter chemical earnings increased by $179 million. Stronger margins, mainly in U.S. commodities, 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. Thank you, Mr. Rosenthal. The question and answer session will be conducted electronically. If you would like to ask a question, please do so by pressing the star key followed by the digit 1 on your touchtone telephone. We request that you limit your number of questions to 2, so that as many may have the opportunity to participate as possible. If you're using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we'll take as many questions as time permits. Once again, please press star 1 on your touchtone telephone to ask a question. We'll take our first question from Doug Leggate with Bank of America Merrill Lynch. Hi. Good morning, David. How are you? Good morning, Doug. How are you? I love the exotic name I get on these calls. Anyway, two quick questions, please. The unit profitability, David, on the upstream continues to lag the historical kind of capture rate. Can you comment as to whether something material has changed there? If, I guess a couple of years ago, we talked about the start of LNG trains, but is there anything specific you can point to that could lead us back on track to where we've been historically? Yeah, I think if you look at what's happened over the last couple of years, as you've 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 mix 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've seen, you could reasonably expect the profitability to reflect those increases in both the production as well as the margins. I think 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 and you are not chasing the decline that we had in prior years, you will not be investing as much money to keep the production levels where they are. I think the other thing that is positive as we look down the road, again, in addition to the liquids increase that we have talked about in the analyst meeting and the increase we are 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. 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. 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. Okay. Thank you. My follow-up, hopefully a quick one. Somebody has got to ask you, David, the share buybacks. $14 billion of cash flow, you are not covering the cash outflow. Can you just talk about what you are signaling to us? Oil is still over 100 bucks, and you are cutting the buyback program. My recollection is you are not using that as a planning assumption. Any color you can give us would be appreciated. Doug, let me hit that coming 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. We also had some timing of tax payments and that sort of thing. But the cash flow again is just an outcome of the earnings, give or take these timing effects. As we said, in terms of the buyback, I have to tell you, there is no change in our approach to capital allocation and the use of our cash flow. As you saw, we once again raised the dividend here. The board announced that yesterday, 10.5% this year, following on the 21% increase last year. We continue to raise the dividend on a consistent basis. The share buyback is strictly a function of cash flows in the quarter and expectations going forward in the quarters. No change in terms of signal or the way that we approach the allocation of the funds. All right. Thanks a lot, David. We'll take our next question from Doug Terreson with ISI. David? David, can you hear me? Yeah, sure can. Hi. Hi, how are you? My question's also on upstream profitability. I'm just going to ask it a little bit of a different way and specifically on the international side, meaning your point is taken on U.S. natural gas and 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 Rick's comments on declining drilling and completion costs in March, I just wanted 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 in exhibit 12, and maybe also whether or not there's a geographical aspect of the mix effect that's at work here. If you look on the international side, and you take a look at the profitability, one of the things that we're seeing there is a mixed impact with some of the loss of some of the higher margin barrels from the production sharing contracts that we've seen over the last couple of years. Then the mix, certainly when you get into this part of the year of European gas sales. Okay. Nothing structural, nothing really to point 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. Okay. Thanks for the clarification. We'll take our next question from Paul Cheng with Barclays. Hey, Dave. Good morning. Morning, Paul. How are you? Very good. Two questions. One, can you give us what is your 2013 CapEx on the North American Shale Oil Play? And versus that, if not an absolute, but versus the 2012, and what's the expectation for 2014? Paul, I couldn't hear you. Could you just repeat the question on the U.S. CapEx? Okay. Right. Yeah. Two questions. First, for North American Shale Oil, 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, then can you tell us what is that comparing to 2012? Also, if you can give us an idea, then what is the expectation for 2014? Is that going to be higher, or it's going to be sustained at that level? Do you want to answer that and then I go for the second question? Yeah. How about I answer that one, and then we'll go to your second question. I don't have a specific actual CapEx outlook number for you. But as we've 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'd be allocating to dry gas. And clearly, as we integrate the Denbury acquisition that we did, the Celtic acquisition that we did, it'd 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're 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 is coming up, but the efficiency that we are getting, improved completions, improved performance. That strategy and that approach is starting to play out, and you are starting to see the dividends. In terms of going forward, 2014, again, I do not have a specific outlook for you, but it would be reasonable to assume that as we continue to progress these liquids-based opportunities and continue to drill the wells and have the activity that we are having, and leveraging the ability we are getting now with these additional properties. Certainly as we ramp that up, you could expect on a relative basis over time for the CapEx to go up. But I do not have a specific actual amount for you. Dave, just curious then, say $3 billion or $4 billion currently you are spending, is a ballpark a reasonable estimate, a guesstimate, or that you are not going to be able to comment even on that? Again, I would not want to give an actual number allocated to one particular resource type and one particular geography, other than, again, to 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. Okay. Kearl startup, hopefully that we are now really at the tail end of the phase one startup phase. Just want to see that you learn a lot since you guys have never done the mining project, and so what steps that you have taken or what experience that you have learned now you apply to phase two so that you can ensure that it is going to run within budget and the startup schedule? 