雪佛龍 (CVX) 2005 Q1 法說會逐字稿

Good morning, ladies and gentlemen.

And welcome to the ChevronTexaco First Quarter 2005 Investor Relations Conference Call.

At this time, all participants have been placed on a listen-only mode, and the floor will be open for your questions following the presentation.

It is now my pleasure to turn the floor over to Mr. Stephen Crowe, Chief Financial Officer of ChevronTexaco.

Sir, the floor is yours.

Thank you, Elsa and good morning.

Welcome to ChevronTexaco's first quarter earnings conference call.

I'm Steve Crowe, CFO of ChevronTexaco.

Today on the call, I'm joined by Randy Richards, our Manager of Investor Relations.

On April 4, we announced that we had agreed to acquire Unocal Corporation.

Slides and audio from the conference call related to that announcement are available on our website, ChevronTexaco.com, under "Investors."

We ask you to refer to that material for information about the pending acquisition.

Our focus today is on ChevronTexaco's financial and operational results for the quarter.

I'll refer to the slides that were emailed to you this morning and are available on the web.

Before we get started, I'll remind you that our presentation today contains estimates, projections and other forward-looking statements.

Please refer to the Safe Harbor statement on slide two.

Slide three begins with an update on our strategic progress in upstream.

I'll start with news from West Africa.

In Nigeria, development of the Agbami field is one of ChevronTexaco's most important projects, expected to provide gross production of 250,000 barrels per day, with first oil in 2008.

Recently, we entered into a $1.1 billion construction contract for floating production storage and off-loading vessel or FPSO at Agbami, a key milestone keeping the project on track.

In the same region, we signed a production-sharing contract for Block 1 in the joint development zone, shared by Nigeria and Sao Tome e Principe.

We have 51% equity and are the operator in this block and look forward to advancing exploration activity as soon as possible.

In Angola, we reached a milestone with first condensate from the Sanha project.

This is a large gas re-injection project in Block 0, which involves crude production from the Bomboco Oil Field, as well as condensate and LPG from Sanha.

Altogether, gross liquids volume from the project is expected to peak at about 100,000 barrels per day.

The next step will be the initiation of LPG production, which is expected within the next several months.

Moving across the Atlantic Ocean to Latin America and the Caribbean area; we announced a gas discovery at the Manatee number 1, offshore Trinidad and Tobago.

This well was on trend with our three recent gas discoveries at the Loran Field in Venezuela waters.

Also in Venezuela, we signed a Letter of Intent with Repsol to pursue with the government new joint venture development activities in the prolific Orinoco Belt.

The project would include heavy oil production, a new pipeline and facilities to upgrade the crude to high-quality syncrude or refined products.

In the UK, we saw first oil at Claire, where our interest is 19.4%.

And in Libya, we reentered the country by acquiring 100% interest in Block 177, an exploration opportunity located onshore, in the geologic area known as the Marzuk basin.

Moving on to slide four; the Gorgon project took an important step forward in the first quarter, with the alignment of equity interests across the greater Gorgon area.

Interests will be divided between ChevronTexaco with 50% and ExxonMobil and Shell, each with 25%.

This will facilitate moving ahead with proposed development based on 10 million tons per year of liquefaction capacity located on Barrow Island.

We expect to enter front-end engineering and design, or FEED, within the next few months.

The Angola LNG project took a similar step forward.

We signed agreements with partners to establish principals for gas supply, corporate structure and legal and regulatory framework for the project, and subsequently announced the award of FEED contracts.

The project concept calls for a 5 million ton per year, single train LNG plant located onshore at Soyo.

At the Escravos gas-to-liquids project in Nigeria, Chevron Nigeria Limited and the Nigerian National Petroleum Company awarded a $1.7 billion engineering, procurement and construction contract.

Output of the GTL plant is targeted at 34,000 barrels per day, with startup expected in 2008.

And in Qatar, it was announced that our joint venture Sasol Chevron and Qatar petroleum signed an MOU which defines how the two parties intend to design, construct and operate a base oils production facility as a value add to the Oryx GTL project.

The base oils plant will use ChevronTexaco's unique ISODEWAXING process.

Turning to Downstream; we continue to rationalize our portfolio in order to concentrate capital employed in areas of strength.

