康菲 (COP) 2006 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to ConocoPhillips third quarter 2006 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 hand the call over to your host for today's call, Mr. Gary Russell, General Manager of Investor Relations.

Please proceed, sir.

Thanks, Jen.

And welcome to everyone on the call to ConocoPhillips third quarter earnings conference call.

I am joined here today by Jim Mulva, our Chairman and Chief Executive Officer and John Carrig, our Executive Vice President of Finance and Chief Financial Officer.

The presentation material that we’ll go through today will help us explain the financial and operating performance of ConocoPhillips in the third quarter of this year.

You can find the presentation on our Web site, ConocoPhillips.com.

If you will turn to page 2, you'll find our Safe Harbor statement.

It basically says that the presentation today and the responses that we give to your questions will include forward-looking statements about our current expectations, and actual results may differ materially from our current expectations.

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

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

Okay, Gary.

Thank you and appreciate all those who are joining us on this conference call.

I am going to start my comments on slide or page number 3 which is the highlights of our third quarter.

You can see for the third quarter, we generated $3.9 billion in net income, $6.2 billion in cash flow from operations.

Our net income for the quarter was reduced by $622 million, and that is about $0.37 a share, certain previously disclosed items.

I will talk more about this later.

Items mainly due to recent tax legislation changes that impacted our upstream part of the business and impairment of assets held for sale on our downstream.

As I said, I will go through all this in more detail in later slides.

During the quarter we reduced our debt to cap ratio 2 percent, so we are at 25 percent.

We brought our debt down by $1.7 billion to $27.8 billion, and we continue to fund our capital program and capital required for other investments.

We announced earlier this month we reached agreement with EnCana to create an integrated North American heavy oil business and I'll say a little bit more about this at the end of the presentation.

Now for the third quarter of 2006, we produced 2.47 million BOE a day.

Now this includes 436,000 BOE a day from our LUKOIL investment.

I will again cover more of this in subsequent slides.

Now in the refinery market area, refineries ran at 95 percent of our processing capability capacity.

It's up 4 percent from the prior quarter, then we have some slides on our ROCE and income per barrel for upstream and downstream, which we believe keeps us competitive with our peer group.

I'm going to go to slide number 4 and spend some time on this because it is a really important slide.

We've had a number of questions already about give us as much detail as possibly can to show what is taking place from the second quarter, financial results of '06 to what we just announced this morning, third-quarter.

That's what this slide shows.

Moving through the slide, our worldwide refining margins were significantly lower than in the second quarter.

This negative impact was partially offset by a much improved worldwide marketing margins, slightly higher realized crude oil prices and natural gas prices.

Our natural gas liquids prices, midstream higher margins and chemicals.

The net effect of all of this decreased our third quarter net income compared to the second quarter by $138 million.

That is the red bar, the $138 million second one from the left that I've been commenting on.

Then I move on to volumes.

Lower E&P sales volumes were partially offset by higher volumes in refining, marketing and LUKOIL investment segments.

The net of all this reduced going from second to third quarter, reduced third quarter by the $60 million shown in this slide.

That’s the third bar from the left.

Move to tax legislation.

Recent tax legislation had a significant impact on our third quarter net income, and then the comparison as we went from second quarter to third quarter.

About $400 million of the variance came from the onetime tax benefits from Canada and Texas.

They were recorded and included in the second quarter numbers on the left-hand side of this slide were included in that $5,186,000.

Now the remainder of that $1,073,000 in the middle of the slide under taxes is related to new tax legislation in the U.K. -- United Kingdom -- Alaska and Venezuela.

Talk more about this in later slides.

Now to summarize, we've had tax legislation in the second quarter of '06 we had the benefit of the Canadian and Texas tax changes.

Now we go to the $220 million moving over to the right side of the slide.

We had a $220 million impairment quarter to quarter and its mainly due to the third quarter impairment on refining and marketing assets that are held for sale; this is part of our previously announced $3, $4 billion asset rationalization program.

Don't expect to have any more of this, really, of any significant amount as we go forward into subsequent quarters.

Now the other $181 million shown in green.

It includes business interruption claims, improved foreign exchange impacts, lower turnaround costs, and then somewhat offset by higher DD&A.

And then improved third-quarter and all this improved third-quarter earnings by $181 million.

If you look at all of this then on this slide as a result of our third quarter net income was about $3.9 billion.

Now if the second and the third quarters, both the second and third quarters, you exclude the effects of tax legislation impacts as well as the impairment of assets held for sale, a net business interruption impact, then our third quarter would have been $4.5 billion in net income as compared to the second quarter, $4.7 billion, so about $200 million difference.

We've been asked what is our run rate?

Well our run rate of net income, taking out these unusual items using pricing environment that we had in the third quarter, our run rate of net income is $4.5 billion.

That includes the downtime at Prudhoe Bay.

If we didn't have the downtime in Prudhoe Bay, then our run rate would be closer to about $4.7 billion in the third quarter.

I'm going to go to slide number 5, the total company cash flow.

See, we started on the left-hand side of the slide, we started with cash balance $654 million, and we generated $6.2 billion cash from operations.

Moving across the slide we spent $3.8 billion our capital program and investing activities.

Now in that $3.8 billion, there are $702 million to buy another 1 percent of LUKOIL's equity.

