康菲 (COP) 2008 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the ConocoPhillips second-quarter 2008 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)

I will now turn the presentation over to Mr.

Gary Russell, General Manager of Investor Relations.

Please proceed, sir.

Thank you, Jen, and welcome to all who have joined us on the earnings conference call for ConocoPhillips for the second quarter of 2008.

I have with me today Jim Mulva, our Chairman and CEO, and John Carrig, our Executive Vice President, Finance, and CFO.

Jim will be taking us through a slide presentation that has been prepared to help you understand the financial and operating performance of the Company during the second quarter of this year.

This presentation, along with other supplemental information can be found on our website, www.conocophillips.com.

If you turn to page 2 now, you'll see our Safe Harbor statement.

This statement simply says that there will be forward-looking statements made during our presentation today and the conference call, and these forward-looking statements represent our management's current expectations.

Actual results may differ materially from these expectations.

If you'll take a look at our SEC filings you will find information on items that could cause these material differences.

So at this point, I will turn the call over to Jim Mulva.

Gary, thank you, and appreciate all those who are participating in our conference call.

I'm going to start off on page 3.

You see in the second quarter our income was $5.4 billion.

That is $3.50 a share.

We generated $5.4 billion in cash from operations.

Our debt-to-cap ratio is 19%; it's the same as it was at the end of the first quarter.

In our upstream business we produced 2.2 million BOE a day.

That includes an estimated 448,000 BOE a day from our LUKOIL Investment segment.

On the downstream, crude processing capacity utilization was 93%.

That's up from the 89% in the first quarter.

As we have told the market, we purchased $2.5 billion of our stock in the second quarter, $2.5 billion of our stock, second quarter, reducing average shares outstanding to 1.555 billion shares.

That is 103 million shares lower than the second-quarter 2007 average.

The share repurchase program has had a favorable impact on our per-share metrics, and you can see that on the next slide, slide 4.

You've seen this slide from last quarter.

On the left-hand side you can see the 103 million share reduction I just referred to.

On the right side of the chart you can see second-quarter 2008 earnings per share were $0.60 higher than the same quarter last year.

Now, that is after adjusting for the Venezuelan impairment of last year; and $0.22 of that improvement is directly attributable to our share repurchases.

We will update you on our future share repurchase plans for 2009.

We do that most likely in December when we come out and announce our capital spending program for 2009.

So you can expect us to be doing between $2 billion and $3 billion of share repurchase in the third quarter and the fourth quarter.

Going now to page 5, second-quarter net income was $5.4 billion.

This is $1.3 billion higher than the previous quarter of $4.1 billion shown on the left-hand side of the slide.

As you move from the left to the right you can see the contribution from our asset rationalization program.

The first quarter was higher than the second quarter by $114 million.

Prices, margin, other impacts improved second quarter by $2.1 billion; that is the green bar.

Lower net sales volumes in our LUKOIL and E&P segments, partially offset by higher volumes in our downstream and midstream segments, reduced income $97 million.

As a result of the current price environment, production taxes in the second quarter were $264 million higher than the last quarter, and most of this relates to Alaska.

Operating costs were about $276 million higher than the previous quarter; and we will go into more detail on that in subsequent slides.

There were other items that in the aggregate reduced income $85 million in the second quarter.

Most significant of that was the LUKOIL true-up which was outlined in our interim release earlier this month.

Moving to page 6, total Company cash flow, we start with the gold bar on the left.

You can see we generated $5.4 billion cash from our operations in the second quarter.

You combine that with our beginning cash balance, so we had $6.9 billion of cash available for the second quarter.

As you move from left to right you see we also had additional cash from asset sales of $362 million.

We used the cash to fund $3.6 billion of capital programs, $719 million of dividends, and $2.5 billion in share repurchase.

Had a slight increase, $432 million, in our debt balance.

That has a lot to do with respect to the timing of substantial tax payments that we make in the US as well as in Norway.

Moving to page 7, total Company cash flow, pie chart on the left shows total cash available during the first half of the year of $13.6 billion.

88% or $12 billion comes from operations; the remaining 12% from asset sales and reduction in cash balances, a small increase in debt.

As we look on the right, what did we do with the $13.6 billion?

