雪佛龍 (CVX) 2006 Q2 法說會逐字稿

Good morning.

My name is Matt and I will be your conference facilitator today.

Welcome to Chevron's second-quarter 2006 earnings conference call.

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

After the speakers' remarks there will be a question-and-answer session and instructions will be given at the time. (OPERATOR INSTRUCTIONS) As a reminder, this conference is being recorded.

I would now like to turn the conference over to the Chairman and Chief Executive Officer, Mr. Dave O'Reilly.

Please go ahead, sir.

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

I am joined today by Steve Crowe, our Chief Financial Officer and Irene Melitas, Manager of Investor Relations.

Our focus today is on Chevron's financial and operating results for the second quarter of 2006 and I will refer to the slides that were e-mailed to you this morning and that are available on the Web.

Before we get started, please be reminded that today's presentation contains estimates, projections and other forward-looking statements and I ask that you review the Safe Harbor statement on slide 2.

I will begin with slide 3 which provides an overview of our financial performance.

The Company reported results of $4.4 billion or $1.97 per diluted share for the quarter.

Our results were up 18% compared to the second quarter 2005 on higher crude oil prices and increased production.

Second-quarter results were up 9% from the first quarter of 2006 and Steve will discuss this shortly.

Return on capital employed for the trailing four quarters was 24%.

We continued to reduce debt during the second quarter and at quarter end, our debt to capital ratio was 13.4%.

Our C&E spending totaled $4.3 billion for the quarter.

Stock repurchases in the second quarter totaled $1.3 billion reflecting an accelerated buyback pace.

And we anticipate completing the $5 billion buyback program by year end.

Finally our year-to-date shareholder return is about 21%.

Steve will now take us through the quarterly comparisons first quarter to second quarter.

Steve?

Thanks, Dave.

My remarks compare the results of the second-quarter 2006 to the first quarter.

Bear in mind that our earnings release compared the second-quarter 2006 to the same quarter a year ago.

Turning to slide 4, net income was about $360 million higher in the second quarter.

Starting with the left side of the chart, stronger crude prices improved upstream results but were partially offset by the effects of lower natural gas prices in the U.S.

The positive margin variance in downstream reflects stronger refining margins in the U.S. and improved international margins particularly in Asia-Pacific and Europe.

Second-quarter earnings benefited from higher production in the U.S. related to ongoing restoration of volume shut in from last year's storm activity.

More than offsetting, however, were lower international upstream liftings primarily reflecting the timing of cargoes.

Our second-quarter earnings were adversely affected by a $250 million abandonment charge net of insurance related to higher anticipated costs to dismantle wells and facilities damaged during last year's Gulf of Mexico storms.

The variance in the residual chemicals and other bar is the net of everything else and reflects lower results in chemicals and shipping, a negative swing and tax related and other miscellaneous items.

Slide five summarizes the results of our U.S. upstream earnings which were roughly $310 million lower between quarters.

Higher liquids realizations benefited earnings by 175 million.

The $6.62 per barrel increase for liquids between quarters was less than the rise in industry benchmarks prices.

While the average quarterly price for WTI improved $7.22 per barrel, the Gulf of Mexico benchmark trade month price which is on a lag basis, rose by $6.42 per barrel.

Lower natural gas realizations resulted in a negative $165 million profit effect.

Our average realizations declined $1.57 per thousand cubic feet, less than the average decline in bid week prices reflecting our regional production mix and volumes sold at spot.

The effects of storm recovery volumes and one additional producing day benefited earnings by $65 million.

The charge for higher abandonment costs associated with structures and wells damaged from last year's hurricanes reduced earnings by about $250 million.

Included in the other are lower natural gas trading margins and the negative swing effects of tax related and other miscellaneous items.

Turning to slide six, international upstream earnings for the quarter were about $125 million higher than the first quarter's earnings.

Driven by the rise in liquid prices, higher realizations improved earnings by $325 million.

