雪佛龍 (CVX) 2003 Q1 法說會逐字稿

Good morning ladies and gentlemen.

Welcome to your Chevron Texaco first quarter earnings conference call.

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

If you would like to register to ask a question, please press the numbers 1 followed by 4 on your touch-tone telephone at any point throughout the presentation.

It is now my pleasure to turn the floor over to Mr. John Watson.

Sir, you may begin.

Thank you.

Good morning.

Welcome to Chevron Texaco's first quarter earnings conference call.

I am John Watson the Chief Financial Officer of ChevronTexaco.

Today on the call I'll joined by Pierre Breber, our Manager of Investor Relations.

Before we get started I will remind you that our presentation today does contain estimates, projections and other forward-looking statements As usual please review the safe harbor statement that's in your presentation.

I'll start by making a few summary comments.

Pierre will follow with more detail on the quarter and then we'll both take your questions.

Just to start with, the company really had a strong quarter delivering our highest quarterly earnings since the merger.

The quarter's results were driven by higher oil and gas prices, recovering down stream margins and strong underlying performance.

Our international downstream in particular delivered excellent results.

Cash flow generated during the quarter reduced net debt, that is debt less cash balances by 1.8 billion dollars.

And the total debt to capital ratio is now at 32%.

A return on capital employed was 19%.

The first quarter marks the end of the merger integration and synergy tracking process.

The company is operating as one.

Organizations, policies and practices, important systems are all in place.

The promise $2.2 billion in run rate synergy has been captured.

The full year improvement to 2003 results over 2002 from the synergy will be 400 million dollars after tax.

We've discussed these numbers and the detail behind the synergy several times in the past most recently in last quarter's call.

In the last call Dave O'Reilly also talked about our portfolio evaluation work.

This work is progressing very well and we've actually initiated some early moves in advance of completion.

You may have seen news releases announcing our intent to sell the company's interest in Papua, New Guinea and about 100 smaller oil and gas fields in North America.

These sales are being completed within the head room allowed under the pooling accounting rules that place quantified limits on divestitures so there's no impact on pooling accounting from these sales.

Our exploration strategies continue to deliver very good results.

We had another strong quarter in exploration with successful appraisals in Nigeria.

Also we are 50% equity holder in the recently announced Jan's discovery which is believed to be the largest natural gas discovery in Australian waters.

Finally we announced that one of our Tahiti appraisal wells encountered more than a thousand feet of net pay, among the highest in deep water Gulf of Mexico history.

And confirming the company's initial estimate of 4 to 500 million barrels of recoverable oil reserves.

We are very excited about Tahiti and continue to pursue aggressively its appraisal and development.

This quarter we achieved major milestones for three of our projects under development.

We approved the Tengiz production capacity expansion in Kazakhstan and the Banguala Belize Libido Tomboco development in angola's block 14.

Both will contribute significant productions in earnings growth when they come on stream in 2006.

The Athabasca Oil Sands project Canada achieved fully integrated operations in April when it's upgrader starting processing bitumen from the Muskeg river mine.

In addition we added to our upstream gas portfolio with the award of the Plataforma del Tonic exploration license in Venezuela and the signing of the Catalina project agreement in Colombia.

At the same time we started the company's new wholesale U.S. natural gas marketing unit which became operational in April.

In summary the company had a very good quarter.

Our best financial results, progress on portfolio work, major project advancement and additional exploration success.

This is a great foundation for 2003.

Dave will talk in more detail about our portfolio and other plans in a meeting in New York that's now planned for August 1.

Before I turn it over to Pierre I want to point out that you see a slightly different presentation from the company this quarter in our earnings press release.

Our supplemental materials and presentation slides.

In response to Securities & Exchange Commission regulation G we're only referring to net income.

However, we will continue to identify separately special items which will allow you to adjust for them if you choose to do so.

Now I'll turn it over to Pierre who will make a few remarks on the quarter then Pierre and I will com back and answer your questions.

Thanks, John.

I'll refer to slides which were e-mailed to you this morning and are also available on the web.

I'll also remind you that my remarks will be comparing first quarter of 2003 to the fourth quarter of last year.

The earnings press release this morning compared the first quarter of this year to the same quarter quarter a year ago..

Chart 4 shows first quarter net income per diluted share was $1.81.

Excluding charges related to the cumulative effect of accounting principal changes first quarter net income per share was $1.99.

During the quarter, the company recorded a special item charge of 39 million dollars on the sale of minority interest in two subsidiaries by LG Cal Tech.

Our 50% owned downstream affiliate in Korea.

This final charge was in line with the range provided in the interim update.

The quarter also included foreign exchange losses of 45 million dollars.

Excluding these two items income would be higher by about 8 cents per share.

Chart 5 shows that net income increased by over one billion dollars.

Oil and gas prices are up significantly.

Higher U.S. production volumes with more than offset by lower international liftings.

