Good day, and welcome to the ExxonMobil 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 Investors 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 3 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's 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…

[Operator Instructions] We will take our first question from Evan Calio of Morgan Stanley.

My question on production is for Kearl, is that weather the driver in the short-term delay in the production ramp? And should we be considering a 3-quarter ramp-up to 110,000 barrels a day, I guess, exiting the year at that capacity? And then I have a second question, please.

Yes, 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 2 things actually. One, weather came earlier than normal and then it has been just brutally cold up there, and so we've 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 frac treatment process comes up, that'll give us about 37,000 barrels of bitumen a day, and then we'll bring up the next 2 frac treatment trains kind of in sequence, and that'll get us up to 110,000. I don't have a specific date for achieving the 110,000 but it'll 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've mentioned. And we are making really good progress this quarter, but again, it's 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's great. And my second question, it really relates to the use of rail for oil movement in North America. And I know that Exxon has a large existing railcar fleet, a diversified and growing liquid footprint. I also read a report recently that Exxon's placed a significant railcar order recently. And so I just wondering do you see rail as a potential solution for taking [ph] barrel production in the event maybe the Keystone is delayed or denied, or if you have other kind of specified or a contemplated use for rail as a bit more permanent solution for oil movement in North America.

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 crude 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, some bottlenecks across the industry and there's a lot of different modes of transportation being used to move that product to market, of which railcar is certainly one of them, waiting for some of these pipelines to come in. As you mentioned, we have -- or 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, and so 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 advantaged feedstocks for our refining circuit. And so 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. I wouldn't have a comment on it specifically, but I can say there's nothing out of the ordinary in terms of what our organization, our supply organization is working on, again, getting our crudes to market for the best value and getting the lowest cost advantaged feedstocks into our refineries and chemical plants.

We'll take our next question from Doug Leggate of Bank of America Merrill Lynch.

I've got a couple, so I'll try and be fairly quick on these. But 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. The last -- not just in this quarter, but the last 2 or 3 quarters, it looks like it's been sliding a little bit, and I'm just wondering if there's a particular trend that you can observe there or for something that you're seeing as well, what might be behind that? And then I have a quick follow-up, please.

Yes. That -- yes, 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. And 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. But again, I think if you look over the longer trend and you look at the projects we've 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 on this, at least I'm presuming, so buybacks and dividends, David, there's some chatter in the market that the sustainability of your buybacks may not be -- it might not be realistic to assume $5 billion on a quarterly basis. But you have still got very, very low net debt to cap. So I'm just curious about how management is thinking about where the balance sheet [ph] ought to be for a company given the level of your capital spending and what the priorities would be potentially for, again, for the [indiscernible]?

Yes, I mentioned in the prepared remarks that we're looking at another $5 billion of buybacks for the quarter. I don't have any guidance going forward, that'll be -- depend on a number of things, including commodity prices and margins. In terms of the balance sheet structure and use of debt in our cash flows, Doug, I -- there's really no change in what we've 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 very large projects starting up between now and the end of 2016, getting all that funded, as well as our pipeline of portfolio projects. And 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 wouldn't 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. And so although there's wide variability in prices and margins as we go through the cycles in the business, those constants will remain just that. And we really don't -- really wouldn't have any change that I could foresee coming.

We'll go next to Ed Westlake with Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: So I just was going to keep this on the actual earnings, but one question for 2013. Obviously, you've made some small acquisitions, you've Denbury and obviously Celtic. If you can just run us through what volumes you expect in '13 and when you expect, I think, the Celtic deal to close.

Yes. 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. So 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 operating production of about 33,000 barrels a day this year, and that was up just over 50% from last year, and that excludes a little bit of a contribution from the Denbury acquisition there at the end of the year. I will say that this acreage that we're picking up is in the high-performing middle Bakken and upper Three Forks area. It's also pretty adjacent to the properties we already had, so we get some good synergy and leverage there. So 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. So we're pretty excited about it, but we just got it and we're just getting to work on it. Edward Westlake - Crédit Suisse AG, Research Division: Okay. And then just in the quarter you had, I mean, European gas, I mean is it -- was demand weak or was it declined? And then on Africa, you fell a bit in Q4 versus Q3, and I'm just wondering, was that anything unusual?

Yes. If you look at -- so let's take Europe first. It's really decline, just normal decline, nothing out of the ordinary there. We did see -- we also had a little bit of -- if you're looking, say, year-over-year, particularly in the fourth quarter, we did have some asset management impacts as well. So think about it as a little uptick in demand, offset by normal decline and the impact of the assets that we divested. Edward Westlake - Crédit Suisse AG, Research Division: And then Africa oil fell Q-over-Q and obviously, year-over-year?

