康菲 (COP) 2006 Q2 法說會逐字稿

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

If at anytime during the call, you require assistance, please press * followed by 0 and a coordinator will be happy to assist you.

I will now turn the presentation over to your host for today's call, Mr. Gary Russell, General Manager of Investor Relations.

Please proceed, sir.

Thanks, Jen.

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

I'm joined today by Jim Mulva, our Chairman and Chief Executive Officer, as well as John Carrig, our Executive Vice President of Finance and Chief Financial Officer.

The presentation material that we will use today will help us explain the financial and operating performance of our company during the second quarter of this year.

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

On page 2 you will find our Safe Harbor statement.

This statement, among other things, says that our presentation today, along with responses to your questions, will include forward-looking statements about our current expectations.

Our actual results may differ materially from our current expectations.

You can find a list of the items that may cause material differences between our current expectations and what actual results will be -- can be found on our filings with the SEC.

So now I'll turn the call over to Jim Mulva.

Gary, thank you and I appreciate all those who have called in for our second-quarter earnings conference call.

I appreciate your interest in our company.

And I'm going to start with my comments on page number 3.

And looking at page 3 or slide 3 you can see we generated $5.2 billion in net income, $4.8 billion in cash flow from operations.

We continue to fund our capital program and other investments in the second quarter and through the first half of the year.

So far this year we've effectively reinvested 97 percent of our income back into our businesses.

In addition, we were able to reduce our debt level to $29.5 billion from $32.2 billion as we started the second quarter, so our debt-to-cap ratio has gone from 30 percent to 27 percent.

We're pleased with the progress we've made integrating the Burlington Resources operations into our portfolio.

As such our second-quarter results include the full impact of the Burlington Resource assets for the entire second quarter.

Now looking at the second quarter of 2006 our E&P production, which excludes LUKOIL -- the LUKOIL segment, was 2.13 million BOE a day, which is higher than the previous quarter as we expected.

And I'm going to cover more about production in some subsequent slides.

Our estimate share of LUKOIL's production for the quarter was 403,000 BOE per day.

In refining and marketing, our refineries ran at 91 percent of crude processing capacity -- that's up 6 percent from the prior quarter.

We have a subsequent slide on return on capital employed which is competitive and we'll discuss ROCE a little bit later in the presentation.

So I'm going to move now to page 4.

This slide shows a sequential quarterly comparison of our net income.

A major contributor to the variance between the prior quarter and this quarter is the inclusion of Burlington Resources in the second quarter.

Our worldwide realized oil prices and refining margin were higher than the first quarter.

However, worldwide realized natural gas prices, along with olefin and polyolefin margins were lower than in the first quarter.

The net effect of all of this along with some other market impacts increased our second-quarter net income by about $1.2 billion compared to the first quarter.

Second-quarter net income was positively impacted by about $1.3 billion and this is a result of higher E&P sales volumes, higher volumes in our downstream segment.

We're going to talk more about this in subsequent slides.

In addition, the net impact of recent changes in tax legislation in Canada and Texas, they were positive.

In Venezuela the tax legislation change is negative.

The net effect of all this though improved our second-quarter earnings by $376 million.

Sequentially we had higher DD&A and that reduced earnings by about $523 million.

Our operating costs were higher by $287 million compared to the previous quarter.

I'll talk more about this in subsequent slides.

And then last, our financing costs were higher as a result of the Burlington acquisition and then there were some other minor items that basically offset each other.

So the result is, as you can see on the right hand of the slide, net income was approximately $5.2 billion.

Now I'm moving on to page 5 -- total company cash flow.

You see we started the quarter with a cash balance of about $3 billion and then we generated $4.8 billion in cash from operations.

Our capital spending and investments amounted to $3.6 billion in the quarter.

This included the acquisition of 1 percent of LUKOIL's outstanding stock and that cost us about $648 million.

And we paid out $595 million in dividends and then we reduced debt by $2.7 billion.

Also, we purchased 6.7 million shares of ConocoPhillips stock in the second quarter at a cost of $425 million.

We're on target for completing the 1 billion share buy-back program for this year.

So after considering the other sources of cash flow we ended the quarter with about $650 million of cash.

I'm moving on to slide 6, which is the capital structure of the company.

Looking at slide 6 you can see we made good progress improving our debt ratio.

If you look at the chart on the left you can see equity grew to $79 billion in the second quarter.

The balance sheet debt you can see in the middle of the slide is $29.5 billion, so the debt ratio has come from 30 percent down to 27 percent at the end of the second quarter.

I'm moving now to E&P, exploration and production, on page 7.

Our worldwide realized oil prices for the quarter were $64.34 a barrel.

That's 14 percent higher than the previous quarter which was $56.63 a barrel.

Global realized natural gas prices for the second quarter is $5.85 per MCF, 19 percent lower than the first quarter which was $7.24 per MCF.

Our E&P production in the second quarter was up 32.5 percent mainly due to the addition of the Burlington Resources assets production.

And the initial would be in crude oil with these.

Furthermore, our exploration expenses were $134 million in the second quarter, $22 million higher than the previous quarter but it's somewhat lower than we expected.

Moving on to page 8 -- total company production.

You can see on this slide that just illustrates the sequential variance for the second-quarter production compared to last quarter.

We saw higher BOE output largely due to adding the Burlington Resources assets and then the initial liftings that we talked about in Libya.

And we also saw higher production from the ramp up of production in the Timor Sea and all this increased production was -- that we talked about here in this slide was partially offset by planned maintenance in the United Kingdom and then the impact that the higher crude prices have in terms of our production sharing contract production in Vietnam.