We spent $7.2 billion in our capital program.

We purchased $5 billion of our stock, and paid $1.4 billion in dividends.

Now we go to page 8, starting on the left-hand side of the slide.

We grew our equity to $94 billion.

Our debt balance shown in the middle is $21.9 billion.

You can see on the right our debt-to-capital ratio remains at 19%.

As I move to slide 9, talk about E&P quarter-to-quarter.

Realized prices for both crude oil and natural gas were higher in this quarter.

Our realized crude oil price was $118.01; that's $25.13 per barrel higher than the previous quarter.

Our realized natural gas price was $9.87 per MCF: that is $1.84 per MCF higher than the first quarter.

As we indicated in our interim, E&P's production volumes were lower than the previous quarter.

We will talk more about this in another slide.

We had higher production taxes mainly in Alaska, and that had a negative impact on earnings.

So I go to page 10, we talk about our production, sequentially quarter-to-quarter.

Production in the second quarter from our E&P segment -- now that excludes LUKOIL -- was 1.75 million BOE a day.

That is 44,000 BOE a day lower than the first quarter, which was 1.79 million BOE a day.

That is shown on the left-hand side of the slide.

So we move across from left to right, you can see that production was lower in Norway, Canada, United Kingdom, and Alaska.

All of that totaled 61,000 BOE a day.

The vast majority of this reduction is due to planned maintenance and seasonality.

Production in the lower 48 was 17,000 BOE a day higher, as we had reduced production due to planned maintenance in the second quarter.

That was more than offset by the impact of restoring the production in the San Juan Basin that had quite a negative impact on us in the first quarter.

That related to the non-operated natural gas processing plant in the San Juan Basin.

Then you add our equity share of LUKOIL production, and that takes you up to 2.2 million BOE a day, shown on the right-hand side of the slide.

Moving to page 11, E&P net income for the second quarter was $4 billion.

That compares to $2.9 billion in the first quarter.

Start with the green bar on the left, prices and other market impacts improved income $1.5 billion.

As you move to the right, you can see that sales volumes negatively impacted income $47 million in the second quarter.

Now this includes an adverse impact from inventory changes that does reflect the regional mix and the divergence of effective tax rates.

Rather complicated, but all-in it's $47 million.

Mentioned earlier, production taxes were $264 million higher in the second quarter, primary in Alaska.

Operating costs were higher, primarily due to increased planned maintenance.

We had also higher lifting cost, and this reduced our income $107 million compared to the first quarter.

There are some other items; in the aggregate improved income $32 million.

That is how you get to the $4 billion.

Moving to page 12, downstream.

Our realized worldwide refining margins were higher than the first quarter.

Our US margins were $10.29 a barrel; and that is $2.29 a barrel higher.

Then the international margins were $6.70 a barrel; and that is higher by $0.28 a barrel in the second quarter compared to the first.

As we outlined in our interim update earlier this month, we did not fully realize the improvement in refining margin in the second quarter.

This is due to the significant negative impact from secondary products such as fuel oil, natural gas liquids, and petroleum coke.

These secondary products represent about 20% of overall refined product production in the second quarter.

Our global capacity utilization was 93%; that's up 4% from the 89% in the first quarter.

In the US, utilization was 94%; that's 4% higher than the first quarter as our Gulf Coast refineries ran much better.

International utilization was 88%.

It's down -- well, it's 2% higher than our first quarter, but we really move our -- our hydro-skimming margins have quite an impact with the Wilhelmshaven refinery, so when we have pretty good hydro-skimming margins we run it; and when we don't, we shut it back in terms of production, and this impacts the international utilization rate.

If we look now to page 13, you can see downstream second-quarter income was $664 million; $144 million higher than the first-quarter income of $520 million shown on the left-hand side of this slide.

As we move from left to right, you can see the contribution from asset rationalization was $114 million lower in the second quarter than the first.

Prices, margin, and other market impacts increased income in the second quarter by $249 million.

It's primarily driven by higher realized margins, partially offset by the impact of foreign exchange and higher utility prices.

Overall, our downstream -- we improved our volumes, which is a result of the higher US utilization; and that improved income $84 million.

We had higher operating costs, mainly due to turnaround activity in the second quarter; and that reduced income $102 million.

