ConocoPhillips (COP) Q4 2010 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2010 ConocoPhillips Earnings Conference Call. My name is Regina, and I will be your operator for today. [Operator Instructions] I would now like to turn the conference over to your host for today's event, Mr. Clayton Reasor, Vice President of Corporate and Investor Relations. You may proceed, sir.

Well, good morning, and welcome to ConocoPhillips Fourth Quarter Earnings Conference Call. We'll begin by thanking you for your interest in the company. I'm joined today by Jeff Sheets, Senior Vice President of Finance and Chief Financial Officer. In this morning, we'll provide a summary of our key financial and operating results for the fourth quarter and full year 2010, and as well as provide some outlook for 2011. As in the past, you can find presentation materials on the IR section of the ConocoPhillips website. Before we get started, I'd like you to take a look at the Safe Harbor statement on Slide 2. It's a reminder that we'll be making forward-looking statements during the presentation and Q&A. Actual results may differ materially from what's presented today. And factors that could cause actual results to differ are included in our filings with the SEC. Now I'd like to turn the call over to Jeff Sheets to take you through our prepared remarks and presentation.

Thanks, Clayton. I'll start on Slide 3, which is a summary of our fourth quarter results and highlights. So during the fourth quarter, our earnings after adjusting for special items were $1.9 billion, which is $1.32 a share. That's up from $1.20 a share for the fourth quarter a year ago. Cash from operations for the fourth quarter were $6.2 billion, and annualized cash return on capital employed for the quarter was 19%. Upstream production for the quarter was 1.73 million BOE per day, which is slightly up from last quarter and down from the fourth quarter a year ago. And yesterday, we reported our E&P organic reserve replacement number as 138% for 2010. Our refineries ran well during the quarter, and we completed major turnarounds at five of our domestic refineries. We also progressed our disposition program during the fourth quarter with $1.2 billion in cash proceeds from asset dispositions and $1.9 billion of LUKOIL share sales. But for the year, we generated cash proceeds of $7 billion from asset dispositions and $8.3 billion of sale of LUKOIL shares. So we ended the year with $10.4 billion in cash and short-term investments. Turning to Slide 4. We'll review the company adjusted earnings comparing fourth quarter 2010 to fourth quarter 2009. So total company adjusted earnings were $1.9 billion, which is up $100 million fourth quarter over fourth quarter, with both E&P and R&M improved from over a year ago. Our E&P segment was up $146 million due to higher commodity prices, partially offset by lower production volumes. Compared to the fourth quarter of last year, our R&M segment generated $411 million more earnings this quarter primarily due to higher refining margins. A significant difference between the fourth quarter of 2010 and 2009 is that in the fourth quarter of 2010, we no longer used equity accounting for our interest in LUKOIL due to our sale of shares of LUKOIL. So that reduced the fourth quarter earnings compared to last year by $457 million. So if you exclude the impact of LUKOIL and you look at the fourth quarter earnings the last year before LUKOIL earnings and compare that to this year's fourth quarter, we were up 43% fourth quarter over fourth quarter. Now we'll take a look at upstream production on the next slide, Slide 5. Fourth quarter production was 1.73 million barrels per day. That's down 5% or 99,000 BOE per day. This quarter production was higher than the third quarter production due primarily to the startup of the Qatargas 3 project. Production in QG3 came online earlier and higher than we have projected. So looking at the year-over-year change, you can see from the chart that 18,000 BOE per day reduction were due to market factors, which include increased royalties at FCCL, FCCL curtailments of our Western Canadian gas production and some PSC price impacts. As of the end of December, all of our Western Canadian gas production was back online. So for 2010, we sold assets with a run rate production of around 50,000 barrels per day, with 25,000 barrels per day, that coming from Syncrude, which we sold around midyear, and about 25,000 BOE per day associated with assets in Lower 48 in Western Canada we sold primarily over the course of the fourth quarter. So the impact of these asset sales on fourth quarter production was 37,000 BOE per day. During the quarter, we also closed on the -- as I mentioned before, we closed on six -- on asset sales of $1.2 billion. That was made up of several different packages. We had six different packages in the Lower 48 and four different packages in Western Canada that made up those asset sales. The decrease in operations was driven largely by a normal fuel decline, which is offset by new production. And 2/3 of the decline came from North Sea, Lower 48 and Alaska. And partially offsetting this decline was about 120,000 BOE per day of new production, which primarily came from QG3, Bohai, the liquids-rich shale place in the Lower 48 and our continuing investments in the Canadian SAGD projects. Our next slide is a review of 2010 production compared to 2009. So turning to Slide 6. 