During last quarter's earnings call, we told you that we completed a program to sell over 1,500 retail sites worldwide, and in fact, had exceeded the targeted number of sites.

Moving beyond that program, we just announced that we've agreed to sell 118 stations in the United Kingdom following earlier announcements that we had reached agreements to sell our retail stations in Dubai, Peru and Columbia.

On slide five, I've shown an overview of our financial performance.

The Company had a solid first quarter with earnings of $2.7 billion.

Upstream earnings benefited from higher prices, but Downstream earnings were affected by lower realized margins and downtime in US refineries.

Return on capital employed over the trailing four quarters was 25%.

Our ROCE for the calendar year 2004 was 26%, and now that competitor financial statements have been published, we can confirm that last year, we achieved the top ROCE among our major competitors.

Our balance sheet provides tremendous financial strength and flexibility.

The debt to capital ratio ended the quarter at 19%, with net debt below zero.

Stock buybacks in the first quarter totaled over $700 million.

Over the past year, the Company has repurchased 2.8 billion of its common shares as part of a $5 billion repurchase program.

Randy will now take us through the quarterly comparisons.

Randy?

Thanks, Steve.

Slide six shows first quarter net income per diluted share, was $1.28.

Foreign currency effects were a very modest negative, just 1 cent per share.

My remarks on the variance slide will be comparing first quarter 2005 to the fourth quarter 2004.

Keep in mind that the earnings release compared first quarter 2005 to the same quarter a year ago.

Slide seven shows that net income decreased $763 million compared to the previous quarter.

The decrease was driven mainly by weaker Downstream results, reflecting lower realized refining and marketing margins in the Company's major markets.

Starting on the left side of the chart; special items were down $146 million between quarters.

There were no special items in the first quarter, while the fourth quarter included gains related to several upstream asset sales.

The program we first announced in 2003 to sell non-strategic Upstream assets, is substantially complete.

Foreign exchange effects resulted in a smaller book loss in the first quarter compared to the fourth quarter.

Upstream profits increased between quarters, due to higher oil prices and higher liftings or actual sales volumes.

In the international segment; the negative variance shown by the other bar reflects higher net charges in the other segment.

This was due to lower results from our equity interest in Dynegy and the absence of favorable corporate tax items.

Slide eight shows US Upstream earnings, which declined $192 million, in part due to reduced gains on asset sales, reflected in the special items bar on the chart.

Gains on asset sales identified as special items totaled $87 million in the fourth quarter of 2004.

And as previously mentioned, the asset sales program has essentially been completed and there were no significant gains or losses associated with US asset sales in the first quarter.

Higher liquids realizations boosted earnings about $20 million.

Quarterly average prices per WTI increased $1.54 per barrel, while San Joaquin Valley heavy rose only 24 cents per barrel.

Our realizations rose about 70 cents per barrel, reflecting the mix of light and heavy crudes in our portfolio, as well as price lags in the Gulf of Mexico.

Lower natural gas realizations had a $25 million profit effect.

Average Henry Hub bid week prices fell more than 80 cents per 1,000 cubic feet, while California Border and Rocky Mountain bid week prices were up about 30 cents.

Our average realizations declined 29 cents per 1,000 cubic feet.

This was a smaller drop than the bid week indicators would suggest, because approximately 20% of our volumes are sold on a spot basis, rather than at bid week prices.

And average spot prices at Henry Hub actually increased slightly between quarters.

Lower volumes reduced earnings by $40 million, but it's important to note that the majority of this effect is merely due to the first quarter being shorter by two days.

Daily production rates were off only slightly.

Depreciation, depletion and amortization expense increased between quarters, reflecting higher rates on a lower US reserves base.

The $15 million variance in the other bar reflects several offsetting items.

Unfavorable variances include FAS 133 mark-to-market accounting for several long-term natural gas contracts, and higher exploration expense.

While favorable variances include lower casualty expenses related to storm damage.

International upstream earnings increased $344 million, as shown on slide 9.

Looking at the special items bar, the fourth quarter included gain on sale of a portion of our interest in the Northwest shelf project in Australia to CNOOC.

Foreign exchange effects caused a positive variance between quarters, mainly in the UK.

Higher realizations provided an earnings gain of about $180 million.

Liquids realizations increased $2.93 per barrel, roughly in line with the average of spot Brent prices.