Then we paid out $593 million in dividends.

We reduced debt $1.7 billion.

We spent $250 million buying 3.9 million shares of our company stock in the third quarter.

You take the $250 million in the third quarter, plus what we purchased in the second quarter and what Burlington Resources purchased in the first quarter, we are on our target of doing $1 billion of share repurchases this year.

And then after all, minus all things, we ended the quarter with $696 million of cash.

Go to slide number 6.

In this slide number 6, these pie charts show what's our sources and what is our uses of cash.

When you look at the first three quarters of '06.

On the left-hand side total cash available to the company $19.5 billion and 82 percent was generated from operating activities.

If you look at the right-hand pie chart, you can see what we've done with $19.5 billion.

Now we spent about $12 billion or 62 percent of our variable cash to fund our capital investment programs, including in that is the acquisition of increased ownership in LUKOIL.

Now that 62 percent of available cash if you look at our net income, we reinvested 97 percent of our 2006 net income back into our businesses.

And we've returned 6.7 billion or about 38 percent of our available cash, to our shareholders and debtholders through dividends, share repurchase and debt reduction.

I'm going to move to slide number 7, which shows a little bit further illustration compared to peer group ROE returned cash to shareholders and debtholders in the first nine months of the year.

I said earlier in a past slide we returned 38 percent of available cash or $6.7 billion to the first nine months.

This is about half of the peer group average, which is up near almost 60 percent, and the reason we’re at 38 percent is a higher reinvestment rate back into our business.

We have a large number of good return projects that we are funding, which in the years coming forward we will see further enhanced income and cash flow.

Now as we meet our debt reduction target by late 2007, then we would expect a much larger portion of our available cash to be returned to our shareholders through higher dividends and share repurchases.

I'm going to go to page number 8, which shows the capital structure of the company.

We continue to make good progress, improving financial flexibility in our debt to equity ratio, once you look on the bar chart on the left it shows during the third quarter equity grew by $3 billion, so we are up to $82 billion.

And then we reduced our balance sheet debt by $1.7 billion to $27.8 billion, so the resulting debt to equity ratio now is at 25 percent.

And we expect as we go into fourth quarter, the end of the fourth quarter the end of this year, we will be down a couple percent more as we finish this year.

I am moving on to page 9, exploration and production.

We’ll talk about upstream and then downstream, and this is sequentially what is taking place from the second quarter this year to the third quarter.

Our worldwide realized crude prices were slightly higher in the third quarter, about $0.70 per barrel.

It is up near $65.04 a barrel.

Our realized -- our global realized natural gas prices were $5.91 an Mcf.

That is up 1 percent from the second quarter, which was $5.85 per Mcf.

On the U.S., our Lower 48 realized gas price was $6 per Mcf in the third quarter.

That is up 3.2 percent or $0.19 per Mcf from the second quarter.

Our E&P production in third-quarter was lower than the previous quarter, and that’s primarily because of the shutdown of production associated with Prudhoe Bay and then planned maintenance activities at normally undertaken third-quarter time of the year in the U.K. and Venezuela.

I also mentioned earlier the tax legislation changes in the U.K., Alaska and Venezuela had an impact on our third quarter E&P results.

Now I am moving to page number 10.

We will talk about our E&P Company production sequentially from second quarter to third quarter.

As we said on our last conference call in the second quarter results, our production in third quarter was lower than the previous quarter due to the planned maintenance in the U.K. and Venezuela, and we also see a seasonal decline up in Alaska.

Then in addition, as I said, we saw lower production due to the shutdown of production, some of the production in Prudhoe Bay.

During the third quarter we also saw higher production from the, we ramp up gas production associated with our Darwin LNG project.

Then we had some other impacts due to production in the third quarter, which include higher production in the Lower 48, somewhat offset by lower production in Canada.

And then when you add the 436,000 BOE a day, which is our estimate of equity share of LUKOIL's production, then you get to the total 2.47 million BOE a day in the third quarter for the company.

I'm going to move now to slide number 11, which looks at our E&P net income.

In the third quarter it was $1.9 billion.

This is $1.4 billion lower than the previous quarter.

Now let's go through this in a little more detail.

Our third quarter results, this first green bar from the left, third quarter results were improved $70 million over the previous quarter mainly due to slightly higher realized crude oil natural gas prices and other market impacts.

Then we look at volumes.

Our lower sales volume reduced third quarter earnings by $212 million.

That is the first red bar going from the left.

This is primarily due to decreased sales volume from Alaska, U.K., Venezuela and then this is all partially offset by higher LNG sales for Darwin LNG.

Then we talk about taxes.

That’s the 1,151 bar in the middle of the slide.

Recent tax legislation reduced net income by $1.15 billion compared to the second quarter.

Now as I said earlier, about $400 million of this variance is from the onetime tax benefits from Canada and Texas that were included in the second quarter results of $3.3 billion, left-hand side of the slide.

And the remainder of the variance relates to the tax legislation in U.K., Alaska and Venezuela.

During the third quarter, the U.K. enacted an increase in their North Sea tax rate 40 to 50 percent.

So, this resulted in a onetime deferred tax adjustment $270 million, and since the tax rate increase was retroactive to January first of this year, then the third-quarter results also include $130 million impact in the first and second quarters, in addition to the $40 million impact for the third quarter.

