Earnings Call: Q4 2012

Feb 1, 2013

Summary

Q4 earnings rose 6% YoY as downstream and chemicals gains offset lower upstream results. FY earnings reached $44.9B, with $63.8B in cash flow from operations and asset sales supporting $30.1B of shareholder distributions and $39.8B of CapEx.

Good day, and welcome to the Exxon Mobil Corporation fourth quarter 2012 earnings conference call. Today's call is being recorded. At this time, for opening remarks, I would like to turn the call over to the Vice President of Investor Relations and Secretary, Mr. David Rosenthal. Please go ahead, sir. Good morning, and welcome to ExxonMobil's fourth quarter earnings call and webcast. The focus of this call is ExxonMobil's financial and operating results for the fourth quarter and full year 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 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 remained weak in the fourth quarter, driven by the U.S., Japan, and Europe. Preliminary fourth quarter U.S. GDP showed a slight decline of 0.1%. The Japanese and European economies remain challenged, with Japan experiencing its second recession in three years and Europe likely marginally positive. Meanwhile, China's growth rate showed some improvement, reflecting an upturn in industrial production and higher retail sales. Energy markets were mixed in the fourth quarter, with higher U.S. natural gas prices and relatively flat Brent crude oil prices, while WTI prices declined. European and Asian chemical margins showed improvement. However, global industry refining margins deteriorated significantly versus the third quarter. Turning now to the fourth quarter financial results, as shown on slide 4. ExxonMobil's fourth quarter 2012 earnings were just under $10 billion, an increase of $550 million from the fourth quarter of 2011. Earnings per share for the quarter were $2.20, up $0.23 from a year ago. The corporation distributed $7.6 billion to shareholders in the fourth quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was used to repurchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the first quarter of 2013. CapEx in the fourth quarter was $12.4 billion, up 24% from the fourth quarter of 2011, primarily due to the Denbury transaction. Our cash generation remains strong, with $14 billion in cash flow from operations and asset sales. At the end of the fourth quarter 2012, cash totaled $9.9 billion, and debt was $11.6 billion. The next slide provides additional detail on fourth quarter sources and uses of funds. Over the quarter, cash decreased from $13.3 billion to $9.9 billion. The combined impact of strong earnings, depreciation expense, working capital, 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 $10.1 billion and shareholder distributions of $7.6 billion. Additional financing and investing activities increased our cash by $300 million. Moving now to the full-year results, as shown on slide six. ExxonMobil's full-year 2012 earnings were $44.9 billion, up $3.8 billion from 2011. Earnings per share for the year were $9.70, up $1.28 from 2011. The corporation distributed $30.1 billion to shareholders in 2012 through dividends and share purchases to reduce shares outstanding. Of that total, $20 billion was utilized to purchase shares. CapEx in 2012 was $39.8 billion, up $3 billion from 2011, primarily due to continued progress on our world-class project portfolio, including the Kearl Oil Sands project. Included in full-year CapEx was about $3 billion of acquisitions. Our cash generation was very strong, with $63.8 billion in cash flow from operations and asset sales, including $7.7 billion associated with the asset sales. Moving now to the full-year cash flow statement, as shown on slide seven. During the year, cash decreased from $13.1 billion to $9.9 billion. The combined impact of strong earnings, depreciation expense, working capital, and the benefit of our ongoing asset management program yielded $63.8 billion of cash flow from operations and asset sales. Uses included additions to PP&E of $34.3 billion and shareholder distributions of $30.1 billion. Additional financing and investing activities decreased cash by $2.6 billion. Moving on to slide eight and a review of our segmented results. ExxonMobil's fourth quarter 2012 earnings of just under $10 billion increased $550 million, or 6%, from the fourth quarter of 2011. Primarily due to higher refining and chemical margins, partially offset by lower production volumes and lower gains on asset sales. Upstream earnings decreased $1.1 billion, while downstream earnings improved by $1.3 billion. Chemical earnings were up $415 million, and corporate and financing expenses increased by $141 million, primarily due to tax items. Guidance for corporate and financing expenses remain at $500 million to $700 million per quarter. As shown on slide nine, ExxonMobil's fourth quarter 2012 earnings increased by $380 million compared with the third quarter of 2012, primarily due to higher production volumes and gains on asset sales, partially offset by lower refining margins. Looking now at the full year comparison on slide 10, ExxonMobil's full year 2012 earnings were up $3.8 billion to $44.9 billion, an increase of 9% from 2011, primarily due to divestment and restructuring gains and higher refining margins, partially offset by lower production volumes. Upstream earnings decreased $4.5 billion, while downstream earnings were up $8.7 billion, and chemical earnings were down $485 million. Corporate and financing expenses for the full year 2012 were down a favorable $118 million from 2011. Moving next to fourth quarter business highlights and beginning on slide 11. We continue to advance our global portfolio of high-quality upstream projects. At the end of the fourth quarter, construction of the Kearl initial development was complete, and we are currently progressing phased startup activities. Mining operations have commenced, and ore is being stockpiled adjacent to the ore processing plant, which is being commissioned. Commissioning of the utility systems is well advanced, with two boilers operational. The ore preparation plant crusher and slurry preparation conveyors also began running in December. The bitumen process facilities are being readied for the introduction of solvent, and the diluent and natural gas supply systems are operational. We expect production of mined diluted bitumen from the first of three froth treatment trains in the