Higher volumes contributed to earnings improvement that was greater than production volume would suggest.

Liftings were lower than underlying production volumes in the fourth quarter, but substantially higher than underlying production volumes in the first quarter.

Exploration expense declined compared to a high fourth quarter level, providing an $80 million improvement to after-tax earnings.

Expense was down, reflecting lower well costs in Nigeria and Brazil and lower geological and geophysical costs in several African locations.

The other bar is a negative variance mainly due to the absence of several positive international tax items that were recognized in the fourth quarter.

Slide 10 summarizes the change in worldwide oil and gas production, including other produced volumes.

Volumes were essentially flat between quarters.

US production fell 5,000 oil equivalent barrels per day, as normal field decline, operational factors and asset sale effects offset the gradual restoration of volumes shut in due to hurricane Ivan.

The volumes still shut in, in the first quarter averaged about 36,000 barrels a day compared to a fourth quarter impact of about 60,000 barrels per day.

Outside the US, oil and gas production increased 3,000 oil equivalent barrels per day between quarters.

Key increases were in Venezuela, where Hamaca reached full production and in the Philippines, where an upgrade to the electricity grid spurred higher natural gas deliveries from Malampaya.

Net production was lower in Indonesia and Kazakhstan, in part due to the effect of higher prices on cost recovery and royalty volumes.

In comparing the first quarter versus the same quarter last year, the impact of asset sales was 47,000 oil equivalent barrels per day in the United States, and 48,000 oil equivalent barrels per day outside the US.

Excluding asset sales and storm effects, US production fell about 8%, a higher rate than our expected full-year decline of 6%, mainly due to weather-related problems in California, and several operating issues in the Gulf of Mexico.

Outside the US, production increased about 3%, if we exclude asset sales and the effect of oil prices on cost recovery and royalty barrels.

With increased production coming from Venezuela, Chad, Kazakhstan, Train 4 at Australia's North West Shelf, and China.

On slide 11, US downstream net income fell sharply, as the company's realized margins declined, particularly marketing margins for gasoline.

Motor gasoline marketing margins suffered steep declines in both the east and west - the Los Angeles gasoline-marketing indicator falling more than $9 per barrel to near breakeven.

Although the West Coast refining indicator margins strengthened, and the Gulf Coast price differential between light and heavy products widened slightly, we were unable to capture the uplift in the refining indicator margins, primarily due to downtime in certain upgrading units within all three of our major US refineries.

In addition, crude oil purchase costs in both quarters were affected by final pricing adjustments for long-haul crudes.

These adjustments lowered first quarter earnings by $50 million, compared to $40 million in the fourth quarter.

Looking at the volume bar, the negative profit effect occurred in refining.

While total refinery inputs were flat between quarters, lower volumes of high-value light products were produced due to the unit shut downs.

Products not produced in the refineries in the first quarter were sourced from inventory or purchases, allowing the company to meet all customer needs.

Total refined product sales and branded motor gasoline sales increased slightly.

The positive result in the other bar is mainly due to higher pipeline earnings, due to an asset sale gain and the absence of fourth quarter storm-related casualty expense.

Turning to slide 12, first quarter international downstream earnings of $351 million were roughly half of the record level achieved in the fourth quarter.

Most of the variance was due to lower refining and marketing margins.

The industry benchmark Singapore refining margin decreased $3.77 per barrel between quarters from over $9 per barrel in the fourth quarter, to a still healthy $5.50 per barrel in the first quarter.

Northwest Europe refining margin dropped nearly $2 per barrel, averaging negative $1 per barrel in the first quarter.

And UK marketing margins were down about $3 per barrel.

Refinery input was off 2%, due to downtime at our Pembroke Refinery in the UK and a turnaround at our Burnaby Refinery in British Columbia, Canada.

The other bar includes international trading and shipping variances.

Slide 13 shows chemical results were $137 million in the first quarter, up $62 million from the fourth quarter.

Strong ethylene prices and margins drove very good performance by the Chevron Phillips Chemical Company, though these margins have come off a bit in recent weeks.

Our Oronite additives business is included in the other bar.

Oronite's results increased largely due to the absence of fourth quarter costs, associated with closing an additive plant in Brazil.

The all other segment is covered on slide 14.

Foreign exchange effects in the first quarter were a negative $14 million, down $40 million compared to the fourth quarter.