Alaska also increased its production tax rates making the new rates effective April 1st of 2006.

So as a result our third quarter net income was negatively impacted by a $94 million charge related to second quarter, in addition to the $86 million impact for the third quarter.

We had some other related tax impacts, including a full quarter of the new extraction tax in Venezuela as well as a onetime deferred tax adjustment resulting from an increase in a Venezuela income tax rate to 50 percent on our heavy oil projects, and that was effective back to January 1st of 2007.

Then we had some other factors that reduced our third-quarter E&P net income as compared to the second quarter, included higher DD&A recognized for both the second and third quarters and the application of purchase accounting for the Burlington Resources acquisition at the operating area level.

We had some higher operating expenses partially offset by improved foreign exchange impacts.

Now if you look at this slide, number 11, if you exclude the effects of the recent UK and Alaska tax legislation on deferred taxes, and on previous quarters' results, then our E&P third quarter results, given the price environment we had in the third-quarter -- our third quarter results would have been $2.4 billion and to make these adjustments for taxes related to second quarter, the second quarter results would have been $2.7 billion.

That is excluding these tax legislative items.

So effectively, we’re comparing $2.4 billion in the third quarter to $2.7 billion in the second quarter.

I am going to move now to downstream and slide 12.

It sequentially shows what took place in refining and marketing.

Refining margins were lower than in the previous quarter.

In the U.S., our-third quarter realized crack spread declined about $3.13 a barrel to $14.10 a barrel, in the third-quarter.

Our international realized crack spread declined $1.18 a barrel to $6.46 a barrel in the third quarter.

Our U.S. refining system ran at 96 percent of stated capacity.

That is up from 91 percent in the second-quarter.

Our international refining system ran at 89 percent of stated capacity.

That is 5 percent lower than the second-quarter, and this is due to planned downtime at the Wilhelmshaven refinery.

As a result our worldwide crude oil capacity utilization is up near 95 percent.

Our turnaround expenses amounted to $42 million pretax for the quarter, so that is $73 million lower than the second-quarter.

I mentioned earlier, we recorded an impairment on assets held for sale related to our asset rationalization program.

And then, we recorded a net benefit from business interruption insurance and that was related to our 2005 hurricane activity.

I want to move on to slide number 13.

Now slide number 13 shows that our net income in the third-quarter, on the right-hand side of the slide, is $1.46 billion.

That’s $244 million lower than the second quarter.

The far side and left side of the slide.

This said, we experienced significantly lower worldwide crack spreads, but they were partially offset by higher worldwide marketing margins.

This along with other marketing impacts reduced third quarter income by $263 million.

That’s the red bar, first red bar on the left side of the slide.

On volumes, our higher volumes due to improved crude oil capacity utilization increase our earnings $130 million.

As I said earlier, we benefited by the impact of business run interruption insurance claim of $111 million, which does not include the effect of higher premiums.

Impairment of assets held for sale that is part of our $3 to $4 billion disposition program; that reduced net income by $249 million.

And then the other impacts, which included lower turnaround costs partially offset by negative impact on foreign exchange net of all this, improved net income by $27 million.

But like E&P, if you exclude the impairment of assets held for sale and the net business interruption benefit, if you exclude these unusual items then our refining marketing results would have been approximately $1.6 billion in the third quarter, which is pretty close to what we actually did in the second-quarter.

I am going on to slide number 14 and talk about our LUKOIL investment.

Our estimated equity earnings for the third quarter from LUKOIL were $487 million.

That’s up from $387 million in the second quarter.

At the end of the third quarter we owned 19 percent. $851 million authorized in issued shares of LUKOIL.

Starting in the third quarter, we are reflecting our ownership in LUKOIL based on the shares outstanding, so in accordance with U.S. GAAP.

Therefore, the results recorded in the third quarter include adjustment necessary to reflect our interest in LUKOIL on that basis.

Now for a comparison, ownership on the basis of shares outstanding is about a half percent higher than the ownership on the basis of authorized and issued shares.

I'm going to move from LUKOIL on page 14 to page 15 to talk about our joint ventures, midstream chemicals and emerging business.

Our earnings for the midstream business in third quarter is $169 million.

It's up $61 million from the second quarter.

This improvement is the result of higher NGL prices, along with some certain tax adjustments.

Our chemicals joint venture earnings were $142 million.

Now that is $39 million higher than the second quarter primarily due to higher margins in most all of the business lines of the chemicals joint venture.

That emerging business results were $23 million higher than the previous quarter in the second quarter.

As a result of improved power results mainly due to the absence of the write-off of a gas turbine at our Sabine River Works cogeneration facility, which we took in the second-quarter of this year.

I'm going to move onto corporate, page 16.

The corporate segment’s impact on net income in the second quarter is shown on the right-hand side as a loss of $301 million. $111 million lower than the second-quarter loss shown on the left-hand side of the slide of $412 million.

The impact from foreign exchange improved by the results $84 million, and then net interest expense was $25 million lower than the previous quarter, mainly due to lower average debt balances, debt reduction.

I'm going to move to slide number 17.

It shows our earnings and ROCE on comparison purposes to our peer group.

So first E&P net income for BOE, and this shows for the years 2003 through 2005 then the first three quarters of this year.