There were some other negative impacts to our production in the second quarter which included the seasonal declines that we experienced in Alaska and then the on-plan downtime that we have not only in Alaska but the Lower 48 and at Hamaca.

When you add 403,000 BOE a day, which is the estimate of the equity share of LUKOIL's production, then all in the second quarter our production was 2,537,000.

So now I'm moving on to net income of E&P, page 9.

In the second quarter our E&P net income was $3.3 billion.

Now that's about $750 million more than the previous quarter.

Our first-quarter results were improved $76 million over the previous quarter mainly due to higher realized crude prices partially offset by lower realized natural gas prices.

Burlington Resources' assets contributed $385 million to E&P segment earnings in the second quarter.

If you exclude Burlington Resources, sales volumes were lower mainly due to the timing of the liftings.

This reduced our quarter-over-quarter earnings by about $19 million.

The net impact of recent changes in tax legislation in Canada and Texas which were positive, negative in Venezuela, but the net effect has improved our second-quarter earnings by $363 million.

Then there are some other factors that reduced our second-quarter E&P net income as compared to the previous quarter and it included some higher impacts from foreign exchange and then we wrote off a small amount of the investment we had in the Compass Port LNG facility.

Now I'm moving on now to refining and marketing on page 10.

You can see our worldwide refining margins were quite a bit higher than the previous quarter.

In fact, in the second quarter our realized crack spread improved $7.05 a barrel to $17.23 a barrel and our international realized crack spread improved by $2.34 a barrel to $7.64 a barrel.

Our U.S. refining system ran at 91 percent of stated capacity and that's up from the 83 percent that we had in the first quarter.

All of this is a result of some pretty heavy turnaround activity and unplanned downtime in the first quarter, as well as in the middle part of April, we turned the Alliance refinery back to normal operations.

International refining system ran at 94 percent of stated capacity which is the same as the first quarter.

We're going to discuss turnaround activity and unplanned downtime in another slide.

Our turnaround expenses amounted to $115 million pre-tax for the quarter and that's about $48 million lower than the prior quarter.

I'm moving on to page 11 - R&M net income.

As you can see, our net income was quite a bit higher than the previous quarter, up by $1.3 billion.

So we had significantly higher worldwide crack spreads and marketing margins along with other market impact.

So it improved our second quarter by about $1.1 billion.

Higher volumes improved our earnings $160 million.

Several, though, of our refineries which were down in the first quarter for extensive turnaround activity and unplanned downtime returned to normal operations in the second quarter.

As I said earlier, our Alliance refinery returned to normal operations in the middle part of April.

However, this benefit was partially offset by extended full plant turnaround at the Trainer refinery and then we had unplanned downtime at the Lake Charles and the Humber refineries.

So the result was our worldwide crude oil utilization was 91 percent.

The impact of recent changes in tax legislation in Texas helped our second-quarter earnings by $34 million and there are some other factors that improved second-quarter downstream net income as compared to the previous quarter, and it included the lower impacts from foreign exchange partially offset by higher DD&A as a result of having the Wilhelmshaven refineries for a full quarter.

Now I'm going to give you some numbers that reflect just what we did in the second quarter by the components of the downstream part of the company -- it's not in a slide, but you might want to jot these numbers down.

In the second quarter refining in the United States our net income was $1,484,000,000.

Our international refining net income was $267 million, so in refining around the world we earned $1,751,000,000 in the second quarter.

Now in marketing in the United States we lost $76 million.

In international we earned $17 million, so marketing around the world was a loss of $59 million.

But when you add up not only refining and marketing worldwide, but then we have some expenses that held at the corporate part of the downstream part of the business and we have specialty -- all in, everything was $1,708,000,000, but I wanted to give you the numbers on refining and marketing to help you better understand the components of our downstream earnings in the second quarter.

Now I'm moving on to page 12.

We increased our equity ownership in LUKOIL by 1 percent.

We're now up to 18 percent at the end of June, so as a result our average ownership in the second quarter was 17.5 percent.

So our estimated equity earnings for the second quarter from LUKOIL was about $387 million and that's up from the $249 million in the first quarter.

This increase is mainly attributed to the benefit from the alignment of our estimates in the fourth quarter of '05 and the first quarter '06 and also to LUKOIL's publicly released results for this time period but to this true-up.

And also contributing to the increase was the higher ownership that we had from quarter-to-quarter and our higher estimated sales volumes and higher crude oil prices.

So all this contributed to stronger performance from the LUKOIL segment.

Now moving on to slide 13 where we talk about our joint ventures in the midstream and chemicals.

Our earnings from the midstream business were $108 million in the second quarter, pretty flat with the first quarter.

And in our chemicals JV our earnings were $103 million, $46 million lower than the first quarter and mainly due to the lower margins that we experienced in the second quarter from olefins and polyolefins.

Now with respect to the emerging businesses, the results were $20 million lower than the first quarter mainly due to a write-off of a failed gas turbine at our Sabine River Works cogeneration facility.

If we didn't have that obviously the results would've been much better in the second quarter.

Now I'm moving on to slide, page 14 where we take a look at corporate sequentially.

The corporate segment impact on net income was a loss of $412 million in the second quarter, and that's $244 million higher than in the first quarter.

This is about $50 million higher than the quarterly run rate in the guidance we gave in our first-quarter conference call.

The difference is primarily a one-time transition items and the impact of foreign exchange.

Subsequent quarters are expected to be back in line with our previous guidance.

The previous guidance and what we're giving now is about $360 million a quarter.

Now going back looking at the second quarter on this slide, the net interest expense was $166 million higher than the previous quarter and it's due to the higher average debt balance resulting from the purchase of Burlington Resources.

Furthermore, the Burlington Resources transition costs were $34 million higher than the previous quarter.