The P&L businesses in this segment include Dynegy, power, and P&M coal.

Most of the variance reflects a swing between quarters in the accounting for our share of Dynegy's earnings.

Keep in mind that due to previously established reserves and other considerations, ChevronTexaco's recognition of discreet items related to Dynegy often differs from a straight equity percentage of Dynegy's published results.

The variance in the other bar primarily reflects the absence of positive fourth quarter tax items booked at the corporate level.

Our guidance for this segment calls for net quarterly charges in the range of 160 to $200 million, excluding Dynegy.

As we advised in our interim update last month, first quarter net charges were actually a bit higher than the top of our guidance range.

And that completes our brief analysis of the quarter.

And I'll turn it back to Steve.

Thanks, Randy.

Slide 15, I'll wrap it up by spending a moment on the dividend increase, approved by our board and announced a few days ago.

We increased the quarterly dividend 5 cents per share, to 45 cents, a 12.5% increase.

This follows a 10% increase in the third quarter, last year.

The resulting yield in long-term dividend growth are very competitive with our peer group.

We've increased annual dividends for 18 consecutive years.

Our policy is to increase the dividend consistent with sustainable earnings and cash flow, and in this regard, we're confident in the company's prospects.

That concludes our prepared materials.

We'll now take your questions.

So Elsa, please open the lines for questions.

Thank you.

Thank you.

The floor is open for questions.

If you have a question, please press "star" "one" on your touchtone phone at this time.

If at any point your question is answered, you may remove yourself from the queue by pressing the "pound" key.

Questions will be taken in the order they're received.

Please do not use your speakerphone when posing your question, as this affects sound quality for all of us.

Once again, that is "star" "one" for any questions at this time.

Our first question comes from Mark Flannery with CSFB.

Please go ahead.

Hi.

I would like to focus on the operating issues in US refining, which generated the weak results.

Could you briefly run us through what they were, and give us some reassurance that they're nonrecurring?

And then I have a very quick follow-up.

Sure, Mark.

Thank you.

Perfectly reasonable question.

Our first quarter results were impacted by both planned and unplanned downtime in our US refineries - our three major refineries, the two on the West Coast, one in Richmond, California and the other in El Segundo, as well as our refinery in Mississippi.

On order of magnitude is the impact of the shutdowns, had they not occurred at all, would probably be on the order of a little bit in the excess of $200 million as it pertains to the first quarter in absolute terms.

And roughly speaking, the impact of planned versus unplanned, was about 50-50, with the greater impact on the unplanned side, on the West Coast.

As you can appreciate, the determination of the impact is very much an analytical exercise, with the first order being the additional maintenance costs that one incurs.

But beyond that, there are second and third-order effects in trying to determine the lost profit opportunity.

Certainly, as units come down, one must change the mix of feed stocks, including changed intermediates.

Different units at each refinery are consequently impacted, and the products made at those refineries change as well.

On the West Coast, where it's not as deep a market as it is, say in the gulf, to the extent that there's significant downtime, it changes the spot prices at the refinery gate, which in turns impacts the marketing margins that the marketing folks incur in meeting marketing demands.

So as we look at planned downtime in the United States, roughly speaking, about 60% of the planned downtime was expected to occur in the first quarter, fairly minimal amounts during the second quarter.

And the balance of it really spread between late third and then the fourth quarters.

We typically plan our shutdowns to occur in the first and fourth quarters of the year, to be outside the heavy driving season here in the United States.

As to the second part of your question, we had a few units that were still slowed as we came into the month of April, but we certainly don't expect the same type of impact in the second quarter as we have seen in the first.

Mark, you said you had a follow-up question as well?

Just a very quick one.

If you could just update us on the status of some of your LNG projects, particularly, with regard to import terminals, I'm thinking?

Well, with respect to import terminals, we have an Atlantic and a Pacific strategy, for the sourcing of equity LNG to North America.

As you recall from earlier announcements, the company has made, we've received the three key permits for a terminal in Baja, California, and that project is still progressing.

In the Gulf Coast, we've gotten capacity at the facility at Sabine Pass that will be constructed.

And we're still looking at other alternatives, including the construction of a LNG facility adjacent to our refinery in Pascagoula.

So those projects and other locations are all in the mix at this stage of the game.

