康菲 (COP) 2010 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the ConocoPhillips third-quarter 2010 earnings conference call.

My name is Jen and I will be your coordinator for today.

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

We will be facilitating a question-and-answer session towards the end of today's conference.

(Operator Instructions).

As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the presentation over to Mr.

Clayton Reasor, Vice President of Corporate and Investor Relations.

Please proceed, sir.

Thank you.

And thanks for, everybody on the line, your interest in ConocoPhillips and our third-quarter conference call.

I'm joined today by Jim Mulva, our Chairman and CEO, and this morning we'll be discussing third-quarter results and also provide an update on the status of our strategic initiatives.

A summary of our key financial and operating results for the quarter will be provided as well as our outlook for the remainder of 2010.

And as in the past, you'll find our presentation materials on the IR section of the ConocoPhillips website.

Before we get started I'd like you to 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.

Moving to slide 3, a summary of our key third-quarter results and highlights.

You can see that earnings for the third quarter adjusted for special items were $2.2 billion, or $1.50 per share, up 56% from this quarter a year ago.

Cash from operations was $4.3 billion.

Cash returns on capital employed was 20%.

Upstream production, excluding LUKOIL, was 1.72 million BOE per day.

Our refineries ran at relatively high capacity utilization.

R&M's adjusted earnings topped $1 billion through the first nine months of the year.

We completed $6.3 billion of dispositions including $6 billion of LUKOIL share sales.

Debt was reduced by $2.7 billion during the quarter and we ended with an $8 billion cash balance.

So turning to slide 4 -- total company adjusted earnings were $2.2 billion, up over $800 million compared to the third quarter of last year.

Both E&P and R&M improved earnings year over year.

Our E&P segment improved $559 million primarily due to higher commodity prices partially offset by lower volumes.

Compared to the third quarter of last year R&M adjusted earnings increased $174 million mainly due to improved US refining margins.

The $149 million improvement in Other reflects a reduction in corporate costs as well as earnings improvements in our Midstream and chemicals ventures.

September 2010 year-to-date adjusted controllable costs were approximately $400 million lower compared with the same period in 2009.

The improvement is evenly split between E&P and R&M segments.

Total controllable cost, unadjusted for market factors and asset sales, for the first nine months of 2010 were $9.6 billion compared to $9.4 billion during the same period in 2009.

Moving to slide 5, cash flow sources and uses.

You can see that we generated $10.6 billion in cash during the quarter; $4.3 billion came from operations and $6.3 billion in cash proceeds from dispositions, primarily the LUKOIL stock sales.

We repaid $2.7 billion of debt, funded $2.5 billion in capital, repurchased almost $900 million of ConocoPhillips common stock and paid over $800 million in dividends.

At the end of the quarter we had a cash balance of close to $8 billion, the majority of which we expect to use to repurchase ConocoPhillips shares.

Now let's review our upstream production on slide 6.

Third-quarter production was 1.72 million BOE per day, down 4% or 74,000 BOE per day from the third quarter of last year.

You can see from the chart that 14,000 per day of the reduction was due to market factors including PSC impacts due to higher prices and royalty impacts at Foster Creek and Christina Lake.

FCCL production continues to grow; however higher royalty take caused a negative impact on reported production.

Late in the quarter we initiated production curtailments of approximately 180 MCF equivalent or 30,000 BOE a day in response to continuing low gas prices in Western Canada and parts of the US.

27,000 barrels a day of production was lost due to asset sales of Syncrude and Lower 48 production.

Maintenance activity was about the same as last year.

The decrease in operations was mainly due to normal field decline offset by new production.

The majority of our decline came from North America with almost 90,000 BOE per day and in the North Sea which had almost 40,000 BOE per day of lower production.

Almost 75,000 barrels a day of new production from China, our SAGD operations in Canada, Australia and other locations partially offset this decline.

Unplanned downtime was about the same as last year.

And we'll talk more about the 2010 and 2011 production expectations later during the outlook portion of today's conference call.

Turning to slide 7, E&P's adjusted earnings for the quarter were $1.5 billion, up almost 60% from the same quarter a year ago.

Higher prices and other market impacts contributed more than $600 million of the increase in earnings.

The earnings improvement was partially offset by a $207 million decrease from lower sales volumes primarily coming from normal field decline.

The positive $149 million in other is largely comprised of lower dry hole costs and DD&A partially offset by increased impairments and lower contributions from equity companies in Russia and Canada.

Year to date 2010 E&P adjusted controllable costs improved by about $200 million compared with the first nine months of 2009.

And looking at the table at the bottom of the slide, you can see that both US and international adjusted earnings improved significantly compared to last year.

Let's move to slide 8, E&P unit metrics.

You can see that our metrics were significantly better than a year ago reflecting the improvement in realized oil and gas prices.

Third-quarter E&P income increased $3.78 per BOE or 66% compared to the third quarter of 2009.

Compared to the second quarter of this year, income and cash per BOE were slightly better in spite of realized oil prices being down about 2%, and this is due to LNG, bitumen and US natural gas prices all sequentially improving.

As our OECD focused portfolio shifts more towards Oil Sands, LNG, Lower 48 liquids production, we expect to see additional improvements in our income and cash flow per BOE metrics over time.

Turning to R&M on slide 9 -- you can see that Refining and Marketing adjusted earnings improved 185% over the same quarter last year.