2010 production averaged 1.75 million BOE per day, which compares to 1.85 million BOE per day for 2009. And the changes in production were similar to the ones that I talked about on the previous slide where we explained the quarter-over-over differences. As we talk about asset sales, the assets we sold had a run rate of about 50,000 BOE per day, and the 2010 impact from that was about 19,000 barrels per day given the timing of those dispositions. So if you exclude the impact of asset dispositions and market factors, 2010 production was close to 1.8 million BOE per day. And of the approximate 100,000 BOE per day drop in production, about a little over 50% of that was from North America gas production. Now turning to Slide 7, we'll talk about E&P adjusted earnings, comparing fourth quarter 2010 to fourth quarter 2009. E&P adjusted earnings were $1.9 billion, which is up 9% from the same quarter a year ago. So unadjusted for special items, E&P earnings were $1.7 billion. For the special items in the quarter included a roughly $640 million impairment related to our interest in Naryanmarneftegaz joint venture in Russia, and that was offset by around $440 million in gains on asset sales. Higher prices and market impacts contributed $452 million to the increase in earnings. These earnings improvement was offset by about $370 million decrease related to lower after-tax revenues from lower sales volumes primarily coming from normal fuel declines and our asset sales program. The $72 million increase to other is comprised primarily of lower DD&A and taxes, partially offset by higher costs and foreign currency impacts. So if you look at the bottom of the slide you can see that U.S. adjusted earnings declined compared to the fourth quarter last year. This is largely driven by lower sales volumes, which were partially offset by higher liquids prices. Our overall realized prices for the key commodity prices were higher than in the fourth quarter of last year. So we move on to Slide 8 and talk about E&P unit metrics. Our fourth quarter E&P income and cash contribution BOE metrics were better than a year ago and better than the third quarter, reflecting the improvement in realized commodity prices. Over the last three years, we have reduced our exposure to natural gas in Canada and Lower 48. In 2008, Lower 48 and Canadian gas comprised 28% of our total E&P production. In 2010, this was down to 26%. Given our view that North America natural gas prices will remain subdued in the near term, we expect to continue to shift our exposure to North America liquids plays. So we'll turn to Slide 9 and talk about R&M adjusted earnings. Our Refining & Marketing adjusted earnings improved significantly over the same quarter last year. Our downstream marketing conditions were stronger as global crack spreads improved over 60%, primarily driving the $456 million improvement in margins. Volumes were a small benefit this quarter compared to the fourth quarter last year, mainly due to international refining and U.S. marketing volumes. Our U.S. refining capacity utilization rate of 83% was unchanged from last year, and our international refining capacity rate was 61% compared to 58% for the same period last year. But if you exclude the Wilhelmshaven refinery, our refining marketing ran at a 100% of capacity internationally and 85% globally. Now compared to the fourth quarter of last year, operating costs increased $72 million, primarily from higher turnaround and utilities costs. So about 45% of our turnarounds for the year occurred in the fourth quarter. And substantially all the turnaround activity was in domestic refining, with five of our U.S. refineries going through major turnarounds during the fourth quarter. Pretax turnaround expense of $207 million impacted R&M's adjusted earnings by $130 million. Inventory effects also reduced the U.S. Refining & Marketing earnings this quarter, and benefited international R&M earnings. International R&M earnings were also benefited by increased premium coke production at the Humber refinery. So we look at the results from our other segments on Slide 10. Adjusted corporate expenses were $305 million for the quarter, which compares to $311 million a year ago. During the fourth quarter, our 50% interest in CPChem generated $118 million in earnings, $64 million more than the fourth quarter of last year due primarily to higher ethylene and polyethylene margins. So for the year, CPChem earnings were nearly $500 million, which is the strongest results for CPChem since the formation of the Chevron Phillips joint venture. And CPChem generated a return on capital investment of 22%. We also received $370 million in cash distributions from CPChem in 2010. As I mentioned earlier, we discontinued the equity accounting for the LUKOIL segment so there are no earnings for LUKOIL in the fourth quarter. Also we will no longer be reporting reserves related to LUKOIL at year end, which impacted our 2010 reserves by 1.85 billion BOE. We ended up 2010 holding about 2% of LUKOIL, and we expect that we'll conclude the sale of that interest during the first quarter of 2011. So we'll move on to Slide 11 and look at our cash flow during the fourth quarter. We generated $6.2 billion of cash from operations, which included a $2.1 billion benefit from reductions and working capital, primarily due to year-end inventory reductions. We also generated $3.1 billion in cash proceeds from dispositions, and that was comprised of $1.9 billion from the sale of LUKOIL shares and $1.2 billion from other asset dispositions. We funded $3.6 billion in capital, which is higher than the capital program earlier, in the earlier quarters of 2010 due