康菲 (COP) 2007 Q3 法說會逐字稿

Good day, ladies and gentlemen.

Thank you very much for your patience, and welcome to the third-quarter 2007 ConocoPhillips earnings conference call.

My name is Bill, and I will be your conference coordinator for today.

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

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

(OPERATOR INSTRUCTIONS) I would now like to turn the call over to your host for today's presentation, Mr.

Gary Russell, general manager, Investor Relations.

Please proceed, sir.

Thanks, Bill, and welcome to everybody to ConocoPhillips' third-quarter earnings conference call.

I'm joined by Jim Mulva, our chairman and chief executive officer, along with John Carrig, our executive vice president of finance and chief financial officer.

The presentation that will follow has been prepared to help us review the financial and operating performance of the company during the third quarter of this year.

You can find this presentation on our Web site, www.conocophillips.com.

If you will turn to page 2, it is our normal cautionary statement.

It indicates that in the presentation today, along with the responses to the questions that you have today, forward statements will be used based on what our current expectations are.

Actual results may differ materially from those expectations.

You can find a list of items that could cause material differences in our SEC filings.

I will turn the call now over to our Chairman and Chief Executive Officer Jim Mulva.

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

I'm on page 3.

In the third quarter of 2007, we had net income of $3.7 billion.

From operations during the quarter we generated $6 billion of cash.

We purchased $2.5 billion of our stock; we continued to fund the capital program, other investments.

Improved our debt ratio to 20 percent, which is 1 percent lower than the previous quarter.

During the quarter, we produced 2.19 million BOE a day.

That includes our estimate of 432,000 BOE a day from our LUKOIL investment segment.

I am going to talk more about this in subsequent slides.

Then in the downstream, our refineries ran at 94 percent of crude capacity; that is about 1 percent higher than the second quarter.

Now I am moving on to page 4.

Our third-quarter net income of $3.7 billion is quite a bit higher than the second-quarter net income of $301 million.

But you recall, in the second quarter we recorded an impairment of $4.5 billion due to the expropriation of our Venezuela assets.

You can see this impairment combined with the second-quarter impact of our asset rationalization program in the green bar on the left part of this slide.

Without these two items, our earnings in the second quarter were about $4.7 billion.

What I would like to do is take a few moments and review the other major variances as we go through this slide, before we get into going through in more detail the business segments.

If you start with the first red bar on the left, prices, margins, other market impacts reduced third-quarter net income about $1.4 billion compared to the previous quarter.

Included in that red bar we have a number of items, but I will just call to mention that in Refining and Marketing, $1.36 billion is part of that $1.419 billion; and LUKOIL is lower by $172 million.

So we had some smaller positives to offset those two, but those are the major negatives in that red bar.

Volumes accounted for a reduction in third-quarter net income of $24 million.

That is the effect of lower volumes from our E&P segment, more than offset higher volumes in Refining, Marketing, Midstream and higher estimated volumes in the LUKOIL side of the business.

We also had a $265 million improvement in third-quarter net income from asset rationalizations.

Then there are other items that increased our third-quarter net income $125 million.

I'm going to talk about that more in subsequent slides.

So as a result our third-quarter net income was about $3.7 billion or $2.23 a share.

Before I go on to the next slide, I would like to go through that $2.23 a share a little bit more, because we have a number of items, positive and negative, that are included in that number.

First, let me go through some of the positive ones.

We had the impact of our asset disposition program.

That was $265 million, and that is $0.16 a share.

Then we had the German tax legislation; that was $141 million or $0.09 a share.

We had the Alaska crude oil quality differential adjustment; that is a positive $80 million or $0.05 a share.

Then we had a negative $11 million related to acquisitions expenses; that is a negative $0.01.

So all of the items I just mentioned was a positive $0.28 included in the $2.23.

Now let me go through some of the offsetting numbers that actually amount to $0.24.

First, we had the negative impact of foreign exchange; essentially, the change in the valuation of the dollar, Canadian dollar to the U.S.

dollar, in Canada is a negative $155 million or $0.09 a share.

Then we had higher operating costs essentially the maintenance program, a lot of seasonality in the third quarter; that was $113 million or $0.07 a share.

Then, we had lower benchmark crack capture on the downstream of $100 million; that is $0.06 a share.

Then we had adjustment for the abandonment and restoration obligation offshore Norway, which was $22 million or $0.01 a share.

So if you look at the $2.23 reported net income per share, included was $0.28 of, you might say, positive items, $0.24 of negative items.

So all net, there is about $0.04 positive in that $2.23.

Now I am going to go on to slide 5, cash flow.

If you start on the left, and you can see we generated about $6 billion of cash from operations.

That is about $1.2 billion higher then in the second quarter.

If you take that along with our beginning cash balance, we had $7.4 billion in cash available for the third quarter.

Then in the third quarter, we spent $2.8 billion on our capital program; $667 million dividends; and then reduced debt by $936 million; and we purchased $2.5 billion of our shares.

Then we had the proceeds from our asset rationalization program; that was $842 million.

That left us with a cash balance the end of the third quarter of $1.4 billion, which is essentially flat with the balance of cash we had at the end of second quarter.

I am moving now on to page 6.