Then there were other items; in the aggregate, improved income $27 million.

The most -- the largest of that $27 million was higher equity earnings from affiliates.

So now I go to slide 14, all the other segments we cover in this slide.

Our estimate of second-quarter equity earnings from LUKOIL is $774 million.

It's higher than the $710 million in the first quarter, primarily due to higher realized prices for crude and refined products, partially offset by the true-up that we previously reported.

Now the downstream income was $162 million, compared to $137 million in the first quarter, mainly due to higher realized NGL prices.

Our chemicals joint venture, the income was $18 million.

That is lower than the previous quarter; in the first quarter it was $52 million.

This is mainly due to lower benzene and polyethylene margins, which were negatively impacted by the higher feedstock cost.

Further, in the chemical business we had utility and turnaround costs were higher in the second quarter.

Emerging Businesses contributed $8 million in the second quarter compared to $12 million in the first.

This reflects lower US spark spreads, and then we also had some planned maintenance.

Our corporate costs were $186 million.

That is $7 million higher than the first quarter, primarily as a result of lower interest income on cash balances.

Let's move to slide 15.

We look at the E&P metrics, you can see the chart shows our E&P income and cash per BOE.

Go back to the year 2003 and then through the first two quarters of 2008.

While we don't have the period data obviously for the second quarter for the peer group, we would expect the effect of purchase accounting to continue to impact our earnings per BOE when compared to our peers.

But when you look at our cash contribution per BOE, we continue to be very competitive and we expect to be in the second quarter.

Go to the next slide, page 16, which is the downstream.

You can see both on an income per barrel and a cash contribution per barrel, we continue to be competitive and expect to be in the second quarter.

Then I go to page 17, which is our return on capital employed.

By the way, the shaded area on the peer group there is made up of the largest integrated publicly traded companies; that is Exxon Mobil, BP, Shell, Chevron, and Total.

This bar chart reflects the Company's return on capital employed with no adjustment for purchase accounting; but we do make adjustments with peer group to reflect purchase accounting for them for their transactions that they've done in prior years.

That is shown in Table 3 which is attached to the presentation.

Our annualized return on capital employed for the second quarter of 2008 was 20%.

That's 6% higher than the year of 2007; 5% higher than the first-quarter 2008.

Now I go to the last slide, 18, the outlook.

As you know, we recently signed the interim agreement with Abu Dhabi National Oil Company, ADNOC, to develop the Shah gas field in Abu Dhabi.

Elsewhere in the Mideast, we approved the continued funding, moving forward on the development of the Yanbu Export Refinery Project with Saudi Aramco.

We are pleased to be working with both ADNOC and Saudi Aramco on these world-class projects that helps meet the growing demand for energy not only in the Middle East but also around the world.

We recently signed an MOU with Petrobras, as you know, the largest Brazilian energy company.

With this agreement we hope to sort through opportunities to work together in our core businesses, upstream and downstream, as well as energy opportunities such as ethanol in Brazil.

In North America, our joint venture with TransCanada, we plan to expand the Keystone crude oil pipeline system, providing additional capacity of 500,000 barrels per day from Western Canada to the US Gulf Coast.

Then we look ahead in the third quarter, we expect our E&P segment production will be similar to the second quarter.

We expect full-year 2008 production will be consistent with our operating plan, which we announced the beginning of the year.

That is 1.8 million BOE a day excluding the LUKOIL segment.

We expect exploration expenses to be about $375 million in the third quarter.

In our downstream refining business, we expect continued negative impacts on market capture due to the secondary product margins that I covered when going through the downstream part of the Company.

We anticipate our worldwide crude oil capacity utilization would be similar to the second quarter, reflecting continued lower utilization at our Wilhelmshaven refinery due to the weak hydro-skimming margins.

Turnaround costs in the downstream are expected to be $100 million before tax in the third quarter, and then we expect our share repurchases in the third quarter to be between $2 billion and $3 billion, which supports our objective of doing $10 billion in share repurchases for 2008.

So that completes going through the prepared comments, and so we are ready to take whatever questions that those participating on our call may have of us.

Okay.

Jen, could we go ahead and line up our questions, please?

(Operator Instructions) Michael LaMotte, JPMorgan.