Liquid realizations rose by $7.11 per barrel in line with comparable increases of spot Brent prices.

Despite slightly higher international production in the second quarter, lower liftings last quarter particularly in the UK and Australia resulted in a negative earnings variance of $240 million or about $0.11 per share.

As mentioned during last quarter's conference call, we were overlifted in the first quarter which benefited earnings and during the second quarter, underlifted relative to production by a similar amount.

Year-to-date liftings are roughly in balance with production.

The other variance bar includes the net effect of various items and includes a favorable swing in foreign exchange and tax items that was partially offset by higher operating costs and exploration expenses.

Looking forward as a result of the recently enacted tax increase on North Sea oil and gas producers, we anticipate taking a third-quarter catch-up charge of about $200 million and expect another $80 million or so on second-half earnings.

Slide seven summarizes the change in worldwide oil equivalent production including volumes produced from oils sands in Canada and production under and operating service agreement in Venezuela.

Volumes were up about 1% between quarters.

U.S. production increased 18,000 barrels per day between quarters mainly on the restoration of volumes shut in due to storms in the Gulf of Mexico.

Despite the increase, the storm-related activity curtailed second-quarter production by about 60,000 barrels per day.

Outside the U.S., oil and gas production increased by 7000 barrels per day between quarters.

The main changes were in Kazakhstan following the downtime in Tengiz in the first quarter and in the UK due to planned maintenance last quarter.

Production increases elsewhere added about 19,000 barrels per day.

Turning to slide eight, production during the first half of the year was 2.66 million barrels per day.

This was lower than our projection at the beginning of the year as a result of greater-than-expected operational downtime and the PSC and royalty effects of higher prices on net production.

In the second half of this year, we expect production will average about 2.6 million barrels per day.

This estimate includes a 90,000 barrel per day effect from the Empresa Mixta conversion in Venezuela, partially offset by production increases elsewhere in the portfolio.

Despite the Empresa Mixta conversions our production growth items discussed at the March analyst meeting remains unchanged.

Turning to slide nine, U.S. downstream net income rose by about $345 million between quarters led by stronger refinery margins.

Margin effects of $400 million contributed favorably to earnings relative to the first quarter reflecting more robust refining margins particularly in the West.

In the West, the A&S refining margins improved by $10.74 per barrel between periods, and in the East, the Gulf Coast slight heavy differential indicator rose by $11.48 per barrel.

On the marketing side, improved aviation fuel margins and stronger seasonal asphalt profits also contributed to the higher downstream results.

Refined product trade sales were down 4% between quarters due to a change in accounting for certain purchase and sales contracts which now requires the transactions to be netted for financial reporting.

Absent the accounting rule change, trade sales volumes in the second quarter would have been up 3%.

Higher operating expenses reduced earnings by $50 million, reflecting an increase in environmental reserves and higher plant maintenance activity at Pascagoula.

Turning to slide 10, international downstream earnings of $444 million were higher than the first quarter's by about 75 million.

Stronger refining and marketing margins particularly in Asia-Pacific and Europe resulted in a positive variance between periods of $240 million.

In refining, increased demand coupled with the industry's heavier maintenance activity pushed margins higher.

The Brent margin climbed $1.53 per barrel and the Dubai cracking margin rose by $4.56 per barrel.

Lower marketing margins in most regions were more than offset by stronger margins in Europe.

The swing in tax related items reduced earnings by about $60 million between quarters.

Finally, the variance in other includes lower shipping and trading results as well as other miscellaneous items.

Slide 11 shows chemical results were $94 million in the second quarter compared to $153 million in the first quarter.

Olefins were down about $60 million primarily due to lower ethylene margins and volumes.

Polyethylene results were also lower due to a decline in sales margins.

The improvement in earnings related to additives was mainly attributable to higher sales volumes and margins.

Slide 12 covers all other.

Second-quarter results show a positive variance from the prior quarter largely due to gains from the redemption of the Company's investment in Dynegy's preferred stock reflected in the P&L businesses bar.