If you look at page 6, on the pie chart on the left, you can see that through nine months we generated about $17.6 billion in cash from operations, and then $3.1 billion from asset sales; so we had $20.7 billion available resources.

What we did is we spent so far $8.6 billion, or 42 percent of the $20.7 billion, in our capital program.

We paid $2 billion in dividends; repurchased $4.5 billion of our stock; and reduced debt by about $5.3 billion.

So you can see where the cash resources -- how they were applied and used.

I am moving on to page 7, capital structure of the company.

Our equity grew to $88 billion; that is $2 billion higher than the previous quarter.

Debt is down $900 million; that brings our debt down to $21.9 billion at the end of September.

Then you can see that, on the right side of the slide, a 1 percent reduction in debt-to-capital ratio at 20 percent.

That is near the lower end of our target range, 20 percent to 25 percent at the capital ratio.

I am moving on to Exploration & Production, slide 8.

Our crude oil prices were higher worldwide in the third quarter.

Our realized oil price was $71.34 a barrel; that is $9.37 higher than the second quarter.

However our natural gas prices worldwide were lower.

Our realized natural gas price of $5.56 per MCF is $0.88 per MCF lower than the second quarter.

Then consistent with our guidance that we gave earlier, E&P's production and sales volume are lower than the previous quarter.

I am going to talk about that more on subsequent slides.

Then in the third quarter, our E&P results benefited from our asset rationalization program.

So I go to slide 10, which is our production.

In the third quarter, our E&P production was 1.76 million BOE a day, which is about 151,000 lower than the second quarter, but somewhat better than the previous guidance of 180,000 BOE a day lower than the second quarter.

You can see starting from the left, we reduced -- we saw the lower production from Venezuela as a result of expropriation.

We had lower production in the U.K.; that is the result of some planned downtime as well as unplanned downtime related to the damage and repairs of a third-party pipeline.

We also had the impact of seasonality and maintenance in Alaska, maintenance in the Timor Sea.

So these reductions in production were partially offset by higher production in Norway, as a result of when we completed our seasonal maintenance as compared to what was expected.

Then we had other impacts, which include lower production in Canada due to planned and unplanned maintenance.

So if you take this 1.76 million BOE a day, and add the 432,000 BOE a day which is our share of -- equity share of LUKOIL's production, you come up with a 2.19 million BOE a day in the third quarter.

Moving on to slide 10, which is E&P net income, third-quarter earnings were $2.1 billion compared to $2.4 billion loss in the second quarter.

As I said earlier, the second-quarter results were negatively impacted by the Venezuela impairment, as well as results of asset rationalization program in the second quarter.

So you can see the net impact in the green bar on the left part of this slide.

Without these items, our E&P earnings in the second quarter were about $2.2 billion; and they are $2.1 billion in the third quarter.

Now moving to the right, prices and other market impacts improved third-quarter results about $74 million as higher crude oil prices more than offset the lower natural gas prices.

However, the lower production and sales volume reduced our third-quarter income by $303 million.

Then we had the results of our asset rationalization program in the third quarter; that helped us by $132 million.

There are other items in the third quarter that offset each other but are important for you to understand and be aware of.

We had a $94 million benefit related to Alaska crude oil quality differential settlements.

Then we had lower product purchases and lower dry hole costs.

Then these items were fully offset by higher negative impacts of foreign exchange, which I talked about already.

Higher DD&A, mainly due to adjustments in abandonment obligations in Norway.

In addition, we had -- operating costs were higher than the previous quarter, mainly due to the large seasonal maintenance program in the third quarter.

Now, I am moving to the downstream part of the company, Refining and Marketing, on page 11.

In the third quarter, our worldwide refining margins were quite a bit lower than the second quarter.

Our third-quarter U.S.

crack spread, $10.86 a barrel, was a 45 percent drop from the second-quarter realized crack spread of $19.59 a barrel.

Our international realized crack of $6.05 a barrel was 38 percent below the second-quarter crack of $9.68.

Our U.S.

refining system ran at 97 percent of stated capacity.

That is about 4 percentage points higher than previous quarter.

But our international refining ran at 84 percent of stated capacity compared to 93 percent in the second quarter.

This is the result of an economic shutdown at the Wilhelmshaven refinery during the month of August.

We did that for commercial reasons.

Our total worldwide crude oil capacity utilization in the third quarter was 94 percent.

That includes the impact of the shutdown at Wilhelmshaven.

This is about -- third quarter 1 percent higher than we did in the second quarter.

Our turnaround expenses in the third quarter were $27 million pretax and $31 million lower than the previous quarter.

Our asset rationalization program helped third-quarter results, as you can see in the next slide.

You look at the net income in Refining and Marketing on page 12, the income was $1.3 billion, which is about $1.1 billion lower than the second quarter.

You can see in the first red bar on the left, the second quarter -- from the second quarter net income included a net benefit of $158 million from our asset rationalization program.

So if you move to the right you can see the $1.4 billion decrease in third-quarter net income is resulting from lower prices, margin, and other impacts.

Now, the largest part of this decrease is a result of significant lower worldwide realized crack spreads.

Included in that red bar of $1.36 billion, the impact of lower crack spreads in the U.S.

on the refining side was $1.123 billion.