And we had some other factors that impact second-quarter results and generally relates to the impacts of foreign exchange and tax.

Now I'm moving on to slide 15 -- return on capital employed.

And, what this chart shows, first, the green bar is our return on capital employed for ConocoPhillips, and the shaded area is the return on capital employed as the numbers are available for the peer group and we look at the peer group we look at the largest publicly traded international oil companies -- Exxon Mobil, BP, Shell, Total and Chevron.

So the bar chart reflects our return with no adjustments for purchase accounting.

What we've done is we made adjustments.

For our estimate of the pooling benefit that some of this peer group received from past major combinations in determining their ROCE which is shown in the shaded area.

And so you can see the adjustments that we made we've included in the attachment on Table 1 so you can take a look at that.

So as you can see on the right bar, our analyzed return on capital employed for the second quarter of '06 was 19 percent.

This includes the full effect of the Burlington Resources transaction.

The breakdown to 19 percent a little bit more.

Including the Burlington transaction E&P was about 16 percent ROCE.

This was all on purchase accounting.

Refining marketing was 32 percent, midstream chemicals was 26, LUKOIL was 22 and the blended is 19 percent.

At the First Call pricing for the last half of 2006, along with the second-quarter actual results, the Burlington Resources dilution is approximately 6 percent.

Now that's higher than we indicated in the first quarter due to the lower natural gas prices in the second quarter.

It's higher -- the dilution is higher by about 1 percent from what we thought when we went forward with the transaction.

If you use current First Call pricing weighted on Burlington Resources' balance between oil and gas, remember they have -- about 30 percent of Burlington Resources are oil and 70 percent is about gas.

And the MCF equivalent has not materially changed from when we announced the acquisition in December 2005.

These numbers are not available but let me go through it because I think it's important to understand.

The First Call pricing for oil when we did the transaction announcement December 9 of '05 for all of 2006 was a price of $57.50.

The current First Call oil price for what we've experienced this half, part of the year and for the remainder of this year is $65.68.

Now if we go to the First Call gas price back in December 9 of '05, the First Call gas price was $8.52 an MCF.

Currently, if you look at what's happened in the first two quarters of this year and the First Call for the third and fourth quarters, that First Call then is $7.49 an MCF.

And also to point out -- make a point here, back at December 9 of '05 the First Call Gulf Coast crack spread assumption was $8.50 a barrel.

Currently, for all of this year of '06, the First Call Gulf Coast crack spread is $11.71 a barrel.

Now if you convert the oil production of Burlington Resources back to an MCF equivalent and at December 9 of '05 the view was on First Call you had an MCF equivalent Burlington Resources' production was $8.85 an MCF.

If you take what's taken place the first six months of this year and First Call's view of oil and gas for the third and fourth quarters, then the equivalent for all of '06 is $8.56 an MCF.

What we're trying to say is that when we did the transaction and announced the transaction back in December we said we assumed that the MCF equivalent would be for '06 was $8.50 for '06 for Burlington production and $7.50 for '07 and $7 in '08.

Well, what you can see is on an MCF equivalent it's pretty much what we thought for different reasons in '06.

Obviously gas price is lower, oil price is higher.

The reason we get the 6 percent annualized dilution on earnings is because the gas production has more profitability than the oil production at Burlington Resources.

But more importantly, you can see we get the dilution impact by more shares outstanding because the downstream is quite a bit stronger.

What we're trying to say is the dilution on income is about 1 percent higher than we thought when we announced the transaction.

Now with respect to the accretion on cash for the year using these assumptions and actual for the first six months of the year, we see the cash accretion for this transaction about 2 percent.

That's about 1 percent lower than we thought for '06.

Now the net income breakeven for the Burlington production on an equivalent basis, we shared with you in prior discussions -- the conference call is about $4 an MCF.

So that's why we wanted to provide you our assessment and views of the Burlington transaction after the end of the first quarter and how we see it going forward for the remainder of the year.

Now I'm going to go to slide number 16 which is our outlook.

Obviously we're continuing the integration of Burlington Resources into -- their operations into ConocoPhillips' global portfolio.

We're pleased with the progress to date.

Another point, in July the United Kingdom enacted higher income taxes retroactive to the beginning of the year.

In addition to the ongoing impact of this rate change, we anticipate a onetime third-quarter charge of about $400 million which includes approximately $125 million related to the company's operations for the first six months of '06.

So we want you to factor that into your assessments and projections going forward for third and fourth quarter.

Our recently announced asset rationalization program is progressing.

We expect to finalize a listing of the assets to be sold and then begin active marketing of them in the third quarter.

As we said, this program would be done over the third/fourth quarters of this year and then over into 2007.

Now although we expect this positioning of the assets to result in an overall gain over this 18-month time period, it's reasonably likely we will record an impairment in our third-quarter '06 financial statements as we change the financial reporting status of these assets from continuing operations to assets held for sale.

And then like we always do and continue to do as a company, we pursue a number of additional business development opportunities, a few of which I'd like to just mention before I close and we go to your questions.

We recently signed an agreement with Saudi Aramco to do a very detailed evaluation and then as we plan going forward with the development of a 400,000 barrel a day full conversion refinery at Yanbu, Saudi Arabia.

In addition, we recently signed an agreement with an international petroleum investment company known as IPIC in Abu Dhabi to study the development of a 500,000 barrel a day refinery at Fujairah, United Arab Emirates.

Both of these ventures fit very well with our basic overall strategy to invest in projects that expand our global refining presence supported by our commercial activities and help and support what we do in the upstream as well.

And this helps us grow our portfolios around the world.

A second agreement was also signed with IPIC which allows us to work together in identifying not only downstream, but also some upstream opportunities that we can be working together.