first quarter. Startup of the two additional bitumen froth treatment trains will proceed in sequence as planned, with production from the initial development expected to reach volumes of approximately 110,000 barrels per day of bitumen later in 2013. Despite U.S. permitting and regulatory issues that continued for almost two years involving transportation of facility modules, our project team achieved industry-leading safety performance and mitigated significant challenges, including an early onset of winter and exceptionally harsh weather during the current startup operations. Our priority remains to complete these activities safely. Also during the quarter, we announced our plans to develop the Hebron oil field offshore Newfoundland and Labrador. The development will utilize a gravity-based structure designed to withstand a variety of harsh Arctic conditions, including sea ice and icebergs. The base, which is already under construction, has been designed to store approximately 1.2 million barrels of crude oil and will support an integrated topsides deck that includes living quarters and facilities to perform drilling and production operations. Oil recovery from the project is currently estimated at 700 million barrels with upside potential. The platform is designed for production of 150,000 barrels of oil per day. First oil is anticipated around the end of 2017. Finally, the Angola Satellites Phase 2 project was sanctioned during the quarter. The development continues to optimize the capabilities of the existing Block 15 facilities and will allow current production levels to be increased via subsea tiebacks to our existing FPSOs. Turning now to slide 12 and an update on our conventional exploration activities. In Tanzania, the Zafarani-2 well successfully appraised the Zafarani-1 Paleogene discovery. Additionally, a new discovery of gas in a high-quality Cretaceous reservoir was encountered. This reservoir is of similar age to the Zafarani discovery and marked the third discovery on Block 2 in 2012. The Zafarani-2 appraisal well spud in December. Additional 3D seismic acquisition and processing is also underway and is expected to be available for analysis in the first quarter of 2013. Also during the quarter, ExxonMobil secured the right to farm in to a 75% operating interest in the Tugela South exploration right, which covers approximately 2.8 million acres offshore Durban on the east coast of South Africa. Separately, we executed a technical cooperation permit with the government of South Africa to study the hydrocarbon potential of the deepwater Durban Basin, covering approximately 12.4 million acres. In the Gulf of Mexico, the Phobos prospect, which is five miles south of ExxonMobil's Hadrian South discovery, spud during the quarter. Additionally, we have plans for an active exploration program in the Gulf of Mexico during 2013. Turning now to our unconventional exploration activities on slide 13. In the Middle Magdalena Basin of Colombia, we drilled the Mono Araña-1 well targeting tight oil in the La Luna Shale formation. This well will be tested during the first quarter of 2013. In Argentina, we have completed the drilling of four wells on the Loma del Molle, Los Toldos-1, and Los Toldos-2 blocks with encouraging results. Completions and testing are now underway. Two additional wells on the Sierra Chata and Pampa de las Yeguas blocks are currently drilling. In Russia, Rosneft and ExxonMobil signed a pilot development agreement establishing a joint project to assess the commercial production of tight oil reserves at the Bazhenov and Achimov formations in West Siberia. The joint venture is 51% Rosneft and 49% ExxonMobil. Work will be carried out on Rosneft's 23 license blocks, covering a total of more than 10,000 square kilometers. Drilling is anticipated to begin in 2013. Also, during the quarter, we closed on the Denbury transaction, which increased our holdings in the Bakken region by about 50% to approximately 600,000 net acres, giving the company a more significant presence in one of the major U.S. growth areas for onshore oil production. Turning now to the upstream financial and operating results, and starting on slide 14. Upstream earnings in the fourth quarter were $7.8 billion, down $1.1 billion from the fourth quarter of 2011. Lower crude oil realizations, mostly offset by improved natural gas realizations, negatively impacted earnings by $70 million. As crude oil realizations declined $3.18 per barrel and gas realizations increased $0.21 per thousand cubic feet. Production volume and mix effects negatively impacted earnings by $400 million. All other items, primarily lower gains from asset sales, decreased earnings by $600 million. Upstream after-tax earnings per barrel for the fourth quarter of 2012 were $19.65. Moving to slide 15. Oil equivalent volumes decreased by 5.2% from the fourth quarter of last year due to the impact of base decline, lower entitlement volumes, and divestments. Volumes were positively impacted by the ramp-up of projects in West Africa and higher demand. Excluding the impacts of entitlement volumes, OPEC quota effects, and divestments, production was down 2.1%. Turning now to the sequential comparison and starting on slide 16. Upstream earnings increased by $1.8 billion versus the third quarter of 2012. Realizations decreased earnings by $50 million, primarily due to lower crude oil realizations, which declined $0.66 per barrel but were mostly offset by improved natural gas realizations, which increased $0.72 per thousand cubic feet. Production volume and mix effects increased earnings by $660 million. Other items, including higher gains from asset sales and favorable tax items, increased earnings by $1.2 billion. Moving to slide 17. Oil equivalent volumes were up 8.4% from the third quarter of 2012, mainly due to higher seasonal demand in Europe and lower downtime, partly offset by base decline. Entitlement volumes were positive due to favorable price and spend impacts in several regions. Turning now to the full-year comparison and starting on slide 18. Upstream earnings were $29.9 billion in 2012, a decrease of $4.5 billion from 2011. Lower crude oil realizations, primarily in the U.S., partly offset by improved natural gas realizations, led to a negative impact of $110 million. Lower volume and mix impacts decreased earnings by $2.3 billion. All other items, including higher operating expenses, unfavorable tax items, lower gains