International was about $180 million.

So that is the bulk of the $1.36 billion.

Also included within this impact of capturing less than the benchmark crack spread than what we expected, we communicated last quarter our expectation was that we would capture about 70 percent of the benchmark, 75 percent of the benchmark.

In the U.S., we were in line with that expectation, but in Europe we captured quite a bit less than the benchmark due to the disproportionately lower European hydroskimming cracks.

This resulted in a worldwide benchmark capture of about 68 percent to 75 percent of our expectation.

Now improved operating performance, even with economic shutdown of Wilhelmshaven in August, helped our income $135 million.

The asset rationalization program improved third-quarter income by $133 million.

We had some other items that improved third quarter by $199 million includes the previously mentioned $141 million tax benefit, legislation benefit in Germany, as well as lower operating costs.

So I am now moving on to page 13.

Our estimate of equity earnings for the third quarter of LUKOIL was $387 million.

This is $139 million lower than the second quarter, primarily due to lower estimated realized prices, higher operating costs, and then the net impact from the alignment of our estimated income to LUKOIL's reported results.

As we said earlier, the alignment from the second quarter was $85 million reduction in third-quarter income.

Our earnings for the Midstream were $104 million compared to $102 million in the second quarter.

Chemicals income was $110 million as compared to $68 million in the second quarter.

That is mainly due to $20 million asset retirement that was included in the second quarter and lower third-quarter utility costs.

Our third-quarter income in Emerging Businesses was $3 million as compared to $12 million loss in the second quarter.

This is due to higher third-quarter power generation earnings.

Our Corporate costs of $320 million were $17 million lower than the second quarter.

That is a result of lower net interest expense, partially offset by deferred tax expense that is related to foreign currency impacts.

If we look at our E&P, slide 14, E&P income per barrel, you can see that our income per BOE for the years 2003 through 2006, as well as the first-half and the third quarter of '07.

Our third-quarter profitability per barrel is slightly lower than the average for the first half of the year.

This is primarily due to lower production in the third quarter and the higher costs associated with our seasonal maintenance program, which is quite heavy in the third quarter.

Now moving on to slide 15, income per barrel in Refining and Marketing.

You can see similarly structured slide.

Our income per barrel is quite competitive with our peers, as well as through the first three quarters of 2007.

I move on to slide 16, return on capital employed.

The bar chart reflects our ConocoPhillips return on capital employed with no adjustments for purchase accounting.

We do make some adjustments for our peers to reflect purchase accounting for this preparation of this slide.

We always include those changes that we -- adjustments we make under table 2, which is attached to this presentation.

You can see from the right, our annualized return on capital employed for the third quarter was 13 percent.

That is 2 percent lower than the first half of '07 annualized, and 5 percent lower than the second quarter annualized.

I am moving to the last page of our presentation, 17, which is the outlook.

As we move into the fourth quarter, we expect our E&P production to be about 50,000 to 60,000 BOE a day higher than the third quarter.

That is a result of normal seasonality and completion of our summer maintenance program.

Then we also gain small amounts with some production -- first commercial production from the Surmont oil sands project in Canada.

For 2007, for all of the year, our production guidance is -- remains unchanged.

We expect to, including the LUKOIL segment, to be at 2.325 million BOE a day.

In the downstream, we expect fourth-quarter crude oil capacity utilization to be in the mid-90 percent range.

Our pretax turnaround costs are going to be about $85 million, which is higher than the third quarter.

So based on -- another point.

Based on our fourth-quarter commodity prices and our operating plans, we expect fourth-quarter results will include after-tax benefit coming from the impact of prior year LIFO inventory layers on anticipated inventory reductions.

This most likely will be near or in excess of $0.10 a share in the fourth quarter.

We anticipate our fourth-quarter share repurchases to be near the same level as we have done in the third quarter.

For all of the year 2007 we expect our capital expenditure program to be somewhere between $13 and $13.5 billion.

Pleased with the progress on our asset rationalization program, we have generated proceeds of about $3.5 billion since the inception of the program.

This is consistent with what we said in our expectations.

We expect to make additional progress as we go through the remainder of this year and then into 2008.

So that concludes the prepared remarks.

So we will now turn to taking your questions.

Okay, Bill.

We are ready for questions.

Thank you very much, sir.(OPERATOR INSTRUCTIONS) Our first question comes from the line of Dan Barcelo of Banc of America.

Please proceed.

Yes, good morning.

Regarding the downstream, results seemed a little bit weaker than I would have thought internationally.

I didn't know if there were any specifics there.

It seems that your realization seemed to trend a little bit behind what you have trended to relative to benchmarks historically.

Then second part of the downstream question, if you could comment a little bit about Marketing, particularly in the U.S., as your realized margins there slipped a bit.

Thank you.

Well, one of the things I did say is our capture of benchmark is less than what we expected on the international side.

That has quite an impact with respect to the international refining side of the business.

In terms of marketing, I don't know; John, do you want to comment on that?

Marketing in the U.S.

was off.

I don't think there is anything --

Unique about it.

Unique about that.

I would say that for the international crack spreads, we thought globally we would capture about 75 percent of the global crack, based on the indicated margin, than we thought -- that -- we did realize that in the U.S., as Jim said.