So this really concludes what opening comments that I had.

And so I think we're now ready, Gary, to move to questions.

We'll take questions that myself, you Gary or John Carrig will try to answer.

Okay, Jen, I think we're ready for some questions.

Ladies and gentlemen, if you wish to ask a question, please press * followed by 1 on your touchtone telephone.

If your question has been answered or you wish to withdraw your question, please press * followed by 2.

Please press * 1 now to begin. .

Gentlemen, your first question comes from the line of Arjun Murti, Goldman Sachs.

Thank you, Jim.

My question was on how we might think about the long-term return potential from the potentially two new refineries in Saudi Arabia and UAE?

I guess I clearly appreciate high margin as they are signaling the need for new refining investments.

I guess the question is in all of our modeling, you spend a lot of capital for a number of years and then you need high margins to last for many, many years into the future.

And it seems like in looking back at the very long-term history of this business -- when people built the new refineries and then ultimately there's some period of lower margins, what might it be about these refineries that I guess reduces the risk at some point out in the future that is you know so far out we can't forecast today, but that you won't sort of get stuck with investments that were built in a high-price environment and then the returns don't look so good in a low-priced environment.

OK, Arjun.

Thanks.

Good question.

When we develop these projects we obviously don't assume the crack spreads that we see today.

We assume crack spreads that are more closer to historic margins but somewhat higher.

Furthermore, the commercial arrangements that we have in place will certainly adjust the margins.

In other words, we look at the cost of feedstock such that we see both in good and not so good times in terms of margins that we realize an expected rate of return over the cycle of higher margins and lower margins, so we build in commercial arrangements with our partners to do this.

Furthermore, I think another thing is we, as you know, we will not have full ownership.

We'll have partial ownership in these refineries and we also expect to use some degree of financial leverage in a way that does not come back in terms of recourse to the company so we look at our returns.

A few points.

First, it's going to be more on historic margins, not looking at just the margins we see today.

Commercially they were structured in a way that realizes acceptable returns in good and not so good times.

And then we will also use some leverage, but when we look at our returns it's on an unlevered basis before in making our decision to go forward.

That's very helpful.

If I can just follow up there, I appreciate the term commercial arrangements with partners is probably sensitive and you may not care to elaborate.

When I think of the E&P business, you have sort of these production sharing contracts which often effectively allow some sort of minimum return with some sort of maximum return.

Is that effectively what one might think of here for a new build refinery internationally versus here in the U.S. where you're just going to have the margin exposure relative to the capital that's spent?

Well, I think what we certainly look at and I really shouldn't be getting into too far because it's not that well-developed on commercial arrangements, but we obviously are looking at acceptable returns in a low margin environment.

But we certainly don't expect to be seeing caps on the upper side.

That is very helpful.

I'll stop there.

Thank you very much.

Jennifer Rowland, JP Morgan.

Thanks.

Another question actually on refining.

First, and maybe to really - just to -- to ask this but I'm going to anyway -- do you have any preliminary cost estimates or startup for the refinery in the UAE?

And secondly, what is your appetite for additional refinery deals?

And the reason why I say that is you seem to have a lot on your plate with the Saudi and now the UAE refinery, also the big upgrade project at the Wilhelmshaven refinery and then of course what you're doing in the U.S, so it seems like you have a lot going on, just wonder if you can comment as far as the appetite for doing anything else on the refining side?

Well, thank you.

You make a good point.

We have a lot that we're doing not only in the clean fuels but increasing our capability to handling heavy oil in the United States whether it comes from Canada or it's imported from other sources.

So we've got a lot on our plate in the United States.

As you say, we have the deep conversion project at Wilhelmshaven, we're looking at a grass-roots refinery that we're very interested and excited about in the Middle East.

So we have a lot on our plate.

We look at things that might be available for acquisition.

But frankly, just by the decisions and what we've announced, you can see where our direction is headed more to increasing our capability in what we have and adding to new grass-roots refineries in the Middle East, deep conversion at Wilhelmshaven.

I think we're also interested in something that could help us augment our portfolio potentially in Asia, but I think your question is right up -- spot on.

I think it's somewhat unlikely that we would be looking at -- we'll look always, but given the cost it's unlikely we'll be making refinery acquisitions.

Okay.

And on the UAE refinery, anything you can provide as far as preliminary costs or startup dates?

Oh no, no.

We're in the feasibility -- very early in the feasibility side of Abu Dhabi which is actually coming behind where we are in the study and the technical work that's been done on the Yanbu refinery with Saudi Aramco.

We're quite a bit further along on the project with Saudi Aramco.

Okay, great.

And just another quick one.

What's the status of the Wood River refinery after the damage it incurred last week or the week before?

Is that almost back to normal operations or is it going to be off-line for a while further?

In terms of startup, and we expect by this time -- sometime next week it will be back to full capacity, full operation.

Okay, great.

Thank you.

John Herrlin, Merrill Lynch.

Yes, hi.

Some unrelated ones.

You had a lot of turnaround expenses and time in the U.S.

Given the extensive nature of the turnarounds, going forward will the turnarounds be shorter and less expensive?

Well, a generic response -- not necessarily unique to each refinery, but a generic response.

We've had a lot of turnaround which was -- not only because we have turnarounds, but also we had to introduce new equipment and changes to meet clean fuels requirements.

So that led to more costly and longer time periods for turnaround to meet these new requirements.

Hopefully obviously one of the things that is moving towards operating excellence is we'd like to extend the duration and shorten the time period -- when we do turnaround shorten the time period of cost, but extend the duration from one period of time for a refinery or unit when we do a major turnaround.