And the gain from the retirement of about $1.5 billion of Unocal debt included in other.

Absent the gain on the debt retirement, the other segments net charges would have fallen within the range of our standard quarterly guidance, that is 160 to $200 million excluding Dynegy.

That completes our brief analysis for the quarter and now I will turn it back to Dave.

Thank you, Steve.

Now let me briefly recap our strategic progress in recent months beginning with the activities on slide 13.

These include in Angola the production of first crude oil from the offshore Lobito Field, which together with Benguela, Belize and Tomboco, comprised our 31% owned and operated BBLT development.

The project was on time and on budget and ramping up.

In the UK, the production of first crude oil from our 85% owned and operated Area C the project in the Captain Field.

In Azerbaijan, the participation in the first crude oil shipment through the BTC pipeline in which we hold an 8.9% interest and in Brazil we announced our commitment to develop the 52% owned and operated Frade Field, our first deepwater development project in Brazil.

Continuing on slide 14, in Nigeria we had an oil discovery in the offshore oil prospecting license 214 in which our interest is 20%.

In Australia, we made a natural gas discovery at Chandon-1 in the Greater Gorgon development area.

Finally in Vietnam, the signing of a 30-year production sharing contract with Vietnam Oil and Gas Corporation for Block 122 (Correction: Misspoken as 22) occurred.

We also announced several strategic initiatives to enhance the development of our alternative fuels portfolio, including the creation of a bio-fuels business unit, the completion of the acquisition of a 22% interest and Galveston Bay Biodiesel and a technology partnership with the Georgia Institute of Technology to pursue alternative fuel development and in particular biofuels.

That concludes our prepared remarks.

We now take your questions, one question per caller please, and we will try to wrap up at or before the top of the hour.

So, Matt, if you would open the line for questions.

Thank you.

(OPERATOR INSTRUCTIONS) Doug Leggate, Citigroup.

Refining and marketing I'm a little confused I guess at what I thought was a fairly low number.

Your comments about the U.S. suggests marketing margins were higher.

Can you just break out the delta please, Steve, between quarters for marketing and maybe try and explain if you saw the capture rate and the strong margin environment as less than it would otherwise have been in previous quarters?

As we look at the refining and marketing variance, Doug, comparing the second to the first quarter we indicated that about $400 million -- it was about $400 million of margin improvement.

Roughly speaking about 40 or so of that was attributable to marketing.

I think inherent in your question and in doing your assessment of what the refining and marketing improvement should be quarter to quarter is based upon looking at indicative margins for refining and indicative industry margins for marketing.

In the case of marketing for example where we give marketing margins in the West and in the East.

In the West relative for motor gasoline relative to dealer tank wagon prices and in the East relative to Houston rack, you've got a mix effect of where the locations of our actual sales are.

And you will get -- you can get some distortions relative to those industry indicative margins.

So you have a location issue to grapple with and you also have a mix of products.

Certainly in the eastern part of the United States where we source a preponderance of our motor gasoline from other than our refineries, their acquisition is based on market at the time.

So it is possible that when you peer in and use indicative margins, you might otherwise assume that the domestic R&M for example would have been higher than we have reported.

Any hangover effects from hurricane costs or anything like that?

Fairly minimal.

As we indicated in the release, we did continue to have but it was mainly upstream, some charges associated with repairs and maintenance as well as the abandonment provision that I mentioned.

And there's a small part still that is associated with operations other than upstream but by comparison it is pretty small.

Steve, Dave here.

Sorry, Doug, I guess is on the phone.

We also did have -- incur expense related to hurricane preparations across the whole system in the second-quarter and we are very well prepared for the hurricane season.

For example, purchasing and installing emergency generators strategically throughout our marketing regions and quite a number of temporary housing expenses that are incurred.

Most of those are included in that $300 million but probably not all of them have been captured; the $300 million that we highlighted in the press release.