And are being progressed to be consistent from the timing point of view, with our natural gas production activities and LNG facilities overseas.

Okay.

Great.

Thank you very much.

Thank you, Mark.

Thank you.

Our next question is coming from Bruce Lanni with AG Edwards.

Please go ahead.

Good morning, Steve and Randy, how you are doing?

Doing fine, Bruce.

Good quarter.

Listen I just have a quick question, kind of a follow-up to what Mark has asked, dealing with refining and marketing.

But specifically, in the US, in your -- could you expand a little on a comment in your release, you stated that sales volumes due to the Texaco brand increased 7%.

Yet, when you look at the numbers year-over-year, volumes are essentially flat.

So, I guess my question is, were there specific markets that you saw some weakness in on the retail side?

And was it due to possibly increased price competition, price wars?

And what are you witnessing right now in respect to what's going on in the retail?

Well, our branded mogas volumes in the first quarter of 2005 were 583,000 barrels a day.

That's about on par with the fourth quarter, but it's up nearly 40,000 barrels a day from the first quarter of last year.

And I think the lion's share of that increase over comparable periods could be attributed to the introduction of the Texaco brand, which is chiefly in the South Eastern part of the United States.

So, I don't think there was any particular weakness in terms of marketing volumes for motor gasoline.

Okay.

Well, total volumes then, Steve.

I mean, when you look at total refined product volumes.

And was there some weakness in jet fuel or other areas that you normally, from a year-over-year?

Because what I'm getting at, if you had a 7% increase from Texaco volumes being reintroduced, I wouldn't expect to see your total product volumes over the course of the year in the US increase slightly, also?

Well, you happen to hit it right on, Bruce.

The weakness was, if you want to call it that, first quarter to first quarter was in jet fuel, and the strength in motor gasoline, so they were somewhat offsetting.

Okay.

Great, Randy.

So that implies that you still have retained strong market share on the retail side, correct, for gasoline product?

It does.

We've done very well.

And as you know, as the price at the pump has been a little bit higher, there's been some switching to lower-quality, and away from the big brands generally in the marketplace.

ChevronTexaco, however, has done very, very well against that trend, and picked up some market share relative to our major competitors.

Excellent.

That's exactly what I wanted to hear.

Thanks.

Thanks, Bruce.

Thank you.

Our next question is coming from Fred Leuffer with Bear Stearns.

Please go ahead.

Good morning, gentlemen.

I wonder if you can just quantify the PSC effects on production versus the fourth quarter and the year-ago.

Randy, I think you mentioned that you were affected in Indonesia and Kazakhstan.

But if you could give us the overall effect, please?

I'll start with versus a year ago, Fred.

The impact is about 36,000 barrel a day in total versus last year.

The impact versus the previous quarter is much smaller than that, and I don't know if I've got it here off the top of my head.

It looks like to me that it's somewhere in the, between 20,000 and 30,000 barrels per day.

Thanks a lot.

Okay.

Thank you.

Our next question is coming from Paul Cheng with Lehman Brothers.

Please go ahead.

Good morning, gentlemen.

Good morning.

Steve, Qatar has announced that they're going to put on hold, delay about further GTL project -- I mean, they singled out the ConocoPhillips and Marathon.

I'm wondering that your GTL proposal, I mean, which is two on Oryx further expansion and also a new integrated GTL development.

Are those going to be impacted at all, or is there any impact here?

Also then when you talk about the Baja California regasification terminal, you received three key permits, how important is the Baja regasification terminal to the Gorgon development?

If there's any say unfortunate event, or further delays under local opposition or something like that?

Is that going to impact the Gorgon development?

Thank you.

Let's start with the Qatar matter, Paul.

The Sasol Chevron JV continues to advance the Oryx 2 expansion and the Oryx 1 and 2 base oils projects in Qatar, on schedule, so those will not be affected by the recent announcement.

On your second question, having to do with the Baja regas terminal, we haven't had any problems in moving forward of that project as it relates to local issues, as you suggest.

And as to the Gorgon project overall, the movements of that resource to market would include not only North America, but it would also include various Asian markets, whether it be China or Japan or Korea.

So, there will be both markets will be sources for that equity gas.

Certainly, we'll consider other options with respect, in addition to Baja, but the Baja project is moving forward.

And as I had alluded to in an earlier question, we need to keep the regas terminal projects in sync with the development of overseas gas.

