ConocoPhillips (COP) Q4 2011 Earnings Report, Transcript and Summary

Welcome to the Fourth Quarter ConocoPhillips Earnings Conference Call. My name is Kim, and I will be your operator for today's call. [Operator Instructions] Please note that this conference is being recorded. I will now turn the call over to Mr. Clayton Reasor, Vice President of Corporate and Investor Relations. Mr. Reasor, you may begin.

Great. Good morning. Welcome to ConocoPhillips' fourth quarter earnings conference call. We appreciate your interest in our company. I'm joined today by Jeff Sheets, Senior Vice President of Finance and our CFO. This morning, we'll provide a summary of our key financial and operating results for the fourth quarter, as well as our outlook for 2012. As in the past, you can find our presentation material on the Investor Relations section of ConocoPhillips' website. Please take a look at the Safe Harbor statement that we have on the bottom of this slide. It's a reminder that we'll be making forward-looking statements during the presentation and during the question-and-answer session. And actual results may be materially different from what's presented today. And factors that could cause actual results to differ are included here, as well as in our filings with the SEC. So with that, I'll turn the call over to Jeff Sheets to take you through our fourth quarter results. Jeff?

Thanks, Clayton. I'll start with an overview of our fourth quarter, which is on Slide 2. During the quarter, our earnings adjusted for special items were $2.7 billion or $2.02 a share. That's up from $1.9 billion or $1.32 a share in the fourth quarter of last year. Our annualized return on capital employed was 13%. We generated cash from operations of $5.8 billion, which is $4.39 per share. In E&P, our production of 1.6 million BOE per day was higher than the prior quarter and slightly above our expectations. In R&M, our global refining capacity utilization rate was 94%. We made significant progress on our asset disposition program with the sale of the Colonial, Seaway Crude and Seaway Products pipelines for $2.4 billion in proceeds during the quarter. Our repurchase of 46 million shares is quite a represented 3% of our shares outstanding, and we ended the year with $6.4 billion in cash and short-term investments. So I'll turn to Slide 3 and talk about those earnings in more detail. Reported earnings for the quarter were $3.4 billion, which included $723 million of special items. Special items included $1.5 billion in net gains from asset sales, largely resulting from the pipeline dispositions I just mentioned. We also had $649 million of impairments. The large impairments included $395 million related to our investment in the Naryanmarneftegaz joint venture in Russia and $190 million for certain conventional and natural gas properties in Canada. Other special items in Q4 included $101 million in settlement and other costs related to the Bohai Bay incident and $25 million related to our repositioning efforts. So taking these special items into account, adjusted earnings were $2.7 billion, which is about $750 million higher than the fourth quarter of 2010. Our E&P segment improved by around $500 million, primarily due to stronger crude oil and LNG prices, offset by higher taxes. R&M's fourth quarter adjusted earnings of $200 million were basically unchanged from a year ago. And combined, our other segments contributed about $250 million to the increase in earnings this quarter, and we'll go through more detail on that on some subsequent slides. So let's go to Slide 4 and look at our 2011 full year earnings. So full year 2011 adjusted earnings were $12 billion, which were more than $3 billion improved from 2010. All of our business segments generated better financial results in 2011 than in 2010. So excluding the LUKOIL segment, for which we stopped recording equity earnings in the fourth quarter of 2010 and which had $1.25 billion of earnings in Q4 '10, our adjusted earnings increased by $4.6 billion from 2010 to 2011. So next, we'll go through some detail on our segment earnings and we'll start with the production levels in our Upstream business which are highlighted on Slide 5. Fourth quarter production was 1.6 million BOE per day. That's down 8% compared to the fourth quarter of last year. If you exclude the impact of dispositions and the suspension of our operations in China and Libya, production was down 1% over this time period. Asset dispositions reduced production by about 30,000 BOE per day. 14 or so of that was from North America natural gas production. In Libya, production was down 43,000 BOE per day compared to the same period last year. Production in Libya started again in late November and continues to ramp up and current production levels are around 20,000 BOE per day. In Russia, we continue to have difficulties with the reservoir in the YK field, and our production was down 23,000 BOE per day in that area. In Bohai Bay, our production was 38,000 BOE per day, lower than a year ago. ConocoPhillips continued the depressurization plan for the field and continues to work with our co-venture and regulatory agencies related to Bohai Bay. So excluding these items I just discussed, increases in production from exploitation drilling, well performance and production from major projects offset decreases associated with decline and downtime. So some things going to -- compared to the same period of last year, fourth quarter production highlights included a 44,000 BOE per day increase in production from our Lower 48 liquids-rich shale plays, the Eagle Ford and the Barnett; 32,000 BOE per day increase from Qatargas 3 project; and a 13,000 BOE per day increase associated with new wells at our SCCL joint venture from the Christina Lake Phase C ramp-up. So we'll see similar drivers when we look at our full year production numbers on Slide 6. For the full year 2011, production was 1.62 million BOE per day, which was down 8% from 2010. Excluding the impacts of dispositions in Libya and China, production was down 2% or about 30,000 BOE per day. Asset dispositions for the year reduced production by 48,000 BOE per day, 17,000 of which was North America natural gas of production. Libya production was down 39,000 BOE per day and production out of Russia was down 23,000 BOE per day, compared to the same period last year. And the full year impact of reduced production at Bohai Bay was 15,000 BOE per day. Like the fourth quarter numbers, 2011 project and drilling performance highlights included significant increases at QG3 and in our North American unconventional plays. And these increases largely offset declines in the rest of our portfolio. So now I'll turn to E&P earnings, which is on Slide 7. Adjusted E&P earnings for the quarter were $2.3 billion. This is 27% higher than the fourth quarter of last year. This increase was primarily driven by higher