康菲 (COP) 2010 Q4 法說會逐字稿

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.

At this time all participants are in listen-only mode.

Later we will conduct a question-and-answer session.

(Operator Instructions) As a reminder today's conference is being recorded for replay purposes.

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.

Good morning and welcome to ConocoPhillips fourth-quarter earnings conference call.

Let me begin by thanking you for your interest in the Company.

I am joined today by Jeff Sheets, Senior Vice President of Finance and Chief Financial Officer.

This morning we will provide a summary of our key financial and operating results for the fourth quarter and the full year 2010 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 would like you to take a look at the Safe Harbor statement on slide two.

It's a reminder that we will be making forward-looking statements during the presentation and Q&A.

Actual results may differ materially from what is presented today and factors that could cause actual results to differ are included in our filings with the SEC.

Now I would like to turn the call over to Jeff Sheets to take you through our prepared remarks and presentation.

Thanks, Clayton.

I will start on slide three, which is a summary of our fourth-quarter results and highlights.

During the fourth quarter our earnings, after adjusting for special items, were $1.9 billion which is $1.32 a share.

That is 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 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.

So for the year we generated cash proceeds of $7 billion from asset dispositions and $8.3 billion from our sale of LUKOIL shares.

So we ended the year with $10.4 billion in cash and short-term investments.

But turning to slide four, we will 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 due to -- 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 fourth-quarter earnings compared to last year by $457 million.

So if you exclude the impact of LUKOIL and you look at fourth-quarter earnings of 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 will take a look at upstream production on the next slide, slide five.

Fourth-quarter production was 1.73 million barrels per day.

That is down 5% or 99,000 BOE per day.

This quarter production was higher than the third-quarter production, due primarily to the start up of the Qatargas 3 project.

Production at QG3 came online earlier and higher than we projected.

So looking at the year-over-year change you can see from the chart that 18,000 BOE per day of the reduction were due to market factors which include increased royalties at 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 of that coming from Syncrude, which we sold around midyear, and about 25,000 BOE per day associated with assets in the Lower 48 and Western Canada that 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 -- 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 normal field decline, which was offset by new production, and two-thirds 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 plays in the Lower 48, and our continuing investments in the Canadian SAGD projects.

Our next slide is a review of 2010 production as compared to 2009.

So turning to slide six, 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-quarter differences.

As we have talked about asset sales, we had a run rate of about -- 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, a little over 50% of that was from North America gas production.

Now turning to slide seven, we will talk about E&P adjusted earnings comparing fourth quarter of 2010 to fourth quarter of 2009.

E&P adjusted earnings were $1.9 billion, which was up 9% from the same quarter a year ago, so unadjusted for special items E&P earnings were $1.7 billion.

So the special items in the quarter included a roughly $640 million impairment related to our interest in Naryanmarneftegaz, a 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 field declines in our asset sales program.

The $72 million in 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 US 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 last year.

So we will move on to slide eight 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 the 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 will turn to slide nine and talk about R&M adjusted earnings.

Our Refining and Marketing adjusted earnings improved significantly over the same quarter last year.

Downstream market 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 US marketing volumes.

Our US 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 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 turnaround costs for the year occurred in the fourth quarter and substantially all the turnaround activity was in domestic refining with five of our US 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 US refining and 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 will 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 result for CPChem since the formation of the Chevron Phillips joint venture.

And CPChem generated a return on capital invested of 22%.

We also received $370 million in cash distributions from CPChem in 2010.

As I mentioned earlier, we discontinued 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 will conclude the sale of that interest during the first quarter of 2011.

So we will move on to slide 11 and look at our cash flow during the fourth quarter.

We have generated $6.2 billion of cash from operations, which included a $2.1 billion benefit from reductions in working capital primarily due to the 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 in the earlier quarters of 2010, due mostly to increased funding in the North American liquid-rich shale plays.

We have 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.

So moving to slide 12 we will look at our sources and uses of cash for the full-year in 2010.

So if you look at the entire year of 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.

The cash was used to fund a -- $10.7 billion of the cash was used to fund a 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 repurchase.

Our average fully diluted shares outstanding at the end of -- for all of 2010 was 1.49 billion shares.

The average for the fourth quarter was 1.47 billion.

We repurchase 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 will 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 have stated our target is.

So we have no plans to significantly reduce debt further at this point.

Our debt is 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 will 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 will wrap up with some forward-looking comments before opening up the line for questions.