We look at the peer group, being the publicly traded companies larger than ourselves, Exxon Mobil, BP, Shell, Chevron and Total.

You can see our E&P income per BOE is pretty competitive with our peer group.

We don't have the results for the third quarter.

When we do, we will put them on the slide.

Up to 80 percent of our production is from OECD countries, and we believe these barrels provide good low risk value for the foreseeable future.

We think net income is a relevant measure, so we started to use this metric both upstream and downstream.

So we go to slide 18, and we look at our net income per barrel for refining and marketing against peer group is the same peer group I just outlined for E&P.

And see our income per barrel is quite competitive with that peer group, and again, we believe for this business line our growth plans will continue to support a competitive net income per barrel.

I'm going to move to slide number 20.

Just return on capital employed.

The shaded area in the background shows the ROCE for the other five companies, publicly traded companies, in the peer group.

This bar chart reflects ConocoPhillips’ return on capital employed with no adjustment for purchase accounting.

We do make adjustments to the peer group to reflect purchase accounting that for the transactions that they made that were done not on purchase accounting, but on pooling and you can see our adjustments that we use table 1, which is attached to this presentation.

See on the right bar annualized ROCE for the third-quarter where our results were 17 percent, and this includes the full effect of the previously disclosed items.

Now I am going to go on to slide number 20, the last slide, which is our outlook.

Our 2006 capital program is continues, including the completion of our planned equity investment in LUKOIL.

We expect to be at 20 percent at the end of December.

We continue to make progress on our asset rationalization program, and we expect to generate proceeds of $3 to $4 billion.

And we’re working pretty aggressively on this -- expect this all to be done, concluded by the end of 2007 next year.

We are actively marketing a number of assets identified for disposition.

For example, in the third quarter we sold our remaining interest in Permian Basin Royalty Trust.

Also, earlier in the month, as we announced, we reached agreement with EnCana create an integrated North American heavy oil business.

We expect -- we are working on final documentation -- expect to close this in the early part of 2007, as previously indicated.

I might add that we're really excited about these two joint ventures because we’re developing a very integrated physically, financially integrated approach to taking and monetize the heavy oil sands in Canada, and bringing those oil sands and bitumen diluent back into our refineries at Wood River and Borger.

We see that the joint venture in Canada, barrels in place, about 44 to 45 billion barrels.

We, along with EnCana, expect initial recovery over the next 30 years to be about 15 percent.

Every 1 percent we're going to be ramping up our technologies.

So every 1 percent increased improvement and recovery is another 450-to-500 million barrels.

So we are really excited about this.

It is going to go a long way towards helping our North America business, adding reserves that helps on reserve replacement and doing it at competitive finding development costs.

It also loads up our refineries, and we will be making substantial investments to handle the bitumen coming from the joint venture with EnCana and the oil sands in the north.

Now again, we expect to have this all completed early, early next year.

So you will see then the results of the two joint ventures as we go through the quarters of next year.

Looking ahead at the fourth quarter of 2006, we expect our upstream production to be higher in the third quarter as a result of resuming these full operations at Prudhoe Bay, get away from the normal seasonality of less production in the third quarter, and we expect then less scheduled downtime.

Now these positive impacts on production would be somewhat or partially offset by the anticipated reduction of about 30,000 BOE a day, and it is the result of production sharing contract impacts in the Timor Sea.

Downstream we expect our refining capacity utilization to be pretty similar to the third quarter.

That’s in the mid-90 percent, and then our full-year exploration expense is conservatively expected to be about $800 million.

In downstream, we expect our full-year turnaround costs to be about $400 million.

That concludes the comments we want to make on our presentation, so now we will move to questions and observations by others that may have with myself and John Carrig and Gary Russell.

(OPERATOR INSTRUCTIONS) Gentlemen, your first question comes from Jennifer Rowland with JPMorgan.

Thanks, I wonder if you could break out the contribution from Burlington in the quarter and just comment on the synergy capture that you’re seeing and the anticipated dilution that you foresee in the '06.

First in terms of synergies, we track this closely.

We’re right on our target.

I think we announced when we did the transaction that synergy was going to be in the neighborhood of $500 million.

That will be captured as we go through 2006 and then fully captured as we put in all the new and switch over the IT systems of the Burlington assets into ConocoPhillips.

That will take a good part of 2007, but it will be fully captured as we finish 2007.

In terms of Burlington contribution, we have higher DD&A than we had in the second quarter.

We see it at the gas prices that we are realizing here in the third quarter contribution is $300 to $350 million, centered the dilution at this price level is similar to what we outlined in the second quarter.

Okay, and on the DD&A comment, can you give us new guidance for what you foresee as DD&A for '06 and then also going forward to '07?

John Carrig, maybe you might want to answer that.

The incremental -- yes -- at the end of the first quarter we indicated that we expected $7.1 billion to be the DD&A for 2006, and we expect the number to be about $200 million higher, $7.3.

As to 2007, I don't think we have a number available yet, but to indicate a change I think whatever you have in using that extra $200 million would not be unreasonable, until we update you with the full numbers in our analyst presentation meeting in March.

Okay, and just another quick one for me.

Do you have guidance that you can give us now for '07 CapEx?