crude and NGL prices and these prices drove both our U.S. and our international adjusted earnings higher. Our earnings in the fourth quarter reflected a $3.50 Henry Hub natural gas price. In addition to price impact, lower DD&A and favorable FX impacts increased earnings this quarter compared to the fourth quarter of 2010. Adjusted earnings were negatively impacted this quarter versus a year ago by lower sales volumes and higher costs. Costs were higher primarily due to the U.K. tax law change and the fact that the QG3 project was fully online. So next, I'll move to Slide 8 and talk about some of our E&P unit metrics. Our cash and income per BOE metrics were better than a year ago and better than the third quarter. For the year, income per BOE was $15.72, which has improved over $10.56 in 2010. Full year cash margins increased from $23.22 to $27.46 in 2011. Now this improvement largely reflects the increase in commodity prices, but there's also a small margin enhancement related to changes in our production mix, and we'll continue to focus on improving margins by shifting our portfolio to a higher margin production as we go forward. So next, let's look at R&M earnings on Slide 9. R&M adjusted earnings of $200 million were basically flat with the fourth quarter of last year. So R&M are offsetting impacts earnings this quarter. Refining margins were lower and that was offset by lower cost and higher volumes and higher marketing margins. And with the exception of the Mid-Continent area, the Refining & Marketing environment in the fourth quarter was generally worse than the refining market we saw in the fourth quarter 2010. This quarter, our refining margins benefited by approximately $180 million, related to the impact of liquidating inventory associated with the portfolio changes we made during 2011. As compared to the fourth quarter 2010, our volumes were benefit to earnings as global utilization rates were 94%. And costs related to turnarounds were $90 million pretax during the fourth quarter, which is $117 million less than the same period a year earlier and utility costs were also lower primarily as a result of lower natural gas prices. So if you look at the full year 2011, R&M generated $2.6 billion in adjusted earnings and $4.1 billion in operating cash flow. So we look at the R&M unit metrics on Slide 10, the per barrel metrics for Refining & Marketing were similar to a year ago and down significantly from the third quarter this year. The fourth quarter income per BOE was $0.70 and the cash contribution was $1.50. For the year, income margins of $2.29 per BOE were improved over 2011 margins of $1.10 per BOE. We continue to look for ways to improve our margins through processing more advantaged crudes and increasing our clean product yield. An example of this is the Wood River refinery, where at current market prices, we expect about a $4 per barrel uplift in Wood River's margins as a result of the CORE project startup in November of this year. We'll take a look at the results of our other operating segments on Slide 11. Adjusted earnings increased in both our Chemicals and our Midstream segments. Chemicals earnings of $156 million improved primarily as a result of higher volumes from international projects. 2011 earnings in this segment were $745 million, up from $498 million in 2010. Midstream earnings increased $27 million up to $118 million in 2011 in the fourth quarter of 2011, reflecting improvements in NGL prices. 2011 Midstream earnings for the year were $458 million, up from $306 million in 2010. Adjusted Corporate expenses were $154 million this quarter. This was lower than what we expected due to favorable foreign exchange impacts, higher capitalized interest and lower interest expense. So now, we'll -- let's talk about cash flow on Slide 12. In the fourth quarter, we generated $5.8 billion in cash from operations, which includes $1 billion decrease -- $1 billion due to a decrease in working capital. Also, during the quarter, we closed several asset dispositions resulting in proceeds of $2.7 billion. During the fourth quarter, we funded a $4 billion capital program, $3.5 billion of which was directed towards E&P. We also paid $4 billion in shareholder distributions, split between $3.1 billion in share repurchases and $900 million in dividends. This quarter, we also reduced debt by $527 million through the retirement of some notes that matured. And we ended the year with $5.8 billion in cash and $600 million in short-term investments. So that's looking at our fourth quarter cash flow. What we'll do on Slide 13 is look at our full year sources and uses of cash. So if you look at all of 2011, we generated $24 billion between cash from operations, asset disposition and the sale of our LUKOIL shares, and we reduced our cash and short-term investment position by $4 billion. The cash from operations number of $19.6 billion in 2011 was $2.6 billion higher than the cash from operations in 2010. So the cash from operations funded a capital program of $14 billion, as well as our dividend of $3.6 billion. Our asset dispositions of $4.8 billion in 2011 included $1.2 billion from our -- sale of our remaining interest in LUKOIL. And these proceeds, along with cash from our previous asset sales largely funded the $11 billion share repurchase program. And during the year, we also reduced debt by $969 million. So we'll turn to Slide 14 and look at our capital structure. At the end of 2011, our equity was down $3 billion compared to the end of 2010, largely as a result of our share repurchase program. Our debt balance was $22.6 billion, which was down $1 billion from the end of 2010. So that left our debt-to-capital ratio at 26% for the year. So next, we'll move to Slide 15 and talk about some capital efficiency metrics. 2011, return on capital employed is 14%, which is up from the 2010 ROCE number of 10%, and our cash returned in 2011 was 23% versus 20% in 2010. The year-over-year improvements in ROCE were primarily driven by increased improved liquids prices and stronger refining margins, as well as lower capital employed as a result of our share repurchase program. So looking at ROCEs on a segment level, E&P ROCE improved from 12% to 16%, while R&M ROCE improved from 5% to 13%. The Chemicals segment had a 2011 ROCE of 29%, which is up from 22% last year, and Midstream was 57% in 2011, up from 34% in 2010. So that completes the review of our fourth quarter 2011 results, and I'd like to next move and talk about and give you an update on our 2010 through 2012 repositioning efforts. So in late 2009, we laid out plans to reposition ConocoPhillips. We've made significant progress on these initiatives and plan to largely finish those in 2012. We've made changes to our portfolio in the past 2 years with $10.7 billion in asset sales and $9.5 billion of proceeds from our sale of our 20% interest in LUKOIL. Additionally, we