Refined product sales margined recovered late in the quarter.

All other items were up primarily due to lower operating and exploration expenses and higher shipping earnings.

After special items in accounting changes U.S. upstream earnings increased primarily due to higher oil and gas prices as shown on chart 6.

As stated in the interim update, the company's U.S. natural gas realization trail the increase in Henry Hub Bid week pricing because of relatively weaker pricing in the rocky mountains and California.

Oil and gas production rates also increased as production was brought back on line after being shut in due to damage caused by last year's Gulf of Mexico's storm.

The beneficial affect of higher production rate was partially offset by two fewer days this quarter.

The absence of last quarter's casualty losses increased earnings while fuel and utility costs were higher this quarter due to the increase in natural gas prices.

All other factors were a slight negative including higher DD&A

cost and severance taxes partially offset by lower exploration expenses.

After special items and accounting changes, international upstream earnings increased primarily due to higher oil and gas prices as shown on chart 7.

Liquids production was flat excluding Indonesia which decreased primarily on lower cost recovery barrels and other production share and contractual affects.

Other produced volumes decreased due to the impact of the Venezuela national strike.

Beginning this quarter, other produced volumes include the contribution from Athabasca which started bitumen production.

During the quarter liquids liftings were less than production and reduced earnings.

Exploration expenses were down between quarters and all other items were positive primarily due the absence of charges last quarter including costs related to the temporary suspension of TCO's next major expansion project.

World wide exploration expenses were about double the year ago quarter consistent with our prior guidance.

Full year exploration expense is expected to be in line with last year's totals.

Chart 8 summarizes the change in world wide oil and gas production between quarters as mentioned earlier production in the U.S. was higher after the impacts of last year's storms in the Gulf of Mexico.

All production is back on line excluding 10 to 15,000 barrels a day of oil and gas production which is not economic to restore following damage caused last year.

The decline in Indonesia production was primarily due to PSD effects.

Excluding these effects production would have been down only five MBD due to shut in wells and reduced work activity as a result of high rain fall and associated flooding.

Venezuela production was down as a result of the nationwide strike.

The company's Venezuelan monthly production average in March was back up to pre-strike levels.

All other production was up slightly.

Production increased in Thailand on completion of an bitumen expansion.

Africa production was down in Nigeria due to civil unrest late in the quarter and in Angola due to planned down time to install peto phase 2A facilities.

In Nigeria the company share of net liquids production is currently about 115,000 barrels as day which is 90% of last year's production level after OPEC restrictions but about 40,000 barrels as day lower than our net production capacity.

The remaining production capacity is on shore and will resume when the area is safe.

Production at Quito restarted in March and is currently producing around 90,000 barrel as day.

The company's share is 31%.

Through excellent efforts and commitment of our employees the company managed to minimize the impact of a difficult operating environment during the first quarter.

Excluding these production disruptions and the effects of higher than planned prices, the the company's production capacity during the quarter was in the line with plan.

On chart 9, U.S. down stream net income increased by over 200 million dollars between quarters primarily due to higher margins and the absence of last quarter's non-recurring items.

Crude product spreads were up across the board with higher refining margins partly offset by lower marketing margins.

West coast mogas margins in particular were stronger late in the quarter.

Lower refinery production and lower branded mogas sale volumes partially offset the beneficial impact of higher margins.

Crude input volumes were down primarily due to scheduled down time at the Pathgola refinery for a major clean fields project.

One crude unit in the quocore pathagola were down during most of the quarter.

The project reached a milestone in late March when the crude unit and coaker were brought back on line.

Relatively minor additional shut down work will continue through May as planned.

Branded mogas sales volume were down primarily due to weaker demand on the west coast.

Foreign crude pricing adjustments were a favorable swing as crude oil prices fell late the quarter.

Fuel and utilities cost increased with higher natural gas prices.

All other items increased earnings primarily due to the absence of last quarter's non-recurring items in addition to lower seasonal marketing expenses and higher pipeline earnings.

In the international down stream on chart 10 earnings were up primarily on higher margins, higher shipping earnings and lower operating expenses.

Refining margins are up strongly in both Europe and Asia and marketing margins recovered late the quarter.

Refined product sales were down primarily in response to higher prices and lower fuel on marketing sales.

Shipping earnings increased with higher spot charter rates which in some cases doubled in part due to security concerns.

These rates have fallen since the end of the quarter.

Lower operating expenses excluding chartering costs benefited earnings this quarter.

Operating expenses were down due to lower refinery maintenance cost in Europe and seasonality primarily in Asia and the international lubricants business.

Among other items increasing earnings were higher trading profits, increased petrochemical earnings at LG Cal Tech and higher Canadian profits.

Chemical earnings declined this quarter as shown on chart 11.

Olafin earnings decreased on lower margins due to higher feed stock and fuel cost and polyethylene price increases which lag increases in cost due to price protection clauses.