Well, we've indicated CapEx would probably be in the neighborhood of about $15 or $16 billion for next year.

We‘re in the process of working through that..We will update that with everyone when we meet in March.

Okay, thank you.

Your next question comes from Arjun Murti with Goldman Sachs.

Thank you.

Jim, maybe a little bit more of a strategic question regarding refining spending plans.

You've got a growing project list between the EnCana joint venture, your existing U.S. plans, the Saudi refinery, potentially one in UAE, what you are doing in Germany and you may be looking at other things.

Should we think of all of these as a series of options of which you might execute on a few of them or are you really -- is it your intention to go forward with all the projects that you've highlighted thus far?

I think the real gist of the question is the spending, if it occurs over the next five years, it’s happening at a time of very high engineering and construction costs, steel costs, etc., and obviously the fear is that you spend in the high environment and who knows what the long-term outlook for refining is 10 or 15 years in the future.

But how do we have confidence that the returns would hold up if the environment turns out to be much different than what we’ve been in?

Thank you.

Arjun, thank you, you make a good point.

It’s not just about refining capital spend.

It’s capital spend for all of our very large projects.

We are experiencing and see when we look at these new projects, many of which have not been as you outlined not sanctioned at this point in time, and we see some very significant increase in capital costs.

And as I said earlier, our capital spend for next year -- I said $15, $16 billion.

It may be very likely it could be less than that.

We are looking at all these projects, and we also look at what we think the normalized pricing environment will be on crack spreads and oil and gas prices.

And in many regards we don't like what we see in terms of the increased capital costs.

So whether you call it option value or some of these projects, are they going to go forward or not?

A lot is going to depend upon what the capital costs are for these projects because when you commit to them they take many years to build.

And then we have to take a very realistic assessment of normalized pricing assumptions, which we don't use in our models to be with that which we've experienced here lately in terms of oil prices and crack spreads.

So I think you're right, we push many of these very, very hard.

We are very pleased about the opportunity in Saudi Arabia but have quite a number of these; we frankly are going to have to step back and assess capital costs whether we think it makes sense for us to commit capital to do all these projects.

So my response to you is you’re spot on in terms of the impact of capital costs and it is very likely that not all these projects will go forward as we want to constrain our spending.

And second, it may be that a number of these projects just get deferred over a number of years until we see maybe the aggressiveness or cost inflation that we are experiencing for new projects moderate some.

So you're right, not all these projects will go forward, and certainly some of them will get deferred because we feel very strong about the discipline that we need in terms of achieving.

We want to get the debt down, as we said down towards $20 billion by the end of '07.

We want the debt ratio at below 20 percent, and we’ll ramp up with the pricing environment, annual dividend increases and share repurchase.

So, we’re really stopping and taking a good hard look at the capital spend.

Not all these projects are going to get sanctioned.

Jim, that’s a very helpful answer, I do not mean to put you on the spot but would you care to share your current view of normalized prices, for oil and maybe refining in particular?

Well, I think when we look at crack spreads and refining what we really look at is really more the ten-year normalized numbers which are quite a bit lower for the U.S. and Europe and Asia, and we look at what we've seen in the last two years; we don't use that for our crack spread assumptions.

So we look at something a little bit higher than the ten-year average, and then I think with the oil and gas prices, why don't we just share that when we go through with you in March?

That's terrific.

Thank you very much for your response.

Your next questions is from Steve Enger with Petrie.

Hi guys.

Jim, I guess a broad question with maybe a little specificity around Venezuela.

Can you give us some comments as to how you are seeing at this point in time your interest in doing business down there?

And, specifically on Corocoro, do you slow down the development timeline that you may have had and kind of see how things are going to shakeout or are you pushing ahead aggressively?

How are you looking at that?

Well, obviously Venezuela is difficult for us at this point in time.

We continue to certainly talk and work with PDVSA and the ministry.

Our projects, we have substantial investment in Venezuela in terms of Petrozuata, Hamaca and we are building the first phase of Corocoro.

Everything that we said we were going to do for Hamaca and Petrozuata we are doing.

Our volumes are spot on per the contract.

We’re running well.

We would like to expand and develop.

I should say we have the ability to expand the volumes of Petrozuata and Hamaca, but of course that takes a lot of discussion with PDVSA and with the ministry.

And we're in the process of doing just that with the ministry.

In terms of Corocoro, there is no change.

We've committed.

We will bring Corocoro and develop it, the first phase is as we've outlined.

It has all been approved.

Capital spend committed, it is built into our plans.

In terms of further phase development of Corocoro or other projects in Venezuela, I think we have to really stop, assess and work with PDVSA and ministry to see whether those are value creating for ourselves and as well as for the country.

Yeah, fair enough.

In Alaska, coming out of some of the recent events at Prudhoe Bay, do you see any significantly different practices?

Do you think costs are going to increase meaningfully up there as a result?

Well, first, practices, we all -- all companies use and share best practices with each other.

I know for our operations where we are the operator for Kuparek, Alpine and west of Prudhoe, we continue to for multiyear effort work very hard in terms of maintenance and doing all the latest in terms of inspection.

We’re going to do even more than we've ever done before, more routine.

I know the same is going to be done at Prudhoe so practices have changed.

We thought we were all doing the right thing but we are going to be doing even more; result is that the cost will be higher in terms of maintenance operation and all.