Thanks Paul.

Thank you.

Thank you.

Our next question is coming from Ben Shyman with John Levin & Company.

Please go ahead.

Okay.

Thank you.

Good morning.

Good morning, Ben.

Thanks for the generous dividend increase shareholders appreciate it.

My questions are focused on the US upstream, I've two questions first you're showing in slide eight, that volumes impacted net income by about $40 million.

I'm a bit curious.

Your profit per barrel if you just take net earnings and divide by the number of barrels you produce, is about $12 a barrel.

If the production was down by $2 million barrels from quarter-to-quarter how does that equate to $40 million barrels of profit impact?

Ben, one of the things that I said in my comments is that, this is kind of a little bit tricky.

Because really, that bar is reflective of two less days of activity in first quarter 92 days in fourth quarter and 90 days in first quarter.

Okay.

So I should be looking at on a date of production basis, daily production?

If you look at daily production, and we were off only slightly, and there wouldn't have been any significant volume effect.

But this is just a classic price or price variance analysis and volume variance analysis.

And the total barrels were down because of the shorter quarter.

Okay.

Maybe that explanation will touch on my second question and that is your DD&A rate is apparently up.

You said that your DD&A rate was impacted by, and I think this is what you said, higher rates on lower reserves.

I understand lower reserves on asset sales but every E&P Company that I've ever looked at that usually sells high-cost assets, their DD&A rate usually falls but yours is up by $45 million on 65 million barrels of production, which is about 70 cents of BOE.

How do you account for that?

Well, Ben that's a fair question.

The answer is that at the end of last year, we had revisions to our proved reserve quantities in the US.

Okay.

And when you go through the math of calculating the rates then, the DD&A moves up.

I think looking back at our supplemental oil and gas tables for 2004 in the United States, if memory serves me, right it's on the order of about $5 a barrel.

That's the DD&A rate.

As a result of the lower proved reserve base, you're going to see the DD&A rates move up here in 2005.

And order of magnitude, it's probably up a little over $1.

Okay.

That sounds about right.

Okay.

I appreciate the answers.

Thank you.

Thanks Ben.

Thank you our next question is coming from Paul Sankey with Deutsche Bank.

Please go ahead.

Hi, good afternoon gentlemen.

Specific questions on Venezuela, first you mentioned that Hamaca hit peak, what's your volume outlook now in Venezuela going forward?

I am specifically thinking of Boscan, and how well that's going to hold up over next couple of years?

Well Paul when you hit peak or I guess our volume outlook is very similar to where we've, to where we've been.

So you've got over 100,000 barrels a day from Boscan, maybe 110,000.

You've got another number of close to 10,000 barrels a day from LL-652.

And then you've got our volumes from Hamaca which our 30% share of roughly 180,000 barrels a day is over 50,000 barrel a day before the royalty.

You take out a little bit for the royalty, and it's in the high 40s.

So you just put those three things together.

Are you expecting Randy those to hold flat now, going forward?

That's what they've done I guess in the past.

Right, we don't see any reason for changes in any of those three areas.

I was thinking just in terms of the budget issues that you had faced with OSAs, is that not a challenge then to the Boscan volumes?

No, we don't have any projected change to the Boscan volumes.

Great.

That is perfect.

Thank you.

And on the downstream volatility sorry to keep on about that, but, I was thinking that your third quarter results of last year also seemed quite low, if you like, against expectations.

Thinking again to Mark Flannery asking about how one-off this result was, what were the similarities between third quarter and first quarter this time around?

And what is it, apart from what you said, that might have been similar between those two disappointments?

Well, we did have an impact, Paul, in our Pascagoula refinery attributable to the hurricanes that came through.

So, we lost some production at the refinery.

And had some casualties to deal with, and slowed-down units in the latter part of third quarter that carried on into fourth quarter.

The other thing that you'll remember that was similar is that motor gasoline marketing margins on the West Coast were terrible in third quarter.

And then, they were wonderful in fourth quarter and then they were terrible again in first quarter.

And it reminds, I guess, all of us that CVX has got more weighting to the West Coast than our competitors.

And we think that's a good thing.

If you have the patience to look at it over a time, it has been a competitively good thing.

But it certainly has been volatile in the last four quarters.