But the realization in Europe, because of the compressed hydroskimming margins, were closer to 45 percent instead of 60 percent to 65 percent.

So that had a major impact on operating results in our European downstream.

Dan, I think if you saw in the interim release, we did indicate that the benchmark margins for our wholesale marketing business were down considerably from the second quarter.

So you would have expected results from our U.S.

Marketing business to be a little bit down from the previous quarter.

Thanks very much.

Thank you very much, sir.

Ladies and gentlemen, your next question comes from the line of Neil McMahon of Sanford Bernstein.

Please proceed.

Hi, I've got a few questions on the volumes in the upstream, and then one on net income per barrel in upstream as well.

Maybe you could just go over in terms of the Libyan volumes, how much of the volume -- if there is any volume increase -- is getting impacted by production sharing agreements.

I didn't think there was much there, or if it was simply an underlift position.

Secondly, when is Darwin in terms of both the gas and LNG sales getting back up to normal levels?

What should we be looking at as an exit year production number for Surmont?

As I said, I have got a follow-up on net income per barrel.

Well, in terms of the Libyan volumes, they are pretty flat on a sequential basis.

Jim Mulva.

Not impacted by PSC.

No, Libya is not a PSC region.

Darwin is back up to --.

For us, Libya is not a PSC regime for us, and Darwin is back up.

Is back up to normal operations.

In terms of Surmont, we are just in the very beginning part of small amount of production as we started up those wells.

You have no idea of sort of where you are looking for Surmont to get to in the first, say second quarter, maybe?

I think we would have to come back to you.

I don't really have that answer, Neil, but I can get back with you.

Okay, then maybe just a quick second one on the net income per barrel.

I was sort of expecting -- as the Venezuela volumes are out of the equation -- that potentially net income per barrel might turn back up again in the third quarter, versus being flat on the second quarter with increased oil prices.

Any comments there, why it didn't go back up again?

Well, first of all, we have had a lot of maintenance, and the result is we have lower volumes.

The cost of the maintenance program in the third quarter is quite a bit higher.

And we also get the impact on BOE equivalent with respect to the low natural gas price.

Okay, great.

Thank you very much, sir.

Ladies and gentlemen, your next question comes from the line of Paul Cheng of Lehman Brothers.

Please proceed.

Good morning, gentlemen.

Jim, or maybe this is for John.

John, international E&P tax rate, about 64 percent seems high.

Any unique factors there?

Or there is just an asset mix issue of that quarter?

And what are the tax rates we should expect for the fourth quarter and 2008?

The international tax rate for the third quarter, if I recall correctly, was impacted by the Canadian deferred tax item that we mentioned in the release.

Paul, it is mixed because you had Norway production coming back up, but you have Australia production down, along with Alaska -- along with Timor Sea down, so you had some mix impact in the U.K.

So you had some mix impact and then also the deferred tax issue that John talked about.

So from that standpoint, should we assume that around 63 percent, 64 percent would be a reasonable estimate into the fourth quarter for your international E&P?

No, order of magnitude, I would -- excluding Venezuela impact -- impact point you to towards more the first quarter.

(inaudible) to the first quarter, so about 51 percent, 52 percent?

I have not calculated the number, but --

Mid-50s.

Yes, mid-50 range.

50?

Maybe I think it is maybe either Jim or Gary on that.

In the fourth quarter, your production guidelines is sequentially up 50,000, 60,000 barrels per day.

Honestly, that seems low to me, given that when we look at in the third quarter you have quite a lot of planned downtime (inaudible), including the Timor Sea and everything.

Just assuming those coming back, and if you take into consideration of the normal seasonal factor, your North Sea, of higher gas sales (inaudible) and also higher production in Alaska during the wintertime, should we expect the production to be higher than 50,000, 60,000 barrels per day?

Is there any expected plant shutdown or something like that impacting negatively on the result?

No, Paul.

This really is our best assessment of what we think the production will be.

To the extent that we can operate better than we have been our plan, then we would do better than 50,000 or 60,000 barrels a day.

But that is really -- if you look at the entire portfolio of production, we think that is our best estimate for the fourth quarter.

So, Jim, you don't have anything that you know of that is going to be shut down, either planned or unplanned at this point?

Nothing major, Paul.

If you take a look at where we think fourth quarter will land, it really is consistent with our previous guidance.

So really the only impacts we have this year from our original guidance is really the loss of Venezuela production; and then some impact from the U.K.

being down because of the CATS problem.

And that is --.

And the timing of asset dispositions.

The timing of asset dispositions, those are the only things that really are impacting us.

So we're looking at fourth quarter being about where we would have expected it to be.

Sequentially from the third to the fourth quarter, is there any negative impact from asset sales, in terms of production?

Paul, I don't know.

I can circle back with you on that.

I just don't have that answer at this time.

They wouldn't be major.

It is not significant, but --.

I see.

A final question, Jim, I am wondering if you can share some market intelligence.

I know you guys are not big in retail marketing in U.S.

anymore.

But in terms of your wholesale operation, in California recently they are coming up and said from the tax authority, California's state production, the state gasoline consumption is actually down year-over-year by about 0.4 percent in the first half of the year.