Downstream market conditions were stronger as global crack spreads improved 15% and helped increase earnings by about $100 million.

However, this quarter's earnings were negatively impacted by about $75 million due to inventory impacts and how we value inventory and we expect to recover this loss in the fourth quarter.

Year over year we saw a decrease in R&M earnings of $18 million from lower volumes which were primarily driven by the sale of Conoco Flying J truck stops.

Our US refining capacity utilization was slightly lower compared to the same period last year and our international refining capacity rate was 60% during the quarter compared to 81% for the same period last year.

This decrease in international reflects the shutdown at Wilhelmshaven refinery.

Excluding the impact of Wilhelmshaven, R&M ran at 93% of capacity and clean product yield improved to almost 83%.

Compared to the third quarter of last year operating costs increased $22 million due to higher utilities and turnaround costs which were partially offset by foreign exchange and asset sale benefits.

However, through the end of the third quarter, controllable costs adjusted for market factors and asset sales were down around $200 million compared to the first nine months of last year.

Lower effective tax rates and foreign exchange benefits made up the majority included in the $114 million bar labeled Other.

Sequentially our downstream business was negatively impacted by lower earnings of more than $50 million from our premium coke and chemical feedstock business and $70 million from lower contributions from marketing.

Now let's move to slide 10, which shows year-over-year variances for other segments.

Adjusted corporate expenses were $162 million for the quarter compared to $286 million a year ago.

These results exclude a $114 million make whole premium for early debt retirement.

The $124 million sequential decline in corporate is primarily due to lower interest expense and higher foreign exchange gains.

Foreign exchange gains are driven by the US dollar weakening against the Canadian dollar and British pound.

Results in our DCP Midstream segment were $15 million higher this quarter compared to a year ago, mostly due to higher NGL prices.

Sequentially NGL prices were down $1.45 a barrel but have recovered as a percentage of crude oil.

Our 50% stake of CPChem generated $132 million; this represents almost $30 million more than the third quarter of last year and was due to higher ethylene and polyethylene prices and margins.

These higher margins were partially offset by higher utility and turnaround costs.

During the quarter ConocoPhillips received a $220 million distribution from CPChem.

The LUKOIL segment generated $436 million in adjusted earnings for the quarter and is based on LUKOIL's second-quarter reported earnings.

We will discontinue equity accounting of the LUKOIL segment at the end of the third quarter and no longer report LUKOIL reported proved reserves or production.

Turning to slide 11, which provides more detail on the impact of the LUKOIL share sales, you can see that the chart shows an undiscounted cash increase generated by our investment in LUKOIL stock.

The green bars represent proceeds coming from dividends and the sale of stock.

The first two provide the amount of after-tax proceeds from the dividends and shares sold through the end of the third quarter.

The third bar estimates the amount of after-tax proceeds we would generate if the sale of the remaining shares was done at the closing price on October 21, 2010.

Together these proceeds total about $10 billion.

The original acquisition cost of 170 million or 20% of LUKOIL's shares amounted to $7.5 billion leaving a cash increase of about $2.5 billion.

As mentioned, we'll discontinue the use of equity accounting for the LUKOIL segment after this quarter and report earlier realized gains on future share sales as we reduce our ownership interest, which was 4.6% and 39.2 million shares as of yesterday.

Looking at the impact of this decision on an earnings per share and cash flow basis, if we assume the estimated proceeds of the $9 billion for our sale of the entire interest in LUKOIL were used to repurchase ConocoPhillips stock at $60 a share, and we assume no equity earnings for LUKOIL were recorded, we estimate the net reduction on adjusted EPS to be about $0.16 per share this quarter, or about 10%.

Looking back over the last three years, the reduction in adjusted EPS would also have been about 10% on average.

On a cash flow basis the decision to sell LUKOIL and buy ConocoPhillips stock is accretive, this is due to the difference in dividend yield as dividends received from LUKOIL, which were the only source of cash flow from the segment, were less than the ConocoPhillips dividend saved from those shares purchased.

Looking more narrowly at cash from operations on a per share basis, on the average over the last three years cash flow per share would have been about 10% higher.

Moving to slide 12, our capital structure.

These graphs provide the last several quarters and two-year's history of equity and debt levels.

During the first nine months of 2010 we reduced debt by more than $5 billion bringing our debt level between below $24 billion.

We ended the quarter with a cash balance of about $8 billion due largely to the sale of LUKOIL shares combined with the cash we had on hand at the end of the second quarter.

And considering this cash position, our growth in equity net-to-cap rate would be around 18%.

The majority of current cash position is expected to be used for the repurchase of ConocoPhillips stock.

And while our debt-to-cap level is above our target of 20%, we don't plan to significantly reduce debt further over the next year or two.

Let's move to slide 13 which provides some history on distributions to shareholders.

Since the formation of ConocoPhillips in 2002, we've grown dividends per share by 13.5% per year through the eight consecutive years of annual dividend increases.

In addition to those dividend payments, we purchased $16.1 billion of stock during 2006-2008 timeframe and expect to purchase another $10 billion of ConocoPhillips stock in 2010 and 2011.

These share repurchases have been divided by the fully diluted share count and are shown on the graph above on a per-share basis as the blue bars.

Share repurchases have ramped up over the last couple months and through October 26 we've repurchased about 37 million shares at a cost of $2.2 billion.

The average fully diluted share count during the third quarter was 1.493 billion.