But it would have a real significant impact on, I will say income, cash flow and all.

It will continue to be a real significant contribution legacy asset for our company.

Sure.

And then finally on Alaskan gas, obviously we seem to be at a pause there with elections coming up.

Is that fair and what is situation the vis-à-vis the proposed reserves tax?

Well, we‘re very disappointed that what was negotiated with the governor, negotiated by our company, along with Exxon Mobil and BP, we worked hard on this for the better part of at least two years.

We thought it was certainly a win-win for the state of Alaska, certainly a win for North America and the United States and for our companies.

This is indigenous natural gas resources that need to be developed.

And just couldn't get it through and approved by the legislature for a lot of different reasons that are really pertain to the state of Alaska.

We are very disappointed it didn't go through late last year, and certainly this year.

I think we've lost at least one year, if not two years, getting this project going forward.

We obviously know that we will be working with a new governor, and that will as a result of the elections with less than two weeks from now.

In terms of the reserve tax on natural gas, we’re very much opposed to this because, first of all, we don't think it makes good economic sense, and that's going to further delay the development of the gas pipeline.

We talk about the gas pipeline, it is not just for Prudhoe Bay and Point Thomson, but once the gas pipelines put in place, the infrastructure we know that there is a lot more gas resources up in Alaska that can be developed.

So we very much oppose the reserves tax because we think it is going to have an adverse impact in terms of development and delay the gas pipeline.

We also don't think it is good economic or public policy.

It's not good for the state of Alaska, it's not good for the country, and it’s not good for the producers.

So that's our view.

Yes, I agree.

Good luck on getting it restarted and moving to market.

Your next question is from Dan Barcelo with Banc of America.

I wondered if you could give a little bit of a strategic update on LUKOIL.

Maybe a little bit of progress on Timan-Pechora, any discussions yet on West Qurna?

Also, in terms of LUKOIL strategy, they've talked about interest in the U.S. downstream at various degrees in time.

And are there any thoughts to start thinking more about integration downstream with LUKOIL?

Thank you.

Okay, first with respect to LUKOIL, I congratulate LUKOIL and its leader, CEO, Vagit Alekperov, very much admire him, respect him.

He is a good friend.

Obviously we work very close together.

He just last week celebrated the 15th year of anniversary, LUKOIL has.

Our strategic relationship is going very, very well.

We meet quite routinely to see what it is that we can be doing together.

Lukoil and ConocoPhillips in Russia and outside of Russia.

So as I say, we meet just about every month or every two months and we talk pretty frequently on the phone.

So everything is going really well in terms of relationship with LUKOIL.

Timan-Pechora, our joint venture, it's a challenging development of the YK field and hopefully, in time, other satellite fields in the area.

It is challenging because it is way up in Siberia, but we continue to work hard on this along with LUKOIL.

We have equal governance.

We seconded employees up there, signed them to the joint-venture.

We see production starting up late '07, essentially more '08.

And of course we have the pressures on costs and the pressures on everything.

It is technically and commercially challenging, but we have no reason to feel differently about this project than we did when we sanctioned it and put it together.

In terms of the West Qurna Field, of course you know that is in Basra area southeast Iraq.

We feel quite strongly that that contract, which was negotiated between Saddam Hussein and (technical difficulty)ago is a good contract, and we are expect and working on it will be confirmed by the existing Iraqi government.

And then we look forward to working -- we have 17.5 percent interest, we look forward to working closely with LUKOIL because we think it is a pretty significant opportunity.

Now we also look at other things that ConocoPhillips can be doing in Iraq, but we are looking for the stability of the government and security before we can advance this, and I know I don't think our position is any different than the other companies in the industry.

We would like to see this stability and security sorted out because it’s an opportunity for the world to develop a lot of oil and hopefully gas resources that is diversification and needed in the world.

But the thing we are working on most is with LUKOIL, the U.S. government, the Russian government to confirm this contract in West Qurna.

We think that that would be a unique opportunity not only for LUKOIL, but for ourselves.

In case of the downstream, we work closely with LUKOIL.

I would have to say we've seconded employees into LUKOIL, to help them upstream, downstream, they live and work in Moscow and Russia.

LUKOIL has secondees with our company here back in the United States.

I would say that we, on the downstream we look at how we can help each other, but I think when you look adventures or opportunities to invest together it is primarily Europe and eastern Europe.

Thank you.

Gentlemen, your next question is from Doug Terreson with Morgan Stanley.

Good morning, guys.

Jim, I think that you mentioned recently or might have been quoted saying that strategic actions might be less likely for the company over the intermediate term with the rise in asset prices and so, first, is that a true statement?

And, either way, could you provide some color on the trends you're seeing in the asset markets both in the upstream and the downstream?

Okay, Doug.

Thank you.

In terms of strategic transaction, of course our company has done a lot of transactions over the last five or six years, and I don't see a strategic acquisition or transaction in the cards for us.

I can't say never, but we've got a lot that we need to be working on, organic growth, digesting all the things that we’ve done.

I think we've been making good progress in terms of assimilation of all the things we've done.

We are working on synergy capture from Burlington Resources.

We want the balance sheet right.

We are working hard on consistency, reliability of operations.

