康菲 (COP) 2011 Q2 法說會逐字稿

Welcome to the second-quarter 2011 ConocoPhillips earnings conference call.

My name is Kim, and I will be your operator for today's call.

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

Later we will conduct a question and answer session.

Please note that this conference is being recorded.

I will now turn the call over to Mr.

Clayton Reasor, Vice President Corporate and Investor Relations.

Mr.

Reasor, you may begin.

Thank you, Kim.

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

We appreciate your interest in our Company.

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

As we normally do, we will provide a summary of our key financial and operating results for the second quarter as well as an outlook for the remainder of 2011.

We will also provide you with a brief update on the repositioning of ConocoPhillips as two separate leading energy companies as we announced two weeks ago.

You can find our presentation material in the Investor Relations section of the ConocoPhillips website.

Before we get started I would like to take a look at the Safe Harbor statement that we have shown on the next slide.

It is a reminder that we will be making forward-looking statements during the presentation and during the question and answer session.

Actual results may differ materially from what we present today, and factors that could cause actual results to differ are included in this slide, as well as in our filings with the SEC.

So with that, I will turn the call over to Jeff Sheets, who will take you through our prepared remarks and presentation.

Thanks, Clayton.

I will start on slide two, which highlights some of our second-quarter results.

During the second quarter we had adjusted earnings of $3.4 billion.

That is $2.41 a share.

That compares to adjusted earnings of $1.63 a share in the second quarter of 2010.

During the quarter we generated cash from operations of $4.44 for per share.

This was a good quarter for the Company.

We ran well both in E&P and R&M.

Second-quarter production was 1.64 million BOE per day.

Our global refining utilization was 91% during the quarter.

We generated $6.3 billion in cash from operations.

Our annualized return on capital employed was 15% for the quarter, and our cash return on capital employed was 24%.

Also, during the quarter we distributed $4 billion of cash to our shareholders in the form of shareholder distributions -- share repurchases and dividends.

Our repurchase of 42 million shares this quarter represented about 3% of our shares outstanding.

In our earnings release this morning we highlighted that in addition to creating value for our shareholders, ConocoPhillips' activities also contribute substantially to job creation and economic growth.

Slide three recaps some of the numbers associated with our activities for the first half of the year.

During the first half of 2011 the Company spent $6.5 billion on operating expenses, which supported 30,000 jobs at ConocoPhillips, as well as jobs at our suppliers and contractors.

A further $6.1 billion was invested in capital projects, which helped to create new energy supplies and also fuel additional job creation.

$7.7 billion was paid to local state and federal governments in the form of income, production and severance taxes.

In addition, ConocoPhillips distributed $6.6 billion to a wide shareholder base, which includes numerous state and local pensions and investment funds, which benefit millions of individual US investors and retirees.

So let's turn to slide 4 to discuss some of the details of our performance for the quarter.

Total Company adjusted earnings were $3.4 billion.

That is up about $950 million compared to the second quarter last year.

Our E&P segment was improved over $1 billion due to higher prices, which were offset by higher taxes.

R&M adjusted earnings were basically unchanged from a year ago.

In the second quarter of 2010 our earnings included $430 million related to our ownership interest in LUKOIL.

And since we have now sold our interest in LUKOIL, we don't have similar earnings as part of our second-quarter 2011 results.

Our Other segment's adjusted earnings improved by $290 million as a result of lower corporate expenses, higher -- and then higher chemicals and midstream earnings.

So next we will look at more detail on our segment earnings, starting with production and our upstream business, which is highlighted on slide five.

Second-quarter production was 1.64 million BOE per day.

That is down 5% or 93,000 BOE per day from the second quarter last year.

The decline from the second quarter last year was a result of asset dispositions and the loss of our production from Libya.

Asset dispositions negatively impacted production by around 62,000 BOE per day.

This primarily reflects dispositions in Canada and the Lower 48.

Of that 62,000 BOE per day, 16,000 BOE per day was North American natural gas.

So the exclude if you exclude the impact of our asset dispositions and the loss of production from Libya, our second-quarter 2010 production would have been 1.623 million BOE per day.

In the second quarter of 2011 we produced 1.64 million BOE per day.

And the changes there include a decline of 28,000 BOE per day in our North American natural gas production, which was offset by an increase -- a net increase, of 45,000 BOE per day of liquids production and international gas production.

So stepping back and looking at all the changes from 2010 to 2011 second-quarter numbers, you can see that the declines in production that we have had are primarily attributed to the declines in North American natural gas production and the loss of our production in Libya, which are both relatively lower margin portions of our portfolio.

Looking at our production on a per-share basis, we see that our production has increased 4% from the second quarter of 2010 to the second quarter of 2011.

So now I will turn to E&P earnings on slide 6.

E&P, our adjusted earnings for the quarter were $2.6 billion.

That is up $1 billion from the same quarter a year ago.

This increase is largely driven by higher prices, offset by higher taxes, and to a smaller extent by lower sales volumes.

So even though production was down 93,000 barrels per day the impact of those reduced volumes was only about $100 million.