We believe this increase in shareholder distributions is an approach that differentiates us from most of our peers.

We expect that the share repurchase will allow us to improve returns on capital while growing production on a per share basis.

Moving to slide 14, which provides capital efficiency metrics.

Our ROCE and cash returns have improved during the year driven by earnings and cash flow growth while constraining capital employed expansion.

Compared to this quarter last year returns are higher; however third-quarter results were sequentially lower.

And this decline was due primarily to the third-quarter adjusted capital -- adjusted earnings being about 10% lower than the second quarter, as well as some expansion in capital employed.

We ended the third quarter with about $93.5 billion of capital employed of which $24 billion is in R&M and $57 billion was in E&P.

2009 average capital employed was $87.5 billion.

The $6 billion increase in third-quarter capital employed came from currency translation effects and growth in retained earnings.

The increase was partially offset by debt reduction and share repurchase.

If we had repurchased about another $1.5 billion of additional shares our ROCE for the quarter would have been closer to 11%.

As execution of our capital allocation plans shift our spending toward E&P and our asset dispositions result in better margins per BOE, we expect to see our returns on capital employed expand further.

That completes the review of the third-quarter 2010 results.

I'll wrap up with some forward-looking comments before asking Jim to make a few remarks and then open the line for questions.

Consistent with the previous full-year 2010 production guidance we expect production to be flat with 2008 or about 1.8 million BOE per day before dispositions and market factors.

We anticipate fourth-quarter E&P production to be close to about what it was in the third quarter.

And during the fourth quarter the production impact from asset dispositions will be between 40,000 and 50,000 barrels per day, natural gas production curtailment of 20,000 to 30,000 BOE per day while price and PSC effects are expected to reduce production by 10,000 to 20,000 BOE per day.

We expect 2011 production to be 2% lower than 2010 before considering the impact of 2011 E&P dispositions.

So around 1.7 million BOE per day.

We'll give you more information about our 2011 production targets, sources of production growth and regional plans early next year.

In our R&M business we expect fourth-quarter turnaround activity to increase significantly with pre-tax expenses to be around $200 million and total pre-tax expense for the year of around $450 million.

Fourth-quarter utilization rates should be almost 80% and capacity utilization in the US will be around 85%.

And the international utilization rate is expected to be low in the low 60% range which includes the impact of Wilhelmshaven.

Regarding controllable costs, we're on track to deliver our cost reduction targets of about $350 million from E&P and $200 million from Refining and Marketing.

For full-year 2010 we expect unadjusted corporate expense to be approximately $1.3 billion.

Our capital program for 2010 is expected to be between $10 billion and $11 billion, down from earlier guidance and from 2009 levels.

This is due to permitting delays and slower pace of development primarily in Asia-Pacific, North Sea and North America.

2011 capital program is expected to increase to around $13 billion with a ramp up of Lower 48 Shale activity and the APLNG project being key drivers of the increase over 2010 spending levels.

We'll provide you with more information on our 2011 capital program in December and give you more detail at our March 23 analyst meeting in New York.

Moving to exploration, we expect 2010 exploration expense of $1.1 billion to $1.2 billion.

We completed the Wildcat in the North Sea which was determined to be a dry hole, our 30% interest in the well resulted in a $6 million after-tax charge.

In the Caspian the Rak More well spud in the third quarter and we may be able to provide some well results on our January earnings conference call.

In the Arafura Sea we expect to spud our first well in the fourth quarter and the second well in 2011.

We have 51% interest in those wells.

Additionally, the 20% owned Dalsnuten wildcat that spud in the third quarter is expected to TD late in 2010.

And we will begin the next appraisal phase on Poseidon offshore Browse Basin in Australia during the first half of 2011.

Several development options are being discussed and the final determination regarding development is dependent upon the upcoming appraisal wells.

We continue to increase the pace of drilling activity in the liquids rich Shale Plays of Eagle Ford, Bakken, North Barnett, Cardium.

At Eagle Ford we had eight rigs drilling at the end of the quarter, nine are drilling currently and 11 are expected by the end of October.

Additionally, we have secured two dedicated frac crews for 2010 and expect to increase that number to three early next year.

We've drilled a total of 33 wells in Eagle Ford Shale, completed 20 and are seeing production of roughly 8,000 BOE per day from the 14 wells that we've brought online to date.

In the liquids rich Cardium area of Western Canada we'll be drilling nine operated wells and participating in six non-operated wells during the fourth quarter.

These wells are almost all oil producing with some associated gas.

Also in Canada we continue to see good return in production growth opportunities in our SAGD areas, Foster Creek, Christina Lake and Surmont.

Expect production of around 60,000 BOE per day this year from these projects with a compound annual growth rate over the next five years estimated between 10% and 15%.

In Australia APLNG is engaged with several potential LNG buyers in support of moving to FID.

But we're not in a position to discuss information regarding specific market discussion at this time.

However, we plan to have an announcement regarding the sale of two trains of LNG before year end.

Our plans to sell $10 billion in assets by the end of 2011 are on track and so far this year we've closed transactions with proceeds of $5.6 billion and expect proceeds of roughly $7 billion by year end.

We may sell more than $10 billion in assets during 2010 and 2011.

The assets being sold in 2010 have a production of approximately 55,000 BOE per day.

Most of the Lower 48 and Western Canadian E&P assets will be closed in the fourth quarter and will generate about $1.5 billion in proceeds.