I will start with the R&M business.

We expect 2011 turnaround activity to be similar to what we saw in 2010, so that is around $450 million pretax.

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 start-up in the fourth quarter of 2011.

We continue 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 are 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.

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 are currently running 12 rigs in the play and we expect to 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, AP LNG is engaged with several potential LNG buyers in support of moving that project to a final investment decision but we are 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 first production earlier than anticipated and at better-than-expected initial rates.

And in Canada we continue to see good returns and production growth opportunities from our SAGD developments for the Foster Creek and Christina Lake as well as our Surmont development.

We will provide additional information about these plants at our March analyst presentation.

So that concludes our prepared remarks and we will now open the line for questions.

(Operator Instructions) Paul Cheng, Barclays Capital.

Good morning.

In the -- I think earlier in your prepared remarks talking about the inventory impact, benefit the US and hurt the overseas, can you quantify for us how big is those numbers?

Yes, so overall for our R&M it was about a $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.

Wow, that is a huge swing between the two.

I presume those numbers you are talking about are after-tax, right?

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

Okay.

For the impairment charge in your Russian joint venture, I don't think it has come as a total surprise.

Just want to confirm that this is really just related to the reservoir issue that you guys had disclosed before or there is some additional problem that you have found.

No, you are correct.

It's a reservoir-related problem.

As we have continued to develop the field we have just found the reserves.

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 are correct (multiple speakers).

Is the field in decline already or that is still holding at, say, around in the 150?

No, we are starting to see a decline in the field currently.

Okay.

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 have said that it's going to be around $13 billion and that is probably still a good number to work with.

Okay.

And 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 to the 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 two-thirds of it would be related to that.

And have you guys did a pro forma that if we don't have LUKOIL from the beginning of the year and what that number may look like and assume that whatever your gain is buying back the stocks to reduce 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 by ConocoPhillips shares.

But we will have to -- we can provide that reconciliation later.

That might be something we do at the analyst meeting as well.

Okay, thank you.

Paul Sankey, Deutsche Bank.

Good morning, guys.

You have talked about an overall disposal program now that has left you with $10 billion on your balance sheet.

You had said, I think, it would be a $10 billion program.

You did $7.1 billion last year.

What is the likelihood that you exceed that program, the implied $2.9 billion for this year going forward, was the first part of my question.

So we will 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 are getting for assets.

So it's hard for us to predict at this time.

I think we feel comfortable that we will get to at least the $10 billion number.

After that it's really just a function of what we are seeing in terms of values.

And we should continue to think that you will dedicate the majority of cash, given you have identified your CapEx for the year more or less, given that you have 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 have said is that we would spend $10 billion in share repurchase over a couple 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 will see how commodity prices develop, how asset sales develop, what kind of opportunities we might see for some additions to CapEx, we will 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 have 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 would like to do longer term in terms of volume growth and how you think your organic base can generate -- to extent to which it can generate growth in production?

Thanks.

Yes, that is a good question so maybe just we will take a minute to talk about all the different things we have going on on the organic growth area and we can start with the Lower 48 where our focus is really on liquids-rich shale plays.

We have talked a fair bit about the Eagle Ford, the Bakken, and the Barnett; we have very aggressive development programs going on in the Eagle Ford in particular.

The Eagle Ford, as we mentioned earlier, we are running 12 rigs now.

That is probably going up to 13.

We will look to drill probably 140 to 150 wells in the Eagle Ford this year.

In the Bakken we will probably drill 50 to 60 wells there on the things that we operate.

The things that our partners are operating we will probably drill another 50 wells in which we have interests in.

In the Barnett, what we operate we will probably drill somewhere between 30 and 40 wells, and our partners and the things that they operate we will 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 are continuing to progress our own Surmont project that we sanctioned in 2009.

We will see increased production from some of the FCCL phases that start up in 2011 and that is kind of a continuing increase as the phases continue to come online there.

We have got significant projects coming online in Asia, investments in Malaysia which will start up in kind of the 2013 through 2015 timeframe.

We, of course, have the AP LNG project which we are progressing in Australia which starts up in the 2014/2015 timeframe.

And then we have the QG3 project which we talked about, which we will see production increases in 2011 because we will have a full year of production from that asset.

And then we have continued to reinvest in our legacy areas as well in Alaska, in the North Sea, and North America.

Great, thank you.

Doug Terreson, ISI.