One other item and for the benefit of others in our press release and as we have been disclosing for the last several quarters in our SEC filings, effective on April 1, is an accounting change with how certain purchase and sales contracts are handled.

It has an effect on the income statement of reducing the revenues and an exact offset on reducing purchases so there's no P&L effect but the volumes will change.

And so you will note in our press release for example on the attachments, you can get the quantification of that as it relates to refined products but I would emphasize there is no P&L effect.

This is simply a matter of netting rather than treating it on a gross basis.

But it is something that the analyst community will need to factor into its models going forward.

Thanks very much, Doug.

May we have the next question?

Neil McMahon, Bernstein.

Just really going toward these abandonment costs, I was very surprised that it wasn't included within your interim update that such costs were coming.

And are they related to the Typhoon Field which I believe -- or Typhoon Platform which I believe has been sunk over the last quarter?

If that is the case, are you going to take any reserve write-down on that or what is the back-up or follow-up plan for that field?

Thanks.

Neil, I will state that, this is Dave.

We obviously would have liked to have this in our interim update but unfortunately the data was not available until the last few weeks.

And as you know, we put our interim update out about end of the third week of June.

The issue does not have a reserve effect.

We have already accounted for that as best we could of course at the end of year.

It has not really got a lot to do with Typhoon.

This is to do with a more detailed subsurface analysis of the damaged facilities and wells that are going to be abandoned and the complexity and the costs incurred in basically fully and securely abandoning those facilities.

It also meant analyzing the availability of insurance to cover those events and when the complete work was done, the plan filed with the MMS and approved by the MMS and the full understanding of what insurance was available to cover this, it became obvious that we just have had an exposure here that we had to take because it is an abandonment charge.

So what we are reflecting here is that new information from the last few weeks that will secure those facilities but they -- it does not involve reserve write-down.

It does not involve a charge or anything related to Typhoon.

And with that, I guess as far as we know we have dealt with as much as we can possibly and appropriately account for at this time.

That is great detail.

Just wanted to ask about Typhoon then.

What at this stage, given the fact that you are ongoing with investigations and still concluding the costs, what should we look forward to on this field?

Is there future of getting more oil out of that field at the moment?

There obviously is the potential to recover more.

We're working on plans.

We're working on plans to recover the fields that are economic to do so.

And we have a multiyear plan that we will phase in over the next few years as we put it in our project queue.

You will recall that we had about 300,000 barrels a day of production in the Gulf pre-Katrina, last August and we have said that this year we would achieve about 200,000 barrels a day. 25,000 to 30,000 barrels a day will probably not come back as associated with the permanent loss of production but the other 60,000 or 70,000 barrels a day we are still working on and we will continue to work on it.

And if it is economical, we will continue to work at recovering it.

So we have a plan, we can't commit to the details of that plan right now other than it is being worked.

For your benefit and others, I would just make a couple of other comments.

As was the question with Doug, we do have ongoing repair and maintenance costs and the way that is accounted for is the expenses are taken as the costs are incurred.

By contrast, an abandonment provision is something that once it is estimable and probable, you have a legal obligation to recognize it all at once.

And we had had an abandonment provision associated with the damaged structures and wells and once we have been able to do the more detailed review of what we found to be far more mangled and more complicated than abandonment, we needed to have a larger provision net of insurance and that is why we booked it.

Your point is well taken though.

That effect is worth about $0.11 per share and likewise the analyst community is not in a good position to estimate the impact of the liftings pattern that I alluded to in my comments.

That again is worth about $0.11.

So that's a $0.22 swing which in my mind taking that into consideration, the community out there did a pretty good job, recognizing that those two items were not knowable from your perspective.

Thanks very much, Neil, for your call.

Arjun Murti, Goldman Sachs.

My question relates to your various biofuels related announcements.

I was wondering if you could characterize order of magnitude investments you might be making over the next several years?

I presume it is a relatively small amount in light of your overall spending.