We expect the 2010 full-year average production impact of asset dispositions to be roughly 20,000 BOE per day with a reduction of reserves of about 310 million BOE.

Assets which may be sold as part of the 2011 program include our Wilhelmshaven refinery, additional Lower 48 and Western Canada E&P assets and other international assets in both upstream and downstream businesses.

The REX pipeline is outside of the 2011 scope.

As we did this year, we intend to provide you with production, reserve and earnings impacts resulting from our asset sales program during the first quarter of 2011.

Our guidance of spending $10 billion on share repurchases over 2010 and 2011 remains unchanged.

Our current Board of Directors authorization is for $5 billion.

So that concludes my prepared remarks.

I'd like to turn it over now to Jim Mulva for his comments before we open the call for questions.

Jim?

Okay, Clayton, thank you.

I think you covered most of the points, I'll just maybe confirm a few points.

First, from an operating point of view we've operated quite well all of this year and through the third quarter.

We're doing really quite well on not only the operations but the cost constraint.

We're maintaining our facilities certainly, but we're doing well on cost constraint and that's a result of good commitment by our employees and the help of our contractors.

In terms of the portfolio of restructuring, we're right on track, no change in strategy.

Clayton covered the asset dispositions, I think there's the opportunity as we go through 2011 and we'll update you with time to be doing more than -- somewhat more than $10 billion of asset sales.

We're on track on the restructuring where we want to move E&P up towards more as a portion of our portfolio of Refining and Marketing from 25% with time closer to 15%.

Capital guidance, we're probably going to spend closer to $10 billion this year with expectations of capital spending closer to about $13 billion this next year.

Clayton indicated LUKOIL dispositions, we still have about 4.6% ownership at LUKOIL share prices we are currently experiencing, we continue to sell our shares.

So I think if these market levels continue you'll see us dispose of all our interest in LUKOIL far more quickly than the guidance which would be the end of 2011.

We continue to buy ConocoPhillips shares in the marketplace and, as the slide indicates, guidance shows that we would spend maybe closer to about $4 billion in 2010 for purchase of ConocoPhillips shares with about $6 billion this next year.

The board has approved a $5 billion program, but we've indicated the proceeds from the LUKOIL disposition would go essentially towards share repurchase.

In terms of debt reduction, our debt is in the neighborhood of $23.5 billion.

We don't have any required maturities left this year, the debt is quite efficient.

In this next year we have some required maturities which might be in the neighborhood of about $0.5 billion to $1 billion.

We'll certainly retire those, but have no real compelling economic reason to accelerate and buy in more of our debt.

So we're quite satisfied with the debt; it will come down over the next several years with required maturities but still longer term.

I think we question going much below $20 billion in debt because we have a strong balance sheet across that is quite acceptable.

In terms of utilization of our free cash flow, as I just said, we don't feel there are any compelling reasons to bring the debt down more quickly than where it is right now other than required maturities.

We feel we have the cash flow to support the capital program that we've outlined.

We like the discipline of increasing our dividends; of course it's subject to Board approval, but we, for the past several years, have been raising our dividends early in each of the years.

And then we'll probably operate with a cash balance of about $2 billion for opportunities and liquidity purposes.

So to the extent that we sell more assets and that we have good cash flow after we fund capital program and dividends it would be available for additional share repurchase.

So I think, Clayton, that covers what I'd like to do.

I think we should open it up for questions now.

Great.

Jen, if you'd like to line some questions up for us, we'll be happy to take them.

(Operator Instructions).

Doug Leggate, Bank of America.

Thanks, good morning, guys.

Thanks for taking my question.

Jim, one of the things you've talked about I guess more recently than anything else is the issue of remaining as a fully integrated company.

I wonder in light of what's going on in refining right now and the refocus of capital towards the upstream.

If you could just bring us up to date as to your latest thoughts on the potential of maybe being a little more aggressive in perhaps separating the Company sometime down the line.

And I have one follow-up.

Okay, so the question is on the refining side of the business and the aggressiveness to reduce our exposure restructuring wise.

Well, I just would say it's certainly a confidential area when we're working and talking with others with respect to either shut down a facility or joint venturing a facility, selling a facility or taking, looking at the region by which we take our refineries in a region and how we can partner them up with someone else or who should have an economic interest.

We did indicate about a year ago that we felt that the environment for transactions and restructuring would be more amenable to be in the 2012 time period.

But I think you make a good point.

We're starting to see that there's maybe a little more interest and opportunities for restructuring a little more quickly than waiting until 2012 and 2013.

So we are working pretty hard; we want to make sure that whatever we do we're doing it in a way that's not really destroying value for the shareholder.

But you make a good point and we're pretty aggressive and we're really focused on how we can accelerate this a little more quickly than the guidance we've given in the past.

Great stuff.

And my follow-up is completely unrelated.

It's really the progress in Poland.

This is obviously an area that the industry is watching very closely.

And I was just wondering if there was any additional color that you could give on the results that you've had there to date and what your future plans might be?

And I'll leave it at that.

Thank you.

Well, we're the first one drilling several wells and we're doing a lot of -- using a lot of technology in the evaluation of the wells and we kept this rather confidential and I think it's going to take us a little bit longer before we determine just what we've -- what the results are from those wells.

But I think that's something you're going to hear from us over the next several months or so.

All right.

Thanks, Jim.

Jason Gammel, Macquarie.

Thank you, guys.