If you look at the Transportation Department, the traffic monthly reports indicate for the first eight months of the year, U.S.

vehicle miles driven is actually flat year-over-year.

So it just seems showing a pretty significant negative picture of the gasoline consumption.

Wondering, is there any marketing intelligence you guys can share with us?

Well, I read the same things that you do.

I would have to say that it does appear that there are starting to be an impact with respect to demand as a result of price.

So that is something that is good for our country with respect to conservation and demand, and a better supply-demand situation.

On the other hand, in terms of our operations, we find that everything that we produce we have absolutely no issue or trouble in selling and putting into the system.

So it is kind of a dichotomy for us.

We read what is taking place in total demand, but we don't see much impact with respect at all to the demand for what we produce coming out of our system.

I see.

Thank you.

Thank you very much, sir.

Ladies and gentlemen, your next question comes from the line of John Herrlin, Merrill Lynch.

Please proceed.

Yes, hi; I've got a couple quick ones.

In the press, Jim, there's been quotes saying that you're still negotiating with Venezuela.

Can you address that all regarding the expropriation?

Well, we continue to discuss and negotiate amicable settlement for the assets that were expropriated in Venezuela.

Those discussions will continue on over the next several weeks, next several months.

We will more than likely over the next several weeks move to filing for arbitration.

It doesn't change in any way our overriding objective of reaching an amicable solution.

But we feel that it is probably just good parallel process that we should follow to make sure that we preserve the rights and protect our shareholders.

But that, we will probably do that over the next several weeks.

But primary objective is to continue, and we are continuing our negotiations with the Venezuelan authorities to reach an amicable settlement.

Great.

Recently, there was a large central Gulf of Mexico lease sale in the U.S.; also there was a western sale; and versus the not too distant past, Conoco was much more aggressive.

Could you address what you are thinking about in the deep water?

Most recently, we have a pretty extensive acreage position in the Gulf of Mexico, which we acquired quite some years ago.

But with the deeper horizons and the Paleogene prospects, we looked at this, and we have quite a nice portfolio.

We attained it over many years ago for different horizons and different interests.

But then we looked at what we had, as well as the lease sale coming up was probably one of the largest lease sales that we have seen in years, that we could complement our program.

So we had some very distinct -- or very, I would say, a few areas that we were quite aggressive on that we felt that we really wanted the acreage, would complement our position that we already have in certain regions of the deeper part of the Gulf.

That is why we went after those, and we were successful.

It complements our program, so I think you're going to hear a lot more from us as we go forward of what we see in prospect, drillable prospects, in our exploration program in the deepwater Gulf of Mexico.

We are going to share that a lot more fully with you when we go through the Analyst Meeting early next year.

Okay, great.

Last one for me is on Canada.

Your company made a very nice reply to Our Fair Share in terms of the critique.

In the event that the proposed Albertan royalties go through, how much do you foresee paring back spending in Canada?

Or is it too early?

Well, it is a bit too early, but we have already for 2007 pared back our spending in conventional gas developments up in Canada pretty substantially.

We will take that all into consideration as we are developing our 2008 program.

So we have the conventional, unconventional work that we do in Canada; and then we also have our Oil Sands projects that we do with EnCana: Foster Creek, Christina Lake.

We also have the ability to add and further develop the Surmont project that we have.

So we -- it is very important to us; but we are going to wait and see what ultimately comes forth from Alberta in terms of how we adapt.

But certainly, the changes that are contemplated are going to have a real significant impact in our capital spend in Canada.

Great, thank you.

Thank you very much, sir.

Ladies and gentlemen, your next questionn comes from the line of Doug Terreson of Morgan Stanley.

Please proceed.

Good morning, guys.

Jim, do you guys have any segmentation for the earnings in the Refining and Marketing business in the U.S.

and overseas?

Yes.

Can you provide them?

I think you are asking, I think, Doug, to share with us how much we are making on the Marketing side, domestic and international; and then the same with -- on Refining.

Is that the question?

Yes, that is.

Yes, we have that.

Let me pull that out and just share that with you.

First, you're talking about this quarter?

I am, yes.

Okay, net income for worldwide Refining and Marketing was $1.3 billion and $7 million, $1.307 billion.

Domestic Refining was $817 million.

Domestic Marketing, $42 million.

International Refining, $387 million.

International Marketing, $67 million.

Everything else was a negative $6 million.

Okay, and one other question, Jim.

You guys have obviously been involved with EnCana for a short period here, so this may be kind of a preliminary question.

But have there really been any surprises, either favorable or unfavorable, as it relates to that particular venture?

Can you just provide an update as to how things are going with that situation?

You're talking about the EnCana joint venture?

I am, yes.

Yes, well, I think we are probably very close to what we expected we would be on production, maybe 5 percent less than we thought production-wise from Foster Creek, Christina Lake, so far in 2007.

Part of that is we had an operating hiccup in early part of the year.

Going forward, I think we can see though -- certainly it does have an impact what the Canadian fiscal legislation may be.

But these are the best projects up there, Christina Lake and Foster Creek.

What we do find is that the availability of labor at all and the cost of it -- maybe our ramp up of production may not be quite as fast as we initially thought.