And then related to that, regarding ethanol, is your focus primarily on cellulosic and future technologies or would you have any interest in corn-based ethanol especially in light of the significant ethanol use in California?

Thank you.

Arjun, a couple of points.

The investments are relatively small.

We are a major renewables producer but most of our investments in renewables are in geothermal and we spend a number of hundreds of millions of dollars a year investing in geothermal growth in Asia primarily in Indonesia and in the Philippines.

Our investment in biofuels in the U.S. is relatively small.

We are focused on what we call second-generation ethanol which is not the corn-based ethanol but the next generation which we hope will be the result of transforming some waste material or cheaper to grow material into biofuels.

That is our area of focus in our research work so the money there is relatively small.

Having said that with respect to California, we are working on a marketing program for E85 in collaboration with ethanol manufacturers and with the State of California.

We are building some service stations in California and using California state automobiles and trucks as our sample.

And the idea here is to test the efficacy of E85 in California because there is some concern in the state regulators mind's about the air pollution consequences of ethanol because it is more volatile.

So we have an active program here which is small but it will lead us to a more realistic appraisal of E85.

Having said all of that, 30% of our gasoline today around the United States has ethanol in it primarily 10% ethanol and we are as you rightly point out a big consumer of ethanol.

I think we buy or consume about 5% of the ethanol that is produced in the United States.

But our main focus is on testing the efficacy of E85 and second-generation ethanol in addition to the work we're doing on biodiesel.

Relatively small in the near-term.

That is really helpful.

Thank you, David.

Bruce Lanni, A.G. Edwards.

Good morning, Dave, Steve and Irene.

Just a real quick question.

I want to just get some further clarification on your production guidance because if I am correct wasn't it originally somewhere between 2.7 to 2.8 million barrels a day by year-end versus the 2.6?

And in that context, does that mean that to account for that you are saying the PSCs and downtime make up the difference?

Could you maybe go into that a little more deeply?

You are absolutely right.

Our original guidance if we go back to that chart, chart number eight, was for 2.7 to 2.8.

In the first half of the year we achieved 2.66, about 40,000 barrels a day below the lower end of that band; 25,000 barrels a day of that is PSC effects because our assumption for the pricing for the year for the purpose of calculating the volume at that time was $55 based on the volume, our assessment at the beginning of the year.

So the difference between $55 and $70 or so explains 25,000 barrels a day.

And then we have some operational downtime primarily in the first quarter in places like Tengiz which we discussed at the end of the first quarter.

In the second half of course, we're going to feel the impact of this conversion of Empresa Mixta which takes 90,000 barrels a day of OSA, operating service agreement, production out of our portfolio and leaves us with about 30,000 barrels a day or so of equity crude in its place.

The financial impact of that is immaterial to Chevron because we are going to a higher margin but lower volume amount of crude there.

But it does affect our volumes.

So the volumetric effect here is much bigger than any of the financial effects and now we feel our second half production with that 90,000 barrels a day impact will be about 2.6 million barrels a day as our production ramps up, continues to ramp up in places like Angola which is in the process of increasing production and some of the other growth activities in our portfolio.

So that is how we see things today related to the guidance that we gave you in the analyst meeting earlier this year.

So Dave, am I to infer then from your second half numbers where you have the PSC royalty effects of 25,000 barrels a day, are you now assuming that the second half oil price is going to be $70 rather than $50?

We just made a calculation that the price is what it is today and we haven't made any assumption about it going up or down.

So we are assuming $70 and this is calculated on a $70 basis.

We had to calculate it on some basis so we decided to stick with what we had experience in the first half of the year.

That is perfect.

Thanks a lot, guys.

Nicki Decker, Bear Stearns.

Good morning.

My question is on the international upstream.

On your variance analysis in the other category, you talked about three impacts, the favorable FX and tax items and operating costs which included operating expense.

Can you itemize those items?

We typically don't break out the specifics of the other for exact quantification but I will give you a general direction here.