Jim, I was hoping that you could make some comments on the management changes that were announced over the course of the quarter, how you feel about this new team that you now have in place and what that potentially means for your remaining tenure as CEO.

Well, first of all, with respect to the management changes -- the overriding objective is to put in place a real robust secession process that really looks out without any ambiguity both internally and externally of the Company.

Here's the new team that will emerge, provide the leadership of the Company over the next five- and 10-year period of time.

The changes for executives that are retiring has nothing to do with health or performance issues, the objective is very clear and very simple to put in place the future management team.

And out of that group of individuals will come my replacement and this will be done over the next couple of years and then that team will continue on.

I am 64 and a half years old, so we don't have a mandatory retirement age, but you can expect from this group will come my replacement just over the next several years.

We want to make sure that putting this group together that had a lot of operating expertise.

We wanted also to bring -- develop our own senior management within the Company.

But we wanted to augment it with others from the outside with experience, both upstream and downstream, that can give us also a fresh set of eyes to help us with respect to as we restructure and execute and implement the portfolio of changes becoming more upstream and less downstream.

So, without any ambiguity that's essentially what we're doing, it's in place, it's been worked actually with our Board of Directors over this last one- or two-year time period.

We're quite pleased with the team we put in place.

And I think you'll see -- you'll get the opportunity to see all of them in presentations together in March, but we'll make sure that the financial community gets to see them in presentations individually as we go through the year.

Okay, look forward to hearing from them.

And maybe one more, if I could, Jim.

A couple of the coal bed methane to LNG projects in Queensland were granted environmental approval by the Australian Federal Government just over the last week or two.

I was wondering if you could give us an idea on when you plan to submit your own EIS and what that means for the overall track to final investment decision?

Well, actually we've, over the last year or 18 months, we've really caught up with everyone else.

We've made our submissions and all and we would expect similar approvals here within the next month.

So we essentially are looking at FID at about the same time, point in time.

Okay, thanks for the thorough answers, Jim.

I appreciate it.

Ed Westlake, Credit Suisse.

Good morning, Jim, Clayton.

Just on APLNG, obviously there is this groundwater contamination investigation in Origin; they've said it's a bit of a storm in a teacup.

But in terms of -- is that impacting your discussions with potential buyers in terms of potentially having delay?

And then just on the APLNG CapEx, how much of the $13 billion next year -- how much is APLNG included in that total?

Clayton can answer the second one with respect to the information on some of the wells is really not having an impact with respect to discussions with potential buyers of LNG from this project.

Certainly most concerned to ourselves, we address this; we think we're going to be able to handle this.

But it's not having an adverse impact with respect to potential buyers.

In terms of our capital spend, I guess Clayton you could --.

Yes, it's between $1 billion and $1.5 billion of additional capital in APLNG over what we've spent this year.

Okay.

And then on the outlook for European refining sales, I mean obviously the Humber refinery complex has got a lot of scale.

If you were to sell it presumably you should be looking for a reasonably good price, not a fire sale on that.

Well, we're not looking to do a fire sale on anything.

Humber is really a complex great refinery, so it's one that we really look at; it really fits our portfolio for the long-term.

But then on the other hand, you never know, it's possible that for the right price and/or the opportunity for joint venturing, these are things that we have to consider when we look at restructuring our portfolio from 25% or 26% down towards 15%.

Wilhelmshaven, we're really not going to continue it as a refinery.

We will look at selling it if someone wants to take it or converting it to a terminal.

Our equity interest in other refineries, these are good equity interests but they're relatively small and so you have to ask yourself, do we have the opportunity to monetize them.

So the real legacy asset, the [ERP] that we have with respect to refining is the Humber refinery.

Thank you.

Robert Kessler, Simmons & Co.

Good morning, guys.

I was wondering if you could quantify the incremental CapEx headed to the Eagle Ford in 2011 versus 2010?

So I think the 2010 Eagle Ford spend is somewhere around $300 million.

And 2011 Eagle Ford spend -- of course these capital programs haven't been approved yet, but it's between $1 billion and $1.5 billion a year.

Okay, great.

And is that all organic, so to speak, or is any incremental acreage acquisition embedded in those?

No, that's all drilling and completion and there's no additional acreage in that number.

Great, thank you very much.

Paul Sankey, Deutsche Bank.

If I look at going back to the cash -- use of cash sums, if I look at our numbers we're at about $18 billion of cash flow from operations next year.

You said there's a higher $13 billion CapEx giving me $5 billion spare.

I've then got around $4 billion of disposals giving me $9 billion and you've got $8 billion in cash approximately equating to $17 billion spare.

But your guidance is for only $6 billion of buyback next year.

Is what you're saying in terms of planning opportunities related to the potential for bigger acquisitions?

I think that you've guided towards $2 billion potentially to be spent in the Gulf of Mexico.

Is there risk here that we get back on the acquisition path to regenerate the organic opportunities there or are you really lowballing this buyback number?

Thanks.

Well, Paul, you make a good point, the numbers are consensus views of cash availability for the Company going forward.

And so I think you make the following.

If we spend $13 billion for capital there's no more required for debt reduction, maybe required repayments of $1 billion next year.

But like we've indicated, we like to increase the dividend 5% to 10% a year.

We're not looking at acquisitions other than the opportunities we might have in the Gulf of Mexico or the Lower 48 which we can farm in or get a handle on an asset we potentially could spend $2 billion or $3 billion doing that.