But the recoverable reserves, the ultimate production level is certainly there.

That hasn't changed at all.

I think it really comes down to just how fast we can bring the production curve up as we go into 2008 and subsequent years.

We are going to share that when we meet with the financial community in the early part of next year.

But no surprises whatsoever in terms of reserves and production capacity ultimately.

The other thing is the relationship of the joint venture of EnCana and ourselves is really going quite well, both upstream and downstream.

We work well together.

Good, good.

Okay, great.

Thanks a lot.

Thank you very much, sir.

Your next question comes from the line of Nicole Decker of Bear Stearns.

Please proceed.

Good morning, everybody.

Just wondering if you could give us an update on drilling at Bastone?

Well, it is taking us longer than we thought.

We are probably going to finish the well in the early part of next year.

We wanted to get it done by the end of this year; but it is going to take us into the early part of next year.

So we have nothing to say at this point, because we don't have knowledge to say anything.

Okay.

Also, you did not mention in your production guidance any contribution from Alpine.

Should we expect a contribution from Alpine in the fourth quarter?

We don't see any contribution from Alpine.

This is the Norwegian project that we participate in.

Production is going to come sometime in the earlier part of next year, not in the fourth quarter.

Okay.

So that is quite a change; and that is factored into our numbers as we have gone through 2007.

Great, okay, one more if I could.

On the downstream, you are running your U.S.

system at 97 percent, which is impressive and it contrasts with other US refiners who appear to be running closer to the 90 percent level.

Could you maybe highlight some of the things that Conoco is doing that enables you to run at such a high level of utilization?

Well, it is hard for me to -- I can't really comment on other companies, but -- because I am sure they have similar programs as ourselves.

But we are really stressing very hard operating excellence, which goes on to integrity of operations; and so we spent a lot of time on that.

We, I think, safety, environmental performance.

But it's really stressing the operational operating excellence.

We have always prided ourselves on doing that reasonably well and so we see the results of it.

So I can't really comment why others may be for either commercial reasons, or turnarounds, or whatever, or installing new facilities.

But we have always been able to get in the higher 90s, mid-90s, ultimately.

We have some refineries -- and I am sure the competition is the same way -- some refineries that are running at 100 percent of capacity when they are up and running.

But of course, they are more sophisticated, more complex.

So to achieving really high 90s really takes great operating excellence, given the sophistication of facilities we have compared to 10, 20 years ago.

That's great.

Thank you, Jim.

Thank you very much, ma'am.

Ladies and gentlemen, your next question comes from the line of Mark Gilman of Benchmark Company.

Please proceed.

Guys, good morning.

I had a couple of things I wanted to go over.

First, it appears to me, and this is somewhat anecdotal, that you're experiencing a pretty heavy amount of conversion unit downtime in the U.S., which doesn't show up in the distillation utilization figures, but nonetheless, has an impact on margin capture.

Could you discuss that for a second, whether you agree that that is true?

And if so, what steps you might be taking to remedy it.

No, I'm not -- I don't think, Mark, we necessarily agree with that.

What we have found is that because of the complexity of the refineries and all and the facilities, that when something goes down it really does go down and in more dramatic a fashion.

So I don't think -- we can come back to you and talk to our people about this.

But I don't think we accept that premise.

Okay, let me try something else if I could.

It seems that over about the last five sequential quarters, in the international upstream segment there have consistently been modest financial book impairments, which seems a bit unusual to me in the price environment that we have been in.

Is there something in that segment regarding this subject that we should be aware of?

I don't think so, Mark.

The impairments have -- not going and cataloging each one and we can certainly do that offline.

They have been items such as -- most of the items have been associated with assets held for sale.

As you know, there are unique accounting requirements for that class of assets.

Until the assets are disposed of, they can have some volatility in the impairment line.

Then we had, as we mentioned, there was a dismantlement asset retirement obligation that we booked here in the third quarter.

But I have not been able to identify any particular trends or underlying theme associated with those impairments.

They seem to be pretty asset-specific.

Okay, just two quick financial questions if I could.

Could you go over, John, a comment I think you made regarding the Canadian deferred-tax issue?

Then also on the capital budget for '07, Jim, I think you said between $13 and $13.5 billion, which is down I would guess about three-quarters of a bill from comments that I think you made as recently as a couple weeks ago that suggested $13.5 to $14 billion.

Which in the environment of a very weak dollar, one would tend to think it would go in the opposite direction.

Is there something specific being deferred?

No, there is nothing being deferred.

Let me just clarify that.

We really expect that we are going to spend $13 to $13.5 billion for 2007.

I think comments I made several weeks ago, I was really referring more to our 2008 and subsequent years.

If we look at 2008 and subsequent years, we haven't finalized all of our plans for the capital spend.

It is probably going to be $14 to $15 billion for 2008 and 2009.

But for 2007, there is nothing deferred.

Sometimes projects don't go as quickly as we would have thought in terms of the spending.

But there has been no change in capital plans, so it's $13 to $13.5 billion for 2007.

Now, John can go to the other question.

Well, the deferred tax item relates to differences between booking and spot rates for non-dollar -- non U.S.

dollar functional currency related to dollar liabilities.