Aromatic earnings increased on higher parazilee margins and higher styrene and Benzene production.

Excluding the change in special items, net charges for the all other segment as shown on slide 12 increased primarily due to the absence of last quarter's favorable tax adjustments.

Excluding Dynergy related income this quarter's all other charges were in line with the previous guidance of $200 to $225 million per quarter.

That completes our detailed analysis for the quarter.

Let me now turn it back to John.

OK, thanks Pierre.

We'll now take your questions consistent with our prior practice we ask that you limit your questions to one per person so that we can get to as many of you as is practical.

We plan to wrap up at the top of the hour so we have up to 45 minutes.

Operator, please open the lines and we'll start taking questions.

The floor is now open for questions.

If you do have a question or comment, please press the numbers 1 followed by 4 on your touch tone telephone.

We do ask if you are a speaker, please use your handset to provide optimum sound quality.Our first question is from tie Len den of Banc of America Securities.

Our first questions is coming frim Tyler Dann of Banc of America Securities.

Good morning, John and Pierre, how are you.

Good.

Hi, Tyler.

I was -- I have a multi-part question about the down stream, please.

And it's related to operating expenses in the United States and in non-U.S. as well.

Could you please detail - I noticed there was a $50 million sequential improvement in operating expense related to international.

I don't see a similar number for U.S. and so could you please go through system wide what your operating expense improvements have been sequentially and year over year, just detailing some of them please.

I'm not sure we'll be able to give you as much detail as you seem to be looking for.

But I will tell you in general you have a number of affects that have hit the down stream in operating expenses for us just as a company.

I'll make some general comments then I'll get to the segments.

First naturally with the rise in fuel prices this period you are going to see higher fuel costs that hit operating expenses.

Some of that you can see on the income statement as well.

The first affect you have is higher operating expenses from fuel.

But on the flip side I think you are starting to see a lot of the benefits from the companies coming together in the merger .

You get a little bit of lower seasonality in the first quarter but we've been talking about improvements to our business so you are seeing that as well.

The last item that I'll speak of in general is last quarter did have some items that hit operating expense that you'd classify as really non-recurring items of sorts that just happen to hit the operating expense line.

I think we've talked about that.

I think we've talked about that in the last quarter.

So that's -- those are the general affects that I would comment on that have impacted operating expenses between periods.

In addition, we've had a shut down a significant shut down Pascagoula refinery which incurs operating expenses as well.

As far as the specific operating expenses per segment we don't disclose that as a matter of course per period.

There are a couple of bars that we show in the -- that Pierre went through - in the variance analysis that impact operating expenses.

And maybe I'll let Pierre embellish a little bit on what I've said so far.

Sure.

Thanks, John.

Internationally again what we cited was excluding a chartering cost which that would be up sequentially first quarter versus fourth quarter.

But we made money on it.

But you would see that in your operating expenses and international down stream segment.

We had lower refinery maintenance cost.

We had refinery cost in Europe last quarter that did not recure.

Again some seasonality in Asia and the international lubricants businesses are two of the areas.

Then to echo John's comment if you look at fourth quarter you would have seen some of the bars going the other way so some of it is the reversal of some other costs that you saw last quarter in the third quarter and fourth quarter variance.

In the U.S.

I think again marketing expenses you see lower advertising costs.

John has talked a lot about we've had a very tough budgeting cycle also this year so I think you are seeing the affects of that also going through.

But as John pointed out there were higher shut down costs.

So you are not seeing a variance in the U.S. down stream on ofex because some of these items are offsetting but lower season market is expenses were one of the contributions but wasn't significant enough to get its own bar because there were offsets on the fuel side and refinery shut down side.

Thanks, Tyler.

Thank you.

Thank you.

Our next question is coming from Douglas Terreson of Morgan Stanley.

Good morning, guys.

Hi, Doug.

I have a couple strategic questions related to E&P specifically on some of the projects that John mentioned in his comments.

First in Australia while I realize it may be preliminary to comment on Jan can we work on the assumption that it's unlikely to be commercialized before goragan did his location and the relative value of the gas in the two projects and as if not, why not. .

On Venezuela O&G, can you talk about ChevronTexaco's viewpoint as to where the liquid faction infrastructure should be, the next steps for the project, timetables, et cetera.

Let me take the first one and let Pierre try the second one.

Okay.

With respect to Australia and the Jans discovery there are a couple leases that are in a little bit deeper water than goragan.

We have a 50% in both leases.

Exxon announced the big discovery in Jans and they're a 50% holder in one of the leases.

It is believed to be a very large discovery.

Our view is that it will be developed after goragan.

It's part of the greater goregan complex but just its location and the relative progress that's been made on the two suggests that the goregan field will be developed first then Jans.

There are some differences at this point in what I call quality of the two.

The goregan gas does have a fairly high CO 2 content and that's something that we are considering in our development options.