So what's left then is we have a lot of cash that's available not for making a large acquisition, it's available for additional share repurchase above the $10 billion number.

It's not that we're trying to signal in any way that it's available to make a significant acquisition.

No, we're not changing our strategy; it's more available for distributions to the shareholders.

Right, I understand.

And on a kind of financial theory level, the stock X the LUKOIL earnings is looking obviously more expensive than it did when the plan, the strategy was outlined where you were I think under $50 a share.

Can you just talk about how you view the investment at these relatively elevated multiples as opposed to the other opportunities you would have in terms of other reinvestment opportunities and why you feel that buyback is the most appropriate way forward?

Thanks.

Well, we look at the valuation of our shares and certainly we have improved the share price over this past year and with the announcement of the strategy of what we've been doing with the company this past year and we'll continue going forward in 2011 and subsequent time periods.

Management is never happy with the share price being what it is today.

But if we look at what we're trying to do is really increase the normalized -- the normalized earnings and cash flow per share given our asset base and our opportunities, we feel that we can over the next number of years be spending $13 billion, $14 billion a year.

And we can convert our resources and replace our reserves and then ultimately in the 2014, 2015 time grow our absolute level of production, we can do that on $13 billion, $14 billion, $15 billion a year of capital.

Still raise our dividends 5% to 10%.

So if you believe that there will be a somewhat better oil price, which I think we believe with time there will be, and a somewhat better natural gas price, not $3.50 her Mcf but maybe closer to $5.00 an Mcf, then we think even at the levels of $60 plus distributions to our shareholders in the form of additional share repurchase gives us the best opportunity to be raising the share price on a normalized basis going forward with whatever assumptions you have for commodity prices, that we do that by having fewer shares outstanding, more capital discipline and ultimately replacing our reserves and growing our production on absolute terms, but even more so on a per metric per unit share.

So we feel that -- we continue to look at it, but we think there is an opportunity for quite a bit more share repurchase.

And I'm sure you'd be considering a special dividend within the various tools that you have got available to you, Jim?

Well, that is an alternative and an opportunity, but that is something for the Company -- for the Board to determine.

I think our priority would be primarily raising the normal dividend and share repurchase before a special dividend.

Okay, thank you.

Mark Gilman, Benchmark Company.

Jim, Clayton, good morning.

A couple things.

Can you provide us with some individual well metrics on your Eagle Ford effort up to this point, and any trends in terms of well costs, reserves per well and IP rates?

I can't do that right now, Mark, but we can get that information.

I mean I think what we have said is these wells are generally around 1500 BOE per day.

Well costs are running in the $8 million to $9 million per well range.

I don't know if we have given a ultimate reserve number on the field or by well, but we are really encouraged by what we have seen so far.

I think there is some information that is out there publicly that I could share with you on our well results.

We think we are in just the right spot of Eagle Ford and really encouraged by the results.

But I can get more detail to you following this call.

Clayton, is that 1500 a 30-day, 24-hour --?

That's a 30-day average rate.

Okay.

Jim, I'm hoping you might be able to clarify your decision a little bit regarding the REX pipeline and the decision not to offer it for sale currently.

Does this reflect an expectation that you might get better value down the road or a change in sentiment?

If it's the expectation of better value down the road, help me understand the basis of the belief.

It's not a change in sentiment; it's that we didn't feel that the bids that we got were meeting our expectations of what we could get at a later date.

And so, we're not changing the direction, we're just saying we feel that we can come back at a later point in time and get our -- at a better price.

So what we're really saying is we're not going to dispose of assets in a fire sale.

We think this asset is worth more than the bids we got, so we're going to go back out whether -- it could be late 2011, 2012.

When we think the market is better prepared for this or more interested in it that's when we will do it.

Okay.

One final one for me, if I could.

The trend in Bohai production has, I guess, surprised me a little bit that we're not seeing a bit of a larger ramp up.

Clayton, Jim, can you talk about that a little bit and when you would expect to see the plateau level reached from Phase 2?

What's taken us longer, the well performance is more difficult, more challenging.

It's not that it's not expected, but it's taken us longer than we expected.

I was just over in China, Beijing about two weeks ago, and I think Clayton can confirm this, but I think we're getting up to 150 gross -- 150,000 barrels a day, maybe a little bit more than 150,000 barrels a day.

And as I recall I think ultimately we're trying to get up to 160,000, 170,000 barrels a day gross.

Clayton, you can update those numbers.

Yes, our net production -- I see what you're saying, Mark.

Our net production out of Bohai is at -- it is running at 55 a day right now.

I think there are, as Jim said, the development of the production has been slower than we expected.

But overall production growth in Bohai has continued with the earlier guidance that we have given.

Okay, thanks, Clayton.

Doug Terreson, ISI.

Congratulations on your results, guys.

Thanks, Doug.

Jim, you guys have seven to eight major E&P projects which appear likely to lead to almost full reserve replacement through 2014 by themselves and have pretty attractive economics too.

And at the same time the Company has a new exploration program that's gearing up also.

And so my question regards the conversion process on these reserves, meaning -- what is your level of confidence that the team can execute such a large plan of commercial conversion for these reserves over that period of time?

And on the exploration front, where are you most optimistic when you think about how the profile may be supported over the longer term?

Conversion of reserves, we really feel what we're doing in the Oil Sands of Canada -- Surmont, Foster Creek, Christina Lake -- we feel really good about that.