have reduced refining capacity by about 500,000 barrels per day since the end of 2009. And we expect to continue an asset sales program of $5 billion to $10 billion during 2012. We continue to progress our plans to create 2 leading energy companies, and we updated the Phillips 66 Form 10 in January, and the distribution of the Phillips 66 shares and the completion of that transaction is expected to occur in the second quarter of 2012, possibly as early as May. Another key part of our 3-year plan is enhancing returns. As I just discussed, our returns improved significantly over this time period, and we continue to focus our capital on higher-margin production to help drive margins and returns higher. We've also focused on improving our financial flexibility and we reduced debt by $6 billion over the last 2 years. The company's in good financial position today with a debt to cap of 26% and cash and short-term investments of $6 billion. And we've grown shareholder distributions with $15 billion in share repurchases in 2010 and 2011, with an additional $5 billion to $10 billion plan for 2012 as we continue to execute the asset sales program. And we remain committed to maintaining a competitive dividend that increases annually. So we've outlined our plans, and you can turn to Slide 17 and see some of the impact that, that has on our per-share metrics. If you look at Slide 17, you see our reserves per share increased 12% from 2010 to 2011, went from 5.7 BOE per share in 2010 to 6.4 BOE per share in 2011. And our production per share, when you adjust for the impact of the events in Libya, increased 5% from 2010 to 2011. And we expect that, that will increase this year by another 3% to 5%. So I'll wrap up with some forward-looking comments before we open up the line to questions. Some guidance for 2012, starting with our R&M business. We expect turnaround activity to be about $450 million pretax, with about 40% of that activity occurring in the first quarter 2012, and global refining capacity utilization is expected to be in the low 90s in 2012. In E&P, we expect 2012 production to be about 1.6 million BOE per day, excluding the impact of any additional asset sales. And the guidance we would give around the impact of additional asset sales is that could reduce production by 50,000 to 100,000 BOE per day, and this production guidance assumes that we have some restoration of our production in Libya and Bohai Bay. As we announced earlier this week, we had 2011 organic reserve replacement of 120%. Of the organic reserves we added last year, less than 10% were from natural gas and Lower 48 in Canada. We'll report our F&D costs when we file our 10-K in late February, but we expect those to be in the $15 to $20 per BOE range. As we previously indicated, our capital budget for 2012 was $15.5 billion, and 90% of this will be directed towards E&P. We expect our 2012 exploration expense to be around $1.2 billion, and I'll make a few comments about our progress in developing our exploration portfolio in some core areas. First, in Australia, we have plans to commence a 5 to 7 well appraisal program around the Poseidon discovery later this quarter. In Angola, we've officially received our operating licenses for Blocks 36 and 37, and we've committed to a seismic program that's going to begin this quarter. In the Gulf of Mexico, we've participated in the recent deepwater lease sale where ConocoPhillips was a successful bidder representing an expenditure of about $157 million net for 75 blocks in the pale Eugene play. And we continue to pursue high-quality liquids-rich unconventional opportunities. In 2011, we added 500,000 acres in North America shale plays in areas that include the Avalon, the Wolfcamp, the Niobrara and the Lower 48 and the Duvernay and the Canol in Canada. In the Caspian, we expect to spud the Nursultan well later this quarter. So now I'll shift to our progress in growing our liquids-rich shale business in North America. That's the Eagle Ford, the Bakken, the Permian and the Cardium plays. First, at Eagle Ford, we are currently running 16 rigs in the play. We expect to maintain a 16 rig count average and drill about 180 wells in 2012. Production in late December was around 50,000 BOE per day, and we continue to see some impacts from curtailments related to infrastructure constraints as a result of the higher well volumes and the increasing liquid content and just our ongoing development activity. We would anticipate that average production from the Eagle Ford should grow to around 100,000 BOE per day by the end of 2012. In the Permian, in the Bakken, we are running a total of 12 -- 10 rigs and expect to increase this by as much as 50% during 2012. The fourth quarter production at the Permian and Bakken averaged 50,000 BOE per day and 18,000 BOE per day, respectively. The Permian activities are focused around the Avalon, the Wolfberry and the Wolfcamp, and we're using both horizontal and vertical drilling techniques there. So in addition to our efforts on shale, we're progressing major projects globally. During the quarter, the APLNG joint venture announced 2 sales agreements that complete the marketing of APLNG's second train, with the sanctioning of this train construction expected during first quarter of 2012. In conjunction with this LNG sale to Sinopec, the joint venture partners also agreed to terms which will allow Sinopec to raise their equity interest in the project from 15% to 25%. In the North Sea, the development of our Jasmine field's under way, with startup expected later this year. We expect peak production rates of around 34,000 BOE per day in 2013 from that development. Our Ekofisk South and Eldfisk 2 projects continue to progress, and production from both these projects are expected in 2013 and 2014, respectively. The Wood River CORE project started operations in mid-November, and it's resulting in a 5% increase in the clean product yield at that refinery. Our Chemicals joint venture plans to build a world scale 1.5 million metric tons per year ethylene cracker and 2, 500,000 metric ton per year polyethylene units near its existing Cedar Bayou facility or near a site, near the CPChem Sweeny Area facility in Old Ocean, Texas. And the estimated project completion date for these will be 2017. And our Midstream joint venture has several growth projects underway. These include developments in Niobrara, Permian, Eagle Ford and the Granite Wash plays, along with logistic opportunities in the Mid-Continent area. And finally, a couple of items from the Corporate perspective. 2012 DD&A is estimated to be similar to what we saw in the fourth quarter this year, and Corporate expenses in 2012 are expected to be around $1 billion on an annual basis, excluding any onetime impacts related to the repositioning efforts. So that concludes the prepared remarks, so we're ready to open up the line for questions.