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 learned, and applying those to the Kearl expansion project. 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 have mentioned before, about 90% of the engineering carries over. The new trains are being built adjacent to the existing ones. It is really the efficiency that you get in building the second set of trains right behind the original project. I think that is where you will see that. In fact, if you look at where we are today and the progress that we have made, we are actually ahead of schedule right now on the expansion project. So I think that is where you are seeing the real efficiencies. 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 a low starting point, I do not think I would characterize it that way. But again, as you know us, we will be continuously improving everything we are doing as we start up and ramp up the current project and then head into the next phase. Okay. Thank you. Now, Dave, can I just stick in with a short question for clarification? In your earlier comment, for 2013 production guidance that given in March for 1%-2% decline, is that already factored in the potential PSC impact based on the $100, $110 Brent or that is- Yeah not included? Yes. The impact of PSC effects at the $112 price that we used is in that estimate 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 there at the assumed price. Thank you. We'll take our next question from Iain Reid with Jefferies. Hi, David. Morning, Iain. How are you? Yeah, I'm doing very well. A couple questions. First question on the downstream, if I could. You had a very strong performance in U.S. downstream, relative to where the margins seemed to go, and also probably a weaker performance in your non-U.S. downstream. Do you want to talk about the kind of drivers there? Were you accessing more advantaged crude in the U.S., perhaps, than we estimated? And in international downstream, was there anything really driving that one, which kind of offset what the benefits you got in the U.S.? Yeah. If you're looking at the downstream, in particular, if you're looking, I'm not sure if you were actually referring to our quarter-over-quarter or sequential. Well, both, really. Well, if you look at both of them, yes. We saw very strong refining margins, in particular in the U.S., and 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. That's coming 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. If you're looking sequentially and you look at that nice bump in U.S. earnings, a good bit of it is actual margin improvement and the other is an absence of the prior quarter's 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 maintenance activity in our refineries, particularly in Europe and in Canada. 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. Then again, if you're looking sequentially, the absence of the LIFO gain that we had in the non-U.S. from the fourth quarter. I think if you step back and look at all this and just take out the LIFO gains and asset sales that we had talked about in the fourth quarter as well, the operations are running great. We're taking advantage of the feeds that are available, particularly 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. Okay. Thanks for that. My second one. You're obviously building up now significant further volumes in Canadian bitumen. We've seen the differential there widen even further in the first quarter. Can you talk about how Exxon is impacted by market differentials there? I think you said at the analyst meeting that you thought you could take advantage, if you like, of your own pipeline systems to get around some of that. Do you just want to kind of flesh that out a bit. Sure. If you look at our refining footprint in what we call an extended mid-con, if you will. 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 have 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'll be able to capture those in our own refining circuit. Okay. So it's the second phase which you're going to have some problems with then? Well, when you look at the second phase, we'll be looking at both the opportunity to run more of that crude into our existing refineries, as well as obvious into third party. So we're working those logistics now, looking at our various options and opportunities. We've got till 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. Okay, so we should be expecting maybe lower E&P earnings from Kearl, but higher downstream earnings. The whole mix kind of comes out in the wash. Well, I think that'll 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 then that integration into Kearl. And the ability to process other crudes including disadvantaged imports, light crudes in the U.S. and that sort of thing. So it's really optimizing across the entire circuit, as well as geographic optimizations. But we feel pretty good about where we are and how our assets match up and how we're managing those, and look forward to benefiting more as we go forward with this integration. Okay. And just one very quick one, if you don't mind. Sure. You talked about an asset gain in chemicals. Are we talking on an absolute basis hundreds of millions of dollars there? How much is that in terms of improving chemical earnings? Kind of all in just under $100 million. Okay. All right. That's great. Thank you very much indeed. All right. Thank you. We'll take our next question from Pavel Molchanov with Raymond James. Hey, guys. 