on asset sales, and unfavorable foreign exchange impacts reduced earnings by a total of $2.1 billion. Moving to slide 19. Full-year volumes declined by 5.9%, or 267,000 oil equivalent barrels per day compared to 2011. Lower volumes were primarily driven by base decline, lower entitlement volumes, and divestments, partly offset by project ramp-up in West Africa and lower downtime. Excluding the impacts of lower entitlement volumes, quotas, and divestments, production was down 1.7%. For further data on regional volumes, please refer to the press release and the IR supplement. On slide 20, we show actual 2012 production volumes compared to the outlook provided at the March analyst meeting. Overall, actual 2012 volumes were 2.7% lower than this outlook. About half of this variance was due to operational performance, with the balance due mainly to entitlement and Iraq spend impacts. Operational performance for the year was slightly below forecast, reflecting the timing of work program execution and the duration of downtime events, particularly in the U.K. North Sea. While the 2012 Brent crude price of about $112 per barrel is near the basis of our March analyst meeting outlook, prices in the first half of 2012, most notably February through April, were higher than our outlook basis, which negatively affected volumes due to the timing of both permanent and price-related impacts. The efficient use of capital in Iraq resulted in lower spending, which also lowered net volumes. Moving now to the downstream financial and operating results and starting on slide 21. Downstream earnings in the fourth quarter were $1.8 billion, up $1.3 billion from the fourth quarter of 2011. Improved margins, mainly in North American refining, increased earnings by $1.2 billion. Volume and mix effects increased earnings by $80 million, mainly due to increased capture of advantaged North American crude supply. All other items increased earnings by a net $80 million. Turning to slide 22. Sequentially, fourth quarter downstream earnings declined by $1.4 billion. Lower refining margins decreased earnings by $1.4 billion, while volume and mix effects increased earnings by $260 million, mainly driven by optimization and yield improvements. Other items reduced earnings by $270 million, primarily due to the absence of the gain on the Switzerland investment. The full-year comparison for the downstream is shown on slide 23. Downstream full-year 2012 earnings were $13.2 billion, up $8.7 billion from 2011. Higher margins, mainly in North American and European refining, increased earnings by $2.6 billion. Volume and mix effects increased earnings by $180 million as refining optimization activities, including increased capture of advantaged North American crude supplies, were partly offset by higher planned maintenance activity and lower contributions from divested assets. Other effects increased earnings by $5.9 billion, mainly due to the restructuring of our downstream holdings in Japan. Moving now to the chemical, financial, and operating results, starting on slide 24. Fourth quarter chemical earnings were $958 million, up $415 million versus the fourth quarter of 2011. Stronger margins increased earnings by $330 million, mainly reflecting higher aromatics realizations and improved light feed advantage. All other items increased earnings by $90 million. Moving to slide 25. Sequentially, fourth quarter chemical earnings increased by $168 million. Stronger margins, mainly due to improved aromatics realizations and improved light feed advantage, increased earnings by $180 million. All other items decreased earnings by $10 million. On slide 26, we show the full-year comparison for chemical results. 2012 earnings were nearly $3.9 billion. Weaker margins, mainly in Europe and Asia, decreased earnings by $440 million, while volume and mix effects decreased earnings by $100 million. Other effects increased earnings by $50 million due to the Japan restructuring, partly offset by a number of items, including unfavorable foreign exchange impacts. Moving to slide 27. ExxonMobil's fourth quarter and full-year financial and operating performance reflect the value of our integrated business model and other competitive advantages. In the fourth quarter, we earned just under $10 billion, generated $14 billion in cash flow, invested $12.4 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 unparalleled global integration, ExxonMobil remains well-positioned to maximize long-term shareholder value. Finally, I would like to mention two upcoming events. First, in mid-February, we will be releasing our 2012 reserves replacement data. Second, as many of you will already have seen, our analyst meeting this year will take place at the New York Stock Exchange on Wednesday, March 6th. This will include a live audio webcast beginning at 9:00 A.M. Eastern, 8:00 A.M. Central Time. ExxonMobil's presenters will be led by Chairman and CEO Rex Tillerson. 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 the opportunity to participate as possible. If you are using a speakerphone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will proceed in the order that you signal us, and we will take as many questions as time permits. Once again, please press star one on your touchtone telephone to ask a question. We will take our first question from Evan Calio of Morgan Stanley. Morning. Morning, David. Morning, Evan. How are you? I am good. I got some strange feedback here. Maybe it is just on my line. My question on production is, for Kearl, is that weather the driver in the shorter-term delay in the production ramp? Should we be considering a three-quarter ramp up to 110,000 barrels a day, I guess exiting the year at that capacity? I have a second question. Please. Yeah. The weather situation was a major factor in the startup, moving from what we had originally said by the end of the year to the first quarter. We had two things, actually. One, weather came earlier than normal, and then it has been just brutally cold up there, so we have had to adjust accordingly. As we move through the quarter and continue progressing some of the activities I mentioned in my prepared remarks, we do expect as that first froth treatment process comes up, that will give us about 37,000 barrels of bitumen a day. Then we will bring up the next two froth treatment trains kind of in sequence, and that will get us up to 110. I do not have a specific date for achieving