It is a fairly involved determination.

But it is primarily this spot versus forward rate differential.

It flows through in deferred taxes because we have made the determination that this difference is a temporary difference.

Therefore, it goes through the deferred tax line.

John, how much was that?

Was that included in your certain items page in the supplemental material?

I would have to check on page 3 or the -- I don't believe it is in the certain items page.

But it was reflected in our talking points.

I thought we said it was -- did we give a number, Gary?

I don't recall whether we --.

Let me circle back with you and see what we said, if I can.

There is a net change in corporate tax, I thought about $35 million; and then that is where it shows up, in the Corporate segment.

Okay, thanks.

I will confirm the number with you, Mark.

Okay, thank you, Gary.

Thank you very much, sir.

Ladies and gentlemen, your next question comes from the line of Doug Leggate of Citigroup.

Please proceed, sir.

Thanks.

Good morning, gentlemen.

I love the way they pronounce my name.

Just to kick off with two quick questions if I may.

I want to go back to Neil's earlier question about net income per barrel if I may, but specifically on the international business.

If you just look at the numbers, take the third quarter of last year versus the third quarter, so theoretically we are still hitting the high maintenance period.

Your realized net income per barrel was down just about $4 a barrel.

The realization on the revenue side is up about $8 a barrel.

If we take your -- I think you said $113 billion of additional OpEx, Jim, related to the maintenance, that is only about $1, which still leaves us quite a bit short in your ability to capture the higher realizations.

Also, gas prices were relatively flat, I believe, over that period.

Can you help us understand what is going on there?

Because it looks like things are -- maybe costs are going up or something else?

Well, we have the impact of Venezuela.

So Venezuela a year ago, we had lower cost and pretty good realizations.

We also have in terms of production sharing contract, in terms of payout and all, with respect to Bayu-Undan, that does have some impact.

Those are the two things that seem to come to my mind pretty quickly.

I don't know, John, if you have something else.

No, I don't.

I don't have any -- I would have to go back and evaluate that, Doug.

I am not sure that I --

Yes, I think, Doug, I think Jim hit the main ones.

But I can get back with you and go through additional details.

But Jim hit the main ones.

Okay, is it possible to maybe -- maybe we can do it offline.

I was going to ask about the actual operating costs in Venezuela relative to the rest of the international.

But we can maybe do that offline.

Yes, I can do that at the same time.

Okay, great.

The only follow up I had is it may be a little too early, but ex-EnCana on the conventional production, any early look at what reserve replacement might look like this year?

Well, what we have said all along, I'm not going into the details of it, but we haven't changed at all.

We said over the 2007 and subsequent years that we would have reserve replacement near 100 percent.

Some years it might be 80 percent, some years it might be 120 percent.

But we haven't changed that.

If you look at 2007 and subsequent years, we're going to be somewhere around100 percent.

We are going to update all of that when we meet with you early next year.

Okay, I guess just one final one from me.

It actually relates to what is going on with ethanol prices right now.

Could you maybe just give us some feel as to how the very low ethanol price translates into the downstream earnings, maybe particularly as we are now into winter-grade gasoline?

It doesn't have too much impact.

We are a buyer of ethanol and blend it in, in certain regions.

But in terms of performance of financial impact of the company, it is relatively -- really small.

It is not reflected in the cracking margin that we use as our benchmark, so we try to provide clarity by not doing that.

Okay, great.

That's it for me.

Thank you.

Thank you very much, sir.

Very sorry about the mispronunciation on the last name.

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

Please proceed.

Hi, good morning, gentlemen.

Jim, major project update question if you could.

Could you just give us your status and best guess of the timing on three particular ones.

One would be Brass River; the other would be Qatargas 3; and the final one would be Shtokman.

If you could just kind of give us an update, that would be great.

Thanks.

First, on the Brass LNG, probably going slower than we would have expected.

There is a lot of work that has to be done on the engineering side, the commercial side, the fiscal side.

So that is probably, we know it is going to take quite a bit longer in moving towards development than might have expected.

So that is really the update on Brass.

Qatargas 3, we watch over not only Qatargas 3 but also Qatargas 4.

A lot of work that is being done in Qatar and Ras Laffan, so -- but in terms of cost and schedule we are still maintaining our cost and schedule.

But on the other hand, a lot of the work that is being done for us is going to ultimately come from the completion of prior LNG trains ahead of Qatargas 3 and Qatargas 4.

Whether that is going to have any real impact in terms of schedule or that remains to be seen.

But so far, what we are doing on Qatargas 3, we are still holding with our schedule and our cost.

In terms of Shtokman, I think it is really probably more appropriate that you just talk to Gazprom about that.

I know that we have been interested in that and submitted proposals, but really the decision and the announcement on that really has to come from Gazprom, not from ourselves.

Sure, I understand.

For CapEx next year, should we think about a similar number to this year, the $13.5 billion that you have talked about?

I know it is early.

I have been saying somewhere between $14 and $15 billion.

$14 or $15 billion for next year?

Okay.

That's great.

I think I will leave it there.

Thanks a lot, Jim.

Thank you very much, sir.

Ladies and gentlemen, your next question comes from the line of William Ferer of W.H.

Reaves.