mostly to increased funding in the North American liquid-rich shale plays. We've repurchased 42 million shares of ConocoPhillips stock at a total cost of $2.6 billion and paid nearly $800 million in dividends. At the end of 2010, we had $10.4 billion in cash and short-term investments, and we expect to use the majority of this cash to repurchase ConocoPhillips shares. Moving to Slide 12, we'll look at our sources and uses of cash for the full year and 2010. If you look at the entire year 2010, we generated $17 billion in cash flow, had $7 billion in asset sales and raised $8.3 billion from our sale of LUKOIL shares, for a total of $33 billion of cash generation. $10.7 billion of the cash was used to fund the capital program, which was made up of $9.3 billion to E&P and $1.3 billion for R&M. That compares to $12 billion of capital in 2009. We also reduced our debt by $5.1 billion, and we had shareholder distributions of around $7 billion for the year, roughly comprised of $3 billion of dividends and $4 billion of share purchase. Our average fully diluted shares outstanding for all of 2010 was 1.49 billion shares. The average for the fourth quarter was 1.47 billion. We repurchased 65 million shares over all of 2010, so our year-end share count was roughly 1.45 billion shares. So turning to Slide 13, we'll take a look at our capital structure. After our debt reductions -- after the $5 billion of debt reductions this year, our current debt balance is $23.6 billion. And our total debt to cap is 25%, which is in line with where we've stated our target is. So we have no plans for significantly reduce debt further at this point. Our debt's longer-term and it's low-cost. If you look at the pretax cost of debt, our average interest rate is around 5.6%. So we move to Slide 14 and talk about some of our capital efficiency metrics. Both our ROCE and our cash returns improved in 2010 driven by earnings and cash flow growth. Capital employed was basically flat throughout the year. The percent of capital employed represented by R&M decreased from 26% to 24% in 2010. Upstream return on capital employed was 12%, while downstream was 5%, both were improved over 2009 metrics. As we look forward to 2011, our ROCE metrics will benefit as we deploy some of our cash towards the repurchase of ConocoPhillips stock. Our efforts to reduce controllable costs on a normalized basis in 2010 were also successful and helped contribute to the improvement in return on capital employed. After normalizing for market factors and portfolio changes, controllable costs in 2010 were about $550 million or 4% lower than in 2009. And E&P and R&M roughly contributed equally to this improvement. So this completes our review of fourth quarter 2010 results. I'm going to wrap up with some forward-looking comments before opening up the line for questions. I'll start with the R&M business. We expect 2011 turnaround activity to be similar to what we saw in 2010, so that's around $450 million pretax. Now we expect 2011 global refining capacity utilization to be around 90%, excluding the Wilhelmshaven refinery. Regarding the core project, the Wood River core project, the new units are scheduled for startup in the fourth quarter of 2011. And we continued to explore opportunities to reduce our R&M footprint so that the percentage of capital employed decreases to around 15% over time. Moving to E&P. We expect 2011 production to be around 1.7 million BOE per day, excluding the impact of any additional asset sales. We expect 2011 exploration expenses to be flat with 2010. In the Caspian, we completed drilling of the Rak More wildcat in Kazakhstan. Evaluation of this discovery is ongoing, and we are preparing to drill a second well later this year. The 20% owned Dalsnuten wildcat was completed and was determined to be a dry hole. We continue to evaluate our shale opportunities in Poland. During 2010, we successfully completed two vertical wells with encouraging results. And we're planning and permitting for the first horizontal well, which we expect to be drilled and tested during 2011 along with two additional vertical wells scheduled for later in the year. In the Lower 48, we expanded our position in several existing and emerging plays, shale plays, by about 110,000 acres. And during all of 2010, we acquired about 150,000 additional acres in North American shale. But we continue to operate at an elevated development activity in the liquids-rich plays of Eagle Ford, Bakken and North Barnett. At Eagle Ford, we're currently running 12 rigs in the play, and we expect increase that to 13 rigs in the near future. We also have three dedicated completion crews working in the play. In the Chukchi Sea, we have entered into an agreement to farm down 10% of our working interest, and that agreement is subject to regulatory approval. In Australia, APLNG is engaged with several potential LNG buyers in support of moving that project to a final investment decision. But we're not in a position to disclose any further information on that at this point. Our QG3 project came online during the fourth quarter. We achieved the first production earlier than anticipated and at better than expected initial rates. And in Canada, we continued to see good returns and production and growth opportunities from our SAGD developments, the Foster Creek and Christina Lake as well as our Surmont development. And we'll provide additional information about these plants in our March Analyst Presentation. And so that concludes our prepared remarks, and we'll now open the line for questions.