We're looking at Barrel Island as a location for a facility to process the gas.

And that's our working assumption at this point.

We're doing a lot of work with the Australian government and our partners to try to develop that option.

I but I guess I'd say your comment about which is in sequence it is most likely in our view that goregan will be developed first then Jans.

And those are second half of the decade type developments that you would expect.

Sure.

And Venezuela, Doug.

Are you referring to platform or dell tana.

I'm

Which is an exploration block we were just awarded.

There is an existing discovery but I think it's a little premature to talk about it.

It's in a block that neighbors, a block that we are 50% holder in Trinidad Tobago so we're very excited by the acreage and by the opportunities not only with the existing discovery which is sort of a Legacy discovery but additional exploration potential.

But we were literally just awarded the block a couple months ago.

So first things first.

Sure that's not the issue, right.

Thanks a lot.

Thanks, Doug

Our next question is from Paul Ting of Smith Barney City Group.

Hi, Paul.

Mr. Ting your line is live.

Do you have a question.

Can you hear me okay.

Go ahead.

Sorry.

I got a real simple question.

In your press release you talked about jet fuel and there are increased volume on military grade jet fuel.

Can you quantify how much are we talking about?

Well, I can't give you details on the military jet.

I guess my overall comment is the jet fuel business is in pretty tough straits right now.

When you look at reduced air travel from the SARS flue in Asia and you look at the general impact of high prices and the condition of the airlines it's a pretty tough market.

But I guess I would say overall that the jet - increase in jet sales that we've enjoyed really are relatively modest in the grand scheme of things.

Can you talk about percentage at all?

I don't have the specifics on international jet fuel sales, no.

Thanks a lot.

Sorry.

Thank you.

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

Good morning, gentlemen.

Hey, Bruce.

How you doing.

Good.

Great quarter.

Just wanted to touch base and maybe you need to talk more in general terms, but in the -- now that the merger is over twelve months behind you, you are going to probably generate a lot of free cash flow and that's assuming that the current commodity price environment sticks.

So what are your plans to do with any excess cash?

You have a debt to cap now down at 32%, should we look to see that go lower?

Can you give us some guidance what your overall thoughts are on this?

I can.

You know my first observation is if you look at what the credit rating agencies have been -- the positions they've taken with all industry right now, they have pretty high standards.

The number of -- someone told me the other day the number of double A and triple A companies industrial corporations in the country are are down to 30.

So we enjoy the double A credit rating that we have and intended to keep it.

We are comfortably within that range right now but our view is that for the time being we're going use the surplus cash that we're generating obviously to fund the continuing development program that we have our capital program but also to reduce debt.

I think once we get under 30% we've got other things we can consider.

And we've talked before about the possibility of a share repurchase program et cetera but for the time being we'll be reducing debt.

We want to stay comfortably in that double A range and if we do initiate a repurchase program we want it to be something that would be of some magnitude and that we'd be able to sustain.

So if you are really getting a repurchase program we've done repurchase programs before.

We're obviously open to doing it again, but given the uncertainty around the sustainability of commodity prices and obviously the earnings that are derived from those commodity prices our view is to shore up our balance sheet a little bit so we're comfortable, can fund the projects that we have that we think are good for the shareholders then consider a repurchase program.

Okay, John, just an extension to that since you brought it up.

Would you entertain increasing your capital spending on additional projects this year then?

Well.

I would say the impact of higher prices on our capital program tends to be at the margin.

There are some places where we've got what I call fast gas that we can hook up in the Gulf of Mexico where we have great infrastructure.

You can move spending a little bit but that's not really the message that I'd like to leave you with.

In general we've been trying to be pretty disciplined about our capital spending.

Most of the projects that we have are long lead times and they're based on a lower assumed commodity prices.

And we really don't like to move our capital program around based on the variation in oil prices even oil or gas prices over the short-term.

So I guess what I leave you with is that I don't really see much of an impact.

Our capital program for the year is 8.5 billion dollars including our equity share.

And I think that's still a good working number.

Excellent.

Thank you very much.

Again great quarter, guys.

Thanks.

Thank you.

Our next question is coming from Steven Pfeifer of Merrill Lynch.

Hi, John, hi, Pierre.

Hi, Steve.

Wanted to probe with you the issue of asset restructuring and divestment since you guys are starting to announce a little bit here as we get close to the end of pooling and what specifics can you help us in terms of what may happen as you get past pooling.

Ir guess the real genesis in what's behind the question is that obviously in your view you got the cost-cutting, you've got the 2.2 billion, are you sort of satisfied or is there an opportunity to push the ROCE and how hard do you think you can perhaps enhance ROCE and return as you go through the next phase which would be asset restructuring.

The first will be that Dave will talk in more detail in August about all these subjects.

But in advance of that let me make a couple comments.

Maybe the latter one first on operating expenses.