We know that translates all of those things, translate along with a stronger balance sheet, debt reduction and increased dividends to a better share price.

But I have to look at what is available potentially in the way of M&A transaction; everything is very, very expensive.

And so we know, and our shareholders, we talk with our shareholders, we've talked to the buy-side, sell-side analysts in the marketplace, and we feel it is really important for us to at this point in time -- I just don't see us doing large strategic transactions.

Maybe that comes years down the road, but we have a lot that we need to be working on, and we have to just as the earlier question/comment, our capital spend, we've got to look at the cost of everything, reign in our capital spending, can't do all these projects.

The emphasis really is going to be directed towards shareholder value creation, to sticking with what we have and the organic growth that we have.

And in terms of assets, cost of assets, I think they continue.

We’re not surprised, but the cost of E&P asset and the cost of refining capacity continues to go up.

And in terms of the refineries, essentially we believe I don't know this for sure, but acquisition refineries it's almost approaching 100 percent replacement cost.

So it’s pretty difficult to look at buying things upstream and downstream.

Okay and also I think that you mentioned earlier that the proceeds from the divestiture program were likely to approach $3 to $4 billion and the timing was the end of '07.

And that is obviously a pretty significant number even for a company your size.

So is that mostly a North America number or are there other components of that number that are relevant as well, and if so what are they?

Well, we have some very mature assets in North America E&P and Canada and the Lower 48.

And those are things that essentially, production is produced in the next 18-24 months, and we look at and say can we monetize it for more than holding it?

Now there’s no strategic important legacy asset that we are selling.

We are looking at some of the smaller positions that Burlington had international that we would consider selling and monetizing.

We’re looking at marketing and minority interest in refinery size, the downstream part of Europe.

Maybe some midstream assets, but that is essentially what it all adds -- I may be missing a few points but I'm trying to give you color.

We think that that all adds up to $3 or $4 billion, and the other thing is when we sell these assets, it doesn't have a lot of impact to income or cash flow, particularly if you look out on the E&P side two or three years from now.

It doesn't change production profile of the company, maybe in the short-term but not in the long-term.

Longer-term meaning two or three years or four years from now.

The other thing is we don't want to sell anything that has a big tax bill.

It doesn't make a lot of sense to sell something and then pay 50 percent tax.

So it’s got to be very tax efficient, as well.

Okay.

Those are good answers.

Thanks a lot.

Okay.

Your next question is from Paul Cheng with Lehman Brothers.

Thank you.

Good morning, gentlemen.

Jim, two quick questions.

One, in the past you have shared with us that in the downstream, the breakdown between refining and marketing profit splits.

Wondering if you can share with us for the third-quarter on that.

Secondly, in Venezuela, the government have officially contacted the company in terms of picking a majority ownership in Petrozuata and Hamaca?

Also then after I think the they passed a law they wanted to raise the effective income tax rate to 50 percent.

If the new tax rate has been enacted in the third-quarter we sell, if not when it is going to be.

Thank you.

I will get the first two questions.

First, on refining and marketing, the split in the third-quarter.

In the third-quarter, domestic refining did about $1.2 billion of net income.

Domestic marketing did $200 million net income.

International refining did about $150 million of net income.

International marketing did $100 million net income, and the other is a loss of $200 million, and that is primarily the impairment of assets held for sale.

Remember we said $249 million, so it doesn't – you know -- I have given you the four, five parts that come up with $1.464 billion, so it doesn't all add up just perfectly, but that gives you the split, the $1.464 billion of net income in the downstream.

Yes.

For the quarter.

In terms of Venezuela, I think the thing to indicate there is that we are in discussions as I said earlier with PDVSA and the ministry.

In terms of their expectations of what they would like to do with Petrozuata, the heavy oil projects like and the Orinoco Belt, Petrozuata, Hamaca.

We are in discussions and talking with PDVSA and the ministry.

In terms of the tax question either Gary or John, maybe you can comment on that.

The tax rate was raised to 50 percent effective January 1, 2007.

And when the impacts were what we outlined earlier on the call, that there was a deferred tax impact that if we took in the third-quarter, but the tax actually applies commencing January 1, 2007.

Thank you, gentlemen.

Your next question is from Neil McMahon with Bernstein.

Hi, good morning.

Jim, maybe if we could turn to page 17, the net income for barrel chart, I’m really struggling with this to see how this is going to be competitive whenever the all our third quarter results come out.

If you look at the difference between the third quarter of '06 and compare it to 2004 there’s not a huge increase in net income for barrel, but there has been a 50 percent increase in the combined oil and gas commodity prices.

And is this not a bit worrying going forward that if a very similar situation in commodity prices the first of Q2 '06 you've got such a big drop in net income per barrel?

Maybe you can walk through where the major increases are there and what it looks like going forward.

Well, first, you make a good point.

Part of that is you see some reduction in the price environment, but also it’s a mix.

In other words, where do you have -- where are your barrels coming from?

In some cases your barrels are coming from I will say non OECD, you may have volumes but you have less profitability.

Maybe the cost structure is offset or lower cost structure.

But for us what we are seeing some impact also is with the Burlington transaction we see lower natural gas prices.

You factor that in that is impacting our per barrel profitability.

Going forward, our approach and view as we've been pretty transparent about this, is we feel very strongly about the foundation of our company, the E&P and the downstream business having a lot of exposures to OECD production, reserves in production.