On slide six for everyone's benefit, there was a $42 million favorable variance between quarters.

You can determine from the press release comparing this press release and last, that the foreign exchange effect is $27 million favorable.

The tax benefit effect between periods is a little more than twice that and offsetting those to come down to the net 42 is our higher operating expenses in the 50 to $60 million range.

And a smaller increase in exploration expense after-tax in that segment.

So those are the three main components, again favorable in terms of tax and foreign exchange and clawing some of that back in terms of operating expense and exploration costs.

That is real helpful, Steve, thank you.

Are those operating costs -- will they be ongoing, the higher costs?

We are seeing increases in our cost structure so in all likelihood that will be the case.

But again, the amounts that I referred to were comparisons between quarters so directionally I think your presumption would be correct.

And includes such things as turnaround costs as well and maintenance so those would not be repeated from quarter to quarter necessarily.

Can you quantify that, Irene, what portion of the 50 to 60 this quarter that would be?

Maybe about a third.

Thanks, Nikki.

May we have the next call please?

Mark Flannery, Credit Suisse First Boston.

I would like to look forward to say 2008 specifically with the Escravos Project.

There's some news coming out that you may be getting some delays and/or changes in the cost structures out there.

Could you just comment on what you are seeing with that project?

And more broadly do you guys still expect roughly 3 million barrels a day of production in 2008?

Let me address the first question on our projection.

As I had mentioned in my earlier remarks we are still holding to the guidance that we had given in March, Mark, that we will see a greater than 3% growth in our OEG production from 2005 to 2010.

Even allowing for the impact of the changed structure in Venezuela we think that is still a good guidance.

Clearly as we get later in the year and review our plans again for the analyst meeting in the early part of next year, we will update that guidance but at this stage that is still an appropriate assessment.

Just to be very specific, whether 3 million in 2008 is -- I don't think I want to be pinpointed to that.

I think our 3% per year for that period of time from '05 to 2010 is what Steve is saying and that is the guidance that we gave I think in March.

On your other question on Escravos, the GTL -- I think you are referring to the GTL project, is that I correct?

Yes, that's right.

That project is underway.

The site there have been done.

There have been some delays there and there have been some concerns expressed -- I have seen in the press by reports on the part of one of the contractors.

However, we anticipate that that project is going to continue to progress.

It is making progress.

I think our project completion date there is 2009.

I think you might have referred to a different date, I'm not quite sure.

But it is underway and it has begun including major equipment fabrication and site preparation.

So this is not a theoretical one, this is actually in full swing and it will be completed.

Okay, great.

Thank you very much.

Mark Gilman, Benchmark.

Folks, good morning.

I noticed on the wires a story relating to the fact that you're offering your interest in the Nerefco refinery for sale.

I am hoping that you can either confirm or disaffirm that.

And at the same time address the question of a broader withdrawal or divestiture of the European downstream given the fact that the potential sale in Nerefco would further reduce critical mass in a region where that might have been a question even before such sale?

Your observation is a good one.

Let me clear up this issue for a while.

We do not view Europe downstream as a core part of our business.

And we have a sale underway of our interest in Hydro Texaco which is the marketing operations in Scandinavia which should be complete by the end of the year.

We are entertaining offers for our interest in Nerefco and our marketing operations in the Benelux countries which -- and there is data room and there is activity underway currently on that front.

However Pembroke refinery is a different kettle of fish.

The Pembroke refinery is actually integrated into our Atlantic basin strategy and a considerable portion of its production actually is targeted to North America and so we view that as a part of our strategy.

So just to clear it up, we are not planning to expand in Europe.

We are decreasing our exposure there.

We think this is a good time to do that.

We think the market is suitably positioned for us to do that but Pembroke is an important part of our portfolio.

If I could just follow up, UK marketing, Dave, where does that fit?

UK marketing we have already done quite a bit to move that to third parties.

So we announced a deal last year with one of the retailers in the area so we basically have reduced our investment substantially in UK marketing.