You know I said that we're closing the book on synergy because as you get further away from our base year of 2000 the comparisons just become more difficult to talk about synergy.

I know some companies have kept it going for many years but our view is we've been as transparent and kind of set the standards for disclosures around synergy and we're moving on from that.

I mention last quarter that it's been the tightest budgeting cycle that I've ever witnessed in the company and I would say that general view continued.

So the pressure is on internally to deliver lower operating expenses across all of our businesses.

And I think you are see some of that in the results and hopefully you will continue to see more of that going forward.

By no means are we sitting back when it comes to operating expenses.

The environment is simply too competitive out there for us to do anything other than that.

When it comes to divestitures we will get some improvement in our performance from divestitures as well as some cash proceeds from the divestitures the general criteria around this is what we're really doing, we've had a couple years to look at the performance of the combined company to assess the assets that we have and there's some ongoing what I would call pent up demand for normal and customary asset sales and divestitures.

For example rationalization of service station programs and marginal and after review of our upstream business in the U.S. a number of marginal properties or properties that we traditionally get very good value from independents or others from - we don't have a lot of value to add to it that point.

That's one announcement that you have seen.

We haven't talked about service station rationalization publically but we're doing a little bit of that in the background. 100 fields or so in the U.S. are sort of the first installment on what you might think of as a rationalization of our upstream portfolio in the U.S.

Apart from that we're taking a fairly strategic view of what basis do we want to be in around the world on the upstream side?

Which ones are really beyond their useful life?

Or do we want to continue to focus on and which ones do we really not have a lot to add to going forward?

Particularly we're going to focus on assets of size and quality.

So when you look at the announcement we made around Papua new guinea I think that's typical of the kinds of things you'll see where we are going focus on something where we can make a difference.

Our share production at P&G is down to about 6,000 barrels as day.

While there's a gas project that's been looming out there for many years we'd be a small part of that so we think it's time to exit that.

I think that's indicative of the kind of view we're going take.

On the down stream side we're taking a look at markets where we think we can be where we have a strong competitive position either in terms of market share or sources supply.

So and there are some markets where we may have a good asset but we may just feel that we're not competitive or they may be worth more to somebody else will fit better with someone else.

So you will see additional divestitures on both the upstream and down stream side.

But that's probably about all I can say at this point.

Dave as I said Dave will come back to New York in August and talk a lot more about this and likely some organizational implications of these things as well.

Dave, just one last question John.

I'm going honor the one question --

I just want to say in August can you talk about it given the pooling instructions.

How much detail do you think you'll be able to share?

You can talk about your plans as long as you don't irrevocably commit to a disposition prior to the exploration of the pooling deadline for anything significant that would be over the threshold.

Thanks a lot.

Okay.

I'll just make one additional comment on that.

There may be some divestitures that we won't talk about for sensitive reasons related to government until they're executed but we'll certainly give a range of size and magnitude about the sales that we're talking about.

Our next question.

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

Good morning , guys.

Good morning, Fred.

My question has to do with the synergy program.

Just a couple of parts to it, John.

And that is were there any realized cost savings in the fourth quarter net of offsets?

Where do they show?

Where will the $400 million in savings come from through 2004? and can we expect an extension to the cost cutting program that's already announced.announced.

If I may without violating the rules, .

You already have.

Thanks for being tolerant.

Just in response to Bruce's question on uses of free cash flow you didn't mention dividends and I think Chevron has a long record of consecutive dividend increases.

Where do dividends fit in just in that framework?

Well I was remiss in not talking about dividends when I made the comment earlier.

It's just incrementally they don't -- if we were to increase the dividends doesn't consume a tremendous amount of additional cash.

But I will tell you dividends are a priority for this company.

We've increased the pay out per share 15 years in a row for the company and we value that record.

Having said that, we will increase dividends, the board will increase dividends as the pattern of earnings and cash flow permit.

So if our current and expected view of earnings and cash flow is strong enough to support a dividend increase I think you will see our board strongly consider it.

With respect to synergy, the way to look at synergy as you know we've talked about a run rate concept of synergy which is the 2.2 billion dollar number.

So the reason that we see an increase in - that we talk about an increase to the bottom line in 2003 over 2002 is that we were achieving that synergy gradually over the two year period.

So you get the full year affect of the synergy coming through in 2003.

Just as an illustration.

We said that synergy is at 2.2 billion dollars here.

But the average at the end of the fourth quarter was less than that.

So for example we were at 2 billion dollars at the end of the -- the average was about 2 billion dollars at the end of this fourth quarter.

The average in the first quarter was 2.2 billion so.

We get an increment in run rate for the year that we'll see.

For example, the total amount that we expect this year is 1.2 billion dollars in terms of after tax impact.

The total for last year is 800 million.

So that's roughly -- that's where we get the 400 million dollar increase.

Of course the question is are we seeing it in the numbers?

The answer is yes.