[Operator Instructions] Your first question today comes from the line of Paul Cheng with Barclays Capital.

I think that earlier in your prepared remarks, talking about the inventory impact benefit the U.S. and hurt the overseas, can you quantify for us that, how big is those number?

Yes. So overall, for R&M, it was about $60 million benefit. The international was improved by $110 million to $120 million, and the domestic was hurt by around $50 million to $60 million.

Oh, that's a huge swing between the two. I presume those number, you're talking about after-tax, right?

Yes, those are after-tax income -- impacts from inventory movements, right.

And for the impairment charge in your Russian joint venture, I don't think it's come as a total surprise. I just want to confirm that this is really just related to the reservoir issue that you guys have disclosed before, or there is some additional problem that you have found?

Yes. You're correct, it's a reservoir-related problem. As we've continued to develop the field, we've just found the reserves are -- some of the upside that we expected there is not there in the development, and the production profile is not happening at the rate we had expected as well, so you're correct.

Has the field declined already or that is still holding at, say, around in the 150?

We're starting to see a decline in the field currently.

On the 2011, any kind of rough estimate, what is the CapEx going to be?

We haven't given out detail on our capital program for 2011 yet. We've said that it's going to be around $13 billion, and that's probably still a good number to work with.

And then for 2010, when you are talking about the return on capital employed, a 3% improvement from 2009, any rough estimate? Out of the 3%, how much is related external market environment?

It's really hard to slice the numbers that way, but a good portion of it's related to the internal market environment, so probably 2/3 of it would be related to that. But...

And have you guys did a pro forma that if we don't have LUKOIL from the beginning of the year, what that number may look like? And assume that whatever you gain you're sort of buying back the stocks so reducing your capital, what that return may look like?

We did some of that work earlier in the year, Paul, as far as showing the accretion that comes from selling LUKOIL shares and buying ConocoPhillips shares based on assumptions on what we were going to sell the LUKOIL shares for and what the gains were and what we were going to buy ConocoPhillips shares. But we'll have to -- we can provide that reconciliation later. That might be something we do at the Analyst Meeting as well.

Your next question comes from the line of Paul Sankey with Deutsche Bank.

You talked about an overall disposal program now that has left you with $10 billion on your balance sheet. You'd said, I think it would be a $10 billion program. You did $7.1 billion last year. What is the likelihood that you'll exceed that program, the implied $2.9 billion for this year going forward was the first part of my question for you.

So we'll continue to look at several assets for potential sale over the course of 2011 and really on into 2012 and 2013 as well. Whether or not we exceed the $10 billion number really depends on the values that we receive, that we see that we're getting for assets. So it's hard for us to predict at this time. I think we feel comfortable that we'll get to the at least the $10 billion number. And after that, it's really just a function of what we're seeing in terms of values.

And we should continue to think that you will dedicate the majority of cash given you've identified your CapEx for the year more or less, given that you paid down debt and don't want to do anymore that we could expect this to be an above guidance year for buyback?

So what we said is that we would spend $10 billion in share repurchase over a couple of years. A lot of that funded by the sale of the shares in LUKOIL. I think as we see the year go on and we'll see how commodity prices develop, how asset sales develop, what kind of opportunities we might see for some additions to CapEx, we'll make judgments about how we might be adjusting the share repurchase program.