I'll ask Clayton -- I'd like to share with you what our breakevens are when I get done answering your question.

But conversion of the Oil Sands is a pretty significant part of our conversion and reserve replacement over the next five years, feeling really good about that.

And then the oil, we've really -- our portfolio I don't think is well understood in the marketplace.

Our portfolio of what we have in the Eagle Ford and in the Bakken and the oil play of Barnett and other areas that we have, we're really getting more and more encouraged all the time and it's why we're increasing our spend by $1 billion or more in 2011.

So we feel real good about that.

Obviously we've got to deliver on what we say we're going to do with APLNG, but we really feel that project is coming together and that's pretty important LNG projects in the future.

And then we're having discovery success in Alaska like Poseidon, it's a little bit longer in turn.

So LNG projects, what we are doing in the Lower 48 Oil Sands and then we're going to go forward with the redevelopment of Ekofisk and Elfisk, we feel pretty certain about adding reserves there.

Those are some of the big areas.

Now on the exploration front we've got the Rak More well and we've got more opportunities, more features to drill in the Caspian.

We are looking for more acreage in Turkmenistan, we're looking for more acreage essentially in other places of the world.

But we also think we're uniquely positioned as a company, exploration wise and maybe BD wise, for larger companies and smaller companies in the deepwater Gulf of Mexico.

We don't know what the rules and regulations are going to be, we don't know for sure what the risk/reward is going to be.

But that's why we've said in prior responses to questions that we've reserved a couple billion dollars that we feel that we could go into some discovered resources and participate as an opportunity.

For all these reasons we really believe very strongly, and we'll update everyone in the March analyst meeting, conversion process of reserve replacement and doing that at competitively finding and development cost, we feel pretty good about this over the next five years and we'll share that with everyone.

Now, Clayton, maybe would you -- in our March meeting -- but would you go through just -- I think the breakevens on we have for Foster Creek, Christina Lake as well as Surmont gives you a better feel.

We've got the resources there but why we're committing the money and why we feel we can grow production 15% compounded over the next number of years for a long period of time?

Yes, most people believe the Oil Sands require significantly higher prices to generate 13% returns.

Our cash breakevens at Foster Creek and Christina Lake for the third quarter were $15.08, and on the net income basis it's $25.70.

And that's representative of about where it's been running on average for the entire 2010.

At Surmont, Surmont is not quite as good as FCCL, but the cash breakeven at Surmont is $21 a BOE and on a net income basis it's $27.65.

So, very competitive projects, they will continue to attract capital.

Yes, and the other thing I didn't mention, Doug, is not only can we replace our reserves and grow our production, not just on per-share basis but absolute level as we get into 2014 and 2015 from these type projects, but they do have very good returns.

So they really deserve and it's built into our capital spending plans.

Sure, great.

Jim, thanks a lot for the information.

Okay, thanks.

Blake Fernandez, Howard Weil.

Good morning, guys.

Thanks for taking my question.

I wanted to go back to the REX pipeline.

I just wanted to confirm, are there additional expansion or operational opportunities over the next couple of years that are going to enhance the attractiveness of that asset?

Or are you just simply needing the macro environment to improve?

I think it's just the macro environment to improve.

I don't think we're looking at expansions or that.

I think there is a question, a concern that has an impact to potential buyers on the REX pipeline, how quick and fast is Marcellus going to develop?

Is that back up?

The purpose of the REX pipeline?

And it's not over the next 10 years, that's pretty well signed up for in the throughput and the users of the pipeline and questions beyond 10 to 20 years out.

So I think that's really the impact.

It's not because there are going to be changes in the pipeline, it's how does it fit longer term and that has an impact in a rather skeptical business environment to buy assets like this, but we think that will improve.

Okay, great, thank you.

And the only other one for your, the 180 million cubic feet that was curtailed late in the third quarter, would you mind providing any specifics on regions or basins that that's coming from?

I can give you a little bit.

I think 150 Mcf a day is Western Canada and then there's six a day -- about 35 Mcf a day out of San Juan and the Bossier.

We'd actually do more curtailment if we could, and the reason is that we have partners.

And we have maybe smaller companies or independents or whatever, lease holders that won't go along with curtailment.

But we would do more if we could because we just think it adds more value in the future.

Now you can look at our production guidance for the fourth quarter of guidance with -- ultimately will come in 2011.

I mean, we could make our production 1.75, 1.78 by spending more money and not curtailing production.

But we look at it and we say it doesn't make a lot of sense to spend money for dry gas in a lot of places in North America and we should really be curtailing production.

But if you want production to be 1.75 or 1.78 we can do it, but we don't think that's a wise spend of our money.

That's why we come up with the numbers we do for guidance -- for production.

Right, no, that makes sense.

Thanks a lot.

Khan Faisel (sic), Citigroup.

Hi, it's Faisel from Citigroup.

I apologize if I missed some of your comments; I dropped off the call.

But, just following up on the last question in terms of the volumes that are shut in.

I guess how long do you guys plan to keep the volume shut-in?

Or I guess the more important question is what's the breakeven price that you kind of bring back that production?

Well, in many respects we can get the breakevens where, even at price levels you're seeing today, you can maybe argue that you would produce this.

But on the other hand, we're not willing to just push volumes to push volumes and essentially just break even.