So I think we've been pretty good in terms of telling you ahead of time what our turnaround expenses are for the remainder of the year.

If, maybe John Carrig has that he can update you on the third and fourth quarter.

We indicated on the first-quarter call that we expected full-year turnaround estimates for 2006 to be $385-390 million, around that neighborhood and we still expect that.

And of course the bulk of these costs at about 285 have been incurred in the first half of the year.

So we have a much lighter planned turnaround schedule for the third and fourth quarter.

Great.

Upstream regarding the asset sales, can you give us a ballpark on potential volume exposure?

Well, we really don't have that available.

I don't have that immediately available and I think the other important point we would want to say is we're looking at selling in total several billion dollars of assets kind of upstream and downstream.

If we don't get the right price it won't be sold.

So I think we can give you a much better update on that in the third-quarter conference call in about three months.

Okay.

Regarding the corporate Burlington transaction cost, was that pretty much retention and is that the end of those kinds of transition costs?

Those were costs related to retention as well as some exploration type costs that were in the nature of one-time costs.

And we have some transition costs that we indicated that we would expect to have, but to get back to the run rate of the 360 we wouldn't expect these onetime costs to continue.

Okay, last one for me is on North American natural gas.

Mr. Mulva mentioned that prices were weaker in the second quarter.

They've been getting stronger.

You've got a bigger marketing presence now in North America.

So what are you seeing on the demand-side?

The demand, I guess from our point of view, our production is not impacted necessarily by demand.

We are finding a lot of competition in terms of having certainly always the workforce to do all the work that we plan to do and weather impacts that as well.

But I don't think we're finding it an issue with respect to the ability to sell the gas since the issue is with what's the price.

Right.

And the storage overhang.

So there's no new issues out there that we see -- and the demand is dominated by weather.

Okay, I was just wondering if maybe you were seeing some industrial load increase, that's all.

Thank you.

Nicki Decker, Bear Stearns.

Good morning.

I was wondering if you could help me with your 2006 CapEx guidance.

I think you made mention in the press release of a spending level of about $18 billion.

I had you down for $17 billion post Burlington Resources so does that reflect an increase in your CapEx guidance?

No, we still are saying CapEx plus getting to 20 percent ownership in LUKOIL we're going to spend $18 billion, and still -- we haven't changed that at all.

You can look at the first six months of the year and you could argue, well, maybe we won't spend all $18 billion, but we've got a lot of ramp up on projects.

So at this point in time maybe we could say in the third quarter as we go to the latter part of the year we'll certainly update on the numbers, but it's still $18 billion.

And so, some of your competitors have mentioned inflationary pressures.

It sounds like you have some wiggle room in your budget for inflation.

We don't have any wiggle room for -- I thought your question was going to be are we experiencing some pretty severe and strong inflation and cost pressure.

Yes, we are seeing it in just about every part of our business.

So I don't think there's any wiggle room in that regard.

The onus and the difficulty is how do we manage our cost structure.

We're no different than the other companies in the industry.

We are experiencing and it's a difficult subject, but how do we manage the escalation in cost pressures?

It's not only operating expenses, it's also certainly in our capital spending programs.

Okay.

And just on another topic;

I think you ended the first quarter with an underlip position in Libya and you had expected that to be reversed, at least in part, in the second quarter.

Could you just talk about the status of that?

I think a lot of it has been reversed in the second quarter.

We may have a little bit more to go, but we're certainly not in the same position we were at the end of the first quarter.

Gary, do you have anything more on that?

Yes.

I would tell you we're still probably on track to complete the recapturing of that underlip through the end of this year.

We did capture some in the second quarter, you can see some in the numbers.

The production number for Libya was 74.

You would have expected it to be somewhere around 45, so you can see the effect of that capture.

But there's more to come and it probably will take us through the end of the year to get that.

Thank you.

Michael Young, Fidelity Investments.

Jim, good morning.

Great quarter.

I wanted to ask, can you give us an update on your latest contacts with the Venezuelan and Mr. Chavez in particular?

I believe that you were planning to meet with him sometime in the May/June time period.

I was just wondering if that meeting ever did take place.

Our people -- I have not met -- been to Caracas; several of our meetings have been postponed and so we look forward to those coming here over the next month or two.

But our people have -- in exploration and production have been meeting and working with the ministry people in PDVSA and so that has been ongoing.

But in terms of anything new to say with respect to its impact and some of the things we read about it in the media regarding royalty, taxation, impact on operations and Petrozuata and Hamaca, there's really nothing new to report.

Okay.

Doug Terreson, Morgan Stanley.

Good morning, guys, and congratulations on your record results.

In exploration, specifically in Alaska, you guys have a fairly dominant position and it seems like you may have had another success up there.

And on this point I wanted to see if there were any elaborations you could provide at this time on the magnitude of the recent discovery near Alpine.

And also a little bit of an update on the next steps for that program both in terms of exploration and development activity over the next year or so.

Doug, thanks for your comments about the performance of the company.

Actually I don't have anything more to add with respect to what we've been doing up in Alaska.

I think if I just step back on our total exploration program, everything that we've done in the old ConocoPhillips we continue to do as our program in terms of our spend.

Now obviously we have more with respect to the Burlington transaction that we will be doing until the program has expanded.

But in terms of announcing or saying something about the success of the program or what we're doing in Alaska and other places, unless it's already disclosed I don't think I really have anything more to say.

Okay.

And let me just ask you one more question about the proposed new plants in the Middle East.

As you mentioned a few minutes ago, Jim, the Saudi project is more advanced than the one in the Emirates by a year or so.

And so could you elaborate on what you guys might have learned over the past year or so regarding the changing capital requirement to construct new refineries in the world today?