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. Do you envision a point maybe in the next 12 months of sanctioning a development plan? I think if you step back and take a look at Tanzania, we have had significant success there with the wells that we have drilled so far, both the exploration wells and the recent appraisal well. So far, we are looking at gas resources somewhere in the range of 10 TCF-13 TCF discovered to date. But as we look forward, we got a lot of work left to do. We have got a lot more seismic that we are running and processing, a lot more analysis to do. We are looking at drilling an additional well later this year. So we have got to take all of that into account before we can ever really start thinking about a development plan. So it is still early days. We know we have got a very high-quality resource. We have 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 is a little early right now. Fortunately, it is early because of all the success we have had to date. But we 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. Appreciate that. Follow up on a little bit bigger picture question on your unconventional opportunities globally. One of your European competitors recently poured some cold water over particularly shale gas development internationally, talking about all the obstacles. In your annual review, you have noted some of the issues in Germany and obviously earlier in Poland. Can I just get your latest thoughts on how international ex North America unconventional fits into your portfolio and what the plan is? Yeah, I think the most important thing to think about when you look at our international portfolio is how diverse it is. If you just 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 and looking at. We have planned to drill a number of more wells in Argentina. As I mentioned in 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. That's doing very well, and we continue to leverage, again, the expertise that we have here in North America into those plays. Now, having said that, there is prospectivity in Europe, and as we've 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 permits that would allow us to continue our exploration and appraisal process. We stand ready to ramp up activity there pending that. It's a long-term business. It's a long-term resource development. Both the oil companies and the countries that have these resources are just getting started with their evaluation programs and developing policies. We can pace our activity based on local requirements and regulations. Again, the good news for us is we've 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. We are continuing to do that very well into this year. All right. Appreciate the color on all that. Thanks. As a reminder, it is star one if you would like to ask a question. We will take our next question from Ed Westlake with Credit Suisse. Hey, good morning, David. This is Scott Willis on for Ed. Hi, Scott. I would just like to focus on U.S. natural gas for a minute, if I could. Sure. I noticed that your domestic volumes were down around 4% quarter-over-quarter. 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. Well, I think if you step back and look at the unconventional resource in North America and particularly in the U.S. that we're working on, as we've 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. Those efforts are continuing, and we're making great progress in terms of productivity, optimizing the completions, getting the initial rates, and extended rates out. That effort continues unabated, and we will continue to do that. I think the other news that's really good for us 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. 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. Okay, great. 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. Yeah, I cannot 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. I wouldn't want to give you a run rate. 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 have seen this quarter or prior quarters. It will happen when it happens. Got you. Okay. Thanks, David. We will take our next question from Robert Kessler with Tudor, Pickering, Holt. Good morning, David. Good morning. A couple of 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 have 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 have got about $400 million marked in the footnotes as restricted, but is that to say that the full $6.2 billion 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 extent you have got some abroad or that kind of effect? Well, getting to the last part of your question and backing up, there are a number of factors that determine what our point in cash balance is in any quarter. I mentioned some of those this quarter, including closing the Celtic acquisition, some timing of tax payments, working capital changes, et cetera. So we do not have a target in terms of what the cash balance is or a minimum that we have to have or an operating level. We manage the cash just to maintain our flexibility and meet all of our commitments, and it does bounce around a fair amount as you have seen over time. But I would not want to 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 have said before, the share buyback is determined on a quarterly basis and is a reflection of the cash that is available as delivered from the business, given the market conditions that we have. As I said, our expectation is we will buy $4 billion in the second quarter. But other than that, I just would not have any guidance on either the uses of cash or the buyback level going forward. 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? 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 wouldn't expect there to be anything significant or material to worry about or to think about what to do with. Okay, thanks for that. Then a quick follow-up from me on the chemical asset sale gain. 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? Yeah, it's about half and half in the U.S. and half overseas. I said the number was just under $100 million. In total, it's $70 million, and again, half in the U.S. and half in the non-U.S. Great. Thanks very much. With no further questions, I'd like to turn it back to Mr. Rosenthal for any additional or closing remarks. Yeah, I'd just like to say in closing, I appreciate your time and your questions this morning and look forward to our call in about three months. So thank you very much. This concludes today's conference. Thank you for-