As we just discussed, the volume reductions in the quarter compared to the quarter a year ago where primarily from lower margin barrels.

In the cost and other category, this was a help relative to -- this quarter relative to the second quarter last year.

This was driven by lower DD&A, partially offset by some increases in other taxes and operating expenses.

At the bottom of this slide you can see the results broken down between US and international.

You can see that we had improvements in both US and international adjusted earnings, as well as increases in realized prices.

So I'll move on to slide seven and talk about some of our E&P unit metrics.

Income per BOE improved to $17 a barrel from $9 a barrel a year ago.

And cash per BOE improved to $29 a BOE compared to $22 a year ago.

The majority of this improvement is attributed to stronger commodity prices; however, we are also starting to see the benefits of the shift in our production towards higher margin barrels.

So turning to R&M earnings on slide 8.

Our adjusted R&M earnings improved by $20 million over the same quarter last year.

Margins and other market impacts increased earnings by $63 million, which reflects a $205 million increase in US refining margins, offset by roughly $145 million decrease in international refining margins.

International refining margins decreased despite slightly increased market cracks due to inventory impacts and lower secondary product margins, which are a result of higher crude prices.

In the second quarter we saw a decrease in R&M earnings of around $20 million from lower volumes compared to the second quarter of last year.

This was driven primarily by lower domestic refining volumes, partially offset by higher international refining volumes.

The lower domestic refining volumes largely relate to unplanned downtime at the Sweeney and Bayway refineries, as well as turnaround and planned maintenance activities at the San Francisco and Los Angeles refineries.

Our refining capacity utilization rate for the second quarter was 90% in the US and 96% internationally.

Compared to the second quarter of last year we saw operating cost increased about $18 million, but this was primarily driven by foreign exchange impacts.

Take a look at R&M unit metrics on slide 9.

The per barrel metrics for refining and marketing increased compared to the first quarter this year, and they're basically flat with where we were in the second quarter of last year.

So second-quarter net income per barrel this year was $2.58 and the cash contribution was $3.32.

We will take a look at results from our other operating segments on slide 10.

Our Chemicals segment posted another strong quarter with earnings of $199 million, which is up from $138 million a year ago.

This increase was primarily due to higher ethylene and polyethylene margins, as well as increased equity earnings from CPChem's interest and ventures in the Middle East.

Midstream earnings of $130 million were more than double the earnings they had from that segment a year ago.

And this is primarily related to higher natural gas liquids prices.

Corporate expenses of $203 million for this quarter compared to negative -- compared to $367 million a year ago.

This improvement is primarily driven by foreign exchange impacts and lower interest expense.

So we will move to slide 11 and look at our cash flow from operations for the second quarter.

We generated $5.4 billion in cash from operations this quarter, excluding a $900 million decrease in working capital, which also benefited cash from operations.

In the first quarter we saw a working capital decrease of about $2 billion -- a working capital increase, excuse me, of about $2 billion.

The decrease this quarter is primarily related to reductions in inventory in our downstream business.

These working capital numbers are going to fluctuate from quarter to quarter, but we expect these changes to average zero over time.

We generated $116 million in cash proceeds from dispositions in the second quarter.

Dispositions during the quarter included some E&P assets in Western Canada as well as some technology and transportation assets.

We funded a $3.1 billion capital program that was $2.8 billion in E&P and $300 million in our R&M business.

Distributions to the shareholders this quarter amounted to $4 billion, which included the repurchase of 42 million shares at a cost of $3.1 billion and $900 million paid out as dividends.

Share repurchases, since we started our program in 2010 have totaled $8.7 billion, which represents about 9% of our shares outstanding.

We ended the quarter with $5.5 billion in cash and $2.6 billion in short-term investments, so $8.1 billion in total cash and short-term investments.

Turning to slide 12, we will take a look at our capital structure.

Our capital employed is essentially flat with where it was at the end of 2010 with small increases in equity and small decreases in debt.

Our equity increased by about $1.5 billion.

The combination of income and some foreign exchange impacts were offset -- largely offset by share repurchases and dividends.

Our debt to total cap remains at 25%, which is in-line with our target.

In the second half of 2011 we expect to retire about $500 million of maturing debt.

So we will move to the next slide and talk about our capital efficiency metrics.

Both our ROC and cash returns improved in the second quarter, driven by the growth in earnings and cash flow.

Our annualized ROCE for the second quarter was 15%.

If you look at the upstreams part of our business ROCE was 17% and downstream was 13%.

That completes the review of the second-quarter 2011 results.

I will wrap up with some forward-looking comments before we open the line up to questions.

So let me start with updates in a few areas.

In R&M we have had pretax turnaround expenses year-to-date of approximately $160 million.

We expect full-year expenses to be around $350 million.

And this is lower than the previous guidance of $450 million.

We expect global refining capacity utilizations to be in the low 90s in the second half of 2011.

On the upstream side of our business when we look at the production for the rest of the year we see the third quarter that we will have increased maintenance and turnaround activities, primarily in Alaska, the UK, the Middle East.