Please proceed.

Thank you very much.

Good morning, gentlemen.

I too would like to tour the world a little bit, but in a different sense.

Nigeria today announced possible onshore changes in operating terms.

Kashagan is speaking on the tape from time to time about possibilities.

And we have the ever-present tax changes in Alaska that seem to the bouncing back and forth.

Jim, could you provide us a little update on how you see each of those areas?

Okay, first on Nigeria, I am getting information about it as quickly as you are.

Nigeria, I hate to see these changes, because impact on -- or any changes on prior contracts and all is really not helpful in terms of investment, new investment that is required to add resources.

We have really a very modest, small position in Nigeria.

It has been important to us over the years.

It has been good financially.

But it is really not a good sign when we see the different countries or different jurisdictions looking at changes to the fiscal take.

Because it is going to really impact the industry's capability to add resources.

The resources that we are adding are always more complex, more costly.

So every barrel or MCF of gas we produce is going to cost us a lot more to replace what we produce.

So that is on Nigeria.

On Kashagan there is a lot out in the media.

We continue to work very closely with the other consortium partners, along with the ministry and the people handling this for Kazakhstan.

In terms of Kashagan it is really not appropriate for me at this point in time with the negotiations, discussions taking place, to really comment on this.

Other than to say that our company and all of the companies in the consortium are working well together and working with Kazakhstan and hopefully we can sort this out over the next several weeks or months.

In terms of Alaska, we know that the governor has called into special session a review of the oil tax and the changes of last year.

From our perspective, we look at this, we are no different than the industry.

We see changes in the fiscal take from one year to the next, and we don't think it is really appropriate given the amount of investment we have made and intend to make.

It is not going to be helpful in terms of developing more resources and certainly has an indirect impact, as you see the fiscal legislation and changes taking place or under consideration.

It has a negative impact to develop the gas resources and ultimately the gas pipeline from Alaska.

So we look at this, and we say, you know, we feel that we have already made change and accepted and pay more taxes last year.

There is no real need for changing the fiscal take or the regime this year or going forward.

Thanks very much.

Thank you very much, sir.

I would like turn the call back to Mr.

Russell for his closing remarks.

Thanks, Bill.

Again, we appreciate everybody participating on the call this morning.

Let me remind you that you will find a replay of this webcast along with a transcript posted on our Web site, www.conocophillips.com.

Thanks again for your participation and good day.

Thank you very much, sir, and thank you, ladies and gentlemen, for your participation in today's conference call.

This concludes your presentation for today.

You may now disconnect.

Have a good day.

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

This transcript of a presentation given by ConocoPhillips' management on October 24, 2007 includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, which are intended to be covered by the safe harbors created thereby.

You can identify our forward-looking statements by words such as "anticipates," "expects," "intends," "plans," "projects," "believes," "estimates," and similar expressions.

Forward-looking statements relating to ConocoPhillips' operations are based on management's expectations, estimates and projections about ConocoPhillips and the petroleum industry in general on the date the presentations are given.

These statements are not guarantees of future performance and involve certain risks, uncertainties and assumptions that are difficult to predict.

Further, certain forward-looking statements are based upon assumptions as to future events that may not prove to be accurate.

Therefore, actual outcomes and results may differ materially from what is expressed or forecast in such forward-looking statements.

Factors that could cause actual results or events to differ materially include, but are not limited to, crude oil and natural gas prices; refining and marketing margins; potential failure to achieve, and potential delays in achieving expected reserves or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks, and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas; unsuccessful exploratory drilling activities; lack of exploration success; potential disruption or unexpected technical difficulties in developing new products and manufacturing processes; potential failure of new products to achieve acceptance in the market; unexpected cost increases or technical difficulties in constructing or modifying company manufacturing or refining facilities; unexpected difficulties in manufacturing, transporting or refining synthetic crude oil; international monetary conditions and exchange controls; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; general domestic and international economic and political conditions, as well as changes in tax and other laws applicable to ConocoPhillips' business.

Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting ConocoPhillips' business generally as set forth in ConocoPhillips' filings with the Securities and Exchange Commission (SEC), including our Form 10-K for the year ending December 31, 2006, as updated by our subsequent periodic and current reports on Forms 10-Q and 8-K, respectively.

ConocoPhillips is under no obligation (and expressly disclaims any such obligation) to update or alter its forward-looking statements, whether as a result of new information, future events or otherwise.

Cautionary Note to U.S.

Investors - The U.S.

Securities and Exchange Commission permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions.

We may use certain terms in this transcript such as "oil/gas resources," "bitumen," "Syncrude," and/or "Society of Petroleum Engineers (SPE) proved reserves" that the SEC's guidelines strictly prohibit us from including in filings with the SEC.

U.S.

investors are urged to consider closely the oil and gas disclosures in our Form 10-K for the year ended December 31, 2006.

This transcript of the presentation includes certain non-GAAP financial measures.

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

Investors are urged to consider closely the comparable GAAP measures and the GAAP reconciliations available by reference to the listing of previously disclosed items in the company's earnings release dated October 24, 2007, footnotes to the tables provided in the presentation, and the appendix to the presentation which, in each case, are available on our Web site at www.conocophillips.com.