Right. And then if you could just talk a little bit, you did mention a list of organic developments that you've got going on. You then also guided, I think, more or less to flat volumes year-over-year excluding any per share impacts of buyback. Could you just talk about what you'd like to do longer term in terms of volume growth and how you think your organic base can generate to the extent at which it can generate growth in production?

Yes. It's a good question, so maybe just I'll take a minute to talk about all the different things we have going on the organic growth area, and we can start with the Lower 48 where our focus is really on liquids-rich shale plays. We've talked a fair bit about the Eagle Ford, the Bakken, the Barnett. We have very aggressive development programs going on in the Eagle Ford in particular. The Eagle Ford, as we mentioned earlier, we're running 12 rigs now. That's probably going up to 13. We'll look to drill probably 140 to 150 wells in the Eagle Ford this year. In the Bakken, we'll probably drill 50 to 60 wells there on the things that we operate. The things that our partners are operating, we'll probably drill another 50 wells in which we have interest in. In the Barnett, what we operate, we'll probably drill somewhere between 30 and 40 wells. And our partners and the things they operate, we'll probably drill 20 to 30. So pretty aggressive program for development of the liquids-rich shale plays in Lower 48 during the year. We continue to progress on the SAGD projects. We would hope to sanction additional phases in our FCCL projects, on Christina Lake and Foster Creek this year. And we're continuing to progress our own Surmont project that we sanctioned in 2009. We'll see increased production from some of the FCCL phases that start up in 2011 and other -- and that's kind of a continuing increase as phases continue to come online there. We've got significant projects coming online in Asia, investments in Malaysia, which will start up in kind of the 2013 through 2015 time frame. We, of course, have the APLNG project, which we're progressing in Australia, which starts up in the 2014, 2015 time frame. And then we have, well, the QG3 project which we talked about which we'll see production increases in 2011 because we'll have a full year production from that asset. And then we will continue to reinvest in our legacy areas as well in Alaska, in the North Sea and in North America.

Your next question comes from the line of Doug Terreson with ISI.

In exploration and production, you guys are obviously doing pretty well with the reserve replacement, finding costs result that you produced yesterday for '10, and 2009 was pretty good, too. And you just went through some of the key projects. I mean, you guys have eight -- it looked like they're going to generate 80% reserve replacement by themselves in the coming years. And so on that part of the profile, are you still comfortable with -- just to kind of paraphrase what you just said or summarize it maybe with the productivity from that part of the profile? And a few minutes ago, Jeff, you think you also talked about the exploration plans this year, and it seems like things are progressing pretty well there. You mentioned a couple of particular areas. Didn't mention Bangladesh, Horn River and China, I don't think. And so can we just get an update on that area, too? So it's a two-part question.

Okay. Maybe I'll just talk about exploration and kind of what's ahead in the near term there. If you think about on the wildcat side, as we mentioned earlier, we've got the second well in Kazakhstan that we'll be drilling probably in the second half of the year. We have wildcat to drill in Indonesia. We've got a wildcat in Norway, which is kind of an analogue to the Jasmine discovery that we had in the U.K. that we'll be drilling. And provided things start opening up in the Gulf of Mexico, we've got the potential to drill the Coronado prospect there as well. A lot of exploration effort will be going into appraisal as well this year. We're working on the plans for our appraisal program for the Poseidon discovery in Australia. That will probably be a 2011 and 2012 program. And again, in the Gulf of Mexico, we had discoveries that we would hope to begin to evaluate and appraise in 2011. A lot of exploration effort will be going in to try to further delineate the shale plays that we have: the Eagle Ford, the Barnett, the Bakken, the extensions of those. We'll also be looking to do pilots on kind of emerging shale plays. And you'll probably hear us talk more about those as the year progresses. And then of course, we're always on trying to build the portfolio and get access to new acreage opportunities, both domestically and internationally.

Maybe it would be helpful, just as a follow-up, just talk -- characterize the reserve replacement announcement we made yesterday and maybe regionally, where those reserves are.

