Exxon Mobil Corporation (XOM) Q4 2011 Earnings Report, Transcript and Summary

Good day, and welcome to this Exxon Mobil Corporation Fourth Quarter 2011 Earnings Conference Call. Today's call is being recorded. At this time, for opening remarks, I'd 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 of 2011. 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 customary cautionary statement shown on Slide 2. Moving to Slide 3, I'll start with an overview of some of the external factors impacting our results. Global economic recovery was slower in the fourth quarter, largely due to weakness in Europe. GDP improvement in the United States and Japan was tempered by negative growth in the European Union. U.S. real GDP growth was 2.8%, improving from 1.8% in the third quarter, while Japan delivered another quarter of positive growth as post-earthquake recovery continues. In general, non-OECD growth remains robust, even with the slight decline in growth from China. Energy markets were mixed in the fourth quarter. Crude oil and non-U.S. natural gas prices remain strong, while worldwide industry refining margins saw significant declines, as did commodity chemicals margins. Turning now to the fourth quarter financial results as shown on Slide 4. ExxonMobil's fourth quarter 2011 earnings, excluding special items, were $9.4 billion, an increase of $150 million from the fourth quarter of 2010. Our effective tax rate for the quarter was 47%. Earnings per share for the quarter, excluding special items, were $1.97, up $0.12 from a year ago. The corporation distributed more than $7.2 billion to shareholders in the fourth quarter through dividends and share purchases to reduce shares outstanding. Of that total, $5 billion was utilized to purchase shares. Share purchases to reduce shares outstanding are expected to be $5 billion in the first quarter of 2012. CapEx…

[Operator Instructions] And we'll take our first question from Arjun Murti with Goldman Sachs.

Dave, 2 somewhat unrelated questions. Can you comment on the status of West Qurna and how that project is going? And then the related part of that is, can you make any comments on adding acreage in Kurdistan? There's obviously been a lot of press about that. I don't think you've put out anything officially. That was -- that's the first question.

Yes, let me -- Arjun, let me actually answer those in reverse. I don't have any comments to make today on Kurdistan. I will, though, tell you that in the West Qurna field, things are proceeding on plan. We continue to meet our production commitments and progress the redevelopment projects in West Qurna, and that's going very well. The common sea water supply project is also progressing, and we are in the process of finalizing commercial terms with the Ministry of Oil and other participating IOCs. So things are going well and continuing to progress as planned.

The other question was just on U.S. gas. Looks like your production ticked up here in the fourth quarter. Obviously, the current gas outlook is pretty weak. You all, I know, take a longer-term view. Can you provide any comments on how you're thinking about your U.S. gas rig count and outlook and in light of what at least are currently pretty weak prices?

Yes, thank you for that question, Arjun. That's a very topical item today, and I know there's a lot of questions and a lot of interest in the U.S. gas business and what we're seeing and what we're doing. So I might just take a moment and kind of address the broader picture of U.S. gas. I'll start by saying we remain bullish on the future of natural gas as an energy source. For those of you that are familiar with our recently released energy outlook, you know we are very bullish on the demand side of natural gas as an energy source in the U.S. And as we all know, given the fairly steep decline in conventional gas, unconventional gas will play the dominant role going forward. In that regard, we are very pleased with our unconventional resource portfolio and look forward to a major participation in that space. Now as we all know, due to record production this year and record storage levels and a relatively mild winter to date, prices have weakened significantly recently. I can tell you that we have not curtailed any gas production, and we're still running 65 to 70 rigs across the space. What has changed over the year is we have reallocated a large number of those rigs to liquids and liquids-rich plays. For example, if you were to step back a year and then come forward to today, we have actually doubled the percentage of the rigs in that fleet that are drilling either liquids or liquids-rich plays, and I mentioned some of those examples in my prepared remarks. So although the overall size of the fleet has remained about the same, a very substantial portion of that -- those rigs are drilling liquids or liquids-rich plays. Nonetheless, I can also tell you that we are still drilling dry gas wells. We do have a few of those that are required for lease maintenance or meeting other contractual obligations, but we are drilling a number that continue to provide good economics. As you would expect, with a drillable well inventory of over 40,000 wells, we're able to put those things in order and have significant optionality and flexibility to drill them, and that really gives us an opportunity to maximize the value of that resource over a long period of time. So if you look at the total market, we continue to be focused long term while making the adjustments in our rig fleet to head to the higher-value, higher-margin products.