And then we expect fourth-quarter production to increase to a level similar to what we have seen in the second quarter.

And overall for the year we would expect production to be somewhere between 1.625 and 1.65 million BOE per day.

On July 19, 2011, the UK enacted legislation increasing income tax rates effective March 24, 2011.

As a result, we expect to recognize a third-quarter expense of approximately $110 million in the E&P segment related to the revaluation of deferred taxes and $80 million due to higher taxes from the March 24 period through the end of June.

On our guidance for DD&A and corporate expenses, we don't have any changes at this time.

In Bohai Bay in China we are working closely with the Chinese government and our co-venture CNOOC following the release of about 1,500 barrels of oil and oil-based drilling mud that occurred in June.

We reported this incident to the Chinese authority immediately after it occurred.

The cause is still under investigation.

And we currently have about 17,000 BOE per day net of shut-in production.

We expect the announcement of the final investment decision for the APLNG project soon.

With the achievement of FID, and as we have announced previously the agreement with Sinopec to subscribe for a 15% equity interest in APLNG, we expect to recognize an after-tax loss of about $275 million during the third quarter related to the dilution of our interest in that project.

So switching to North America.

We continue to pursue adding to our high-quality unconventional resource opportunities.

So far in 2011 we have added about 340,000 acres to our North American resource plays.

Activity levels in our Lower 48 liquids-rich shale plays continue to ramp up.

Our current production at Eagle Ford is about 24,000 BOE per day.

While results there remain encouraging, but we do have some production curtailments due to third-party condensate trucking constraints.

We're getting about 75% liquids content at Eagle Ford.

We are operating 13 rigs in this -- we operated 13 rigs in this play during the second quarter and we expect to be up to 16 rigs there by year-end.

We are also planning to increase activity significantly in the Bakken and North Barnett plays during 2012.

And we would expect that our rig count in these areas to nearly double by the end of 2012.

Second-quarter production from these two areas was about 30,000 BOE per day.

So as we continue to develop our Lower 48 opportunities, we continue to find opportunities for increased investments with strong economic returns.

This year we have already allocated an additional $500 million of our capital program to these activities.

And as we look for -- and we are currently working through our plans for increased investment levels in 2012.

Now key to executing the capital program in the Lower 48 is going to be our assessment of capacity and service providers, drilling rigs and completion crews, and our ability to bring production online as quickly as production has increased, and that relates to the buildout and access to infrastructure and takeaway capacity.

On some international items, in Poland our third well has been successfully drilled.

And we've got a multistage frac over the horizontal section of that well that is going to begin in the third quarter.

And then a fourth well is also expected to be spud in the third quarter.

In Australia the necessary permits have been received, and we plan to move forward with the exploration and appraisal program in the greater Poseidon area starting in late 2011 and that will continue on into 2012.

On the downstream side, the core project at the Wood River is scheduled to be online in the fourth quarter.

We expect that this project will generate a mid-teens return.

And at current projects we would expect -- at current margins we would expect that this project could add $200 million to $300 million of net annual cash flow.

On our asset sales program we are in various stages of marketing several assets as part of this program.

Our plans to sell $5 billion to $10 billion of assets in 2011 and 2012 have not been impacted by our announcement of the repositioning into separate E&P and downstream companies.

These processes take time.

We are making progress.

And these processes will continue to include downstream assets.

And our target to reduce refining capacity by 500,000 barrels per day remains in place.

We also continue to repurchase shares, and we expect that we will do so at a rate similar to what we have done in the second quarter.

So I will conclude with a few comments about our recent announcement, which is slide 15 in the presentation.

So on July 14 we announced our intent to create two leading independent energy companies by spinning off our downstream business into a new publicly held company.

We believe this was a compelling transformational event for our Company, and we are convinced that this is the right thing to do long-term for shareholder value.

We see benefits of greater management focus, greater focus on capital allocation, less complexity in running these businesses going forward.

We recognize that the external environment has changed and will continue to change, and that both these companies will have the size and the scale to effectively compete in the environments going forward.

Our assets and ability to grow will be more transparent externally post this transition.

And we believe that the market will value this transparency.

We understand that there is uncertainty about the exact allocation of assets and where the joint ventures will be, as well as what the capital structure will be for these companies and the management team for these companies.

We expect -- and we plan to provide you additional information on these items in September of this year.

We also expect that we will be naming CEOs for both of these companies before the end of the year.

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

We will now begin the question and answer session.

Ed Westlake, Credit Suisse.

Good morning and congratulations on the operational performance.

So just firstly on the downstream spin-off, it has been a few weeks, is there anything you can say in terms of the reaction of some of your partners and some of the JVs that you have had, CPChem, Cenovus, (inaudible), DCP Midstream?

No, it is really too early for us to make any comments on that.

Those discussions have started, and until we have concluded those discussions it would be premature for us to say anything.

Okay, and just on the disposals, obviously, you have done $1.9 billion so far this year out of the $5 billion to $10 billion that you're looking for.