the 110, but it will be later in the year as a function of progress that we make here across the winter getting things started up safely. So the focus is getting the project up and running, getting that first production online, and then moving forward and getting up to the full capacity that we have mentioned. We are making really good progress this quarter. But again, it is a deliberate, diligent effort to get this thing up safely, recognizing that this is a multi-decade project, and we really want to focus on getting it up right. That is great. My second question really relates to the use of rail for oil movement in North America. I know that Exxon has a large existing rail car fleet, a diversified and growing liquid footprint. Yet I also read a report recently that Exxon has placed a significant rail car order recently. So I am just wondering if you see rail as a potential solution for Canadian barrel production in the event maybe the Keystone is delayed or denied, or if you have other kind of specified or contemplated use for rail as a bit more permanent solution for oil movement in North America. Thanks. That's an all-encompassing question, so I'll probably step back here for just a second and put it in perspective. First of all, with relation or with regard to the Kearl project, we have worked all of the logistics out, and we can place all of our barrels, and we have the capability to run all those barrels in our own refineries for that first 110,000 barrels a day. We may elect to put some into third-party refineries, but we do not have an issue in terms of logistics moving those barrels out of the Kearl project and into the market. As you look a little more broadly, both at the Canadian heavy crudes as well as a lot of the crudes such as Bakken, until pipelines are built and some of the things that you mentioned actually come to fruition, there are today bottlenecks across the industry, and there's a lot of different modes of transportation being used to move that product to market. Of which rail car is certainly one of them waiting for some of these pipelines to come in. As you mentioned, as you would expect with the size of our business, we have a very large fleet of rail cars, both across all of our businesses. That is already a primary mode of transportation for us. We're always looking at that. We're always looking at the logistics and how we can optimize both the placement of our production into the market as well as obtaining advantage feedstocks for our refining circuit. That is an ongoing effort, and there's nothing unusual in that. In regards to the rumor that you heard, I would just say that's a rumor. Wouldn't have a comment on it specifically. But I can say there's nothing out of the ordinary in terms of what our supply organization is working on. Again, getting our crudes to market for the best value and getting the lowest cost advantage feedstocks into our refineries and chemical plants. Thank you, David. I'll leave it at that. Appreciate it. We'll take our next question from Doug Leggate of Bank of America Merrill Lynch. Thank you. Good morning, David. Morning, Doug. I've got a couple, so I'll try and be fairly quick on these. Sure. Can I deal first with the capture rate? We used to look at this quite a lot. I guess it's now become a bit of an issue again. I'm talking about the net income as a proportion of your weighted realizations. Sure. Not just in this quarter, but the last two or three quarters, it looks like it's been sliding a little bit. I'm just wondering if there's a particular trend that you can observe there for something that you're seeing as well, what might be behind that? I've got a quick follow-up, please. Yeah. I know the trend you're talking about over the last couple of quarters. Of course, there's a lot of things working in there. Some of the price differentials that you're seeing, some of the mix effects of where our production's coming from, some of the entitlement effects that you see there. Again, U.S. gas production and that sort of thing. So I wouldn't read anything into a couple of quarters worth of data. We are very focused on unit profitability, and working that very hard, getting some of these projects up. We have seen some increased operating expense as we brought some of these new projects up. Again, I think if you look over the longer trend, and you look at the projects we got coming on, I think that'll sort itself out. But a lot of ups and downs across the year here. Okay. I'll keep an eye on that one. The other one is really, I know you're not going to give me a great answer necessarily, so I'm presuming so. Buybacks and dividends, David. There is some chatter in the market that the sustainability of your buybacks may not be realistic to assume $5 billion on a quarterly basis. You have still got very low net debt to cap. So I'm just curious about how management is thinking about where the balance sheet ought to be for a company, given the level of your capital spending, and what the priorities would be potentially for, again, further. I mentioned in the prepared remarks that we are looking at another $5 billion of buybacks for the quarter. I do not have any guidance going forward. That will depend on a number of things, including commodity prices and margins. In terms of the balance sheet structure and use of debt and our cash flows, Doug, there is really no change in what we have been doing for a very long time, which is making sure we pay a consistent increasing dividend over time. We fund that very robust capital program that we have and get these projects. As you know, we have some very large projects starting up between now and the end of 2016, getting all that funded, as well as our pipeline of portfolio projects. Then the balance of the cash we return to the shareholders via the buyback. In terms of target leverage or any of that sort of thing, I really would not have a comment on that other than we do have an objective of maintaining a very strong balance sheet, keeping that flexibility to take advantage of opportunities. Although there is wide variability in prices and margins as we go through the cycles in the business, those constants will remain just that, and we really would not have any change that I could foresee coming. Great. Thanks a lot, David. We will go next to Ed Westlake with Credit Suisse, please. Hey, good morning, David. Good morning, Ed. How are you today? Good. I just was going to keep