In Exploration and Production you guys are obviously doing pretty well with the reserve replacement and finding costs results that you produced yesterday for 2010 and 2009 was pretty good, too.

And you just went through some of the key projects; I think you guys have eight that look like they are going to generate 80% reserve replacement by themselves in coming years.

On that part of the profile are you still comfortable with -- just to kind of paraphrase what you have just said or summarize it maybe -- with the productivity from that part of the profile?

Then a few minutes ago, Jeff, I 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 in China I don't think.

And so could we just get an update on that area too?

So it's a two-part question.

Okay.

Well, maybe I will just talk a little bit about exploration and kind of what is ahead for -- in the near term there.

I think about -- on the wildcat side, as we mentioned earlier, we have got the second well in Kazakhstan that we will be drilling probably in the second half of the year.

We have wildcats to drill in Indonesia.

We have got a wildcat in Norway which is kind of an analogue to the Jasmine discovery that we had in the UK that we will be drilling.

And provided things start opening up in the Gulf of Mexico, we have 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 are working on the plans for our appraisal program for the Poseidon discovery in Australia; that will probably be a 2011 and 2012 program.

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 will also be looking to do pilots on kind of emerging shale plays and you will probably hear us talk more about those as the year progresses.

Then, of course, we are always on -- trying to build the portfolio and get access to new acreage opportunities both domestically and internationally.

Okay.

Jeff, thanks a lot.

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

Yes, that is 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 will 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.

Okay, thanks a lot, guys.

John Herrlin, Societe Generale.

Two quick ones.

With the Eagle Ford will the tailgate gas percentage run about 45%, is that what you are modeling?

No, it's more like two-thirds liquids and one-third gas.

Okay.

Because for the wells that you presented in your handout it's more like 45%; that is great.

If you broke down your $13 billion in CapEx, could you divide it conventional versus unconventional?

I don't have that split that way.

We will be providing more detail about our CapEx program at our analyst meeting or before.

Okay.

That is it for me, thank you.

Mark Gilman, Benchmark.

Good morning.

A couple things.

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.

Okay, thanks.

Thanks, Jeff.

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 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.

Okay.

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 a 110,000 number and I wasn't able to put those two numbers together.

But can you give me an idea of what the cost of that acreage was?

No, we are not really going to 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 are still busy acquiring acreage in a lot of those plays.

Which was the accurate number for 2010?

The 110,000?

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

I got it, okay.

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.

Are you thinking about some other fields up in Australia, Mark?

No, I was talking specifically about Bayu, Clayton.

I don't think so.

No, I would say not.

Okay.

And final one for me, the shut-in gas number for volumes in the fourth quarter, what was that?

It was around 7,000.

I am sorry, Jeff, I missed that.

Try it again.

About 7,000 a day, Mark.

BOEs?

Yes, 7,000 BOE per day, yes.

And virtually all gas?

Yes.

Canada entirely?

I think it --

A small amount of --.

Yes, I don't know the split.

I think it's pretty --.

90% would --.

Yes, right.

Okay, guys.

Thanks very much.

[Rakash Avandi], Credit Suisse.

Hi, it's Ed Westlake here.

A lot of questions have been answered, but just an off-the-wall one on Venezuela.

Where are we in terms of those discussions in terms of getting the cash back that you are claiming?

So we have 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 is going to be.

Once we get that ruling there will be a potential for an appeals process which could drag the process out for another year or more.

So we are continuing to proceed down our international arbitration process and we expect to hear something later this year.

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?

No, 2011 will 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.

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 is it just purely maintenance turnaround as you through these, in terms of improving profitability of the refining units?

I think it's a mix of that.

And I think that is right, that that is something that we could give you a better color on at the analyst presentation.

Right.

Thanks very much.

Philip Weiss, Argus Research.

Jeff, could you do me a favor and repeat the production guidance figure?

I missed that.

What we have said is that we expect 2011 production to be around 1.7 million BOE per day.

That is excluding any impact from any additional asset sales that we might do.

Okay.

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 -- if you look at the quarter, it was a positive working capital benefit.

It was positive for the entire year; we have had some years where it has 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.

We have an offset for that in the first quarter of 2010 and we will have -- we will build inventories back some in the first quarter of 2011 as well.

So that will swing from quarter to quarter.

Okay, and one more.

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 are generally not going to be giving a lot of granularity on exactly what we sold which packages of assets for.