Yes, that's a good point. So as Clayton mentioned, so we had 138% reserve replacement for the year. And it came very broadly across our entire portfolio. If you look at the makeup of that reserve replacement, and there'll be more details about this when we file our 10-K later in February. 60% to 65% of that reserve replacement came from North America. But of the reserve replacement, about 20% or so came from oil sands between FCCL and Surmont. So oil sands were significant, but it wasn't the majority of the reserve replacement this year. It really came from a broad spectrum of projects across our entire portfolio.

Your next question comes from the line of John Herrlin with Societe Generale.

With the Eagle Ford, will the tailgate gas percentage ran about 45%, is that what you're modeling?

No, it's more like 2/3 liquids and 1/3 gas.

Okay. Because for the wells that you've presented in your handout, it's more like 45%. That's great. If you broke down your $13 billion in CapEx, could you divide it conventional and unconventional?

I don't have that split that way. We'll be providing more detail about our CapEx program at our Analyst Meeting or before.

Your next question comes from the line of Mark Gilman with Benchmark.

Jeff, Clayton, can you quantify the proven reserves sold in the fourth quarter that go alongside that $1.2 billion of proceeds?

So for the year, we sold around 300 million barrels, and about 250 million of that came from the Syncrude sale. And the Lower 48 and Western Canadian sales are 50 million to 60 million barrels.

In your reserve replacement announcement, you highlighted additions in Alaska as being an important area. Could you give me some sense as to where that specifically came from?

It's came from our existing areas. It came from Prudhoe and Kuparuk and the Western North Slope, really a mix across those three areas.

Anything in particular trigger that?

Well, just normal reserve revisions. We did have some positive price impacts as well in the Alaska numbers.

Jeff, I think you said -- I was a little bit confused on exactly the number. You acquired over the course of 2010, 150,000 acres unconventional. You also mentioned 110,000 number, and I wasn't able to put those two numbers together. But can you give me an idea what the cost of that acreage was?

No. We're not going to really be able to comment on the cost of the acreage, or we don't really want to comment on exactly where we acquired those acreage because you can imagine for competitive reasons we're still busy acquiring acreage in a lot of those plays.

Which was that accurate number for 2010, the 110,000...

Yes. The 110,000 was Lower 48, and the 150,000 was all of North America.

I saw recently something in the trades suggesting that your Bayu-Undan project either all or in part might be for sale. Is that accurate?

No, that is not accurate.

You're thinking about some other fields up in Australia, Mark?

No. I was talking specifically about Bayu play.

I don't think so.

No, that's...

The Shannon gas number or volumes in the fourth quarter, what was that?

It was around 7,000 a day.

I'm sorry, Jeff, I missed that. Try it again.

Around 7,000 a day, Mark.

BOEs?

Oh, yes, 7,000 BOE per day, yes.

And virtually all gas?

Yes.

Canada entirely?

A little bit -- a small amount...

Yes, I don't know the split. I think it's pretty...

90% liquid would be up in Canada.

Yes, right.

Your next question comes from the line of Rakesh Avanti (sic) [Advani] with Credit Suisse. Edward Westlake - Crédit Suisse AG: It's Ed Westlake here. A lot of questions have been answered, but just off the all one on Venezuela, where are we in terms of those discussions in terms of getting the cash back that you're claiming?

So we've been following an international arbitration process since our assets were expropriated. We had hearings on that in front of an international tribunal last year. We expect to hear -- have an initial ruling on that sometime later this year. We can't be precise. We don't know exactly when that's going to be. Once we get that ruling, there'll be a potential for an appeals process, which could drag the process out for another year or more. So we're continuing to proceed down our international arbitration process, and we expect to hear something later this year. Edward Westlake - Crédit Suisse AG: And then just on the downstream in terms of turnarounds with the sort of heavy Q4, are we going to be relatively light now in 2011?

2011, we'll actually have a similar level of turnarounds to 2010. So overall, we expect around $450 million of turnaround expense in 2011.

But you would expect the first quarter to be less than the fourth quarter.

Right.

Fourth quarter was just an exceptionally heavy turnaround period. Edward Westlake - Crédit Suisse AG: And this might be for the March Analyst Meeting, but I mean are we going to get a feeling for what the -- are you doing sort of upgrades or was it just purely maintenance turnaround as you go through these in terms of improving profitability of the refining units?

I think it's a mix of that. I think that's right, that's something that we could give you better color on at the Analyst Presentation.

Your next question comes from the line of Philip Weiss with Argus Research.