this on the actual earnings. One question for 2015, obviously, you've made some small acquisitions, Denbury and obviously Celtic. If you couldn't just run us through what volumes you expect in 2015 and when you expect, I think, the Celtic deal to close. Yeah, let me hit the second one first, and then I'll come back to the other one. I really wouldn't give any outlook comments on Celtic. That transaction has not closed yet. We're still in the review process. Making any comment about that probably would not be appropriate. If we go back to the Denbury deal that we did close in the fourth quarter, we did pick up, as I mentioned, a couple of hundred thousand acres there. I don't have an outlook for you, but in terms of what we'll do as we go forward, I can tell you that we did see in our own business in the Bakken gross operated production of about 33,000 barrels a day this year, and that was up just over 50% from last year. That excludes the little bit of a contribution from the Denbury acquisition there at the end of the year. I will say that this acreage that we are picking up is in the high-performing middle Bakken and upper Three Forks area. It is also pretty adjacent to the properties we already had, so we get some good synergy and leverage there. Without giving a specific outlook on the volumes from that, we are certainly looking forward to folding that into our portfolio, optimizing the production out of that, and really putting together, as we always do, a long-term forward plan for developing that resource. We are pretty excited about it, but we just got it, and we are just getting to work on it. Okay, then just in the quarter you had European gas. Was demand weak, or was it decline? On Africa, you fell a bit in Q4 versus Q3, and I am just wondering, was that anything unusual? Yeah. Let us take Europe first. It is really decline, just normal decline. Nothing out of the ordinary there. We also had a little bit of, if you are looking, say, year-over-year, particularly in the fourth quarter, we did have some asset management impacts as well. Think about it as a little uptick in demand offset by normal decline in the impact of the assets that we divested. Africa oil fell quarter-over-quarter and obviously, year-over-year. Yeah. If I'm looking at the Africa liquids, I think we're actually up a little bit in the fourth quarter of 2012 versus 2011. But sequentially, yes, we have I saw you down, yeah. Yeah. If you're looking sequentially, that's really just a planned downtime event. We actually had a little increase in price and spend entitlement impacts, but it was really maintenance and downtime. Okay, thanks. Sure thing. We'll go next to Robert Kessler with Tudor, Pickering, Holt. Hi, good morning, David. Morning, Robert. If I could just follow up on the European gas volume comments. Even if I adjust for the portfolio effects, I would estimate you are still down maybe 5% year-on-year and wondering, one, is that a good adjusted number or where would you point me there? Secondly, how much of the decline might you attribute to loss with increased competition with, say, coal imports into Europe, which appear to have been quite robust mid-year into year-end? How much of that might reverse in the first quarter, would you estimate? Yeah. Let's say it is probably best to look at that on a full year over full year. The quarter I think would be pretty similar. If we look year-over-year in total, we did see a little uptick in demand on a net basis. We actually had a little better performance in our operations from a downtime perspective. That was offset, if you look at the total year-over-year demand, really by decline and asset management impacts. In terms of competition from coal or that sort of thing, I do not think that is a big impact. I know there has been some switching around up there, but I think for our perspective, overall, again, our demand was a little higher. We are just seeing the impact of normal decline and the asset management from the assets we divested primarily in the fourth quarter of last year. Okay, thanks. On the downstream, it sounds like you referenced a better capture on the light end of the barrel feeding into your refineries. Can you give us some more color around that? Are you running more light crude oil in North America as a percentage of the overall feedstock? Are you getting a better price relative to benchmarks in the applicable regions, say, LLS along the Gulf Coast? Any kind of incremental color in terms of earnings contribution on the margin or extra volumes you are running? Yeah, sure. Let me give you just a little bit of data coming right out of the earnings deck that we talked about. If you look at our fourth quarter 2012 over fourth quarter 2011 earnings, there is a volume mix effect there that nets to $80 million. I can tell you within that is about $300 million positive on our optimization of our refining circuit. A big piece of that is going to be higher advantage crude processing, both heavy crudes into a number of our refineries as well as an increased light feed slate along the Gulf Coast. That was offset by a number of things, including assets that we no longer own. But likewise, even if you look on the sequential earnings where you see that volume mix effect of a positive $260 million, embedded in that is about $400 million of total refining optimization effects also including the slate that we're running in, particularly again, the light feeds as well as getting some more of the heavy feeds in. So without being real specific in terms of numbers, we are benefiting greatly. I think one thing that we ought to be clear on understanding is it's not just the optimization of the feed slate into the refineries to produce clean products, it's also the benefit we get from the integration with chemicals and lube. So we're optimizing the products that come out as well across a broader slate. So when we're looking at optimizing the total circuit, it's across all of the business units, and that's where we probably get an advantage that others who don't have this level of integration just aren't able to get. Some of that shows up in the other places as well. I can give you one number that probably help a little bit. As we look at just our U.S. Gulf Coast refining circuit, we have more than tripled the processing of advantage North American crude over the last couple of years. So again, without giving a KBD or a percentage basis, you can get