We're seeing it in the numbers I. think you can see it by some of the boxes that are there.

One thof things that I've talked about several times in the past though is there are some masking affects that we see.

And I won't go through that again because I think us and some of our competitors have talked about those.

As far as whether we'll see anything more beyond the 2.2, we will see improvements in our operating expense structure and improvements to the bottom line.

I thinly veiled some organizational changes that will be coming as a result of some of the divestitures.

I talked about the tight budgeting process.

We're just not going to call it synergy at this point because it's just -- the synergy numbers that we've used in the past have been relative to a base period of 2000 for simplicity.

We just think we're now in 2003 and so for just making it clean and simple anything that we talk about going forward will be just relative to a more recent base period.

So the answer is yes you will -- we'll have more to say about additional cost reductions but we're closing the book on synergy so the 2.2 is the last time you will hear it from me on these calls.

Thank you.

Yes.

Thanks, Fred.

Thank you.

Our next question is coming from Mark Gilman of First Albany.

Hi, Mark.

Hi, guys.

Wonder if you could clarify where you stand on Belize Benguela vis-a-vis government approval as oppose to partner approval?

I'll let Pierre make a comment I think he is closer to that one.

Yeah.

It's effectively been sanctioned by government included.

I think in terms of official releases you may be seeing something here pretty soon.

But the major contract that has been awarded as far as I know that was actually more than a month or so ago.

As a follow up, Pierre, can you put some numbers on it in terms of development costs, reserves, production numbers, things along those lines?

Let me plug our annual report supplement which is available online and you all will be receiving hard copies when they come back from printers..

So all of our major products are up dated there.

And I don't want to get ahead of -- there will be a release forth coming that provides some of that information, Mark.

So if you can just stay tuned.

But there is an existing disclosure that we have in the annual report supplement that I'll refer to you.

Okay thanks.

Thanks a lot,Mark.

Thank you.

Our next question is coming from Arjun Murti of Goldman Sachs.

Thank you.

My question relates to Dynergy.

Just wanted to see how you are seeing that situation.

I believe the one and a half billion dollar concert coming due in November they clearly look like they're in a much better position to make good on some more meaningful portion of that than looked to be the case a few months back.

I think they have told their shareholders and investors they hope to have that resolved by 2Q end of the second quarter.

Can you make any comments related to Dynergy how you are seeing the situation you've got the on-going share ownership, the strategic nature of the company has changed.

Any comment would be appreciated.

Good question.

Obviously we feel a little better about where Dynergy is today than perhaps six months ago.

They just announced earnings which were well received by the financial community and the think Bruce Williamson and his management team have really done a fine job over the last six months of building on some things that have been executed just prior to his arrival.

The company is doing much better, they've shored their liquidity.

They've completed a new set of borrowings from the bank.

So they really executed virtually everything they've said they were going to do despite some pretty difficult conditions.

And they're earning money and restructuring the company.

So I guess I would say my general view is they've really made a lot of progress.

There are some outstanding issues that they have to deal with that Bruce Williamson will talk about dealing with litigation matters, et cetera.

But one of the things that Bruce has said as a part of their financial restructuring and is that he would like to renegotiate the billion and a half preferred convertible that is due to us late in the year.

The terms of their bank agreements allow very modest payments to Chevron Texaco.

And so that's why Bruce says he is going want to work with both lenders and Chevron Texaco to see if they can be negotiate in some fashion.

Dynergy has made the statement that our security is subordinate to all of their debt.

So essentially our preferred convertible is subordinate and it's due date does not constitute liquidity event for Dynergy.

That is their view.

Nonetheless Bruce used it as an obligation and one that Dynergy would like to schedule in some fashion to kind of remove the overhang of that obligation from all stake holders really.

So I guess my comment is we're certainly in discussions with Dynergy on the subject but it's really not our issue alone.

Certainly there are other creditors that would be involved in that determination.

I will say that our carrying value of our preferred convertible continues to be 300 million dollars.

In general the value of Dynergy debt obligations have gone up fairly sharply.

But certainly there's uncertainty around what amount Chevron Texaco will ultimately realize.

The carrying value of our common stock that we have is 70 million which is still under a dollar a share.

We have 97 million shares in Dynergy.

And you've all seen that their stock has gone up to well over 4 dollars.

Last comment I'll make is that Dynergy does have a fairly large incentive to - I think to work out the preferred convertible with us because obviously that claim is superior to the common equity holders.

Maybe that's a soup to nuts view of the Dynergy situation at this point.

That's very helpful update, John, thank you.

Thanks, Arjun.

Our next question is coming from Michael Mayer of Prudential.

Hi, Mike.

Good morning, guys.

Thanks.

I am trying see how I can articulate a two part question without violating the rules.

I think on most estimates of earnings adding back depreciation, subtracting dividend and capital spending, et cetera it looks like the corporation with hardly any asset sales will generate free cash flow on the order of two and a half maybe even three billion dollars this calendar year.