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.

Okay, thank you very much.

Iain Reid, Jefferies.

Afternoon, gentlemen.

Could I ask three questions?

Firstly, in the third quarter you talked I think about potentially looking at assets that might come free in the Gulf of Mexico.

And I am just wondering what the kind of scale of whatever you are kind of reserving in your minds for that and whether that is part of the $13 billion you talked about earlier in terms of your overall spend in 2011.

So what we would be interested in the Gulf of Mexico is 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.

So is that in the 13 -- well, I am presuming that is additional then to the $13 billion you are talking about.

Yes, that is incremental, yes.

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 2012?

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 will 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.

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

Right.

Okay.

Last one was 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 would have to get back to you on that.

Yes, I think we had an announcement on 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 LNG that comes out of Qatar.

Okay.

Well, it would be nice if you did, because you do that for Alaska obviously.

Right.

But you do have a kind of diversion program, do you, to try to sell the gas, if you can, at higher prices in Asia?

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

Okay, thank you very much.

Faisel Khan, Citi.

Good morning.

With regard to the reserve growth from Qatargas, what caused the reserves to go up in Qatar?

Was it better performance or was there a timing aspect of this?

There is -- it is results from our development drilling there, so there is a bit of timing in that in that we book 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 will be booking reserves in the future.

So it's not a case where we book the entire reserve base for the LNG project all at once.

So you will continue to see reserve bookings from QG3 over time as we continue to develop that field.

Okay.

And does that extend the life of the field or is that all part of the program?

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

Okay, got you.

And in terms of when you guys decide to shut-in production and when you guys decide to bring it back online, what is that price point where you guys decide to bring it back online?

Is it anything above $4 or is there sort of rule of thumb that we should use?

It really comes down to 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.

Okay, understood.

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

We are around 8,000 or so a day, and that will just continue to ramp up over time as we execute this drilling program we have talked about to where we would think over in three years time we will be at 65,000 barrels a day, in that neighborhood.

Understood.

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 differentials in the Atlantic Basin in 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 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.

It represents what, 20%?

Yes, and then -- yes, it's about 20% of our refining basis tied to Brent crude.

Can you guys -- are you guys able to arbitrage that and get volumes from other parts of the US to 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 is 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 to those are West African and North Sea crudes.

Okay, understood.

Thanks, guys.

I appreciate it.

Blake Fernandez.

Hi, guys.

Good morning.

I had to prompt back on to the call so I apologize if this has already been asked.

But with regard to the downstream, I am sure we will get some updates at the March analyst day, but I know the intention was to potentially divest some assets once the environment improved.

I am just curious if there is any thoughts to potentially maybe just spinning off the entire downstream similar to one of your smaller competitors has recently announced.

So maybe just some comments on downstream.

If you look at our downstream business today, it makes up about 24% of our capital employed and we have said that we are 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 have done other places, or other types of transactions.

But another thing to point out, though, is that most of our capital investments, so 90%-plus of our capital investment is going into upstream.

So we are 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.

Great, okay.

So while we are not really -- we are 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 have 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 is 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.

I am sorry to belabor the point, but do you believe there is 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 happen.

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 of view, and just from a cost management perspective.

That would probably be disadvantaged if they were operating as a separate business.

Got it.

Thank you very much.

Paul Cheng, Barclays Capital.

Just two quick follow-up.

In the Qatar LNG I presume based on the way, how the (inaudible) right now you are already running at peak production?

Not quite, I think we are close but it's ramping up in production level.

I don't think we get to peak levels, what, till the end of the first quarter or midyear?

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

Okay, so then we should assume it's pretty close, maybe 80%/90%, but it won't get to 100% until the middle of the year?

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

Right, right.

Understand.

And in Eagle Ford, it seems that you already have a number of wells.

I think you have showed those data before.

Wondering is there an update in terms of the per-well recoverable rate, the per-well cost, and the IP rate, and after, say, 90 days what the production may be.

I think we will be giving you more insight into that in our March analyst presentation.

Okay, so no preview.

Okay, thank you.

Ladies and gentlemen, this concludes the question-and-answer portion of the call.

I would like to turn the call back over to Mr.

Reasor for closing remarks.

Thank you.

We certainly appreciate the interest in ConocoPhillips.

You can get a copy of the slides and a transcript on our website.

Look forward to talking to you soon.

Thank you.

Ladies and gentleman, 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.

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