Meaning you talked about some of the obvious competitive advantages that those plants will have, but there has been kind of a wide range of capital investment requirements that have been tossed around.

So could you talk about how that expectation may have changed over the past year or so if you have any updated numbers?

Well, I don't have updated numbers.

Obviously our people are working hard on the numbers.

What's awfully important is the capital investment.

And there's so much that's being done in the Middle East, not only in the downstream but certainly in the upstream in LNG in Qatar and other places that what we are seeing is anything you do -- not only in the Middle East but around the world -- the cost has gone up dramatically.

So we have to really be good stewards of capital and watch this very carefully and have a good idea of what is the cost going to be for a larger refinery or an LNG train or ships or whatever.

And it's quite a factor as we look at the Saudi Aramco project at Yanbu and Fujairah with IPIC in the Emirates.

So I don't really have anything more to say other than we have to -- we'll put in a lot of contingency and escalation when we look at what the ultimate capital cost of these projects will be.

Sure, okay, great.

Thanks again and congratulations.

Neil McMahon, Sanford Bernstein.

Hi, good morning.

I've got two questions.

First of all, when you look at your margins per barrel in the upstream in the second quarter versus the first quarter, they were negatively impacted and it seems largely from much higher DD&A per barrel cost.

It looks like in the U.S. with the Burlington acquisition your depreciation per barrel went up 43 percent.

I'm just wondering what impact you foresee your future divestments having on -- as depreciation per barrel to see if you can drag it back down from the $9.50 per barrel number it is today?

And then I've got a follow-up question as well.

Well, Neil, the divestment program is - it's across the board would be both upstream and downstream assets.

And they're going to tend to be late life assets.

But I wouldn't expect to see a -- to move the needle in a material way in terms of the total company's DD&A per barrel.

Okay.

The second question is -- and I know it's a relatively minor amount -- it looks like it's $25 million in asset impairments in the second quarter which basically hadn't been there for the whole of 2005.

So I'm just wondering if that was associated with the Burlington acquisition.

I wonder, as you've spent more time with these assets, now having a full quarter under your belt and with the persistent low natural gas prices, if there's any greater risk of taking more substantial asset impairments or write-offs associated with goodwill as you go through the year, if there's going to be any ceiling test?

Well, two points.

First, the $25 million or so that we indicated was a property impairment was related to the SRW, the Sabine River Works cogen facility, a turbine there that failed that we talked about earlier during Jim's remarks on the call.

As a successful efforts accounting company, we don't have a ceiling test for our accounting for our oil and gas assets.

As we indicated earlier in Jim's remarks, the asset disposition program we do expect gains overall, but in the third quarter as we changed the status of assets from income from continuing operations assets to assets held for sale, you recognize the losses first.

And we would expect to have some impairments in the third quarter related to the disposition program.

But related to the Burlington assets, we will run the test every year as we always do, and we don't foresee plans of any material write-down.

Okay, thanks.

Doug Leggate, Citigroup.

Thank you.

Good morning, guys.

A couple of things from me.

First of all on the asset divestments, I understand you don't want to give any specific details, but obviously the acquisition of Burlington has had you revisit the upstream, but why downstream?

Why are you suddenly designing to have a look at your downstream portfolio?

Can you maybe just elaborate a little bit on the kind of things you have in mind?

Are we talking about major refinery disposals, for example, or is that just a little bit too far afield?

Without getting into the specifics, we have historically -- strategically, we have had a direction whereby we have been maintaining our position in refining and lightening up on marketing assets.

And with an assets base now that has grown to over $100 billion, and we're talking about a several billion dollar asset disposition program, we regard it as high grading and we're looking across the entire spectrum of our asset base to determine what might be better placed in someone else's hands versus our own.

So I wouldn't -- it's not to say there wouldn't be -- no assets are ruled out.

But we indicated they'd be more on the upstream side, more late life assets or assets that are not strategically significant to us.

And on the downstream side, like I indicated, we've historically lightened up on marketing and there could be some refining, but it would be more oriented towards marketing.

Okay, thanks.

I only have one follow up.

If we look at the debt pay down during the quarter, obviously you delved into your cash by a little bit there.

If we strip the cash and the balance sheet out for a second and look at your capacity to pay down debt from free cash flow even in the kind of current environment.

Can you just give us some sense as to how quickly and what kind of pace you would expect to see the absolute level of debt reduce over let's say the next couple of years?

What kind of aspirations have you got?

What we've said over the next 18 months, which is the remainder of this year and '07, we want to see the debt come down -- first of all we will fund our capital program.

And the capital program looks like it's near $18 billion a year.

It could be a little bit less in '07, but for planning purposes say it's $18 billion.

Second, we want to bring the absolute level of debt down $1 billion a quarter.

Third, we want a competitive dividend and we like the idea of raising the dividend once a year.

We build that into our plans.

And to the extent after doing those items -- three or four items, then what cash flow remains we'll be buying shares in.

That's what we intend to do.

So as you bring the debt down $1 billion a quarter -- we might bring it down a little bit more in a given quarter, but -- and if so right.

But as we get our debt ratio down toward 20 percent, absolute level of debt down closer to $20 billion, then we start doing more on share repurchase.

Okay, that's very clear.

Thanks very much, indeed.

Paul Sankey, Deutsche Bank.

Hi.

Good morning, gentlemen.

Continuing somewhat with the theme here.

In the past you've talked about trying to get your capital employed more into the upstream and less into the downstream, and off the top of my head I believe you used to talk about going from 60 percent upstream downstream to towards more like 70 to 75 percent.

Are you still working within some kind of parameter like that and could you elaborate if you are?

Thanks.

Well, we look at the opportunities and it just happens that the portfolio breaks out to where it is today.