Yes. If I'm looking at the Africa liquids, I think we're actually up a little bit in the fourth quarter of '12 versus '11. But sequentially, yes. We began -- yes, if you're looking sequentially, that's really just a planned downtime event. We actually had a little increase in pricing spend, entitlement impacts, but it was really maintenance and downtime.

We'll go next to Robert Kessler with Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: If I could just follow up on the European gas volume comment, even if I adjust for the portfolio effects, I estimate you're still down maybe 5% year-on-year and I'm wondering what -- one, is that a good adjusted number, where would you point me there? And then 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 kind of midyear into year end? And then how much of that might reverse in the first quarter would you estimate?

Yes. Let's take those -- probably best to look at that on a full year over full year. Although the quarter, I think, could be -- would be pretty similar. If we look year-over-year in total, we did see a little uptick in demand on a net basis, and we actually had a little better performance in our operations from a downtime perspective. So 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 don't think that's a big impact. I know there's been some switching around up there, but I think for our perspective, overall -- again, our demand was a little higher, we're just seeing the impact of normal decline in the asset management from the assets we divested, primarily in the fourth quarter of last year. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. And then 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? And are you getting a better price relative to benchmarks in the applicable regions, let's say, LOS [ph] along the Gulf Coast, and any kind of incremental color in terms of earnings contribution on the margin or extra volumes you're running?

Yes, sure. Let me give you just a little bit of data coming right out of the earnings, Rex [ph], that we talked about. If you look at our fourth quarter '12 over fourth quarter '11 earnings, there's 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. And 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. Now 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 in 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. And it's not just -- 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. And so some of that shows up in the other places as well. I can give you one just number that'd probably help a little bit. As we look at just our U.S. Gulf Coast refining circuit, we have more than triple the processing of advantaged 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. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: I appreciate the 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 the 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 5, what we call, Mid-Continent refineries, so you're talking about the Rockies and then up into Canada, we've got about 600,000 barrels a day of "Mid-Con," 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. So again, if you're thinking about heavy feeds in the refineries, if you're looking at light feeds into the circuit from the Gulf Coast all the way up into Canada, we are optimizing that entire circuit. And again, that's across refining chemicals and lubes, and you're seeing that in our margins both in the Chemical business and in the Refining business.

And we'll go next to Jason Gammel of Macquarie.

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're planning to drill. And then if you could provide similar information on the global deepwater program.

Sure. Let's start with the Gulf of Mexico, and it's really a number of things from drilling wells to processing seismic to capturing additional opportunity. I could 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, and a lot more work going on there. We also -- we followed up on the success we had in Romania, in the northern Black Sea as an example. So it's really a nice pipeline. We're doing appraisal and work on Hadrian and looking at the project there, so that's 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. So we do intend to give you a really good fulsome update on our deepwater program in the Analyst Meeting, and so I probably don't 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'll 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've 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've acquired over the last few years.

Okay, that helps, and I 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 0, would you be able to provide what type of impact it would have on your production guidance?

No, I really don't have that number and wouldn't want to speculate on that. I think if you look at what we were able to do in this past year in Iraq, it's really meet our commitments, get the production up, spend a lot less money, all of that's good. It just -- as you know how the contracts work there, that meant that we got fewer barrels, but I wouldn't want to speculate on what a number might be if the spend went to 0.

And we'll go next to Doug Terreson with ISI.

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. So 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. But 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, I mentioned, the optimization that we're getting out of running some of the feeds, but 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 a retail business rather -- into a dealer and distributor market. And so you might think we'll -- we'd lose all those volumes. But what we've seen, in fact, is we've kept a lot of those volumes and then the B2B business has picked up for us. So 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. So that's really the big driver there.

Okay. And also you mentioned in the presentation just a few minutes ago, 2 of the more high potential, unconventional oil development areas, which being Argentina and Russia, and so I wanted to see if you could provide a little bit more specificity on what Exxon plans to accomplish in the 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 wanted to see if you had more specifics on the next steps in those 2 countries this year.

Sure. Let me start with Russia and then back up into Argentina. So 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. And 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. And 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 in 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 4 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. And 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'll tell you that we have another well that was drilling at year end that we'll get done in the first quarter and get to work testing that this year. And then we have the 6-well, I mentioned, that spud in December. And then we've got 4 additional wells coming this year. So these will be our first operated wells in a number of areas. So when we get done this year, although we'll barely scratch the surface of 800,000 acres, we should have a pretty good idea of what we got with the way we've got these wells spread out.

David, you don't consider infrastructure constraints to be meaningful in either country where you guys are operating?