So while we are supplying some of that market, it is very regional and it helps to balance the output of the refinery so that we can swing appropriately toward the Atlantic basin with some base offtake that is local in that market.

Thanks very much.

Daniel Barcelo, Banc of America Securities.

Just following on the downstream theme here, earlier in the year you bought a 5% stake in Reliance Petroleum.

Just to know if you could give a little bit of a business and strategy update there?

If you are still considering the option you have to increase your stake further?

And then just following on what Mark's question was, is this signaling any portfolio shift also away from -- you answered on Europe.

Maybe you could comment the same way in terms of Latin America building toward a stronger base in your Southeast Asia position?

Let me start with the strategy.

Our Asia strategy, we have been focused on Asia downstream and focused very specifically on it since Chevron and Texaco combined in 2001 and it is clearly a core area for our Company.

In the region we are expanding and modernizing the refinery in Korea.

We increased our interest in the Singapore refinery from a third to a half about 18 months ago.

We have also a large and modern refinery in Thailand and our interest in India is just a continuation of the pursuit of that strategy.

We did acquire a 5% interest in May in this new export refinery that is being built in Jamnagar.

It is 580,000 barrels a day refinery.

It will come on stream late in 2008.

We have 5% and our agreement will permit us to increase our interest to 29%.

And concurrent with that, supply rights and product offtake.

It is an export zone.

It's geared to the export market and we believe it will be the first big refinery to come on in Asia that will still come on in a time frame where the margins are strong.

So we like it strategically and we like it economically.

We have made good progress with Reliance.

They are a good partner.

We are also working with them on pursuing opportunities in the upstream in the gas business in India in the region and as we mentioned in the press release, that went out at the time that we agreed to take that 5%.

So clearly that is an area of focus for us.

In Latin America, we are a very strong marketer in some areas of Latin America.

We're not in the refining business there.

We are focused in places like Brazil.

We have exited however some of the markets particularly in the Andean region where we didn't think we had a competitive advantage and didn't see the economic outlook.

Recently during the quarter, we exited Ecuador for example, and we have been systematically strengthening our focus in the Caribbean and in Central America and in Brazil in that area.

So a big focus on Asia, a big focus on the West Coast of the U.S., less focus in Latin America.

Thank you.

Paul Cheng, Lehman Brothers.

Good morning, everyone.

Dave and Steve and Irene, I have two questions and a comment if I could?

One is just want to get a quick number, what is the environmental charge and also the actual underlifting impact for the quarter?

As well as the $200 million of the UK tax onetime charge that you're going to do in next quarter, how much of them is related to the deferred tax?

Let me take that question, Paul.

Let me start with the second one first.

As I had mentioned, we think we are going to be booking an approximate $200 million catch-up charge in the third quarter.

Roughly 170 of that pertains to the deferred tax and the balance of that refers to the first half of the year's current tax. 140, excuse me.

140 or 170?

I misspoke, it is $140 million for the deferred tax.

It is running approximately $40 million a quarter for the current tax.

As to your other question, as we had shown on slide six, the impact of the shift in liftings between first and second quarters was worth an approximate $240 million.

The swing in liftings between the first and second quarter was roughly 80,000 barrels a day and I think from your perspective, Paul, you can think of that -- it is an approximate equal amount of underlift in the second quarter compared to the amount of overlift in the first quarter.

Going forward at the end of June, we are essentially in balance however.

How about the environmental charge in the U.S. R&M?

An incremental charge in the --.

No, the environmental.

I think you had indicated that the higher operating expense is partly because of the provision for the environmental charges.

Let me see here.

It is not jumping at me right away.

In the great scheme of things, it is not that material but it is measurable.

And if I could just one last question and a comment.

The question is that for Dave, are you concerned that should the oil industry as a whole may have underspend the R&D effort?

If we look at the spending by your Company and the rest of the industry on R&D as percent to whether profit or sales volumes or compared to other industry seems to be a pretty low percentage.