But we are trying to do quite a few things in the upstream -- gas pipeline from Alaska, LNG projects, heavy oil projects -- but then on the downstream the opportunities that we have -- clean fuels -- not on clean fuels but increasing our capability to handling heavy oil at refineries domestically in the U.S. and we have Wilhelmshaven and Middle East refineries.

So we look at the opportunities and we don't get too hung up whether that balance is 60-40 or 70-30.

We look at the opportunities and what we think is best and we don't get too hung up whether it has to be 70 or 63 or 68 percent, as long as it's probably in this 60-40 to 70-30 that's fine with us.

Right, I'm with you.

So it's a question I guess of returns of a given project across the whole suite of opportunity?

That's right.

In terms of the -- more specifically, in terms of the two Middle Eastern opportunities, could you envision a situation then when you were progressing both of them simultaneously?

Sure, absolutely.

Right, okay.

That's kind of where I was headed with that one.

Finally, separately -- hedging.

You've been interesting on the subject in the past.

Could you say if you feel vindicated and further some comments you were making, Jim, during your prepared remarks about hedging and gas in the U.S. and any other items you could add on with the U.S. natural gas market would be interesting, too.

Thanks.

We haven't hedged.

Obviously our commercial organization, we do a lot of trading because we have physical volumes to move.

But we don't take views on oil prices, gas prices or crack spreads and hedge looking forward earnings or cash flow.

We'll continue to always look, but when we took a look at the Burlington transaction back last year and the early part of this year a lot of questions came to us from the financial community -- why don't you hedge with high gas prices?

And we looked at it and a few of the things that we found -- that the accounting treatment was difficult.

We also know it was going to cost us quite a bit of money and then we had basis differential.

We'll keep looking at it, but I don't -- obviously if you can look at it and say you're vindicated, no, we haven't been vindicated because gas prices have backed off.

You could make an argument that we should have been hedging the production, but over the long-term our culture and our approach is that we don't hedge our production.

We think we have the portfolio we like and we change the nature of the company when we start doing those things.

And we feel that we don't do them -- you can't do them on a probability basis over time and get it right.

Sure.

Well, speaking as a dumb analyst I've got to say it's easier to model if you don't.

Thanks.

Dan Barcelo, Bank of America Securities.

Yes, good morning, gentlemen.

Just a few questions if I could continue on Burlington.

The first part was really similar to an earlier question on DD&A rates.

It seems the second-quarter level obviously is up with the step up in the evaluation of those assets.

But I just was curious; it seems that that second-quarter level is higher than what was initially discussed in terms of the step up and also higher than what was in the S-4.

I just wanted to know if that thinking was correct and what could be behind that.

I understand it's a non-cash item, but just trying to get my arms around that DD&A level going forward.

And then just also, from a very high level, if you could maybe just highlight what you've seen now in these BR assets basically looking at them from a good part of this year.

Any more exploration upside you've examined?

How is it going with employees and retention?

Is there any scope yet for a synergy capture uplift?

Well, John will answer the DD&A question.

First of all, in terms of production, Burlington came up before it was acquired by ConocoPhillips with a forecast of production for the year and we continue to stay right with that.

We're realizing the volumes that we thought so that still is right on target.

In terms of what we do see and experience though is the cost.

The cost of everything we are doing, whether it's in Burlington or everything in our company other than Burlington, costs are going up.

And the other point you've raised is in terms of people.

It's not only the people that have come to ConocoPhillips from Burlington, but we, our company and all the companies in the industry, there's quite a competitive environment for people.

And so we have to make sure we're competitive.

It's not just with the Burlington, it's with everyone that works in the E&P upstream part of our company in the industry.

Synergies, we continue to work hard on synergies and we still stand behind the synergies that we said that we were going to capture when we announced the transaction.

Now in terms of whether we're seeing something different in terms of DD&A from what we expected, John can comment on that.

Dan, on the first-quarter earnings call we indicated we expected about 7.1 of DD&A for the full year.

And if you take the 11.80 in the first quarter and the 19.65 in the second quarter, as you increase volume it can go up modestly.

But we don't expect it to go up materially and we would expect to be right in line with that 7.1 on a full-year basis for 2006.

Great, thanks very much.

Gene Gillespie, Howard Weil.

Good morning.

A large Canadian company indicated in the last day or two that they might be interested in swapping some heavy oil production for refining capacity.

And I guess without being specific, on a global basis, Jim, would you have an appetite to be on the other side of that and perhaps swap some refining capacity for resource?

Well, Gene, thanks.

Good point that you're making.

It's something that we have said I think in not only conference calls but in our annual presentations to the financial community.

First of all, we've been making investments in our refineries so as to handle the heavy pour quality crude because we think it's good for the downstream business and so that's why we embarked upon a multibillion dollar program over about five or six years.

In terms of using that refining capacity, we have some choices.

We just buy heavy crude from Canada or import it from other places -- Venezuela or other countries.

We can do that or we can also take a look at and say, well, we don't have as large a position in heavy oils as we might like.

We have our Surmont project which is going to start production late this year or early next year, but we'd like to be more in heavy oils in Canada.

So it's a good question.

It's something that we study and at this point in time we really haven't come to conclusions or are about to say anything, but it's something that we naturally should study.

And it may make a lot of sense for us to do.

Thank you.

Mark Gilman, The Benchmark Co.

I had a couple things.

I want to try the DD&A question of a moment ago from a slightly different angle.

John Carrig, have there been any explicit adjustments to the purchase accounting treatments that was specified in the most recent S-4?

I'd have to -- I'm sure there have been some tweaks to it, Mark, but I don't recall any significant changes.