Not at this point in time. 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.

We'll take our next question from Iain Reid with Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: Going back on production, just looking at it from a high level, you're talking about falling about 6% year-on-year, but gas is down substantially more than that, particularly in Asia. You've talked about European issues, but also in the U.S. So it seems to me that globally, your gas volumes are declining well, about faster than I think was generally expected a year ago at the Analyst Meeting. Do you want to make a kind of 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's some operational issue why gas is falling really so far. And it kind of makes you wonder about whether the rebound which you were forecasting last year, and overall production of 1% to 2% from 2012, is likely under this sort of progression we're seeing.

Yes, that's -- let me kind of look at that on a 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 what I mentioned in the last quarter, we became cost current in our AKG project in Qatar, and you might recall that's a flowing gas project into Qatar as opposed to going into LNG. And that's the biggest driver. If you look at our Asia gas production, down about 500 a day or 10% year-on-year. There's 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 across that was weather-related. And then if you look at the declines in North America, the U.S. down just a little bit. We have, as I've 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, in the places like the Bakken, in the Permian, in the Ardmore and away from some of the dry gas areas. And so you're 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 from that property and just normal decline. So if I look across all of the regions, there is nothing there that's 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. But I will say, just to kind of finish it up, if I look at expectations and performance, 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, so from that standpoint and operationally, overall, downtime was a little better, performance improved there. So I wouldn't looked at the year-to-year change as anything to be concerned about or that we weren't able to do what we had planned to do. But again, in terms of going forward, we're certainly looking forward to visiting with you all in March and giving you a fulsome outlook on that. Iain Reid - Jefferies & Company, Inc., Research Division: Okay, David. Could I tempt you on a question on the reserve outturn for 2012 or you going to hold that one over until you report that?

We'll hold that for a couple of weeks. We're going to do our normal mid-February report out on how the reserves and resource space is looking. And so if you'll bear with us for a couple weeks, we'll get that out about mid-February. Iain Reid - Jefferies & Company, Inc., Research Division: 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've made, so to tell us what the kind of organic CapEx is?

Yes, that's -- let me take the opportunity to update on that because I think we had talked about $37 billion at the Analyst Meeting, and we said that did not include acquisitions. And so 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'd be pretty much spot on the outlook that we gave you in March.

We'll take our last question from Paul Cheng of Barclays.

Two quick ones. David, in your presentation, on Page 16, you indicate that the $1.2 billion is the asset sales gain and the favorable tax primarily. Do you have an actual absolute number for the tax benefit in the quarter?

This was the -- which...

Page 16 on the Upstream.

Oh, okay. That's on the sequential.

Right. So I mean do you have an absolute number, not sequential change, but the absolute number of the tax benefit in the quarter?

Sure. The absolute -- oh, let me see, I have a -- I don't have an absolute number. I can tell you what the change is sequentially, it's about $700 million of the $1.2 billion.

That's the sequential change.

Yes.

If after the call you have that number and will be willing to share, if you don't mind to have someone just send me an e-mail.

Okay.

And secondly in Kearl, if we look at the actual cause for Phase 1 now is $12.9 billion. Last year, I think revised up to $10.9 billion and original budget was $8 billion, so this is somewhat uncharacteristic of Exxon given the cost of a run. And with that only about a year and you'd gone up from $10.9 billion to $12.9 billion, should we be concerned about the Phase 2, the current $8.9 billion that is going to be significantly higher?

Yes, Paul, let me -- let's talk a little bit. As you recall, between the very first estimate and the $10.9 billion that we gave, we reconfigured the project and put it into the initial production project and the expansion project and talked about the bottlenecks 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 recover by the first phase in 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. So 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 on -- 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, 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 kind of a real-time basis. So I don't have another cost outlook for you other than the $8.9 billion, but when you look at the schedule that we're on and the progress we're making, that project is coming along real good. And again, when you look at those 2 projects together, we feel real good about the competitiveness of that project going forward in this space. And then again, as the years go by, we'll look forward to the bottlenecking and getting up to that full 345,000 barrels a day we've talked about before. So...

Okay. And 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's development? Is that going to be higher, about the same or lower than last year?

I think on average, you'll see that because of the big trend we made across last year where we kind of went from notionally 45%-or-so of the rigs as we came into the year doing dry gas, and now we're down to about 1/3 on the gas side, 2/3 on the liquids. So 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've just gotten the Denbury deal done and we're 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 can't give you a specific rig count just yet.

That concludes today's question-and-answer session. Mr. 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 of your questions. And I -- 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. And so we'll see you then. Thank you, all, very much.

That concludes today's conference. Thank you for your participation.