We will pay a higher finding development cost because we believe that a pricing environment doesn't have to be at $70 a barrel or $60 a barrel of oil.

And has to be at $10 an Mcf but the after-tax return from Alaska, Canada or Lower 48, U.K., Norway and I know it is not OECD but Australia, we like the after-tax return.

So our $11.63 is being impacted by the mix.

It is being impacted by increased taxes.

We see increased taxes we just said it is Alaska, as well as other -- U.K.

So that is bringing the per barrel number down.

Also the natural gas associated with the Burlington transaction is bringing the per barrel down.

But long-term, going out forward, we think we will be not only competitive, but differentially more competitive than some of the opportunities that are available in the international side of the world when it’s your profitability per barrel.

Neil, you also have to look at the third-quarter number as having been adjusted only for kind of the onetime items.

We did not place the U.K. first-quarter and second-quarter adjustments back in the first half, nor did we take the Alaska adjustment for the second quarter and put it in the first half.

So you've got a little mix effect on that, as well.

Gary, we've gone and done that, and it still looks like a massive drop.

It actually places you in a similar range along with ENI and Total in terms of your competitive mix having been up at high prices, Exxon Mobil and Marathon.

Just really wondering going forward, as you're starting to see this evolve, does this not get you a bit worried in a lower oil price environment if we do go lower into 2007, that you become quite uncompetitive actually, versus some of your peer group, as well as on being competitive as you had been in a rising oil price environment?

I guess what I would say, Neil, is Jim indicated that some of the impacts were mix-related.

I guess we will see as we go forward where the number lands, but the numbers note what it is in the third quarter.

So.

Okay.

Thanks.

Gentlemen, your final question is from Doug Leggate with Citigroup.

Thank you.

Good morning, guys.

I think we’re still in the morning, I guess.

I want to go back to a couple of things that were discussed, Jim, if that is possible.

One of them was the CapEx outlook, I know it comes up an awful lot.

But I just wanted to be sure that my understanding was correct that the current CapEx budget is aligned with the current strategic plan in terms of production growth and so on.

Is that statement correct?

That ‘s correct.

So does that mean, therefore, that all the options that you have secured, the risk obviously that none of those options have been placed into the current CapEx plan, therefore, the risk the CapEx numbers are on the upside.

Is that a fair statement?

I am not sure what options you are referring to Doug.

Can you help us?

Well, for example, you have a number of possibilities, such as Brass LNG, such as the gas situation in Alaska, such as what is going on in Qatar.

Obviously now the EnCana deal and so on and so on.

There is obviously a number of things that you have that are potential upsides to that CapEx fund.

I just want to make sure my understanding is correct that the current CapEx budget, the guidance you've given us, does not include any of those assets.

And that it basically aligns with the current production target.

No, that's not true because we've already sanctioned and committed to the Qatar project for Qatargas 3.

But it does not include in the budget going forward, full development of the gas pipeline from Alaska.

Those are projects that we spend money to nurture and grow and develop.

But we have not included capital spending to build gas pipeline in Alaska.

But we have included committed sanctioned projects by the company, by the board, such as Qatargas 3.

It's not that we are ignoring these projects.

The gas pipeline from Alaska is a very elongated project.

You wouldn’t expect to see any capital in 2006 and 2007 for that.

Of course, but I think for example there has been a lot of things added on and a number of them have mentioned obviously on the call but for example, the CapEx associated with the refinery expansions and investments, are those included in the $15 to $16 billion?

Those that are approved, yes.

But if we look at going forward for our company, what we find is when we say $15 or $16 billion, we have committed confirmed projects as we look at 2007, 2008.

But if you go out into the third, fourth and fifth year, those projects, many of them are starting to be started up, plus capital spend.

So you have the open area that you hope is going to be the gas pipeline from Alaska.

You hope it's going to be success from exploration which leads to appraisal drilling and all.

So, for guidance purposes, we say $15 billion, $16 billion the next year or two.

But if you look out in the future, we don't have all the projects that add up that have already been sanctioned and confirmed as you go say beyond two years out, '09, '10, '11 and '12.

Okay, I guess the only other one I have is you have given some timeline on disposals and the potential proceeds for that.

Are you in a position yet to give us any indication as to how this impacts the volume targets, the growth targets for the upstream?

Well, I said earlier we are probably going to see some reduction in our E&P volumes.

But the reduction is going to be more of a short-term nature.

In other words, we’re selling things that generally have production that tails off pretty quickly over the next two or three years.

And the result of that is when you look out 2009, 2010 that which we sell will not have -- you know -- much impact on the targets that we had before we announce the program and after we complete the program.

And we're going to share a lot more about all this with you when we meet and go through our plans in I guess February, March in the analyst meeting.

Okay.

That's it for me, gentlemen.

Thank you.

Ladies and gentlemen, as that is all the time we have for Q&A today, I will hand the call back to Gary Russell for closing remarks.

Thanks, Jen.

I want to thank everybody for joining us today and I would remind you that you can find the presentation material that we went through today along with the transcript of the call on our Web site: ConocoPhillips.com.

Thanks again for joining us, and 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 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 25, 2006 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, 2005, 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, 2005.

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 25, 2006, 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.