David, just a really quick follow up, given the comments on the Cardium and some of the oil plays, do you see the opportunity to raise your overall rig count more towards the liquids and liquids-rich plays, or a 65 to 70 kind of plus or minus your number for this year?

I think as we look across the year, I wouldn't expect the 65 to 70 to change a whole lot in total. But I think it would be reasonable to expect that we will continue to expand the focus of that drilling to the liquids and the liquids-rich plays, particularly in some of the areas where we are having good initial success. And we look forward to, again, bringing on some more wells there. So I think that's what you'll see kind of as the year progresses.

Our next question will come from Paul Sankey with Deutsche Bank.

David, obviously, with these PSC effects, you've had quite a significant step-down in volumes. Thinking about your analyst meeting, I think that the 2011 number was guided to be around 4.6 million barrels a day of production. You're about 100,000 barrels a day lower than that. Should we sort of reset your trajectory of growth from that lower level, or should we think about a structurally lower level you've talked about? I guess, PSC volumes, which I guess are now lost because I assume you're blowing through tranches there. Any change in how you're handling -- or somewhat of a change in how you're handling U.S. drilling? Can you just sort of update us on the outlook for 2012? And I have a follow-up.

Sure, Paul. I think we'll give you a broad outlook on 2012 at the March analyst meeting, and we'll look at both this year and what the go forward. Certainly, if you look at our overall projection -- or production for the year, again, if you back out the effects, in particular on entitlements, we did, in fact, actually do a little better than the 4%. I think we had targeted 3% to 4%. So if I just look at the operational performance, we actually did as expected or perhaps even a little better than expected. As you did note, and as we note in the charts, we did see a fairly significant impact from entitlement volumes across the year. In particular, if you look year-on-year, it's about 124,000 barrels a day in total. About 100,000 of that was price-related and the other 20,000 was tranche-related as we talked about, particularly in Nigeria and Angola. So clearly, at the prices that we saw this year, we did see an impact. The prices that we were looking at and we put together our outlook back in March were a little more conservative than what we saw actually. And so that had the big effect. But we'll look forward to giving a fulsome discussion in the March analyst meeting of volumes and drivers for those going forward here again in about a month.

And just more specifically -- forgive me if I missed this in the comments, but the -- there was a large gain in asset sales in Upstream, I think with Apache. I think it's probably there was a deal with Apache in the North Sea. But could you talk about what else was sold? I'm not clear what that was.

Yes, we had a -- that was the biggest one. The biggest impact that you saw was in the North Sea. We had some minor other things going on, but the North Sea was the biggest deal and accounted for the bulk of the asset management gain that we talked about there that you see in the other category.

Okay, so that's quite specific that it was obviously more than 50% of the number was that specific deal?

Sure, sure. Yes, that was the main item in that, Paul.

Next, we hear from Faisel Khan with Citi.

Just one more time, just on the absolute gain in the quarter on the asset sales that -- because it's -- it's $810 million year-over-year, but what's the absolute number for the quarter? And also if you can give us the absolute number for the effects that took place in Chemicals, the unfavorable tax, I think, change?

Sure. The absolute impact in the quarter, if you're looking on that $800 million, we had an impact of about $1 billion in the quarter was the absolute number.

Okay, understood. And then the effect of the tax incentive or tax impact in Chemicals?

Are you interested in the full year impact or looking at the quarterly?

Just the fourth quarter.

If you look at the fourth quarter, again, relative to the prior year, that impact was really most of that $250 million that you see there. That was the bulk of it.

Okay, got you. And then last question for me, on your -- if you could be a little more specific about the rig count in the U.S. You said you've been shifting a lot of the rigs to the liquids-rich plays. But of the 65 to 70 rigs you're running, how many of those rigs now are running in the liquids-rich plays versus the dry gas plays?