[Operator Instructions] And at this time, we have a question from Arjun Murti from Goldman Sachs.

A couple of domestic production questions. You've had a very good sequential growth in your Lower 48 liquids production. It looks like throughout this year 10,000 to 14,000 barrels a day quarter-on-quarter growth. Jeff, you mentioned that some of that is working through the backlog, though there's still a little bit of a backlog. How can we think about these numbers over the course of 2012? You've got a big ramp-up in the Eagle Ford coming. You mentioned the Permian and the Bakken. Are these the types of sequential growth rates that are doable in your Lower 48 liquids business?

Yes, so maybe just talking about Eagle Ford, so as we mentioned, the Eagle Ford is going from, we think, 50,000 a day to around 100,000 at the end of 2012. We probably have around 10,000 BOE per day that's held back because of infrastructure constraints.

And that number used to be like a 30 kind of number if I'm remembering correctly, in terms of backlog production?

It comes and goes. So as we've commented, as Eagle Ford continues to ramp up, we'll be probably working with infrastructure constraints on through this year and on into 2013. I think that once we get beyond the 2013, we feel like the infrastructure constraints will be largely behind us. So if you just looked at Eagle Ford and the Bakken and the Permian, maybe those, our fourth quarter production from those areas was around 116,000 BOE per day, and that was right at 50,000 out of Eagle Ford, about 18,000 out of the Permian, and -- about 18,000 out of Bakken and 50,000 out of the Permian. We see that over time that those are going to grow to where they get to be in the 2013 to 2015 time period of over 250,000 to maybe 275,000 BOE per day. And it's going to just increase just fairly steadily over that time period.

That's great. Conversely, on the gas side, obviously, very low gas price, too.

Right.

Can you talk about where your gas rig count was in 2011 or where it ended the year, whatever metric you have, where it's going in 2012? And then what you think that means in terms of what happens to your Lower 48 gas volumes in 2012?

Yes, I think our Lower 48 gas volumes will continue to decline. I don't have a...

We've got, I think we've got 1 rig running at Lobo, which is primarily gas...

Right.

And San Juan's got some liquids with it, but we've got 4 rigs running there. So of the 35 to 40 rigs in the Lower 48.

Right.

Less than 5 of them are really pointing toward gas.

Right.

And I don't think we've got much capital in 2012 allocated towards new gas drilling.

If you look at gas drilling, it's in the few hundreds of millions of dollars of our capital program that is addressed towards gas drilling. And even that level of expenditure, given the more recent developments in natural gas pricing is something that we're looking pretty closely at.

So would a high single-digit decline rate be a fair number if you're spending essentially no capital on pure gas?

That's probably a fair number, yes.

Our next question comes from Blake Fernandez from Howard Weil.

I know Arjun just kind of covered natural gas, but I had to question that in the past, I know during weak gas pricing periods, we've seen Conoco shut in production. I was curious if we're going to hear something on that front this morning. Is that in the cards here near term?

Yes. Let me talk about -- that's a good question. Let me talk about gas production. So our fourth quarter natural gas production in Canada and the Lower 48 was around 2.5 Bcf a day, so 400, and maybe a little -- 400, 410 MBOE per day. So if we -- as we look across that portfolio, there's probably 2/3 of it, which where the economics are really driven by liquids production and not natural gas prices. So kind of off the top, there's a portion of our portfolio which is just not going to make sense to shut in. Then if you look at -- so maybe 1.5 out of that 2.5 Bcf of natural gas is really associated with liquids production. Looking at, say, the remaining Bcf a day, some of that we operate, some of that they don't operate, and we have partners on a lot of that production as well, and partners have different views about shut-ins. But most, I think our partners generally not wanting to shut in natural gas and lose the cash flow associated with that. So we are looking at the portion of our production that we can -- that we kind of control that decision entirely on, and think that we will have some shut-ins of natural gas going forward and it's going to be on the order of 100 million cubic feet a day, or something like 15,000 to 20,000 BOE per day going forward, and we'll continue to watch that as we -- as the year goes on and we see how the natural gas markets develop.

That's great. Very helpful. And the last question I had for you: I was curious if you have any update on Venezuela. Obviously, one of your peers has had a -- I guess you could say less than favorable arbitration results recently, and I'm just curious if you have any comments you could make.

Yes, so you're referring to the Exxon -- really that got into their ICC arbitration. So we chose not to pursue ICC arbitration and then chose -- instead chose to pursue exit arbitration, which is the World Bank process. We've been through that hearing. We're waiting ruling on that, which we expect will occur, could occur any -- early this year even. But we can't really be certain of the timing of that. And we still feel very good about the case we have there. Again, like we said on previous calls with the initial ruling will be a battle, will probably not result in a number, but will result in kind of the parameters around -- which the number will be calculated and then we'll have a period where that will be done and there'll be a period where appeals can also happen. So we're still at least 2 or 3 years away from having something that we can collect.

Our next question comes from Faisel Khan from Citigroup.

Just a quick question. Going back to, you gave some numbers on the unconventional volumes in the U.S. In the Bakken, you said you did what, about 15,000 barrels a day right now, of equipment production?