a feel for the kind of impact that we're having. I appreciate that ratio at least. Now that you've tripled and we're set to get a bunch more pipe to come online to the coastal markets here in short order, can you give some order of magnitude of how much further you could go as far as a ratio? Again, assuming the price would justify it in a linear programming model. I wouldn't want to give a specific number there for commercial reasons other than to say we are working on that and tweaking things a little bit so that we can continue to pursue the opportunities to do that and get a little more flexibility. One of the things I'll mention, another statistic that I think folks lose sight of a little bit just because of our size is when you look at our five what we call MidCon refineries, so you're talking about the Rockies and then up into Canada, we've got about 600,000 barrels a day of quote, MidCon, if you will, refining capacity. And while that's not a big percentage of our total worldwide capacity, when you look at it compared to others in the industry in the U.S., it is a sizable component of our capacity. If you are thinking about heavy feeds in the refineries, if you are looking at light feeds into the circuit, from the Gulf Coast all the way up into Canada, we are optimizing that entire circuit. Again, that is across refining chemicals and lubes, and you are seeing that in our margins, both in the chemical business and in the refining business. Got it. Thank you very much. All right. Thank you. We will go next to Jason Gammel of Macquarie. Hi, David. Morning, Jason. Hey, David, I was hoping that I might be able to get some more granularity on the comment on slide 12 that talks about the active exploration program in the Gulf of Mexico in 2013, either in terms of number of rigs employed, number of wells planned, or better yet, specific prospects you plan to drill. Then if you could provide similar information on the global deepwater program. Sure. Let's start with the Gulf of Mexico. It's really a number of things from drilling wells to processing seismic to capturing additional opportunities. I can give you a couple of well examples. The Phobos well has spud. We're participating in the Thorn well next, so a couple of wells there. We're also, as you know, we have a very large portfolio, and we're running a lot of seismic activity both on the imaging side as well as the processing and analysis. So a lot going on. I think in terms of the specifics and kind of some of the numbers, I'll hold off, and we'll discuss that in our analyst meeting, and give you a little more granularity and coverage on that. If you look globally, we've got a number of things going on, building on success from last year. As you know, we had the discoveries in Tanzania, very successful there, a lot more work going on there. We follow it up on the success we had in Romania, in the northern Black Sea, as an example. It is really a nice pipeline. We are doing an appraisal and work on Hadrian and looking at the project there. So that is kind of at the front end of the curve. Some other wells going down, building on some successes, and then the pipeline of opportunities coming in, a couple of those I mentioned in my remarks. We do intend to give you a really good, fulsome update on our deepwater program in the analyst meeting, and so I probably do not want to get too far out ahead of that. In addition, and I think equally exciting is we have a number of unconventional wells that are liquids oriented that we will be doing this year. Of course, I mentioned Western Siberia with Rosneft. We have a lot of activity going on in Colombia, continuing to work in Argentina. So probably as balanced a portfolio as we have had in a long time as we head into 2013. And again, building on last year's success and starting to drill a lot of these opportunities that we have acquired over the last few years. Okay, that helps, and look forward to the analyst meeting. As my second question, David, this is probably going to be fruitless, but you do reference on slide 20 that Iraq spend had negative effects on the 2012 production volumes relative to the outlook. If that Iraq spend number went to zero, would you be able to provide what type of impact that would have on your production guidance? No, I really do not have that number and would not want to speculate on that. I think if you look at what we were able to do in this past year in Iraq, it is really meet our commitments, get the production up, spend a lot less money. All of that is good. It just as you know how the contracts work there, that meant that we got fewer barrels, but I would not want to speculate on what a number might be if the spend went to zero. Okay, no problem. I thought that might be the case. Thank you, David. Thank you. We'll go next to Doug Terreson with ISI. Good morning, David. Good morning, Doug. I have a question about the downstream. Your OECD product sales posted a positive comparison for the first time in a while, meaning North America and Europe, Canada. My question is whether or not you guys are seeing better trends in some of these developed countries or whether company specific factors might be driving the improved results. Specifically, a minute ago, you mentioned that you're running a lot more North American crudes and yields might be better. Anyway, I just wanted to see if you could try and reconcile that. Sure. Let me start with the U.S. because that's probably the best indicator of what we're seeing. You do see a bit more of that. I mentioned it's the optimization that we're getting out of run some of the feeds. I think the biggest part and the one that we're really pleased with is we're seeing some good business growth out of our new model and our new footprint. We've been spending the last few years transitioning from a company-owned retail market or retail business rather, into a dealer and distributor market. You might think, well, we'd lose all those volumes. What we've seen, in fact, is we've kept a lot of those volumes, and the B2B business has picked up for us. Okay. Again, we're pleased with the ability. Again, it all gets back to this integrated business model and integrated business teams looking at the new footprint that we have on the retail side and finding ways to profitably move the barrels into the market that we used to run through our own and operated stores. That's really the big driver there. Okay. Also, you mentioned