I would just add, as you look at our supplement, the marketing margins in the west were essentially breakeven.

If we were to take a snapshot, just as recently as last week, they've moved from that more or less breakeven level for Los Angeles, motor gas, that would be the spread between dealer tank-wagon and spot prices.

It's up about to $3.40 a barrel.

And the rack prices, in the Houston area are up to about $2.10.

So there's been some improvement.

And we'd look forward to better results for our US downstream in the second quarter, as a consequence.

Sure.

And as the implication then that the issues you faced in the first quarter with refining downtime haven't overrun into the second?

Well, as I had alluded to, there are a few units as we came into the month of April, that were still slowed as a result of the, the downtime we had in the first quarter.

But again, I don't expect it to be of anywhere near the same magnitude.

I appreciate it.

Thank you.

Thanks, Paul.

Thank you.

Our next question is coming from Doug Leggate with Smith Barney.

Please go ahead.

Hi.

Good morning, gents.

Good morning, Doug.

Hopefully, a pretty straightforward question.

You mentioned that you still had about 36,000 barrels per day shut-in the Gulf.

Can you just give us an idea when you expect to get those back?

And also in the same vein, I think Nigeria; you still have a fairly significant volume shut-in there as well.

And I guess, in answering could you also tell us in your guidance for this year, how you assumed, did you get those volumes back, or are they assumed to be done for the whole of year?

Let me start with the question on the impact of hurricane Ivan in the Gulf of Mexico.

As Randy, had mentioned, the impact on volumes and shut-in productions was about 60,000 barrels per day in the fourth quarter.

And about 36,000 barrels per day in the first quarter.

Petronius came up mid-March.

As about a week or so ago, we still had shut-in volumes at that point of about 18,000 barrels as day, mostly connected with pipelines from others.

We fully expect that will be ramping up here in the second quarter.

There is the possibility that some of that 18,000 barrels a day will not fully come back because it won't be economic.

And your second question dealing with shut-in volumes, from problems we had in early 2003, in Nigeria, I'll let, Randy answer that or complete the answer, but my recollection is that we have brought some volumes back from the southern swamp area.

And that the increased volumes in other areas could come back on-stream as early as the first part of next year.

Yes.

That's right, Doug.

You'll remember the gross volumes were about a 140,000 barrel as day.

Our net, about 45,000 barrels a day, with the civil unrest situation in the swamp in Nigeria.

We've been able to work in the southern swamp and have brought the Abiteye Field back online, it's a small amount of production.

A pumping station has been repaired.

So, we're working our way down, perhaps toward about 40,000 barrels a day, rather than 45,000 barrels day currently.

What we're going to do is take some early production systems that are barge-mounted, and move them up into the northern swamp area, where the bigger impacts at areas like Olero Creek and Dibi are located.

And we're very hopeful that we can get returns of say, a 100,000 barrels a day of production by early 2006.

But we don't expect it in 2005.

That's very clear.

Thanks very much.

Randy Richards.

Thank you.

Thank you.

Our next question is coming from Neil McMahon with Bernstein.

Hi, I've got a question basically looking at your Asian position, mainly in refining and marketing.

First of all could you go any detail regarding the refining situation in case there was any significant turnaround activity there or issues?

And then may be just a general comment about your product sales into the Asian markets.

And I've been asking all oil companies that have reported have you seen any demand elasticity or slowing of demand, especially in the core Asian markets you serve?

Well, Neil, let me answer, as to your first question, of refinery downtime in any of the Asian areas.

No, we didn't have any significant downtime in our Asian refineries.

We did experience some downtime overseas, in the non US area with a planned turnaround in our Burnaby Refinery in Canada.

And there was some downtime in our Pembroke refinery in the UK, but nothing to speak of in the Asian market.

As to the change in volumes as a result of elasticity, I don't have any specific information to address that.

So, you would guide to, you've actually seen absolutely no change between the fourth quarter of last year, the first quarter of this year, or even ongoing in the second quarter, in terms of how well you're seeing demand holding up or not in Asia?

Yes.

I think that's a fair statement, Neil.

We have our total product trade sales, outside the United States were down from the fourth quarter to the first quarter.

You have to remember that largely reflects the situation that's Steve just referred to in Pembroke, which exports gasoline.

And when it produces less gasoline, it sells less export cargos.