Yes, I'll tell you, Faisel, for commercial reasons, we don't want to be that specific. I think what's important is, that it is now a substantial proportion of the total. And, again, I mentioned several examples in my prepared remarks, and you can see the increase we've had in the rigs there. So without adding all that up and giving you a total, it's been a significant increase over the last 12 months.

Okay, then what about the lower 48 production of liquids, how has that trended? Or what number is that in the quarterly number to the volumes?

I don't think we've ever given a -- typically give a specific lower 48 number. If you look at the total in the U.S., that number has been trending about flat or so over the course, and we've seen a number of ups and downs there, but nothing real specific to highlight.

We'll move on to Ed Westlake with Crédit Suisse. Edward Westlake - Crédit Suisse AG, Research Division: David, just coming back to the volumes, if I look at it year-over-year, I mean, all of it's European gas, and that's probably weathering the economy. But of that 214 of net growth, is there any other areas that you feel, as you look at the performance, that has disappointed you?

When we look across the year, in particular on the full year effect, I'll tell you one area where we did not perform quite as well as we would've expected would've been in downtime. For example, if you look at the full year downtime year-over-year was worth about 35,000 barrels a day on a decrease in a number of areas. And I'm pleased to report that as we came across the end of the year, particularly as we went from the third quarter to the fourth quarter, we actually got a lot of that back. And that was a big piece of the increase that you saw sequentially. Other than that, I think as we look across the year, all of our projects that came online performing very well. The base decline performed about as expected. The projects that came online are doing well. And overall operations were good, but I think I mentioned off and on across the year, we did have some unplanned downtime and maintenance outages, and we are working on that. I'll say scheduled downtime was about as expected, so it was clearly the unplanned outages. But again, about 35 KBD. Other than that, we're pretty pleased with how things went. Edward Westlake - Crédit Suisse AG, Research Division: And then if I look at the cash flow, you've got $10 billion of total CapEx. You've got asset sales increasing. Should I read into this that you're going to be a little bit more aggressive about spending organically and then just perhaps selling some of the tail assets, or is it just timing in Q4 for that $10 billion run rate?

I wouldn't read anything into that. We had $10 billion in the fourth quarter. I think that was about the same as it is in the prior year. We generally see a pretty big ramp-up quarter-on-quarter as we get to the end of the year. Likewise, on divestments, and you've seen a number those announced that haven't closed yet and will as we move across this year particularly in the Downstream, I don't think there's anything special other than it's all part of our ongoing asset management program. I'll tell you, a lot of these deals are a long time in the making, some years in the making. And others come up rather quickly as the situation warrants. So no change in direction, no change of philosophy for us, again, timing and -- but we do have a continued program to look at the portfolio, add where we need to add, divest where it's favorable to us and then restructure where it meets all the stakeholders' needs. And I think you saw a lot of that over 2011. And again, many of those deals will close in the first half of this year.

Our next question will come from Paul Cheng with Barclays Capital.

I just want to make sure that I get the number right. And you're saying that the absolute asset sales gain in the Upstream is about $1 billion in the fourth quarter?

Yes, in the fourth quarter.

And that when I looking at from the fourth to the third quarter, the other item is a positive $190 million. Does that means that in the third quarter, we have about $800 million in asset sales gain, or that there's other things in there also?

Order of magnitude, that's about right. There are some puts and takes, but that's pretty close.

So what is the full year absolute asset sales gain? Is the $2.2 billion that you show us, either that is the number or that there's other things inside there also?

No. If you're looking at the full year number, where we show the $2.2 billion, yes, the full year for the Upstream, is about -- the delta is about $2.7 billion with an absolute of about $2.9 billion.

All right. So absolute is about $2.9 billion in 2011? Okay.

Yes.

In Europe, the European gas is down 730 year-over-year. How much of them is related to weather? And how much is actually that their underlying capacity decline?

I think if you look at the total amount, I think about half of that is weather and the other half is decline, more or less. Clearly, sequentially, third quarter to fourth quarter, we didn't see near what we were expecting.