About 18,000.

18,000, okay. And at Permian you're doing around...

50,000.

15,000, okay.

50,000. 5,0. 50,000.

5,0, okay. That makes sense. And then if you can just contrast the Bakken to the Eagle Ford for a second here, because in the Eagle Ford, you guys are running 16 rigs. You're doing 50,000 barrels a day, going to 100,000. In the Bakken, you're going from 10 to 15 rigs and you're only doing about 18,000. I mean is -- are the economics that much better in the Eagle Ford for you than in the Bakken? Or is there some sort of a ramp-up period or well backlog that we're waiting for in the Bakken to come online?

It's both of those things, Faisel. The economics are better for us in the Eagle Ford than they are in the Bakken so that will have priority as we think about where we're allocating our capital. We hold our leases in the Bakken on a long-term basis and don't need to do drilling there in order to maintain our acreage position. So we're taking a very measured approach there. We don't want to get ahead of infrastructure in the Bakken. So you'll see us continue to ramp up our activities there. They're good strong return projects, but it's not as strong as what's -- what we have in the Eagle Ford.

Okay. And just one question on the asset sale program, you announced the Colonial sale. You announced the Seaway sale. Is there -- are there other logistics assets that you guys are looking to divest of? Or are we still expected from here on out for most of the asset sales to be on the upstream side?

Yes, I think the upstream sides and we are -- have a marketing process that's going on, on 2 refineries right now as well.

Our next question comes from Doug Leggate from Bank of America Merrill Lynch.

Just a couple of things. I don't know if I missed this in your prepared remarks, Jeff, but what is the current status of Bohai Bay? Are you back on stream? Are you allowed to bring it back up and what is its production level if you can help us out, first of all?

So production levels were down about 30,000, I think we said 33,000 a day in the fourth quarter, from our previous levels which was our kind of our 45,000, 50,000 level.

15,000 to 20,000 barrels a day.

In the fourth quarter. So we are working through a process of getting a revised field operating and development plan approved. We're working that with the relevant agencies in China where we hope to proceed with that as soon as we can. But we can't really give you guidance on exactly when that's going to occur.

So, Clayton, the numbers are currently at about 15,000 to 20,000. Is that still a good run rate as we look forward for now?

Well, I think we could see that actually -- it'll vary during 2012. It could potentially be lower in the first quarter and then improve as the year goes out.

Yes, it's as good as anything that we can give you right now.

Got it. I hate to pound on the issue of shutting in gas production, but if I may just get some clarification there that -- so you're suggesting you could maybe shut in about $100 million a day. Is that operated or are there third-party production that you might have an interest in as well that might change out further? A little bit of clarity on that would be appreciated, Jeff, please.

So that's just looking at the things that we operate where we largely control the decision, I think...

And that don't have any liquids production.

Because they don't have any significant liquid production or don't have any kind of operational concerns that you have to work through with shutting in. I think this will be a subject that gets discussed quite a bit between partners all throughout the industry as we go forward. And that could change if we have persistent low natural gas prices. But our kind of immediate guidance is that it looks like the numbers we said, something on the order of 15,000 to 20,000 BOE per day or around 100,000.

Up to that amount, I guess, would be more...

Is what it looks like we'll be moving on soon.

Okay, great. And then my final one, if I can squeeze one more in is just a very quick update please on the infrastructure in the Eagle Ford. I mean clearly, the ramp-up has continued to go very, very strong. So are you managing to keep up with that? And I'll leave it at that.

Yes, there are a couple of things that have happened in the fourth quarter. There's -- so takeaway capacity's increased significantly in the fourth quarter over the third. There's additional trucks. There's a new condensate pipeline station which came online in late September. As Jeff mentioned, we have some production curtailment due to infrastructure constraints as a result of well volumes, but we're going to work with several companies to increase offtake capacity in the near and long-term and get transportation commitments set up for condensate and also increase or invest in increasing gas gathering and processing capacity.

Our next question comes from Paul Sankey from Deutsche Bank.

Clayton, can we just talk about the splits? I know you've been fairly specific about this, but I just wanted to reconfirm the date for the intended split. And then I had a question which you may not frankly be able to answer. But if the cash from operations you talked about in 2011, I think it was $19.6 billion, could you separate the upstream and downstream components of that? And perhaps spin forward your latest thoughts on versus whether or not it's a 2011 cash flow, whatever else you assume that cycle cash flow would be, how the upstream and downstream companies in your latest thinking, will be spending money in growing. You mentioned a major Chemicals project in your prepared remarks, for example. Any further just updates on the split process would be great.

Sure. I think Jeff mentioned that you see the split occurring in the second quarter as early as May. I still think that's probably where we want to stay.

Yes, so we're progressing well and kind of the things that you're seeing some Form 10s filed and the revisions of those filed. We're progressing well on our RS.

So no major hurdles essentially as far as you can tell?

No, I think things are progressing well to get in the second quarter and it could happen as early as May.

In terms of your 2011 cash flow question, we gave you net income for R&M...

Yes. So I think, so we generated basically $20 billion of cash flow in 2011. Broadly speaking, 80% of that $16 billion or so came from upstream and 20%, $4 billion, came from downstream.

Yes, I've got $3.75 billion in net income from R&M and $850 million in DD&A. So yes...

From special items.

It's got some special items in it that you have to pull out, but we disclose those. And then you've got also on the cash flow, you've got of course, the dividends that are coming out of the Chemicals and the Midstream business.

Right. So I think upstream will be spending its money predominantly on organic growth, and we've talked a lot about that, what the projects are that are making that up and that we anticipate that we'll be seeing 3% to 4% production growth.