Jim, I was hoping you could elaborate a little bit on the memorandum of understanding with Petrobras, how that came to pass, and sort of ultimately where you think it could go.

Well, obviously, we are quite pleased with starting to work with Petrobras.

We have worked a little bit with them in the past.

But we very much respect what they've done around the world and certainly in Brazil.

We are merely looking at the opportunities of how we can participate in exploration and production, both in Brazil as well as outside Brazil.

Then we also, with our large refining segment in North America, we kind of explore with ultimately their having more crude oil production, where there is opportunities for us to be working with each other in the downstream part of the Company -- for both companies.

And then we also are looking at -- we need a lot of ethanol, ultimately, to blend into our gasoline.

So we look at the opportunities of being such a large ethanol producer in Brazil and how Petrobras participates in that, whether there's opportunities for us to be working with each other.

So to go any further than that, we are really in the initial phases of this study work of the MOU.

But we are really pleased to be working with Petrobras.

I know it's early days, but is it possible that the relationship would even involve JV-ing on hard assets?

Or do you think at this point it will be left to project-specific?

We really don't know.

I mean, we are going to explore all the different opportunities.

But it's just too early to come out; and furthermore, this is always a sensitive area, so we will just have to wait and see how this develops with time.

Okay, and if I can ask you to sort of -- I know you have good access and contacts in DC.

If I could ask you to -- on two issues kicking around Washington now, the windfall profits on the super majors and also the OCS, if you have any comments on those.

Well, first of all, we know that public opinion has really been moving here in just the last few months.

Certainly understanding the challenge and issues with respect to energy and the high cost of oil and gas.

So to the extent that Washington and the states are looking at opening up more acreage, we think that is something that the industry has always been looking for.

We know there's a lot of resources that are indigenous to the United States that we can develop without any compromise to the environment.

So that is very, very encouraging, so hopefully we are going to see continued movement on that.

With respect to windfall profits tax, we know that with the high prices and all and the financial performance of the companies, that is an easy one to talk about.

But on the other hand, the companies are reinvesting their income back into development of energy, and that is upstream and downstream.

You know, we really need this cash to reinvest, to fund our opportunities.

Everything that we do, it costs a lot more than the barrels that we produced in the past.

So we really don't think windfall profits tax is warranted given the huge cost, capital cost, operating costs that we have to continue to replace what we produce.

Furthermore, as a company, or as an industry, we know that windfall profits tax in the past has been tried and it really hasn't worked.

It's actually led to less supply and actually higher impact on costs of energy.

So it's really important for us to get that message out and continue to do that.

We just don't think it's warranted, but we understand that it is talked about.

Do you sense that the swing in public opinion towards more drilling, etc., sort of zaps the momentum for windfall profits?

No, it's difficult to say on that.

They are really in some ways two different issues.

But it is encouraging.

I think the American public -- this is such an important issue to them and we recognize the hardship it has, the cost of energy, on everyone, particularly those with less income.

So to the extent that we can be adding supply and moderating the impact on energy and price of energy is something we really need to do.

The American public -- I think the media is becoming more balanced in all of this.

The American public understands this.

Although it is such a challenge and it's difficult, we need to add supply.

I think that is what is happening with public opinion.

That's great.

Thanks, Jim.

Paul Cheng with Lehman Brothers.

Jim, on the sour gas project, any kind of preliminary production schedule or development plan you can share?

And what kind of reserve booking that we may be looking at in 2008?

Well, I think it's premature to be getting into production levels or anything on the Shah project.

Obviously we've been working this pretty closely with ADNOC for quite some period of time.

We're very pleased that we've come forth with our agreement.

We have dedicated teams from both ADNOC and ourselves.

We are working well together.

It's a challenging project.

We've taken quite an innovative approach toward how to do this one with ADNOC.

I know there is quite a number of issues with respect to value creation from the gas production, value creation from the liquids.

As I said it's pretty innovatively put together.

It's just premature for us to get into reserve bookings or expected production levels.

I think that will come probably more likely when we meet with the analysts in the early part of next year.

But I will say that using reasonable expectations on values of cost and values for oil and natural gas prices and whatever, we see that in no way have we compromised -- in going forward with the Shah project have we compromised our hurdle rates of what we expect for returns on investment.