Okay. And I think you had mentioned -- I probably just missed that, there's a cash on deposit from the future asset sales. How much is that and related to which deal?

Paul, a good question. It's $3.6 billion that we have on deposit for potential asset sales that haven't closed. And although I won't -- don't want to give the specific details of what that relates to because, obviously, the deal hasn't closed and that means we continue to have commercial discussions going on, but I do want you to know it was there because what you have is cash without an earnings impact. And should the transactions mature and close, then you'll see an earnings effect some quarter in the future without a cash flow. But that number is $3.6 billion.

When you suppose -- when you expected to close your deal in Japan?

By about mid-year.

Mid-year. And that until -- wondering, some of your other competitor in the Downstream, they are independent refining company that, in the quarter, they have some significant hedging losses due to using WTI to hedge for the long-haul crude supply. Wondering whether Exxon did any of that at all. Do you hedge and not in the defense for your long-haul crude supply in your Downstream? And if you do, do you use WTI or brand contracts?

Paul, that's a good question, and a pretty straightforward answer, no to all parts of that question. We don't do any hedging, and we certainly don't speculate in the futures markets.

Next, we'll hear from Doug Leggate with Bank of America Merrill Lynch.

I'm going to try a couple also, if I may. And the first one is really more of a philosophical question on your U.S. gas statements that you spent some time on earlier. We're all obviously fairly familiar with the XTO economics from the legacy portfolio. And I think it's probably fair to say that some of your dry gas production is probably challenged from a return on capital on an MPD standpoint. So has that given Exxon's focus on returns -- given the early revenue or the early dependence of those early wells on the early part of the production to basically justify the economics, at what point would Exxon consider basically zeroing out its dry gas drilling or indeed curtailing production? Is it a gas price or is it a philosophical decision that you just keep drilling right through?

Doug, I really can't comment or speculate on any forward operating decisions. The comments I made earlier really talk about where we are today and, again, the plan that I talked about in terms of what we're drilling and where we're going. But I really don't have a comment to make on what any future operating decisions that we might take.

Okay, I thought it was worth a try, David. The second one is also a kind of philosophical question. As we look forward, and I guess you'll give us an update in March, but you have an awful lot of long-life assets that are either already in or will be in the portfolio for the next couple of years arguably stabilizing the underlying cash flow, maybe think about it another way of reducing the maintenance capital. How do you ultimately think about changing the balance between dividends and share buybacks, noting that through all your share buybacks in the last few years, your absolute dividend payment as a percentage of cash flow has actually declined fairly precipitously? How do you think about that? And I'll leave it there.

That's good. Let me hit that in a couple of areas. One, in terms of the CapEx, yes, as you know, we are in a CapEx mode now and have been for the last year or 2 and will for the next couple years, investing in large legacy projects that as we talked about before, have all of their -- or most all of their CapEx upfront. Certainly, in the last few years, the Qatar investments would qualify for that. Now the 2 Kearl oil sands projects, Morgan [ph] LNG, Papua New Guinea LNG and those sorts of things. So surely, as I mentioned in my prepared remarks, a number of projects are due to come on in the 2012, 2014 time frame, and we'll begin to see both the production and cash flows from that. Without going too far beyond that, we've got a lot other opportunities we're working on as we've discussed, and we'll discuss more at the analyst meeting that we hope give us the opportunities to continue to spend CapEx in order to grow the business profitably. As you know, one of the opportunities we have, in addition to our ongoing drilling program, is the strategic cooperation agreement with Rosneft, which we are progressing and progressing as planned. And as I've mentioned in prior calls, that gives us tremendous exposure to what could be a very, very attractive opportunity. Now as far as the dividend versus share buyback, I don't have any change in our approach to communicate today. We are committed to continuing to provide a reliable and growing stable dividend to our shareholders. And then once we've invested in all the attractive projects and opportunities we have available, returning a lot of the cash to the shareholders through share repurchases. So that's a long-term kind of approach we've taken over the last many years. And I would expect, going forward, although we continue to look at that all the time every quarter, I don't have any change to communicate today.