And is that a possibility that because of that underspend that over time you will reduce your competitive edge and particularly in light of more of the national oil companies enter the scene of competition?

Actually I think it is the other way around.

We actually have been maintaining a considerable focus on R&D and given the commodity and nature of the business and the volatility, I don't think that R&D as a percent of sales is a good measure.

I think R&D as a percent of total capital or some other metric is probably even more appropriate and that is something that we monitor.

You'll recall that we had a very in-depth presentation on our philosophy and our areas of focus on research that Don Paul gave at lunchtime following the analyst meeting in March in New York City and we have a very unique model.

We are very proud of it.

We have an integrated technology company.

It is unique.

It manages the whole breadth of our business from the reservoir to the gas pump.

It is a combination of focus on certain areas of proprietary research which we guard very carefully and focus a lot of our effort on as well as leveraging research where we don't have all of the expertise in one place for example in biofuels.

So we have a good combination of proprietary and leveraged research and it is a tremendous area of focus and I believe that for companies like ours, it is a competitive advantage relatives to NOCs who in general do not have the same level of experience in this area.

There are exceptions of course but in general I think that is a competitive advantage.

Very good, thank you.

Jennifer Rowland, JPMorgan.

I'm just wondering if you could comment on the integration with Unocal and in particular your ability to retain key personnel from Unocal and also where you are in the synergy capture?

Let's see.

We are very far along.

We have completed basically all of the integration including all of the essential back office like financial systems and human resource systems so we're very pleased with the integration.

We have captured 80% of the $325 million synergy as of midyear and the rest of the tale has to do with implementing these detailed back office activities that almost all of which is captured by the end of a year.

So we are essentially there.

We're very pleased with the performance of the assets.

They are at or ahead of plan.

We're very pleased with the exploration performance.

We've already had two discoveries on Unocal leases in the Gulf of Mexico including Knotty Head and Big Foot and of course we have been sidetracking Knotty Head and making I think good progress there.

On the people front, I think we have done well.

Has it been perfect?

No.

In fact like most companies, there is a tremendous demand for people and it is not just a matter of demand for Unocal people, it's demand for people who are former Chevron or former Texaco or former Getty or whatever.

So we have the same demands that I think everybody else feels.

Having said that though, we have gained in terms of population of technical people this year.

We have got a net gain but it is something that I think is something that we have to manage very carefully and one that we are focused on because it is critical to our success as it is for many other companies.

We look at our business as being from the outside it looks like it is very capital intensive but like every business, it all revolves around people and the effectiveness of people and their ability to perform and contribute.

Very, very pleased with the performance of Unocal and of course on a value basis, transactions today are occurring at approximately twice the value per -- pick your metric -- compared to what we acquired Unocal for last year.

Jennifer, in addition to all of the business value that Dave was alluding to, when you see our filing which will be next week for the second-quarter Q, while we're closing off on the purchase accounting for the transaction itself, and you will see some final information in the footnotes just for your benefit and the investment community.

So goodwill will have been finalized and the allocation for the assets acquired and the liabilities assumed.

Thanks very much.

Maybe we can take one more question.

Mark Gilman, Benchmark.

Dave, real quick, can you give us an update on the Jack production test?

Everyone asks about Jack.

I really can't.

I can tell you that the production test is complete.

It is being evaluated.

We have a number of partners that are involved in it and until the technical work is complete, we just can't really disclose anything.

I'm hoping that by the end of the year we will have something say about Jack.

But thanks for asking.

Thanks a lot.

I would like to thank you all for participating in the call today.

Should you have any other questions Irene and the team here are ready to respond.

And I appreciate everyone's participation and thank you and I look forward to hearing you at the next call or seeing you at the next meeting.

Thank you.

Goodbye.

Goodbye.

Ladies and gentlemen, this concludes today's second-quarter 2006 earnings conference call.

You may now disconnect.

Have a good day.