Around $15 billion a year for spending?

$14 billion. So we've announced the $15.5 billion capital program for 2012, and that's basically $14 billion upstream and...

$1.5 billion?

$1.2 billion, $1.3 billion downstream and a few couple hundred million of other expenses, other expenditures. So upstream, we'll be executing that organic growth program and that's what -- the production increases, and as we've -- equally significant, the changes are in our portfolio, which are going to drive increases in cash margins for BOE are what is -- are the growth drivers for upstream. And then downstream, we'll be...

For downstream, there's probably $1 billion or so of capital that goes into the R&M business as far as just keeping our refineries safe and making sure that we've got, doing the right things around our refining business. The excess cash flow coming out of Phillips 66, we're talking internally about where that goes right now, whether that's into Chemicals or Midstream ventures. Those are probably more likely candidates for the free cash flow that comes out of the business. But we'll be able to provide you with more of our thinking about that before the split.

Before May, you'll be coming back with a more specific set of go-forward assumptions?

Yes, the plan -- we're not going to have an -- the typical Analyst Meeting that we have in March, we've decided not to have. But we do plan on meeting with you and with others in the financial community about what our plans are both at Phillips 66 and with ConocoPhillips. I think both Ryan and Greg will be available to the Street and we'll -- we haven't scheduled that. But think about a March or April timeframe when we'll be out there and be able to fill you in a bit more on what our thinking is.

Just one, I guess, the main issue in my mind, Clayton and Jeff is the buyback, and just can you remind us what happens with the buyback at once we've split, how that works going forward?

So we are -- we talked about asset sales of $5 billion to $10 billion, and that's pretty heavily weighted to the upstream side of the business, and going forward, when we said that share repurchases will generally kind of track along with that, which says that we are continuing to buy shares currently, not at the same rates that we were buying them last year. But we're going -- so you'll see first quarter that there'll be some buybacks that occur actually in the first quarter. Then the pace of buybacks will depend upon the pace of our asset sales program, and that really goes for ConocoPhillips both before and after the split of the downstream company. And the downstream company, as Clayton mentioned, they'll be out -- will be out before the split, talking more about how we're going to be allocating cash in that business.

Yes, the thinking, at least right now, around use of cash in Phillips 66 post-split, I would say, we've prioritized the first couple of billion or so towards debt reduction versus share repurchase. But those decisions have yet to be made.

Yes, that's great. I think you've given me enough pieces there to fit it again, together. Which is very finally, Clayton, on the asset sales, within Phillips 66, could you -- is there any update on, I think, it was Alliance and Trainer that were publicly known to be out there?

Yes, I think we don't really have updates. I think data rooms are open I think we're -- indicative bids are -- the deadline's coming up and we'll take a look at what comes in and then make our decisions going forward. We don't have anything to add from what we already talked about earlier on Trainer or Alliance.

But news shortly?

If -- maybe.

Our next question comes from Mark Gilman from The Benchmark Company.

A couple of things, if I could. Did the endeavor sale of the U.K. assets close in the fourth quarter?

First quarter, was it...

No, that's still yet to close.

Right. Did not close.

Okay, anything going on with respect to the Vietnam sale? There've been a lot of talk in the trades about bids that you've received, yet haven't heard much of anything in terms of discussions coming to a conclusion.

Yes, I think we're going to give you the same answer we've been giving you on asset sales as we just are working through a lot of different processes, and we -- it's not helpful to us to try to have a lot of information out until we get kind of to a finishing point on those. So not -- I'm afraid there's not much we can update on you -- update you on there.

Okay. And in terms of the Eagle Ford production numbers, Jeff and Clayton, that you talked about, still running about 70% liquids? And do you expect as the numbers build to maintain that kind of liquids ratio?

Yes, I think we see more like 75% liquids, and yes, that is our expectation going forward.

You think you'll hold it at that level?

Yes.

Okay.

And of course, Mark, I think the classification for the liquids there are -- is retrograde condensate is the term that's used internally to describe those liquids.

I'm not sure what you mean by that, Clayton.

The volume just has [indiscernible].

As opposed to NGL, you mean?

Well, no, this is -- I mean it is -- there's an NGL component but it's primarily condensate.

It's a high-value liquid.

Yes, okay. All right. And in terms of the LIFO item, if I can call it that, in the fourth quarter, can I assume that's entirely U.S., that it's an after-tax figure and that it's included in your recorded and published refining margin?

Yes, it is. Yes. It's all U.S. and all -- it is after-tax and it is included.

And one final one for me. There's been a fair amount of talk -- this isn't actually asset sales-oriented, but I've seen a fair amount of talk that you may be seeking partners either for your Eagle Ford activities and/or your Canadian oil sands outside of the partnerships with Synovus. Can you comment on the veracity of that?

So we intend to pursue Eagle Ford as 100% development going forward. So I hadn't heard that one, but we can tell you that there's nothing behind that. We are investigating options for our oil sands properties outside of the Foster Creek, Christina Lake joint venture. We think there's quite a bit of interest in properties like that. So we're going -- we'll do some things to find out how the market would value those and make our decisions going forward based on what we find out. But we would intend to maintain interest in the properties outside of FCCL. It's just a question whether we might -- would it be value to bringing in a partner to develop those.

And Jeff, that would include Surmont?

Yes, it would include Surmont.

Okay, final one for me, excluding the WRB partnership, give me a rough idea of the WTI reference priced crude that you ran in the fourth quarter, taking the partnership out of the equation.

This is fourth quarter WTI?