Given that, what further comments can you make about the level of corporate and other charges on the quarterly basis given that you know most of that is composed of interest expense which should be falling pretty quickly?

Well the corporate and other segment guidance that we've given has been 200 to 225 million dollars after tax excluding our equity share of Dynergy's earnings.

So the charges you saw this quarter are in that range.

Our earnings from Dynergy were 36 million dollars.

They don't correspond exactly to 26% of their earnings for reasons I'll spare you.

But in general if you have a view of Dynergy's result you can see it's 200 to 225 million.

When we reduce debt we obviously would try to call or reschedule or reduce long term debt that has high coupon associated with it.

In general the reduction in debt is coming out of commercial paper and commercial paper programs - we're issuing commercial paper at about 1.25% or something in that range.

So when I talk about reducing our debt load that in the near term, or likely for most of this year the focus will be on reducing debt it's really just to shore up the balance sheet because the cost of that debt frankly isn't very high.

Certainly if and when we chose to - if cash flow remained at the kind of levels you have seen and it would surplus to what we thought was productive for us to invest and we chose to repurchase shares we want to do so from a position where we can sustain it and obviously when you repurchase shares the debt equity ratio goes up.

So I guess my comment, I guess I've answered your question around cash generation and around that segment guidance.

Are you comfortable with the numbers I sort of estimated there in terms of the free cash flow?

Well I am not -- I don't know what all your assumptions are around refining margins oil prices and gas prices et cetera so it's pretty hard for me to assess whether your numbers are appropriate or not.

Okay.

Fair enough.

Thank you very much.

Thanks, Mike.

Thank you.

Our next question is coming from Fadel Gheit from Fahnestock.

Good morning.

Good morning.

Question on asset sales.

Just the magnitude what are you saying the total will be in the next two years and what would be the impact on production volume as well as reserve volume at the end of say next year.

Let me take the last part first.

First I am going to duck the question a little bit until August when Dave will talk in more detail.

The production numbers- the U.S. sale that we announced of some 100 oil fields will reduce production roughly 25,000 barrel as day of net production.

And I mention that Papua, New Guinea was 6,000 barrel a day.

So those are two that we've announced and their impact on production.

In terms of the dollar magnitude of sales we did show a chart last quarter that had asset sales over the last decade that were in the one to two billion dollar per year range on average.

And I think it's safe to say that that's sort of a level or higher over the next three years is reasonable.

Is reasonable to assume.

But we're going to give you more detail in August .

Just to give you a little more detail on those production numbers.

It was 20,000 barrels a day in the U.S. and five in Canada from the marginal profit sales they're really North America sales in Samore Basin but I am going to duck the specific question about the proceeds until August if that's okay.

Thank you.

Thank you.

Thank you.

Our next question is coming from Paul Sanky of Deustche Bank.

Hi guys.

On exploration for the quarter and going forward a little bit perhaps could you just tell me more about your exploration expense, break that down if possible?

And also highlight any kind of useful items we might be looking out for over the next few months?

Well the big year for us reducing exploration expense was last year.

Our exploration expense was give or take 600 million which was down from 950 to a billion on a pre-merger basis.

Obviously there are -- there's variability quarter to quarter.

What we saw in the first quarter was exploration expense that was a little bit higher than -- a lot higher in the first quarter of last year but lower in the fourth quarter of last year.

What I will say as far as guidance for the full year is that it's likely that the exploration expense for the full year will be in the same $600 million range as last year in total.

We just happen to have a couple of dry holes that we recorded this period and a drilling obligation that we exited as well that contributed to slightly higher than higher than proportional exploration expense in this period.

But it doesn't change the fundamental trend.

And anything you are excited about anything on the exploration front?

This is Pierre.

A couple wells we've talked about.

Tonga obviously is something we've talked about in the past which is south of Tahiti.

We'll drill there.

I think that will spud late second quarter.

It's waiting for the rig that's actually still working the southern appraisal well in Tahiti is doing a side track.

Once its complete doing that work it will go down to Tonga.

Maybe another well I'll highlight is we were award the operatorship of the border area between Angola and the Republic of Congo which sits between our block 14 and the American section where WerPartnerFatal is the operator.

That's an area that we know a lot about that has not been drilled previously because of the uncertainly around the border dispute.

That's also a well we're looking to spud here late second quarter.

Thanks guys.

Great result.

Thank you.

Our next question is coming from George Gaspar of Robert W. Baird

Good morning.

The question I like to pursue a little bit more on the cap-ex area.

Can you define any particular change if you look back a year ago current and then forward one year?

And looking at your upstream and breaking out exploration and development what is the -- what percentage of your expenditure load both in the exploration area and the development area would be dedicated let's say to shallow drilling versus deep water drilling?

Can you gi us an idea of how you're doing on that and what the percentages are represented by from your total?