Our next question comes from Doug Terreson with ISI Group.

In the Downstream, between sales in Malaysia, I think, was in Q3 and then Japan and consolidation of fuels marketing and lubes, restructuring is become fairly, fairly meaningful in refining and marketing. And so my question regards the strategic rationale behind these moves, and whether you consider these actions is normal course of business or maybe more. And either way, do you know the productivity benefits that the company expects to realize from these actions?

Yes, that's a good question. I'll say, it's really part of an ongoing program we've had in the Downstream for a long time as opposed to any specific change in strategy or event. We, like others, have been looking at our Downstream assets around the world. And where we have had areas where, in certain locations, that our assets are of significantly more value to others, we've actually sold those businesses. The resulting impact has been very positive on our returns in the Downstream, and so we continue to progress and look at those things. We've about finished up the retail conversion in the U.S. and that has gone on very well, and the earnings associated with those divestments have been very strong. As you mentioned, a couple of the other sales that we have out there in Malaysia, in Argentina and Central America that we announced last year, should close some time in the first quarter or second quarter of this year. And then the Japan restructuring that we mentioned here in the last couple of days, we should also close again by mid-year. So -- but taking all that into account, we do continue to invest in the business where it makes sense, the ultra-low sulfur diesel investments that we've made in the last couple of years. I mentioned some additional lower-sulfur and cleaner-burning fuel projects that are underway, as well as, of course, the chemicals projects that we have underway. So we remain committed to these businesses. But again, as we said in our outlook for energy, in certain parts of the world, the demand for transportation of fuels is flat to down, and I would expect us to optimize there. And where we have opportunities for growth, we will. But I would say, overall, if you look over the last couple of years and kind of what's out there now, it's been a very successful asset management program, and we're very pleased with it. But it is an opportunistic program, and I don't have any guidance going forward other than the deals we got there to close.

Okay, I follow. So -- and also, in U.S. E&P, profitability has been a little soft over the past couple of quarters. And I realize that natural gas prices have been weak, but crude oil performed pretty well. And so my question is whether you could comment on the cost trend that you're experiencing in U.S. E&P and/or any other color that you can provide on U.S. E&P profitability.

Sure. Certainly, on the overall unit margin or unit profitability, we are, of course, impacted by the decline in gas prices. And while we do intend to give a nice update in March on the unconventional business in the U.S., I can tell you that some of the objectives we set out at the time of the merger are coming to fruition. We are seeing improvement in capital efficiency. We are seeing reductions in operating expense. We're seeing improved productivity on the wells through a number of things, everything from pad spacing to length of laterals to how we array the laterals in certain areas. So a number of both engineering and technology. Things we've brought to the table are paying off, and I think that helps mitigate the impact of the lower expenses or the lower prices, if you will. So from that standpoint, I think we're progressing well and optimizing again that portfolio. But at the end of the day, the profitability on a book basis is certainly impacted by the declining price trend that we've seen over the course of the year.

We'll move on to Robert Kessler with Tudor, Pickering, Holt & Co. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: One quick clarification on the U.S. natural gas commentary and then also on the unconventional liquids. So on U.S. natural gas, with your unchanged bullish long-term outlook, any thoughts on being a continued consolidator in the U.S. E&P space? And then on the unconventional liquids, thanks for the color and activity there in the different areas. Can you provide some maybe IP rates? And if I can sort of shoot for the moon, well specific costs on the areas you highlighted?