The fourth quarter WTI reference x WRB?

X Borger and Wood River is going to be -- I think it's going to be around 200,000 barrels a day, but let us check our numbers. Including those 2, it's somewhere between 450,000 and 500,000. So I just have to back out what Borger and Wood River represent.

Okay, well, that's pretty much 100% on those 2, isn't it? If WTI reference, if you include WCS is WTI reference crude?

Yes, and we have half of Borger and half of Wood River so that's what? That's 350,000 or 250,000?

Yes, something like that.

250,000.

I mean, the math seems to work.

It's 200,000 to 250,000, something like that.

Our next question comes from Paul Cheng from Barclays Capital.

Several quick questions. Jeff, you say $180 million of the inventory gain pretax number. Should we just assume a 35% tax rate?

That's probably a good assumption, yes.

Okay. In the Bohai Bay, the press release talking about the settlement with the compensation fund. Is that settled or the lawsuit update or that there's other things that are still pending we should be aware?

So the settlement is for the fisheries that were potentially impacted by the spill, which is the primary issue that we were dealing with. So we -- that's probably about all we can say at that point, we don't know if there will be others -- other things beyond that.

How about from the regulator, I think that they have fined you guys some small amount? I presume that based on the Chinese law that there's really no other major potential fine that we should expect from the regulator, right?

So I think, Paul, all we can really say at this point is we think that the settlement we just announced last night is an important step forward and it resolves kind of the most pressing issues that are out there and we're just going to need to move forward with the process with the authorities there, and there's not a lot else we can comment on at this point in time.

Okay. Jeff, what is the Libyan production right now for you guys?

Libyan production...

Is around 20,000 barrels a day.

Net to you?

Net to us, yes, that's right. So that's our share of the Waha concession.

We've got, what, 16…

16.33% at…

At Waha?

Yes.

Okay, perfect. And Jeff, when looking at your financial statement, you have about $1.2 billion, $1.3 billion of the deferred tax cash contribution in 2011. Is that all contributed from the IDC deduction in the U.S. or does it relate to other things also?

No, really it doesn't. It's primarily related to timing differences between tax depreciation and financial depreciation.

So that's not related to IDC?

IDC could be a small portion of that number, but it's not a big number for us.

It's a small portion. And once that is spin off, the treatment for the IDC deduction is going to change. Currently, you are deducting what, 50% or 75%?

Paul, I'd have to get back to you. We don't -- it's not a very high percentage of that number because of the category that we fall in. It's different rules for different size producers. And then even going forward, it's a complex set of rules upon -- that depend -- that will determine which category you fall into. And we could be still considered and integrated by some of those measures even going forward because we have things like fractionation capacity and some of our processing up in the North Slope. So it's not as clear-cut as just kind of saying that we move from one category to another.

Right. So you currently, based on your best guess is, that you may not change that much for you?

Yes, I'm not sure that we see that that's a significant change for us. That's correct.

I see. And, that, Clayton, is it possible that if you can share that what is the benefit in 2011 for you guys from the cash flow standpoint related to the IDC deduction?

So...

We don't know that number off the top of our heads.

Yes.

So I mean, if at some -- I mean that if you find it, can you just e-mail me?

We can work that up.

That would be great. Final one, the APLNG, the Sinopec, interest increased to 25%. Last time when the opted in there was a waiver. Should we assume the asset we sold that carrying costs for you guys is already now at a level that increase in the interest in [indiscernible] is not going to change in your carrying value?

Yes, so we'll be working that as we go forward. It depends some -- on some exactly when the whole transaction ends up closing. We will have an additional write-down on APLNG when that transaction closes. It won't be of the same magnitude of what we had before. And right now, we'd say that's in the neighborhood of $100 million.

$100 million?

Right.

Our next question comes from Philip Weiss from Argus Research.

Just a couple of quick questions. The North America acreage acquisition that you mentioned, any color on how much or where those were?

They were -- we're kind of reluctant to just give kind of exactly what was where. But it's in the areas we mentioned which are the Duvernay, the Canol, Avalon, Wolfcamp, Niobrara and some other areas. It was probably 2/3 Canadian, 1/3 Lower 48 acreage, and it was all targeting plays which we believe are liquids-rich plays and not gas plays.

There was some public disclosures on the Ute license round at Wolfcamp, but we haven't given a lot of detail yet because we're not finished -- not finished buying.

Okay. The exploration expense, any dry hole charges you can identify in the quarter?

Let's see, I think we got this. So we had, what, $141 million dry hole expense in E&P for the quarter? I think that's the number. But I don't -- think there was -- well, I just don't -- we can get back to you on that one, Phil. I don't know where those were. But obviously it was higher in the fourth quarter than it was in the rest of the year. But we can come back and let you know where those dry hole expenses took place.

Okay, and then last one, there's just something I'm a little bit confused about. When I look at the financial statement information that you gave, that showed impairments in the fourth quarter of $304 million. But then when you have the special items, the impairments were like $695 million, and I didn't understand why that was.

So are you looking at Page 3 on the special items page on the supplement?

Yes.

And the question is, what? E&P impairments or. . .

Well, if I look at the consolidated income statement, it shows impairments of $304 million. And then if you look at Page 3, just for E&P, for international E&P impairments, it's $585 million and for U.S., it's $44 million, so that's $629 million, and I think there was -- I think the total number when you did your whole reconciliation was $695 million.

Yes, let us do some -- let me come back to you on that one. I'll give you a call this afternoon.

Yes, I'm not sure where we put in that $304 million number on the phase of income statement.