in the presentation just a few minutes ago, too, of the more high potential unconventional oil development areas, which being Argentina and Russia. I wonder if you could provide a little bit more specificity on what Exxon plans to accomplish in a joint venture with Rosneft and also in Argentina in 2013, meaning given the pace of activity that you highlighted, it seems like you may be able to frame an outlook in Argentina sooner, but just wondered if you had more specifics on the next steps in those two countries this year. Sure. Let me start with Russia and then back up into Argentina. If you're looking at Western Siberia, in particular, in that unconventional area, the plan for 2013 is really to take this agreement that we've signed and really start looking at testing, analyzing what's there. Of course, on all these unconventional plays, it's not a question of is there something down there, it's a question of can you make it commercial. Okay. As you've seen around the world, some of these have been commercial early, and some have not been commercial. So, the most important first step in Western Siberia tight oil is to see what's there, apply some technology, and see if that's going to be commercial, and that's what we'll be doing this year jointly with Rosneft. Of course, the great thing about Western Siberia is you have an opportunity to leverage the expertise we've developed and are applying here in the U.S. and we've applied elsewhere in other countries. We're currently doing it in Argentina and Colombia, and take that into Western Siberia, marry it up with Rosneft's operating capabilities and all of the assets that they have on the ground, and see if we can fairly quickly ascertain what's there and the commercial viability. I mentioned there's, I think, 10,000 square kilometers over 23 blocks. So defining where the best spots are quickly will also be very key so that we don't spend too much time and money drilling in areas that don't have the best prospectivity. It's still early days in Argentina. I mentioned that we do have these four wells down, and we're very happy to have that, and we're looking at those. We've got 800,000 acres down there, and we know it spans all of the windows from dry gas to mixed gas and liquids, to tight oil. So the real objective of the exploration effort is to figure out what we've got, where it is, can it be commercially produced, and then after that, how you might develop that resource and get those products to market. As we look into 2013 in Argentina, we're going to continue evaluating and testing the wells that we drilled and got down last year. I will tell you that we have another well that was drilling at year-end, that we will get done in the first quarter and get to work testing that this year. Then we have the sixth well I mentioned that spud in December. Then we have four additional wells coming this year. Wow. These will be our first operated wells in a number of areas. When we get done this year, although we will have barely scratched the surface of 800,000 acres, we should have a pretty good idea what we got with the way we have these wells and- David, you do not consider infrastructure constraints to be meaningful in either country where you guys are operating? Not at this point in time. Okay. We've got plenty of assets on the ground that we're deploying, and so we don't see that as an issue, again, in this exploration and evaluation and assessment phase that we're in. Okay, thanks. We'll take our next question from Iain Reid with Jefferies. Hi, David. Good morning. Morning, Iain. How are you? I am doing very well. Very well. Going back on production, just looking at it from a high level. You are talking about falling by 6% year-on-year. Gas is down substantially more than that, particularly in Asia. You have talked about the European issues, but also in the U.S. It seems to me that globally, your gas volumes are declining, faster than I think was generally expected a year ago at the analyst meeting. Do you want to make a general comment on that? Obviously, Exxon is very positive on gas in terms of demand going forward, so it seems strange in a way. I can understand the U.S. situation, but outside of the U.S., it seems strange, unless there is some operational issue, why gas is falling really so far. It kind of makes you wonder about whether the rebound which you were forecasting last year in overall production of 1%-2% from 2012 is likely under this sort of progression we are seeing. Yeah. Let me look at that on the full year basis. As you mentioned, gas in total year-on-year is down about 6%. If you look across the regions, I mentioned Europe already, and that was a chunk of that. One of the big factors is one I mentioned in the last quarter. We became cost curve at our AKG project in Qatar, and you might recall that is a flowing gas project into Qatar as opposed to going into LNG. That is the biggest driver. If you look at our Asia gas production, down about 500 KBD or 10% year-on-year. There are a few things in there, but a big chunk of that is going to be the AKG project. Now, if you look across some of the other ones, we did see, for example, in Australia, some lower demand this year that was weather-related. If you look at the declines in North America, the U.S. is down just a little bit. We have, as I have talked about over the year, had a fairly significant shift of our rig count away from the dry gas areas into the liquids-rich areas, into places like the Bakken, in the Permian, in the Ardmore, and away from some of the dry gas areas. You are certainly seeing that impact there as well. Canada, just there we had the asset sales, you might recall, a year ago, and so we saw some of that. We got good value for that property and just normal decline. If I look across all of the regions, there is nothing there that is unexpected. The only thing that happened a little quicker than we were expecting was the cost currency in AKG. We will be providing a fulsome update on our production outlook at our March analyst meeting, both on the liquids and the gas side. I will say, just to finish it up, if I look at expectations and performance, a decline came in this year right about what we were expecting. Of course, we knew what the impacts of the asset sales would be and the cost currency on AKG. From that standpoint, and operationally, overall downtime was a little better. Performance improved there. I would not look at the