Could you talk in any detail about how much you think you could get done in the second half of the year out of that sort of 18-month program?

I think we will just say that we are still on the $5 billion to $10 billion additional to the $7 billion we did in 2010 over 2011 and 2012.

We have a lot of -- as I mentioned earlier, we have a lot of different transactions that we are working and we would expect that we will be closing some additional transactions in 2011 and probably announcing some that will close in 2011 -- really that will close in 2012 later this year.

We would -- so I was just again reiterate the same $5 billion to $10 billion range that we said for the 2011, 2012 combined.

Then just on the -- final question on the Eagle Ford.

Obviously, you are running into, as you say, a few production curtailments due to trucking.

Pipelines is probably the way forward to get that crude out there.

Can you just give us an update on when you will have your Eagle Ford production fully covered by pipeline export options?

Well, I think it is going to be a continually evolving aspect of this.

We will have additional capacity built out, but then we are also going to be continuing to ramp up production.

And maybe just a couple of comments on Eagle Ford overall.

So the second quarter we averaged 21,000 barrels a day out there.

We currently are producing around 24,000 barrels a day.

We probably could be producing a little over 30,000 if we had no production constraints out there at all.

So we will have periods where we are going to catch up and then we will have periods where we will fall behind again.

But I would think as we move into 2012 and 2013 that we would expect to be out of the curtailments situation.

Thanks very much.

Doug Terreson, ISI.

Congratulations on your results.

Jeff, I have a question about US E&P.

Your results were obviously very strong there even with the penalty of the new tax regime in Alaska.

On this point my question is really twofold.

One, whether you have an idea of the earnings affect of the rise in Alaska and Texas year-over-year?

And, two, whether you have an updated view on the likely outcome or any timing of adjustments that may materialize up there?

Maybe we can just kind of give you some numbers on Alaska production taxes.

If you look at how much we paid in the first quarter it was a little bit -- just under $500 million.

If you look at what we paid in the second quarter in production taxes it was just a little bit less than $800 million.

So a substantial part of the increase in prices, of course, in Alaska goes towards higher production taxes.

We don't anticipate any near-term movement on the political front in Alaska.

Then, secondly, your results -- or your returns in E&P are clearly improving between the higher profitability from Qatar, oil sands, unconventional, maybe some other places as well.

And you do have new production over the next several years.

But on the divestiture plan, I wanted to just ask whether or not the functional and geographical areas from which your sales are likely to unfold, meaning have there been movement or some areas more likely to be sold, others less?

And if so, how has the program changed over the last couple of years, Jeff, if you think it has?

The program really hasn't changed.

We are in a situation where it is kind of the same situation we have been in since we -- even going back to the March analyst presentation where we have outlined what our targets are, but have said that the nature of the things we are pursuing, it is probably best from a commercial perspective if we talk about them once they are nearing -- complete or nearing completion.

So we're going to be probably not able to provide a lot of additional guidance on that.

The same kind of production impact guidance that we gave back in March that this can be 50,000 to 100,000 barrels a day of incremental production that we are selling is still, we think, an appropriate way to look at it, and it can be a mix of things from all across our portfolio.

I am afraid I just -- with where we are in different aspects of this there is not a lot more that we feel it is appropriate to say at this time.

Okay, no major changes then.

Thanks a lot.

Paul Sankey, Deutsche Bank.

On CapEx, I wondered firstly can you just confirm your expectations for 2011 split between upstream and downstream?

And I have a follow-up on that subject.

For 2011 we had a capital program of $13.5 billion.

It was basically $12 billion upstream and $1.5 billion downstream and other.

It is kind of $1.2 billion in downstream and $300 million in other.

That is still pretty much where we are going forward for the rest of 2011.

Then you announced in your comments a significant step-up in US activity.

I assume clearly that will require more CapEx into 2012.

Can you talk about -- maybe give us a bit more color on what you intend to spend it on.

And secondly, clearly how much more you would be expecting to spend in 2012?

Thanks.

So I mentioned in our early comments that we are going to allocate an incremental $500 million to developments in North America.

I think we would anticipate that is going to come just from adjustments that we make in the overall program -- a little bit slower spend perhaps on some projects than what we had initially anticipated to where the budget is going to end up in the same range as what we talked about earlier this year.

We are taking a hard look now as what the 2012 level of expenditure is going to be in that area, but we could see that we could be up another $1 billion next year as we -- as kind of to help you with the possible range from where we were this year as we look at the breadth of our opportunities.

I think we had said $14 billion to $15 billion in CapEx in 2012, and I would say there is no reason to change that at this point.

Thanks, Clayton.

I was just wondering if that was incremental beyond that.

I don't think so.

I think the capital if it comes into Lower 48 was probably reallocated, as Jeff said, from other projects that may not be moving as quickly as we had thought.

But that is something that as the rest of the year -- as this year goes on and we get a little firmer on our 2012 plans that we will be able to provide more guidance on.

Right, and I am thinking about the split companies.

I assume that the CapEx levels would be expected to be in-line with what they were in the combined company, or am I wrong on that?