So, across the world in Asia, we didn't see a change and, you know, it seems like China industrial demand is humming right along.

I'd just add that looking at the Dubai refining margins that we track; that probably hit their low point in January.

But have been moving up ever since, suggesting increased production and demand in that area.

Great.

Thank you very much.

Thank you, Neil.

Thank you.

Our next question is coming from Jennifer Rowland with JP Morgan.

Please go ahead.

Thanks.

I have two unrelated questions.

First, can you give us an update on the refinery gasoline expansion project that you were thinking about for Pascagoula?

And secondly it looks like the piece of buyback, the $5 billion program will likely be done by the end of the year.

I wonder if you can give us some guidance as far as how we should think about the size of the program, going-forward?

Thank you, Jennifer.

Let me address the second question initially on the buyback program.

Just to refresh everyone's memory, it was just about a year ago that our Board approved and we announced a program to repurchase up to $5 billion worth of common stock, in a period of up to three years.

That gives us sufficient flexibility to look at any number of signposts as we move forward.

And we felt over the last year that the signposts were such that we could have a buyback program greater than what might be ratable over a three-year period.

So through the end of, through the end of the first quarter, we had repurchased $2.8 billion of our own stock.

And I think for guidance, going-forward, unless the conditions change substantially from what you've seen in the last six to nine months, it would not be unfair for you folks to anticipate a similar pace, which would likely result in that program being concluded by the end of the year.

I would note, though, Jennifer, that as we had mentioned in our press release in early April and on the call that day, concerning the buyback program post the Unocal transaction that our management and our Board would be considering, a significantly expanded program.

And again, I would envision sometime later in the year, our announcing such a program.

It's a proper usage of cash as we've had a balanced decapitalization over the last year or so, and it would help to make sure the earnings per share stay in line, and we mitigate any dilution that might otherwise occur as a result of the transaction.

Does that help?

Yes, it does.

Thank you.

And your first question again was...

On the Pascagoula refinery expansion plans -- any update on that project?

Well, the project that we've spoken about before has to do with de-bottlenecking the FCC, the Cat Cracker, which will allow us to produce more gasoline from the same type of crude input slate.

We will be involved in capital spending on that program this year in 2005, so it's going to move ahead.

But I don't have anything on the exact time parameters of that project.

We'd have to follow-up on that, Jennifer.

Okay.

Thank you.

Thank you.

Our next question is coming from Mark Gilman with the Benchmark Company.

Please go ahead.

Guys, good morning.

Two quick ones, if I could.

First, of the $150 million volume variance, Randy indicated in the international E&P, can you split it fourth quarter versus first quarter?

Is it 100 million overlift in the first and 50 in the fourth, and is that measured on a revenue or a profit basis?

My second question relates to Tahiti, and I was hoping you could provide some clarification as to what the delay is in a formal sanction for this project?

I guess I'll handle the first question, the specific one about the bar that says 150 million on volumes in international upstream.

The overlifting relative to production in the first quarter was larger than the underlifting in the fourth quarter relative to production.

So a bigger part of that bar is in the first quarter than the fourth quarter.

It's not on a pure revenue basis, but -- it's not on a bottom line margin basis, but it's kind of a gross margin kind of a concept.

And as to your second question, Mark, you know we have a very disciplined approach to move forward for our capital projects.

And with five different phases to them, Tahiti has always been on the boards to be in Phase IV or project sanction here in 2005.So we're progressing that right along.

Steve, there's no particular delay that's gone on here?

It just seems like it's an inordinate period of time between you're having conceptually reached a decision, this is commercial, and actually sanctioning a project for development?

No, there's no specific delay, we're on schedule as we had planned, Mark.

Okay.

Thanks.

Thank you.

We do have time for one more question.

And our last question is coming from John Herrlin with Merrill Lynch.

Please go ahead.

Yes.

Mark asked the question I had on Tahiti, but did you look at a EnCana's package at all, since there were obvious overlaps in the Gulf?

We certainly did look at EnCana but chose not to bid.

Super.

Thank you.

Thank you.

At this time, I would like to turn the floor back over to you for any further or closing remarks.

Well, Elsa, thank you very much.

And I thank you all for participating in the call today.

Good-bye, now.

Thank you.

This does conclude today's teleconference.

You may disconnect your lines at this time, and have a wonderful day.

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