year-to-year change as anything to be concerned about or that we were not able to do what we had planned to do. Again, in terms of going forward, we are certainly looking forward to visiting with you all in March and giving you a fulsome outlook on that. Okay. Thanks, David. Could I tempt you on a question on the reserve outlook turn for 2012, or are you going to hold that one over until you report that? We will hold that for a couple of weeks. We are going to do our normal mid-February report out on how the reserves and resource base is looking. If you will bear with us for a couple of weeks, we will get that out about mid-February. Okay, last one then. If I look at CapEx, which obviously is higher than you outlined a year ago, can you just strip out the acquisitions you have made to tell us what the kind of organic CapEx is? Yeah. Let me take the opportunity to update on that, because I think we had talked about $37 billion at the analyst meeting. We said that did not include acquisitions. We had about $3 billion worth of acquisitions across the year. So if you take the $3 billion out of the $40 billion that we actually reported, we would be pretty much spot on the outlook that we gave you in March. Okay. Look forward to March then. We too. Thank you. Probably got time for one more question if there is one. Okay. We'll take our last question from Paul Cheng of Barclays. Hey, good morning, guys. Morning, Paul. Two quick one. David, in your presentation on page 16, you indicate that the $1.2 billion is the asset sales gain and the favorable tax primary. Do you have an actual absolute number for the tax benefit in the quarter? This was the Which page? Page 16 on the upstream. Oh, okay. That's on the sequential- Right. Do you have an absolute number, not sequential change, but the absolute number of the tax benefit in the quarter? Sure. The absolute, let me see. I do not have an absolute number. I can tell you what the change is sequentially. It is about $700 million of the $1.2 billion. That is the sequential change. Yeah. After the call, if you have that number and would be willing to share, if you do not mind to have someone just shoot me an email. Okay. Secondly, in Kearl, if we look at the actual cost for phase one now is $12.9 billion. Last year, I think revised up to $10.9 billion, and original budget was $8 billion. This is somewhat uncharacteristic of Exxon, given the cost overrun. And with that, only about a year and it has gone up from $10.9 billion to $12.9 billion. Should we be concerned about the phase two, the current $8.9 billion, that it is going to be significantly higher? Yeah, Paul, let's talk a little bit. As you recall, between the very first estimate and the 10.9 that we gave, we reconfigured the project and put it into the initial production project and the expansion project and talked about the debottlenecking would come down, and that was one of the big factors in that. Of course, Forex has played a factor in the overall project, et cetera. I think one of the things that's real important to keep a focus on is if you look at the total bitumen expected to be recovered by the first phase and the expansion phase, about 3.2 billion barrels of bitumen. The all-in cost for that, including this recent update that we gave on the dollar cost, is about $6.80 a barrel total, all in, and that compares to the $6.20 that we had given before. So we're up about 10% on a unit cost basis as we work through both the initial project and the expansion. While that is an increase, we're feeling pretty good about it given a lot of the challenges that we had to deal with in terms of transportation of the modules and the weather, and that sort of thing. If we look specifically at the expansion project, where we have given an estimate of $8.9 billion, and of course, that's a lot less than the first one because of all the infrastructure, the tailings dam, and all that sort of thing that's already in there. The good news on that project is it's actually a little ahead of schedule as we're sitting here today. It's about 27% complete, and moving right along, and really starting to see the advantage of the ability to basically carry over all of the engineering work that was done on the first phase, building the second train right behind the first one, applying the learnings in a real-time basis. I don't have another cost outlook for you other than the 8.9. But when you look at the schedule that we're on and the progress we're making, that project is coming along real good. Again, when you look at those two projects together, we feel real good about the competitiveness of that project going forward in this space. Then again, as the years go by, we'll look forward to the debottlenecking and getting up to that full 345,000 barrels a day we've talked about before. Okay. Thank you. Can I just maybe sneak in? On the shale oil, do you have a rough estimate the number of rig that you're going to use in the U.S. for the shale oil development? Is that going to be higher, about the same, or lower than last year? Yeah. I think on average, you will see that because of the big trend we made across last year, where we went from notionally 45% or so of the rigs as we came into the year doing dry gas, and now we are down to about a third on the gas side, two-thirds on the liquid. As you balance that out across the full year, you would, of course, see on average year to year, more rigs associated with the liquids. We continue to optimize the whole rig fleet. But in terms of what the total rig count would be, that would be hard to say right now because, again, we have just gotten the Denbury deal done, and we are looking at that and thinking about what we want to do and looking at some of the other aspects of our unconventional liquids program in North America. But we will be actively pursuing those resources and working hard on the development, but I just cannot give you a specific rig count just yet. Mm-hmm. Okay. Thank you. Okay. Thank you very much. That concludes today's question and answer session. Mr. David Rosenthal, at this time, I will turn the conference back to you for any additional or closing remarks. I'd just like to thank everybody for your participation on the call today and all your questions. We certainly are looking forward to our meeting in March and having the opportunity to talk more about our results and our plans for the future. We'll see you then. Thank you all very much.