And can you just talk a little bit more about the math that you have for growing the Company as an upstream stand-alone entity once you lose the free cash flow from the downstream?

Thanks.

So I think as we look generally at the upstream part of our business, it is of course, influenced by the level of commodity prices.

But we generally feel like as you look over time that it generates the cash necessary to fund an investment program and to fund the dividend.

Some years it may be a little bit -- generate more cash than CapEx plus dividend.

Some year it may be a little bit less than that.

But both of these entities, when we set up the capital structure for them, we are going to create them with a lot of financial flexibility so they are both capable of handling fluctuations in commodity prices and continuing to invest capital through the cycle.

So we don't anticipate that that suggests any real change in our upstream strategy.

The upstream strategy is still going to be about converting resources to reserves, improving -- and shifting the portfolio to higher-margin production, improving returns on capital, improving -- growing production on an absolute basis and on a per-share basis.

And we will be providing more information about this as we talk in more detail about these companies.

But what you will see, I think, is that both these companies are going to have the financial flexibility to pursue the capital programs that make sense for them.

Yes, thanks.

Correct me if I'm wrong, but I believe that you think the upstream will generate around $17 billion of cash flow from operations, and I think $85 oil, which would then cover the $3.3 billion dividend and leave you the remainder to try and grow, I think, at 3%.

Is that correct?

Those numbers sound about right.

I think we will be, of course, talking in more detail about the outlook on both these companies as the rest of this year progresses.

Sure, and then, finally, I think the statement was you intend to continue buying back stock until you achieve absolute volume growth.

That would imply clearly that you would be buying back stock throughout 2012.

I think what we said is that we are going to continue to buy back -- we have talked -- the guidance we have given for share repurchase is that we are doing through 2011, we have authorized $11 billion in total.

And that we would anticipate that we are going to do the majority of that in 2011.

Then we will continue to evaluate, as always, the relative balance of investment versus share repurchases going forward.

I guess to give yourselves financial flexibility in terms of balance sheet, you might be thinking about less buyback in order to generate stronger -- in 2012 -- in order to generate stronger balance sheets for the two separate entities.

I don't think we really are in a position to comment about 2012 buybacks at this time.

It is just always part of our decision-making on how we are balancing the opportunities for investment versus the opportunities for share repurchase.

Okay, thank you.

I will leave it there.

Iain Reid, Jefferies.

A couple of questions.

Jim, I heard you say on APLNG about the write-down you have to take, but also could you clarify whether you're going to take a one train FID there or whether you think you'll be in a position, having sold enough gas, to take a two train FID?

Well, we will clarify that when we make our FID decision.

But if we end up in a one train FID it would be one train with building out the infrastructure for the second train.

And then we would anticipate making a second train decision once we have got a little bit more clarity on the marketing of the volumes for the second train.

Okay, so there is no update in terms of the marketing status of that?

No, we don't -- no, we don't really have anything that we are in a position to talk about at this time.

But you are intending to sell presumably some of the upstream assets to the buyers who are coming on the second train, I believe?

Yes, there is a potential that that would occur, but I think we would not anticipate that we would be selling the level of interest that we sold to Sinopec as part of marketing the first train.

Generally, the buyers that we are having discussions with on the second train, if they desire equity, they will desire equity in the same levels that Sinopec was after.

Okay.

Second question is, is it possible to give some qualification of the benefit you got in the Mid-Continent in this quarter in terms of the WTI discount, say, compared to the first quarter?

I don't think we will give precise numbers on there.

It is a strong quarter for the downstream operations in the second quarter.

The strong areas were the Mid-Continent, though also there was a fair strength in the Gulf Coast, and the West Coast had fairly respectable margins as well.

The East Coast refineries continue to struggle with margins, but we don't have a breakdown between regions that we are ready to share.

Okay, and last one.

Your full-year outlook in terms of production, does that include a kind of embedded assumption on disposals or is that just how you see the business as it is today?

Well, that kind of sees -- how we see the business as it is today.

We still think that we will be making additional disposals in 2011 or announcing additional ones in 2011 that will close in 2012.

I think those are likely to be weighted later in the year to where they are not going to have significant impacts on production for 2011.

So just to be clear, that is an absolute number that Libya -- obviously, we have taken Libya volumes out.

And we have taken the impact of asset sales so far this year, which is a relatively small amount, maybe 5 a day or less, out of that number.

Okay.

And, finally, just one question on Libya.

Have you had any discussions with the potential new -- obviously, you haven't got a new government there, but the rebels as they are called at the moment or independent people, about any of your assets which they may control now?

We are not in any position to have discussions with any group like that.

All right, well, thanks very much, guys.

Paul Cheng, Barclays Capital.

Several quick questions.

In Qatar what is the net to the Company in oils and in liquids and gas in the second quarter?

I don't think we have disclosed either the volume or the price on LNG specifically to Qatar.

I presume it is already in full production, right?

It is.

Clayton, for your full-year guidance in production, what is the assumption you used in terms of the Bohai Bay shut-in?

Well, as Jeff said, we are down 17,000 barrels a day.