Yes, sure, let me hit those 2 questions. In terms of the first question, I don't have any specific guidance, but as we have said for a long time, I will continue to say we are always looking for opportunities that are out there and you've seen that in some of the acquisitions that we've made over the last year or so. We continue to look at opportunities. Certainly, as the environment changes over time, we're always checking to see what's available and what might be of value to us. But again, no specifics. In terms of the individual IP rates, I don't have any specifics to give you. I will say that if you look, for example, up in the Cardium, where some of the tight oil well rates that you've heard from others, ours are certainly doing well and at the upper end of that range. We're getting good rates in the Woodford Ardmore. We're looking forward to some of the other ones. But again, a lot of our drilling has been delineation in nature, and we have yet to bring a lot of those wells on production. So I wouldn't want to give specifics other than to just conclude and say, that program is going well, and we're very optimistic, and again, in particular, the Bakken, the Cardium and the Woodford Ardmore are all looking very attractive, and I look forward to giving you more update on those areas as this year progresses. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Okay. If I could ask one quick clarification on the Downstream, you mentioned the benefit of inventory liquidation. It sounds like you blew through a couple of LIFO liquidation layers. Any quantification that benefit to earnings more explicitly and then any kind of strategy around liquidation of inventories around year end, ad valorem tax purposes for example, or is this just kind of an inherent volatility in the inventory balances?

Yes, I'll tell you, you didn't see a real big change. I'll tell you the absolute inventory. The LIFO effect for this year in the fourth quarter was $200 million. And frankly, that's about what it was last year. So we didn't see much of a change in any of our businesses, about $200 million. But again, no big shift in program. That's kind of typical as we optimize our inventories at year end.

Next, we'll hear from Jason Gammel with Macquarie.

I just wanted to ask really for an update on some of the other unconventional activity that weren't mentioned in the discussion. So I'll hold it to one, but it's going to be multi-part, if that's okay. First of all, Utica Shale, have you actually spud a well there yet? And are you -- so an acreage position around 75,000, or have you increased that?

Sure. As I mentioned, we would be spudding a well in the first quarter of this year, and we do have one going down as we speak. The acreage position there is about 75,000 acres today, and we're looking forward to working on that.

Great. And then on the Horn River Basin, David, can you talk about what activity levels are like during this particular drilling campaign and if you have advanced any strategy towards potentially exporting that gas as LNG?

I'll hit the first one. We are. We do have a drilling program planned for this year. I think it'll be about the same as we had last year. And again, it's really related to evaluation and delineation as opposed to production, so a similar size program. And it's going to be -- I think it'll be about 2 wells, 2 to 3 wells, which is typically what we've been doing. In terms of strategies for eventual monetization, I don't have any specific information to provide other than, of course, with a resource potentially as large as that, we are exploring all of the options that are out there, and we'll continue to do so. And as soon as I have an update on that, I'll give it to you. I might also mention the Neuquen Basin. I think I mentioned it briefly in my prepared remarks. We do have 2 wells going down there. They are not completed yet, so I can't give you any specifics. But we continue to add acreage down there and looking forward to an active drilling program and really trying to test the potential for both liquids and gas. So that is active. Another country that we've talked about before is Poland, and I think I mentioned in the last call that we would have had the 2 wells down in Poland. Those 2 wells did complete in the fourth quarter. And while we did find gas, it did not flow in commercial quantities in either of those 2 wells, so we'll be analyzing that, evaluating the various characteristics of the shale there and working on our go-forward plans. I think that's kind of an update. If there's a country I missed that you're interested in, I'd be happy to talk about it.

Maybe just as a follow-up, David, what is the condition of the service industry in Argentina? Are you able to find rigs and pressure pumping equipment, or are things really tight? And then I'll leave it at that.

Yes. In Argentina, we're doing okay. We have a -- we farmed into a block there, and the operator there is pretty well established. So at least for the activity that we have ongoing and the wells that we're trying to drill, it's not impacting our program. But we'll see how that turns out as we go forward and the activity in the area increases in general.

Allen Good with Morningstar has our next question.

Most of my questions have been answered. I just had a quick one. I know you said the reserve report was coming out in February. But could you give us any indication if any reserves from Iraq were booked this year or anything else related more to Kearl given the go ahead with the expansion there?

No, I think I'll wait and we'll, of course, talk about both of those, but both of those will be included in our press release. And it'll be out in mid-February, so we're only a couple of weeks away.

Okay. And then just one quick follow-up on Kashagan. Is that still on schedule for this year? And any update you could give there would be helpful.

I think the target is still for year-end this year, and I don't have any update for you different than that.