Sure.

Jim, I know you said early days, should we assume that you will be able to book some reserves this year?

Also do you have a percent, what is the H2S gas (multiple speakers)?

No, I don't think that you can expect us to be looking at booking reserves in 2008.

I think it is in subsequent years that we will be doing that.

Do you have a rough idea -- you say 30% H2S gas, or that is less?

Well, why don't we come back to you on that?

But it has -- it's pretty sour gas, and that is why it is challenging.

We've got to really make sure we do our technical work and all in a way that this is done that in no way -- and I know ADNOC feels very strongly about this -- in no way do we compromise environmental or safety performance.

Okay.

I think that the next two questions, one is BP and Shell recently moved into the tight gas in North America through acquisition.

Wondering, Jim, when you're looking at your portfolio, what is your appetite on those nonconventional gas plays in the US?

You already have some in your portfolio.

Any appetite to substantially increase it, taking the path that the other two guys did?

Well, we've got a nice portfolio of both conventional and nonconventional.

What we need to do is really exploit it, which we certainly intend to do over the next number of years.

As we said in all of our conference calls and presentations, we spread this out in a way so that we make sure we do it well; we don't give up any opportunity of drilling the wells ultimately.

It's been a question of how fast we go.

But we've got a really great portfolio of conventional, unconventional.

When we look at getting more aggressive, it's exploitation, but it's also -- we do continue to pick up acreage.

So our approach really is picking up acreage.

So we quietly do that, and we're always looking for not only the existing areas but what we think will become the new areas, the new hot plays in the future.

So that is really our strategy and where it's directed.

So Jim, based on what you just said, I suppose that we should not assume you're going to make any multi-billion-dollar acquisition there, trying to drastically expand.

You are just going to be more evolution, kind of gradually adding?

Your assessment is correct.

Making large acquisitions of assets is -- we've done that in the past, but we just don't think the environment is right to do that in creating value for our shareholders.

So we are really doing -- our growth is really directed towards organic growth, as I just outlined.

Great, two final questions.

One, Alaskan gas pipeline, I think the Alaskan legislation just gave approval to one of your competitors' proposals.

Wondering if you can give us an update what exactly that means.

Does that mean that you guys go with that one, or that doesn't really mean anything to your current proposal?

Then the last question is for John.

Looking at the international R&M, not sure why that we have a 140% tax credit; and it's not in your special items.

So can you just give us some idea what is that?

Okay, first on the gas pipeline in Alaska, we know that the state of Alaska, the legislature is considering approving the AGIA process of the state working with TransCanada.

We'll have to see how that works out sorts out.

With respect to the Denali project that we are doing with BP, irrespective of what takes place with approval or not by the state legislature, we continue to go forward with BP on the Denali project, doing our field work this summer and moving right through a process of open season that we expect here in the next few years.

So it doesn't change at all the aggressiveness in the plan that we've announced with respect to Denali and our work between ConocoPhillips and BP.

Jim, on that, did Exxon indicate whether they're going to join you guys or not?

Well, I mean ultimately we would like to see everyone participating in the pipeline, all the producers.

Whether a pipeline company participates in that, all that remains to be seen.

I really shouldn't be speculating or indicating for another company like Exxon.

I think that is really appropriate for them to answer.

Now with respect -- as I said, ultimately, I think everyone needs to participate.

The question you had on the downstream for John, I will let John answer.

The negative international tax rate primarily is due to an outperformance by equity companies which don't record any tax on the equity earnings, because that is just by nature of the structure.

Then there were losses in some of the marketing and other businesses that we have internationally that produced a tax benefit in the consolidated accounts.

And that resulted in a negative tax rate.

So there is no tax adjustment or anything?

That is why you didn't break it out as a special item?

That's correct.

I see.

Very good, thank you.

Paul Sankey with Deutsche Bank.

It feels like a couple of the big ticket, if you like, guidance items are back in line here.

Obviously, you're absolutely in line on buyback; and we're looking at, I guess, levels of CapEx -- if you could confirm -- that are exactly in line with what you had guided.

The one area that you seem to be falling a bit short or at least based on what you're saying seems to be falling short is on volumes.