I think production prior to the shut-in of that production was around 60.

I am not sure what we have premised as far as when those volumes come back on.

But --.

That is part of the range that we are giving on that number.

We are having conversations now with the authorities in China about -- well, the incident overall, and the timing of the restart of production.

Jeff, can you tell me what is the range you assume in that guidance for Bohai Bay?

No, we are not --.

0 to 17.

Yes, well.

(laughter).

All right.

Form 10, when are you guys going to file?

On the spin-out?

Yes.

We are working through details of the schedule right now.

We would like to get in a position to where we file the IRS ruling request in the fourth quarter of this year.

But the Form 10 should be before that, right?

Well, yes, it will be different -- it will be around the same time frame and there will be iterations on the Form 10.

Right, so we should not expect that sometime say in the third quarter.

It would be a fourth-quarter event?

I think that is probably right.

Jeff, does any of your joint venture partners, when you guys originally signed the agreement, that gives them the right, such as Chevron or Cenovus, if there is a change in control they will have the right to acquire your interest or that force it on you?

Is there any agreement of that form or they don't really have the right or that the spin-off does not constitute as a change of control?

There are rights -- without getting into any of the details, each of our partners have various rights that we need to work through as we decide which entity each of the joint ventures goes into.

We are not really free to discuss exactly what those rights are, but those discussions have started with each of our partners.

So you think that some of them do have rights that could acquire or [make the] right of acquiring your interest?

Well, they are more along the lines of rights of first refusal, but that (multiple speakers).

Is a spin-off considered as a change of ownership or change of control?

Not -- well, in what context?

I think we would have to say that in terms of the documents that govern each of the joint ventures there is different definitions of how an event -- different ways of how an event like this would be treated that don't really fall into a change in control type categorization.

So I don't think we can really answer that question as, yes/no.

The agreements are more complex than that.

Two final questions.

One, Kashagan is that one of the assets, the Company -- being considered for divestment, given that some of your partners look like they have signaled that they may be selling their share already, given the [chop of that] in that project?

I think -- Kashagan have to move to -- to go back to the same kind of answer that we have given on asset sales before, is that as we move through asset sales program there are certain assets where we are working on and having discussions about where it is probably not appropriate to give a lot of -- it doesn't help us commercially to give a lot of the details about that.

So we don't really want to get into saying it is this particular asset or that particular asset that we are working on at this time.

Okay, that's fair.

A final one, Jeff, I know the guys have indicated you're going to continue the share buyback program, at least through this year, and about $1 billion a month.

I am just curious that the thinking behind when given that by next year you're going to have two separate company, two new management leadership, who are going to be the CEO not going to be from the existing senior management team in some way.

So what is the thinking behind that to take into consideration whether that the Company should stop their share buyback and offer sales to give perhaps the maximum financial and operating flexibility to the new team?

You yourself say that if we are going to continue in this way, by the time we come to the end of the year or early next year the bulk of your cash on hand is probably going to use up 25%, that the capital ratio is not high.

But on the other hand, that is not extremely low that provide them a lot of flexibility either.

So I am wondering how the consideration was thinking -- or that the thinking in the existing management team or the board?

So if you look at where we started the year, we started the year with around $10 billion in cash.

We are generating strong cash from operations this year, which is going to really more than fund the capital and the dividend program.

So absent share repurchase, we would be adding to that cash balance.

At the same time we are continuing to -- with an asset sales program that we think is going to add proceeds in 2011 and 2012.

You raise a good question.

So when we look at this though and we think about the amount of financial flexibility that we have based on cash we started with, cash from operations that we are generating, continued asset sales program, we think that we can execute the share repurchase program we have talked about for 2011, and still have the levels of cash, the levels of -- end up with levels of debt in these entities that will provide us quite a bit of financial flexibility.

So we are still quite comfortable that we are not doing something that would diminish the ability of either of these companies to really have all the financial flexibility they need going forward by repurchasing shares in 2011.

Okay, thank you.

Doug Leggate, Bank of America Merrill Lynch.

I've got a couple of quick ones, or actually a few quick ones, if I can run through them.

Just a point of clarification on the production guidance, please, Jeff.

What is the expected scale of production that will be sold in the remaining $5 billion to $10 billion program?

And just to be clear, I assume the guidance, as you pointed out, that any sales would likely not affect 2011.

I just want to be clear that is indeed the case.

So I think the guidance we have given on production impact from the $5 billion to $10 billion asset sale program is 50 to 100.

Yes, the same barrels a day.

We haven't really come off that number.

That is still to go, Clayton, or has any of that been done already?

Well, I think the first half of the year maybe 5 a day.

Yes, I think you can essentially say, Doug, that it is still to go.

Got it.

And China, the 17,000 barrels a day, have you knocked that out of your guidance for the second half of the year as well?

So the guidance is net of that 17,000 or do you assume it comes back again?

No, we assume that we will be returning those fields to production.

The B and C platform at Bohai will return to production.

The question is just what the timing of that will be.

But it is in the guidance for the second half -- it is included or it is excluded?