Next, we'll hear from Pavel Molchanov with Raymond James. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: One quick one about -- back to U.S. gas. With 18 months having passed since you closed XTO, has the employee attrition rate been consistent with your expectations prior to closing?

Well, yes. In fact, that's turned out to be a pretty positive for us. It's been very stable. We haven't seen any significant increase. And on that front, things are pretty good. I think the folks over there are very pleased with the progress we're making in the business, in the program, the integration, the availability of technology and other resources to advance the programs that were under way. And so, again, that's been a positive for us. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. And then a quick one about Japan. The transaction with TonenGeneral, was that brought about by Exxon proactively, or were you approached by the buyer in this deal who was interested in making this happen? Or just can you tell us a little bit about the background to that deal?

I really can't share any specifics along those lines. I can tell you, when you look at the restructuring and the assets involved and how they're structured and managed today and how they will be after the deal, this is a positive for all the stakeholders involved and really better positions that combined business to meet the market needs of Japan. And I think that's probably the most important part without getting into specifics about how it was initiated. Pavel Molchanov - Raymond James & Associates, Inc., Research Division: Okay. Will Exxon have any wholly owned refineries in Japan after this closes?

No, we won't.

Our next question comes from Philip Weiss with Argus Research.

I just have one -- most of my questions have been answered, but I do have one follow-up on U.S. You said that the rig count that's being used for liquids-rich is rising. But when I look at production, natural gas, as a percentage of your total production, has grown and liquids has actually fallen a little bit. So I wonder if you could just comment on when we might start to see that trend change.

Sure. The falloff in the liquids is really just the overall decline in the conventional, as well as some divestments. You'll recall, we had a divestment in the eastern Gulf of Mexico, and that had an impact on us year-over-year and particularly in the second half. In terms of when we'll see significant production growth out of the unconventional, a lot -- I mentioned some of the increases in percentages, although we haven't given all the specific production volumes, but we'll do that as we progress. One of the things we've seen is a lot of the drilling is really around delineating the resource and appraising it, finding where the sweet spots are, determining what the best approach to frac-ing or otherwise producing those resources, a lot of time being spent on evaluating well spacing. So I think the best way to think about this is a lot of activity and a lot of drilling and a lot of planning as opposed to being in a huge hurry to get a well on production and over to sales. But clearly, as that program advances this year and we continue to put in the wells and the infrastructure, we would expect to see those volumes increase at a fairly hefty rate. And again, we'll talk a little bit more about the overall program and what to expect at the meeting we have in March.

Our next question comes from John Herrlin with Societe Generale.

Just some quick ones. For the Woodford Cana, what's your split do you know between gas and liquids?

In the Woodford Ardmore?

Yes. I'm sorry, yes. Sorry, yes.

Yes, the -- I don't have a specific split number on that. I think what's more important as opposed to specific production is the emergence and the discovery, really, in the Ardmore Basin of the liquids potential. I'll tell you, if you were thinking about rigs in particular on that, we've got 8 rigs drilling liquids and 2 rigs drilling gas, if that was the real nature of the -- of your question. And so, again, early mover in there on our part over the last year or so and really looking forward to ramping up the activity there.

Okay. With many of the U.S. liquids plays you, spoke of being in a delineation mode. Does that mean you're having to deal with HBP acreage capture issues, or you're just trying to get a sense of field sizes?

No, it's not really the HBP capture. It's really figuring out what we've got and what the best way is to go about developing and producing it so that we optimize the total over a long period of time as opposed to, again, being in a big hurry. It's -- if you think about it, it's what's the field size and the acreage position that we have, where are the sweet spots, and then where do you go first and then how do you develop that to optimally produce. And we do -- I will say, we probably spend a little more time than others working on the front-end design and evaluation because, again, we're focused on what the overall long-term value is we can get out of that. And that's kind of the upfront investment in time and resources that we've seen here over the last year. I guess the last thing I'll mention is, even as we're doing some of these delineation and appraisal wells, even that, we find some fairly significant efficiency gains as we go from one area to the other and then capturing those allow us once we get to really producing the resource. We're not starting out from scratch. We've already got some experience. So again, more to that as the year progresses.