We think this market will sort out not in the short-term but ultimately will sort itself out and become less dysfunctional and we'll see the economy improve somewhat and we'll see more demand and there won't be as much drilling for economic reasons, opportunities to take the cash from previously hedged positions with other independents, whatever, the market becomes less dysfunctional.

So, we really look at it and we say as you go forward and look, we think that really price levels we see today are really unsustainable.

So we've got to start seeing price levels moving towards $4 and $5 that we think with time will come.

So that's really factored into our decision.

Yes, Faisal, the Western Canada gas breakevens on a net income basis are between $5.50 and $5.75 an M.

Okay.

And Lower 48, that number is around $3.75.

And then you might go through what the cash breakeven --.

On a cash basis looking at this year, it's been between $1.65 and $2.00 an M for Western Canada and around $2.00 for Lower 48, San Juan and Mid-Continent BUs as well.

Okay, got you.

And then if you could give me -- give us a little more color on the sequential change over change in US refining, refining income.

It looked like you went $782 million in the second quarter to $199 million.

And it looks like the capture rates kind of went down over the quarter too.

Can you talk a little bit about what was going on there?

Yes, sequential change in R&M of about $500 million.

We identified the inventory impact, so that's just how we value the underlying physical against the paper position.

We expect to get that $75 million back.

But we did have lower marketing margins of around $70 million and then our coke business and our chemical feedstock business combined had a negative impact of about $50 million, and then the balance really is realized in our crack spreads.

But there's another thing too, Clayton, and that is we embarked upon a very major turnaround activity late in the third quarter, it's going through the fourth quarter.

And this certainly impacts our performance.

We gave out the guidance in terms of turnaround costs, but we complete these turnarounds we're really setting ourselves up, we feel, quite well for long runs as we go into more turnaround requirements in the subsequent years of 2011.

So we're going through some pretty extensive turnarounds right now and that has an impact on performance and financial results.

Great, got you.

Then one last question.

On the international realized margins of $10.27 to $4.41, that's substantially lower than what the indicated margins did.

Any color on that?

International -- are you talking about international R&M?

Yes, R&M.

Our realized margins went from $10.27 to $4.41.

I'm going to have to come back to you on that one.

Okay, got you.

Fair enough.

Thank you very much.

Pavel Molchanov, Raymond James.

Thanks for taking my question, guys.

First, just on the upcoming exploration, can you give us any pre-drill reserve estimates for the wildcats in Kazakhstan and Norway?

We generally don't, Pavel.

We just have historically not given any kind of orders of magnitude on the size of the structures that we're looking at.

They're significant obviously, especially in the Caspian.

But we don't typically make those kinds of comments.

Can you say if these are more oily or more gas related?

I wish we knew.

Obviously everyone is looking for oil, but I think it's just not appropriate or not really willing to get into that.

Understood.

And then the second one just on a little more conceptually, a lot of your peer companies have been getting into biofuels particularly next-generation biofuels through JVs, partnerships, etc.

You guys have generally stayed away from that.

Are you looking for the right opportunity or are you generally inclined to just stay away from that trend for now?

Well, two things.

First, we believe from a political process let's not create winners and losers and get any into things that are heavily subsidized or the only way they work is you need to have continuation of governmental incentives.

We have quite an opportunity,

there was a prior question -- we have so much to do in our traditional oil and gas business at E&P we're going to allocate all of our money essentially towards that.

And about $1 billion, $1.5 billion through the downstream primarily for maintenance capital and some payout opportunities.

But then you'll see us ramping up more our spend for technology and research.

A lot of that goes towards (technical difficulty) business side, but also just the things you're talking about.

We think it makes a lot more sense to be spending money in understanding and making some technology breakthroughs than to start spending hundreds of millions of billions of dollars in businesses that are questionable value creators for the shareholder and dependent upon subsidies from the government.

So, we're going to study and work this, but we're going to do it primarily through ramping up money that we're spending on research and technology.

Appreciate the thoughts.

Thanks.

Ladies and gentlemen, this does conclude our Q&A session for today.

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

Clayton Reasor for closing remarks.

Right.

Well, we appreciate the interest in the Company.

Obviously if you have further questions we're available to take those.

You can find a replay of the call and a copy of our slides on our IR website on ConocoPhillips.com.

So, thanks again; look forward to talking to you soon.

Ladies and gentlemen, we thank you for your participation in today's conference.

This concludes the presentation and you may now disconnect.

Have a good day.

Company Disclaimer

CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This transcript contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby.

Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results.

In many cases you can identify forward-looking statements by terminology such as "anticipate," "estimate," "believe," "continue," "could," "intend," "may," "plan," "potential," "predict," "should," "will," "expect," "objective," "projection," "forecast," "goal," "guidance," "outlook," "effort," "target" and other similar words.

However, the absence of these words does not mean that the statements are not forward-looking.

Where, in any forward-looking statement, the company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis.

However, there can be no assurance that such expectation or belief will result or be achieved.

The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, crude oil and natural gas prices; refining and marketing margins; potential failure to achieve, and potential delays in achieving, expected reserves or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas; unsuccessful exploratory activities; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying company manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; international monetary conditions and exchange controls; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business.

Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission (SEC).

Unless legally required, ConocoPhillips undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

This transcript includes certain non-GAAP financial measures.

Such non-GAAP measures are intended to supplement, not substitute for, comparable GAAP measures.

Investors are urged to consider closely the GAAP reconciliation tables provided in the Appendix or on our website at www.conocophillips.com.