Well, it is part of the variability that we see and potential outcomes for the second half.

From the standpoint that we didn't have that production in July, we included that impact.

But you're looking at a 25,000 barrel a day variance, and it is awfully tough to get -- that is a pretty small number on a 1.65 million a day.

Yes, I understand.

We are just not really -- we can't be a lot more accurate than that in estimating production.

Got it, thanks.

I understand that there is a lot of confidentiality around Qatar, so I am not optimistic on this one question, but let me give it a go.

That's good.

That's a good way to start the question.

Well, my understanding is that some of the other very large LNG projects have multiyear tax breaks.

Does that also apply to you guys?

Yes, I think that falls in the category of commercial terms that we can't disclose.

Okay, I figured that may be the answer.

I will just try another couple of quick ones and then I will let someone else have a go.

I guess the last operating question is really the liquids-rich plays, Eagle Ford, Bakken, can you just give us an update as to how your acreage position is evolving there?

It looks as if you're -- I am guessing you're continuing to add and bolt-on as you move towards those higher-margin barrels.

So an update there.

And then my last one is strategic, but I will let you answer that and then I will throw the strategic one.

(multiple speakers) no, I think we have very substantial positions in those plays already that we acquired quite a while ago.

The acreage that we have added that we talked about, the 340,000 acres that we have had have been in developing plays and not in the Eagle Ford, Bakken and Barnett.

I think we see what -- we see a lot of running room with the acreage we have already, multiyear development in Eagle Ford.

We talked about looking at the Bakken and Barnett and increasing activity there based on our existing acreage.

We find that acreage is going at a very handsome price right now in those areas.

So we are looking to add acreage other places, and more perspective, not as developed plays, and concentrating on building out and exploiting the acreage which we have previously acquired in the Eagle Ford and the Bakken and the Barnett.

Okay, thanks.

The last one for me is really -- it is maybe actually one for Jim rather than yourself, Jeff.

But in the context of going back through the last year and the very successful asset program -- or sales program, I should say, you started off with Syncrude.

And one of the glaring, I guess, disconnects that you can see in the market is the value given Cenovus versus, let's say, your assets that you share with Cenovus.

And then, of course, there is no now the chance that ya'll is going to get split in two I am guessing.

I am just curious as to why -- when Jim's comment on the separation call, he said, it doesn't really matter to him if production is 1.6, 1.5, 1.4 in terms of getting value recognition.

At least that was my recollection.

Why in light of what management has done to date trying to get value recognition, with restructuring your interest in the Cenovus equivalent assets and maybe trying to achieve that kind evaluation, why is that not an option, or is an option?

And I will leave it there.

Thanks.

I am not sure if I understood what you are suggesting we might do with our Cenovus -- with our assets in the partnership with Cenovus.

Just generally, this all kinds of gets to the whole transparency questions, and one of the things that we think will be beneficial as we go forward when we have -- and even calls such as this one, the subject is focused on one area and we will be, I think, providing more information and more focus on either just the upstream or just the downstream assets.

And we think that increased transparency will cause a better understanding of what our asset base is going to be.

I guess the issue, Jeff, is you released an awful lot of value from Syncrude that wasn't arguably being reflected in the stock.

If you look at the fully integrated oilsands project, in other words, the Christina Lake and so on, all the way down to Wood River, it is essentially the same thing, and you're not getting the value for that.

So why would you make the decision on Syncrude, but you wouldn't look to maybe separate out what has clearly been going given a very hefty market value in the case of Cenovus for almost exactly the same assets.

I guess that is (multiple speakers).

Well, I think maybe the answer there is really more about Syncrude than it is about FCCL.

If you think back --.

They're really not the same types of assets, given our ownership and the running room that we had in Syncrude versus FCCL.

(multiple speakers) really differently that way too.

Just to kind of expand on (inaudible).

What we have in Syncrude was a 9% interest in a very large -- very, very solid strong asset, for which there was a very good market for, and for which we could do the sale in a way that was tax efficient for us.

So all those things lead us to say, well, we can get more value, obviously for Syncrude by marketing that asset than it was worth to us keeping it just from a net present value perspective.

Really on all of our asset sales transactions our guiding principle is we are driven by what is the net present value of the cash flows that we anticipate we are going to get out of these projects versus the value -- the after-tax value of our sales proceeds?

It is not really doing asset sales -- we are doing asset sales because we think we can get more value as we look at it just from a cash flow perspective through selling the asset than we can by retaining the asset.

It is not really because we are trying to say, well, this asset or that asset is or is not contributing to our overall market valuation.

Got it.

I appreciate your answering the question, Jeff.

Thanks, guys.

Philip Weiss, Argus Research.

The first question I have for you, in the past you have talked about having an interest in acquiring acreage should it become available in the Gulf.

I am wondering if there is any changes to that in light of your comments about allocating more money to the Eagle Ford?

No, I don't think so.

We still have an interest in acquiring acreage in the Gulf.

And in particular we have interest in acquiring exploration acreage.