I guess the previous guidance was for a full year 1.8 million barrels a day ex-LUKOIL.

You've talked about flat in Q3.

I guess we can reasonably expect a bounceback in Q4.

But could you just talk a little bit about where we can expect volumes to pan out at the end of the year?

Thanks.

Okay, thanks.

On share repurchase, I did comment on and so the market can expect we're going to $10 billion of share repurchase in 2008.

It's been going at a rate of $2.5 billion a quarter.

Capital spending is going to be around $15 billion, maybe a little bit more, but $15 billion, $16 billion.

But what we said we were going to spend this year is about where we're going to be.

On volumes we said 1.8 million BOE a day ex-LUKOIL.

So we're a little bit below that.

You can expect with a flat second quarter, third quarter that the fourth quarter comes up.

And we still stand behind the 1.8 million BOE a day for 2008.

Great, that's good.

Good news.

The second thing I had, Jim, was on Saudi.

You said that you've agreed to spend more for continued funding for the development.

Could you just clarify, firstly, what that means in terms of capital commitment?

Secondly, could you give us a date around which you expect maybe we might see some volumes out of that project?

Thanks.

Well, it's a long project.

I think we can come back to it.

I will say I think it's about 2012 when we really get going, somewhere in there.

But we're in the process of actually going into the marketplace with bids for the large units of that refinery.

We expect to have a lot of interest, and hopefully it will be within our ballpark guidelines of what we think the bid should be.

Then assuming that is all in place, then we announce and we go forward with the project.

So that is where we are.

We are working really well with Saudi Aramco.

It is a challenging project, but it has -- once it's done and built it creates a lot of value for both Saudi Aramco and ourself.

So that is where we are right now in the marketplace with our bid packages.

We don't see big surprises, any real big negative surprises; and it fits the guidelines and we are going forward announcing.

That's great.

On the date, Jim, any hints you can give us about what kind of price you are looking at for that refinery of that scale?

We'll tell you once we've confirmed the bids.

So that is probably going to be something that we talk to the marketplace in the first quarter of next year.

Brilliant.

Thanks very much, indeed.

Neil McMahon with Sanford Bernstein.

This is actually Katy Raven on behalf of Neil McMahon at Sanford Bernstein.

We just wanted to ask you what your latest views on Arctic exploration were and what your drilling plans were there in the next year or so.

Okay, is this related to the Arctic?

Yes.

I think you are probably -- most of your question is really related to the Chukchi sale; is that correct?

Yes, yes.

Well, we are quite pleased that we won the acreage.

We are working through -- it's a tough area that we have to do a lot of planning.

But we know we've got 10 years, I believe, on these licenses, and so we have to get going pretty quickly.

I don't have right at hand -- I don't think you are going to see drilling any time real soon, because we've got to do a lot of planning and get a lot of permits and approvals to do this.

But we are working the schedule pretty aggressively.

This is one that I am just going to have to get a little more time before we give you more substance in just how this is going to be done.

Yes, my guess would be you are going to hear a lot more about it in the analyst meeting next year, but probably not a lot between now and then.

Okay, thank you.

Mark Gilman with Benchmark Company.

First question by way of clarification, these adverse inventory effects, Jim, I believe you referred to one in the upstream; the press release refers to one in the downstream.

Could you quantify these effects and explain a little bit more what gave rise to it?

I think the downstream one internationally was associated with an inventory build, but would still love some quantification.

Okay, John, maybe you can --

Well, the downstream inventory build, I don't have a precise number at hand; but it relates to just an inventory cost that resulted in an inventory charge in the second quarter.

With respect to the upstream, that is more of a mix issue, where it has to do with underlifts and overlifts quarter-to-quarter, and the mix of those between relatively high tax rate jurisdictions and less high tax rate jurisdictions.

And that mix resulted in an impact to the sales volume.

Mark, I would say further that when we look at the downstream inventory impacts, we would expect that to be a temporary impact because it was related to an inventory build in the second quarter; and we would expect that to be liquidated before the end of the year.

Gary, that is why I was asking for the quantification.

I expect it's temporary also.

Yes.

If I could try another one.

This is for one for John Carrig, a little bit off the wall.