We have the S-4, we have what was in the first quarter Q. And I would say that, as we indicated, we thought it was 7.1 before and we still expect it to be 7.1.

So I don't see a material change.

But if there is we'll have to come back to you.

Okay.

It appears to me -- I'm looking for either confirmation or elaboration -- that the Bayu LNG volumes and earnings are both low.

Could -- John, Jim, Gary -- address yourself to that?

Well, my understanding, and then the others can come in -- we actually started production sooner than we thought.

We had some normal startup difficulties in terms of lining out everything and making the volumes -- not from production or that, but just getting the thing planned out.

But we're back on in terms of our production, just what we expected for our internal plans.

I don't know what we've been saying outside to the financial community, but we watch these things very carefully and in terms of our production we're essentially right on or a little bit ahead of plan.

Right, but we're still in the ramp up phase.

So we're not at full run rates and we think it's a good project and it will continue to be a good project.

So not sure what data you're utilizing to reach that conclusion, but we like the project.

When would you expect to be at full capacity on it, John?

I would say that's a normal ramp up, Mark.

Why don't we just come back to you on that?

Because if I say a date I'm probably going to be off by several months.

Okay.

Just one final one for me.

It looks to me as if you've made some significant changes or adjustments in terms of the inputs at Wilhelmshaven, in running intermediates or blendstocks as opposed to crude.

Is that the case and, if so, what's the thinking on that?

It's fundamentally a hydroskimming facility.

Again, there's no change in the feedstock slate that's jumped out at us, but we will certainly come back to you and indicate whether that's the case for sure.

Okay, guys.

Thanks a lot.

Gene Pisasale, Mercantile Trust.

Yes, thanks.

First, great quarter, congratulations.

Just a comment on the barrels produced around the world.

The major oils really looking at a higher risk profile for their production today than they were five or ten years ago.

And with recent moves in Venezuela and Russia, specifically Russia most recently, in terms of moving forward with various projects and trying to keep out certain players so to speak, are you concerned about having a much higher risk premium to your barrels today than you did let's say five years ago?

And if so, are you just accepting that risk and just trying to spread it around the world?

Thanks, good question.

The first point that I would make, though, is compared to most companies of our size, larger or smaller, we have -- of course we're in a much higher position of OECD reserves and production.

In other words, we start with a very strong base -- can't give you the exact number, but I'll say 65 to 70 percent of our reserves and production come from North America, the North Sea, you could say Timor Sea Australia.

So we start with that position and then as we branch out and go to other places where the new opportunities are.

So in that regard I think we are competitively rather unique.

We have such a high percentage of exposure, position and assets in production in OECD nations.

In terms of Russia, our experience in Russia has been very good.

In other words, we work together very closely with LUKOIL, and in working with LUKOIL -- our ownership in LUKOIL.

We don't see any adverse impact of them operating in Russia or outside Russia.

And then our joint venture project in the Nenets area in the North where we have developed the YK Field and we have 30 percent of it, LUKOIL 70 percent, we don't see any adverse impact, political risk on that.

And the other is we're one of five companies shortlisted for the Shtokman project working with Gazprom.

No decision has been made on that, but we feel we've given a good competitive proposal and hopefully in the next several weeks or months we'll hear the decision of who the participants will be.

But from a point of view of concern about Russia, there's political risk wherever you go in the world.

Political risk can be all kinds of risk from the standpoint -- it can be fiscal takes, changes in fiscal takes, it can be changes in operations -- whatever.

But we start off with a strong base.

And you can see from where we invest, Russia, Caspian and Kashagan, downstream and upstream.

Upstream we're LNG and Qatar, downstream Saudi Arabia, Abu Dhabi.

We certainly wouldn't be making these investments if we didn't think the political risks were acceptable.

Thanks very much.

One more question.

Jacques Rousseau, Friedman Billings Ramsey.

Great quarter.

In under the gun here.

Just a couple quick ones.

What was the opportunity loss in the upstream and downstream that you referenced from the unplanned downtime?

Well first, opportunity loss.

Upstream is we find that some of our production up in Prudhoe Bay that you're aware of has impacted us maybe 20,000 barrels a day.

We've had some downtime in the North Sea operationally that cost us several thousand barrels a day.

We've had some unplanned downtime in certain of our refineries -- Lake Charles and Humber, we noted in our media release.

And when you look at these prices and crack spreads it has quite an impact.

It can amount to a pretty significant impact to both upstream and downstream.

That's what we're referring to.

I know.

I was just curious if you put a dollar amount on it.

Well, we do.

We do it for internal purposes, but we don't put that out externally.

We do it for accountability within the company, but you can look at the numbers when you're down by "x" number of days and you look at the crack spreads and the oil price, after tax you'd probably come up with a number or get pretty close anyway.

Fair enough.

One last one.

With the Burlington acquisition, have you noticed a change to your upstream realizations on gas and oil versus the benchmarks?

We're pretty well in line.

If you look at the quarter-over-quarter decline at Henry Hub, the realizations that we've experienced in the Lower 48 are pretty consistent.

Is that the way you think it will play out in the coming quarters?

Yes, that's our expectation.

Thank you.

Ladies and gentlemen, that is all the time we have for Q&A today.

I'll now hand the presentation back to management for closing remarks.

Well again, we really appreciate you joining us today for our second-quarter conference call and walk-through earnings.

We remind you that the presentation along with the transcript of this webcast will be available on our Web page, www.conocophillips.com.

Again, thank you for joining us.

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

This does conclude the presentation and you may now disconnect.

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 July 26, 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).

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.

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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," "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 may include 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 any GAAP reconciliation tables provided in the presentation and the Appendix to the presentation which is available on our website at www.conocophillips.com.