Jeff, could you do me a favor and repeat the production guidance figure. I missed that.

What we've said is that we expect 2011 production to be around 1.7 million BOE per day. That's excluding any impact from any additional asset sales that we might do.

And then the working capital improvement that you had, is that something that is temporary or do you expect that to be a more permanent effect?

I think we can have some fairly significant swings in our working capital from quarter-to-quarter. As prices change, as our inventory levels change. so I think over time, our working capital, pluses and minuses, will tend to balance themselves out. So if you look at the year -- look at the quarter, it was a positive working capital benefit. It was positive for the entire year. We've had some years where it's been negative. So that is something that will move back and forth. A lot of the impact that we had in the fourth quarter was from inventory reductions. And we had an offset for that in the first quarter of 2010, and we'll build inventories back some in the first quarter of 2011 as well. So that will swing from quarter-to-quarter.

I saw a story yesterday from KKR that they acquired some assets of yours in the Barnett. Could you provide any additional information around that?

We can provide a little bit of detail. We're generally not going to be giving a lot of granularity on exactly what we sold, which packages of assets for. But the package -- but the assets we sold in the Barnett were in the South Barnett, which is the gassier part of the play. And we are retaining and developing our interest in the North Barnett, which is the more liquids-rich portion of the Barnett play.

Your next question comes from the line of Iain Reid with Jefferies. Iain Reid - Jefferies & Company, Inc.: Can I ask three questions? Firstly, in the third quarter, you talked, I think, about potentially looking at assets that might come through the Gulf of Mexico. I'm just wondering what the kind of scale of whatever you're kind of reserving in your minds for that or whether that's part of the $13 billion you talked about earlier in terms of your overall spend in 2011?

Well, we would be interested in the Gulf of Mexico. Trying to pick up additional exploration acreage would be our primary focus. When we think about kind of the size of the opportunities, it's like in the $2 billion to $3 billion range and not something that would be much larger than that. Iain Reid - Jefferies & Company, Inc.: So is that in the $13 billion -- well, I'm presuming that's additional then to the $13 billion you're talking about some...

Yes, that'll be incremental, yes. Iain Reid - Jefferies & Company, Inc.: Second question is your operating costs fell by, I think, you said 4% during the year. Is that something where you have a program for pushing that through into future years, 2011 and '12?

Yes, so our operating costs on a normalized basis fell from 2009 to 2010. I think as commodity prices increase and industry activity levels in different areas change, we'll continue to push to keep our costs flat and try to drive them down over time with a real target on keeping our costs flat or better on a normalized basis.

I think you would be -- it's fair to say that we are starting to see some cost pressures in certain regions of the world.

Right. Iain Reid - Jefferies & Company, Inc.: On Qatargas, can you say where you sold the LNG and some idea of what realized prices were in the quarter?

That, I don't have off the top of my head. We'd have to get back to you on that.

Yes. I think we had an announcement of the first cargo coming into North America. But we haven't really provided a lot on that, Iain. And I don't think we provide specific realized prices for the LNG that comes out of Qatar.

Yes, right. Iain Reid - Jefferies & Company, Inc.: Well, it'd be nice if you did because you do that for Alaska, obviously.

Right. Iain Reid - Jefferies & Company, Inc.: But you do have a kind of diversion program to try and sell the gas if you can at higher prices in Asia?

I think we have the ability to move the LNG to the best market.

Gentlemen, your next question comes from the line of Faisal Khan with Citi.

With regard to the reserve growth from Qatargas, what caused the reserves to go up in Qatar? Was it the better performance or was it just -- was there a timing aspect of this?

There's a -- yes, is results from our development drilling there. So there's a bit of timing in that, and we booked some of the reserves for the project upfront when it was sanctioned. But then as we develop other reserves to continue to feed the LNG facilities, we'll be booking reserves in the future. So it's not a case where we booked the entire reserve base for the LNG project all at once. So you'll continue to see reserve bookings from QG3 over time as we continue to develop that field.

And does that extend the life of the field or is that all part of the program? Because it was...

It's all part of the program, the investment program.

And in terms when you guys decided to shut in production and when you guys decided to bring it back online, what's that price point where you guys decide to bring it back online? Is it anything above four or is there -- or just put a rule of thumb that we could use?