Your first-quarter 10-Q indicated that you chose to defer the implementation of [SAF 57] fair value accounting with respect to business combinations.

John, can you tell me why you exercised your option to defer that?

Just to get more time.

We don't have any large business combinations that we are dealing with, so there is no sense of urgency to get that in place.

Wait a minute, doesn't that relate to BR in particular and others?

Not materially.

There is some residual impact that you might have, like some impacts related possibly to taxes.

But those were not the drivers in that decision.

Okay, one more if I could.

Are you yet incurring take-or-pay obligations with respect to your commitments on Freeport?

Can you give us an idea what that might be if you were unable to utilize the capacity which you contracted for?

Well, we will incur take-or-pay charges related to Freeport.

As you may recall, we signed up for a term to process LNG, and then we are also -- because we funded that, we're also -- we will receive some amount of that back.

So the net impact -- I don't have an annual number, that is something that we can work to try to provide, if not in the next quarter, certainly at our analyst meeting.

But it is something that is rolled in every month.

It is not something that is expected to be a one-time.

Right, that's right.

It's an executory obligation; and if we have the volumes, they will offset the transportation or the processing charge.

And if we don't, then we will have the typical take-or-pay arrangement where you have an expense in the month where you --

Don't use it.

Don't utilize the capacity.

Will it show up in US E&P?

Likely, yes.

Erik Mielke with Merrill Lynch.

A couple of quick questions for me.

Firstly on the proposed Keystone expansion, can you elaborate what exactly it would mean for Conoco?

Do you expect to have any volumes, either shipping volumes or at the receiving end?

And if we should anticipate any near-term impact on CapEx as well?

Well, on Keystone, the expansion -- yes, we expect to use it by taking Canadian crude all the way down to the Gulf Coast.

It gives us good optionality to be feeding our refineries in midcontinent and the Gulf Coast, both from Canada as well as from, say, Venezuela and other crudes that we can get from Mexico and other places around the world.

So we expect to do that.

In terms of capital spending, it has already been geared into our capital spending for this year and for subsequent years.

It is going to be an equity investment, but all of the cost and all of the capital will be just part of our capital program.

Okay, thanks.

Can I ask you about your joint venture with EnCana?

Were there any changes to that joint venture from the corporate changes at EnCana?

In the event that there were to be -- say there were to be a change of ultimate control of the EnCana part of the joint venture, would you have preemption rights?

Well, we don't see any change in our EnCana joint venture.

Obviously EnCana is splitting into two companies.

But the joint venture will be not in the pure gas company.

We are working to know the management well, and they were part of the formation, obviously, of the joint venture.

In terms of once it's completed, which is going to take some time, we don't have preemptive rights on things with respect to this joint venture.

Can I ask quickly on refining marks You mentioned there was an asset rationalization with a net cost of I think it was $140 million.

Are you able to elaborate exactly what that rationalization was?

Well, that rationalization related to the sequential difference.

So there was a gain in the first quarter that didn't show up in the second quarter, because we didn't have any material asset sales in the second quarter.

So that variance is reflected in that $114 million difference in the R&M chart.

Okay, thank you.

Jason Gammel with Macquarie.

Jim, you had made reference earlier to your strong positioning in nonconventional resource in North America.

I was hoping you might be able to expand a little bit about what your activity levels look like currently in the Bakken Shale and the Montaney Shale.

And then possibly even rank where you see the best prospectivity between those two plays, and maybe put the Piceance and Barnett into that as well.

Well, I think it's probably better we come back to you off-line on that.

Because really I don't have right at hand just what our position is in terms of today and what we expect to do.

So maybe Gary can do that.

In terms of how we rank them, what is more prospective than others, that is more of a competitive issue and I don't think we would like to share that with others.

But in terms of position and all, maybe Gary you can do that off-line.

Yes, I will get back with you, Jason.

Okay, great.

Then one more if I could.

A lot of the macro statistics are indicating sort of a 2.5%, 3% decline in US demand for refined products.

Would your own experience as a marketer tend to confirm those numbers?

Do you think they are too high, too low?

No, we are seeing demand down in all the markets, particularly on the West Coast.

So we have to configure our operations and all to make sure that we run the right -- have the right inventories.