Our next question comes from Daniela Almeida from Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: It's Iain Reid, actually from Jefferies over in London. Just a couple of questions, please. Firstly, on the oil sands, just on your oil sands disposal, can you say why it's Surmont you're looking to reduce your interest in rather than the FCCL joint venture? Is it just because of the fact that it's a joint venture that's tied up with the refining? Or is there kind of a specific reason why it's Surmont and the other assets rather than that?

So I think we looked at the Surmont project and our remaining assets and complying with the FCCL and thinking of the size of oil sands in our portfolio and also the values that people attribute to properties that are kind of out in the marketplace right now, I think it makes sense to just find out what value the market would ascribe to that. It's most straightforward to do that on the Surmont project. But it's not just Surmont, it's the Thornberry pipe and Sulesky acreage that we have as well that we would consider doing something with as a package.

And FCCL, I think we would probably look at as more of part of our portfolio and good economics and something that's going to generate growth for us over a longer period of time and good returns. I think most people look at FCCL as probably the premier oil sands assets. And so it could be that TCS and Surmont won't be able to generate the types of returns that FCCL can. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. I wonder whether your thoughts have changed or progressed in terms of LNG exports now you've seen these deals signed up in the Gulf coast, for the [indiscernible] with intent to build. Is that something that -- which you might look at again or put more emphasis on given the sort of substantial amounts of U.S. gas that you're producing? Or will be producing?

I think it's something we are going to continue to study. It's really not just a thinking about it from the perspective of Lower 48 natural gas production. But as we think about to what long-term alternatives are for Canadian gas production. And importantly, as we think about what alternatives could be for development of the North Slope gas in Alaska. Those are all things that we'll be investigating whether liquefaction and export and natural gas makes sense going forward. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. And last one, just coming back. There's $180 million of inventory liquidation. Can we assume that, that is all associated with the shutdown of Trainer and the associated tankage and pipes, et cetera?

A large part of it was Trainer -- things we had in inventory in the Seaway Products pipeline. For example, we sold some terminals during the year that had inventory as well. So Trainer made it with the largest single component of that, but it wasn't all related to Trainer. Iain Reid - Jefferies & Company, Inc., Research Division: So this wasn't a kind of an inventory price adjustment? This was a real liquidation and exit from that?

Yes, that we reduced our inventories kind of across the system by about 10 million barrels during the year.

Our final question comes from Evan Calio from Morgan Stanley.

Just a couple of questions here on the quarter. Just a follow-up on the last question on the inventory liquidation, I mean, is there any quantification on what is coming back, what is year-end related that we should see back in 1Q?

In terms of building inventory?

That's right.

Probably not. You're saying what our inventories levels will return to?

That's right. If there's anything, I know there's some that's some inventory liquidation, but if some was into taking inventories down into year end, if something would come back in 1Q at an offset.

Yes, so I mean, we have inventories related to our system and then we have some inventories that we take on as kind of more of a systems optimization trading type operations. We'll bring some of those back on in the first quarter. But I don't think we have the number that we can give you as guidance right now.

Okay. On the change in the Corporate charge, $151 million, I mean, can you deconstruct that a little bit just so, again, the same, to understand better what's recurring? I presume that the ForEx element would be a nonrecurring change.

Yes. The ForEx is a nonrecurring change, and you can see in our supplemental information that, that was $45 million to $50 million of that difference. We changed the -- in our comments you probably picked up we were saying Corporate costs, we would say going forward are more of a $1 billion per year run rate and we're $250 million a quarter. I think our previous guidance was more like $275 million a quarter. So just interest costs lower being a driver of that.

Capitalized interest.

And then yes, capitalized interest was a little bit higher than we initially anticipated it was going to be. So that -- I think those are the major drivers of it. So ForEx is a big part of that, which is not a -- which is going to be changed from quarter-to-quarter.

Okay, that's great. Angola block payment, was that included in 4Q?

No, it was a first quarter 2012 item.

Okay. And you mentioned Chevron Phillips. You guys were conducting the study for the 3 billion ton Gulf Coast, I think, cracker. What were the key dates in 2012 in that project? I mean, when will we get -- be more specifics on cost and FID dates, timing, et cetera?

Yes, so I'm not sure exactly when we go FID on it. I know, well, to answer your question, I guess, we'll give you more information on that in late March, early April when we come out and start talking about the sources of growth for Phillips 66.

Okay, great. And then just lastly, can you just follow up on the buyback. I mean, does the -- does your buyback guidance in '12 contemplate the $5.8 billion distribution related to the leveraging on Phillips 66 because that would impact the kind of timing of available cash?

I don't think the intent is to use -- how they intend to use Phillips 66 back for debt reduction primarily.

Yes, so primarily. So we're talking about...

All right, I got you. At the Conoco level.

Yes. So we'll have it's like roughly $6 billion of proceeds come in from the distribution as we contemplated it now. And we'll probably use -- we've targeted at taking our ConocoPhillips debt level down to around $18 billion; at the end of the year, $22.5 billion. So we're going to use $4.5 billion of that to reduce debt. So there will be some that goes into the cash from that distribution.

But the thinking on share repurchases is really, Evan, think about share repurchase as being funded the asset sales. That's really what's going -- that's what's going to fund that activity.

Right. And then based upon, at least the bid dates, you're hopeful that the 2 refining asset sales would be -- could be received prior to distribution?

I think it's probably -- no, I don't think that we would give you that impression. There'll be things to work through on refinery sales which will probably take those post -- post-bid.

So I guess that was the last question. Kim, appreciate you lining those up for us and appreciate everybody participating on the call. You can find our material, again, on our website. I look forward to talking with you in the near future. Thank you.

Thank you ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.