We tried to build out what our investment portfolio is going to be longer-term.

So the expenditures that we talked about that are kind of higher expenditures in the Lower 48 are 2011, 2012, 2013 type investments.

When you're talking about adding things in the Gulf of Mexico, you're adding things that are more perhaps some near-term exploration expenditures, but really the larger expenditures are going to come later in the life, and that helps build out our portfolio in the 2015 and beyond timeframe.

So, yes, a good question.

No change in our interest level in Gulf of Mexico assets.

Then the next question I have, realizations, I know that with the relationship with we have among the various types of crudes right now that you realizations have been proved and that is helping the upstream results.

I was just wondering what kind of thoughts you might have as to how long it is going to last, if it going to get any wider, that kind of thing?

Well, I think we will continue to see that happen over time.

Are you talking specifically about the margin expansion that we are seeing or the improvement in margins that comes from greater liquids production versus gas or --?

No, I am talking more just about the difference between like Brent and WTI and Louisiana Light.

So more on the downstream side then?

No, here I am just thinking -- when I look at your realizations relative to where prices came in for the second quarter, they have gone up.

And so I'm just trying to figure out how long that may -- what your view is on how long that spread may last.

I know there is a downstream benefit as well, but I am thinking in terms of what you're selling your oil for.

I don't know that I have really thought about the question in that way.

So, realizations, they have improved in some areas, I guess, in part because our costs in those areas or our liftings in those areas may be different in the second quarter and first quarter.

But why don't we take that one off-line and come back to you?

Okay, that's fine.

Then just one quick one.

I just want to confirm, the debt paydown that you mentioned, that is just maturing debt, it is not any other (multiple speakers)?

That is right.

That is just a maturity that we have in the fourth quarter.

Okay, thanks.

Blake Fernandez, Howard Weill.

Congratulations on the strong results this quarter.

A question on the new acreage that you have added, the 340,000 acres.

I know you said it was developing plays.

For one, I was going to see if you could elaborate a little more on any specific areas on that?

And then in conjunction with that, you mentioned the new Canadian shale play.

I am hoping maybe to get some color on whether that is oil or gas or when you may start drilling there?

So just generally maybe just some broad characterization on the acreage areas that we've added.

It is maybe two-thirds in Canada and one-third the Lower 48.

We find ourselves in a position now where we really don't really want to say a lot more than that, because we still continue to acquire acreage.

And it is a competitive world out there, and we don't really want to give a lot of color on exactly where we are acquiring acreage.

Obviously, we are looking for liquids rich, right, so the shales.

Unconventional that we are going after is going to be more from a liquids perspective than a gas perspective.

Okay.

And on Canada, if you don't mind.

Okay, so again, liquids there and any idea on when you may start testing?

Well, I don't know -- I guess I don't know what the exploration program is around this acreage.

I can't imagine us doing anything this year.

I think the exploration program in 2011 is probably set, so I'm going to guess and say it is going to be a 2012 program.

Okay, fair enough.

Jeff, do you know any more (multiple speakers)?

No, I think it is something will fall in the category as we talk about plans for these -- in more detail for these companies going forward.

That will be -- and we talk about our exploration program going forward, that will (multiple speakers).

But you know it is (multiple speakers).

Put more color on that.

It is consistent with this idea of exploiting some of the existing acreage that we have onshore and adding to our unconventional base in North America.

Last one for you, Clayton.

I know we have talked in the past about your Permian and Bakken and Eagle Ford.

I think the original expectation was to add more capital to Eagle Ford.

Due to some constraints, takeaway capacity, cost, et cetera up in the Bakken, or it may be even Permian, has that landscape changed at all?

I know, obviously, you have mentioned some issues with Eagle Ford, but if you could just give us the lay of the land on how these three look.

So Eagle Ford, the results are all in-line with our expectations -- encouraging in terms of liquid content, in terms of well productivity.

We are managing through the infrastructure questions there.

As I mentioned, we are increasing rig counts in Eagle Ford going from 13 in the second quarter, where we think we will be up to 16.

So we are continuing to expand the pace of that development.

I think capital spend is estimated still at Eagle Ford around the $1.3 billion to $1.5 billion a year in 2011.

Okay.

And the reference that Jeff made earlier about Bakken and Barnett, what did you say, incrementally $0.5 billion?

Right.

Would be into those areas rather than into Eagle Ford.

I guess, I am fishing.

Is that an indication --

And Permian would be part of that as well.

But is that an indication that constraints -- some of the constraints you were initially seeing are beginning to alleviate a bit or --?

That level of spending is consistent with what we think we can have prompt offtake for.

Okay, fair enough.

Thanks a lot, guys.

Thank you.

This concludes our question-and-answer session.

I will now turn the conference back to Mr.

Reasor for closing remarks.

Thanks, Kim, and thanks everybody for participation in the call.

We think we are doing a lot of good things at ConocoPhillips, and look forward to the next time we are able to talk with you.

Have a great day.

Thank you, ladies and gentlemen, this concludes today's conference.

Thank you for participating.

You may now disconnect.

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