You don't want to have too much; you certainly want to have the inventories you need to supply the marketplace.

But yet on the other hand, the way we operate, we continue to expect that we're going to operate our refineries -- with the exception of Wilhelmshaven because it's a relatively unsophisticated refinery -- in the mid 90% level.

All-in, probably the low 90s.

So yes, we've seen the demand falling off, more on the West Coast than the other pads.

Okay, then maybe if I could just ask one last question on a strategic level.

You have taken ownership in the pipeline infrastructure that would generally have attracted utility rates of return.

Can you really expand a little more on the optionality you see in ownership of assets like REX and Keystone?

I think you've already touched on Keystone a little bit.

Well, first of all, we can see in terms of the capital invested -- obviously there's some external financing in most of those, and so the return on capital investment is pretty good and acceptable.

But it doesn't take away necessarily our flexibility over time to do something else with it if we would like to.

We can always do that.

But when you make a commitment, an economic commitment, then why not -- why pay someone else to do some of the financing for it on the basis of your commitment to use the pipeline?

So we look at that and say unless we see something that is really attractive in terms of use of someone else's funds or financing, then we might as well do it ourself, but yet not give up the option or the flexibility to refinance it differently in the future.

Okay, that's very helpful.

Thank you.

Paul Cheng with Lehman Brothers.

Jim, can you give us a bit of an update about the EnCana joint venture?

How well is the production ramp up and also I think you are having some difficulty receiving the permit for the Wood River.

Any update on there?

Also where are we in the Surmont and also the YK production level?

Okay, a number of questions.

First, EnCana.

This joint venture, both upstream and downstream, is very integrated.

We work upstream and downstream well; separately as well.

It really has worked well from the top down through all the operating people.

It's a joint venture that has gone as well as any.

We are pleased with that.

In terms of the production, we had some issues on our production with some mechanical problems in the first quarter.

But yet we seem to be doing a lot better.

So for the year, we might be down 1,000 or 2,000 barrels a day net on this; but we seem to be doing much better than we did in the first quarter in terms of volumes coming from the EnCana joint venture.

The permit for Wood River, of course, we're working that pretty closely with EPA as well as the state of Illinois.

I think -- we would like to think; I'm always an optimist -- like to think we are going to get this sorted out here in the next few months.

We are working very aggressively on it.

We are working with all of the right people, so hopefully we will have some news on that sooner than you might think.

It is important for us to get sorted out.

We think we will get there.

On the YK field, we did start up production, and I think maybe John or Gary could tell you, but it has come on pretty smoothly.

We are really quite pleased at what is going on with respect to YK.

Hopefully we will see some different fiscal -- some of the impact of the Russian fiscal tax changes will have some beneficial impact on the return for that project.

But in terms of volumes, it is already starting to ramp up.

What is the current production, I'm sorry, in YK?

I don't have a precise number on the current production.

I know that we are -- it is early production and continues to ramp up in line with our expectations, but I don't have a -- (multiple speakers)

I will get back with you, Paul.

Okay, thank you.

It is just actually starting up with its first lifting, and so it changes from day to day as we sort this out.

But Gary, we will certainly have more info on our conference call next quarter.

How about Surmont?

Are we still looking at just 20,000 barrels per day at this point?

Where?

The Surmont Oil Sands Project in Canada.

Surmont?

Surmont.

Surmont is actually running really quite well.

Gary, maybe you have the numbers.

I don't have them in front of me for Surmont.

Well, we were looking at a gross about 100,000 barrels a day at peak.

So the ramp up is going really well.

We just started production earlier this year so you would not expect it to be at peak yet.

But it is certainly within 15,000 or 20,000 barrels a day net to us, I think is what we are looking at.

So I will get back with the actual numbers.

I think it's important to get the actual numbers on this.

I do know it is in line, slightly ahead -- in line to slightly ahead of expectations.

Thank you, gentlemen, I will now hand the call over to management for closing remarks.

Okay, thanks, Jen.

Again, we appreciate everybody that participated on the call today.

I would remind you that the presentation material that we went through today, along with the supplemental schedules, are available for your use and viewing on our website at www.conocophillips.com.

Thank you and have a good day.

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

This concludes the presentation and you may now disconnect.

Have a great day.

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