It comes down to on a lease-by-lease analysis on what the breakeven for a particular lease would be, so we don't have a strict rule of thumb for that.

And in the Eagle Ford, can you discuss where you guys are with production right now?

We're around the eight or so thousand a day. And that will just continue to ramp up over time as we execute this drilling program we've talked about to where we would think over in three years time will be a 65,000 barrels a day, in that neighborhood.

And then on the refining side of the equation, with the current wide differentials between Brent and WTI, how are you guys dealing with those sort of differentials in the Atlantic basin with your refining capacity?

So even if you look at refining margins -- if you look at refining margins on a WTI basis for the East Coast, you'd get some really large numbers. But if you look at them on Brent, even if you look at them on Brent, the refining margins are still respectable in that part of the -- for those assets, so.

It represents, what, 20%?

Yes, it's about 20% of our refining base is tied to Brent crude.

Are you guys able to arbitrage that and kind of use -- get volumes from other parts of the U.S. as substitute for Brent or are you kind of stuck with that sort of purchases?

I think we have some ability to move crudes around, but it's primarily a Brent-based supply to those refineries. If you think about Bayway and Trainer, there's really not a good domestic route to get crude. I guess you could move crude around from the Gulf Coast, but most of the crude that goes into those are West African and North Sea crudes.

Your next question comes from the line of Blake Fernandez [Howard Weil].

I had to prompt back onto the call so I apologize if this has already been asked, but with regard to the downstream, I'm sure we'll get some updates at the March Analyst Day, but I know the intention was to potentially divest some assets once the environment improved. I'm just curious if there's any thoughts to potentially maybe just spinning off the entire downstream similar to one of your smaller competitors has recently announced?

Yes. So maybe just some comments on downstream. So if you talk about -- so if you're looking at our downstream business today, it makes up about 24% of our capital employed. And we've said that we're looking at several options to try to take that exposure down closer to 15% of our capital employed over time. So that could be asset sales. It could be doing joint ventures like we've done other places or other types of transactions. But another thing to point out, though, is that most of our capital investments or 90% plus of our capital investment is going into upstream. So we're going to see that just that fact is going to help bring our capital -- our percent of R&M down as a percent of our capital employed over time. So while we're not really -- we're not planning to grow the R&M business itself, but there are strong assets in that. And R&M is a positive cash contributor to the company, even when you have difficult markets like we've had in the last couple of years. So having that in our portfolio does provide cash flow to help fund shareholder distributions and help fund our reinvestments in upstream. So as we think about this question of whether or not you spin out the business, it's really a question of do we think that that's the best way to try to create value for our shareholders long term. We think that really the way you create value is by increasing the underlying earnings and cash flow generation of the business, and it's not clear to us that a spin-out would really do that.

Okay. And I'm sorry to belabor the point, but do you believe there's an operational synergy of keeping the downstream outside of just the pure financial dynamics of adding some additional cash flow?

I think there are some cost synergies that happened that the downstream business benefits by being part of a larger corporation, both from a capital access point of view, handling the volatility in the business point view and just from a cost management perspective. That would probably be a disadvantage if they were operating as a separate business.

Your next question comes from the line of Paul Cheng with Barclays Capital.

In the Qatar LNG, I presume based on the way how the customer in this say, right now you're already running at peak production?

Not quite. Well, I think we're close. But it's ramping up in production. I don't think we get to peak levels like at the end of the first quarter or midyear.

Yes, it's just part of the normal start up of an LNG facility.

Okay. So that we should assume you're pretty close, maybe 80%, 90%, but it wont get to 100% until the middle of the year?

Yes. So for the year, it won't be at 100%, right.

And in Eagle Ford, since that you already have a number of wells, I think you have showed those data before, wondering if there's an update in terms of the per well recoverable rate, the per well cost and the IP rate, and after, let's say, 90 days, what the production maybe?

I think we'll be giving you a more insight into that in our March Analyst Presentation.

And ladies and gentlemen, this concludes the question-and-answer portion of the call. I'd like to turn the call back over to Mr. Reasor for closing remarks.

Great. Thank you. We certainly appreciate the interest in ConocoPhillips. And you can get a copy of the slides and the transcript on our website. We look forward to talking to you soon. Thank you.

Ladies and gentlemen, thank you so much for your participation in our conference today. This does conclude our presentation, and you may now disconnect. Have a wonderful day.