Okay. In terms of going from a delineation mode to development mode, how long do you think that will take before you get your comfort level to reach that sort of level or degree of planning?

Well, I think it depends on the various areas and the resources. Some we've had efforts underway for a while now, and some, we're just starting -- really getting things underway, and it'll vary. But again, I think what you'll find as the year progresses, I'll give you updates as we progress and really get to kind of the production level because it will be different amongst the various fields.

Next, we'll hear from Katherine Minyard with JPMorgan. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Just a couple of quick ones. What's the -- as we kind of look at ExxonMobil's portfolio in North American natural gas, what's the usage been over either 2011 or the fourth quarter just in terms of consumption at the refinery and even the oil sands level?

Kate, I don't have those specific numbers. I can tell you, directionally, in the U.S., one of the benefits we got out of the merger with XTO was an ability to optimize gas feeds into all of our refineries along the Gulf Coast and optimizing feed into there versus sales to third parties. So I don't have those specific rates, but I can tell you, we've been able to optimize that to the benefit of our refining economics. Additionally, we've been able to also, through integration, optimize our feeds, both natural gas for utilities, as well as ethane into the Chemical business. So that's ongoing. And probably, if you talk about integration, that's probably more important than anything that we have going on up in the oil sands space, so a clear benefit and one we're taking advantage of. Katherine Lucas Minyard - JP Morgan Chase & Co, Research Division: Okay, great. And then just switching gears to the cash position. When we think about ExxonMobil's potential uses of cash over the next, say, year or so, should we be considering potential underfunded pension liabilities as a use of cash? I can appreciate that maybe at the year-end 2011, they didn't completely finalize. But is that something that might be on the table as it's been in years past?

Again, I think they're still sorting through all of that, and I think we'll publish that number when the K comes out here in a little while. But I'm not aware of anything significant on the table relative to what we've seen historically.

Next, we'll hear from Mark Gilman with The Benchmark Company.

Just couple, if I could. You mentioned in your prepared remarks asset sales gains in the Downstream. Could you quantify that on an absolute basis in the quarter?

Sure. It was about $200 million.

Okay. It's been indicated in the trades that you are in arrears, or I should say, Baghdad is in arrears to the tune of $500-odd million on West Qurna. Can you comment on the validity of that?

Mark, I really can't comment specifically on the items that you mentioned, particularly in the trade press. What I can tell you is, we have an ongoing relationship with the Ministry on a number of administrative items. But things are -- we're working through that, but I don't have any specific on any one item. We work on issues from procurement to invoicing to payment to a number of things, and those are ongoing.

Okay, I was curious about the Tonen transaction. 22%, kind of an odd number in terms of your retained interest in Tonen. Can you give me some idea how that number came about and, well, why it is that you would want to retain a 22% interest?

Yes, I can tell you, the 22% is -- represents the 80 million shares that we're keeping in the business. I can tell you, again, the whole transaction is really around optimizing the commercial structure in Japan. And when we looked at the various restructuring and consolidations and optimization of the assets in there, that's where we ended up. And it really represents -- we're not -- we're still committed to Japan. You'll see a large presence of ExxonMobil in there. All of our brands will be in there. We'll continue to provide services and technology. But it's really just -- I think, if you looked at the Japan market and how it's evolving, that restructuring was really kind of a natural next step in the integration of those assets and again, will position the combined company to better meet the needs of the market and add value for the stakeholders.

Okay. Last one for me. You've got some license renewals coming up in Abu Dhabi, you and others in the consortium. I think the expiration of those licenses is 2014. In your case, in particular, is there any linkage between these -- the potential renewal of those licenses and the terms under which they get renewed and your Upper Zakum project?

We are involved in commercial discussions that are ongoing. But, Mark, I think as you can appreciate, I really couldn't comment on anything that had to do with the negotiations there or any of the specifics with fiscal terms or anything else. Thank you, Mark, and thanks to everybody for being on the call today. Appreciate your time and questions and look forward to visiting with you at the March analyst meeting. So thank you very much.

That does conclude today's conference call. Thank you for your participation.