Well I am not sure if I can.

But I'll give you a few comments on our spending overall which may or may not get to what you are talk about then I'll let Pierre make a few comments if he can put a little color on it.

I mentioned earlier that our capital spending is including affiliates is 8 and a half billion dollars.

In general we have taken our spending down in the upstream business primarily the U.S.

If you go back to say three years ago and look at our average 1999 through 2001 we spent the combined company over two billion dollars about 2.2 billion for the three year average.

We're down to about a billion seven in our plan in the U.S. right now.

So we're really taking a hard look at where we spend our money and making sure that it's spent very wisely.

The spending in the international upstream has been more or less flat over that same period of time consistent with the timing of project expenditures that we have going forward.

Then we've been -- we've had our down stream and chemical business worldwide on a pretty strict ration over that same time period.

As far as where the spending is going in shallow versus deep water we have selected deep water projects and tests that we're conducting really in three primary areas the Gulf of Mexico, Angola, Nigeria, a little bit in Brazil.

But everything else is either shallow or on shore.

Maybe I'll let Pierre talk a little bit and see if he can put any color on that but I'm not sure we have a break out of shallow versus deep.

I've seen your concern of more focus on North America .

If you look at North America a majority of the exploration expenditures would be in the deep water of Gulf of Mexico.

That's our area of focus.

We actually had a discovery up in the Kinzy Delta, the north Langley well that we participate with one third in with BP and another company I am forgetting its name.

So you will see a a little bit of exploration continued exploration up there when that drilling season resumes but we're pleased to have had a discovery up there.

On the shallow shelf you will see dilly nation drilling continue which you know is - came up as exploration expense and clearly also some deep gas, very limited but we've had some success in the deep gas plays of the shelf.

So you will see a little bit of that also.

East coast Canada is another area which not a focus area but what we call a test area.

I don't believe we have a well planed there this year we did have a well last year that found evidence of a hydrocarbon system working but not in commercial quantities.

Okay.

That's a good explanation.

Thank you.

Our next question is coming from Matthew Warburton of UBS Warburg.

Good morning gentlemen.

Quick question on the cash generation.

Very impressive debt reduction during the quarter.

If we look at your net income, DD&A, exploration expense, obviously the lower cap-ex you didn't make the contingency payment on TCO, I am still finding it difficult to reconcile the 1.8 billion reductions.

Was there anything in terms of seasonal work and capital movement even off the impressive production of last year.

Or tax or other issues that are not immediately evident in the data you have released this morning that have helped you pay down so much debt.

To answer your question there are some pretty substantial working capital movements but I think what I will do our Q's is going to be out very shortly and it will give you all the detail you want.

I wouldn't reach the conclusion that a substantial portion of cash generation is coming from working capital if that's your question.

But there are a lot of swings in a variety of different line items obviously because of the big swing in prices and the timing of tax payments as well as a few other items I won't go into here.

But I guess the best I'll do is refer to you the Q because obviously you will get a lot of detail and that's less than a couple weeks away.

It will actually be out late next week or early the following week.

Essentially some of the cash generation [INAUDIBLE] we see in the quarter will reverse as those cash payments are paid in the second quarter on the tax example?

Well there are -- I think it depends what your assumptions are for earnings for the company.

Depends what your assumptions are for other working capital movements but if you just want to isolate on taxes payable alone, yes.

Right.

Thanks very much.

I think we'll take one or two last questions here.

Thank you.

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

Thank you.

Good morning, guys.

Good morning.

First of all congratulation on good quarter.

John, when I look at the first quarter operating and SG&A cost total is about 2.9 billion dollar versus the year ago 1Q '02 is about 2.6 so that's an increase of 330 million dollars year over year.

Can you tell us how much is the increase related to fuel and utility cost and how much the increase is due to pension expense and for the pension expense do you expect the current first quarter level is a good one or we should expect further increase.

That's a good question.

If you look in our income statement which is what Paul is referring to on the operating expense and SG&A lines that are there there is a increase in first quarter '03 versus first quarter '02.

I wish I could make the world stand still and have no changes to underlying conditions but that's not the case.

The biggest component of the increase that you refer to is fuel costs.

But I'll highlight three or four things that contributed to that.

One is fuel.

The second is higher shipping costs.

Third party shipping costs.

Freight rates were very high and when we contract for tonnage we incurred additional costs.

Pension costs that you mentioned as well as you know with a decline in the U.S. dollar since a year ago and some of our international areas in the down stream for example you do get somewhat higher operating expenses when translated to U.S. dollars.

The last component is obviously inflation and salary programs and things of that sort.

So you get those changes.

As far as specific guidance on pension cost go our pension expense in the first quarter before tax was up 35 million dollars versus the average quarter for 2002.

And it's difficult to project pension expense.

We know what some of our actuarial assumptions are but the big wrinkle in pension expense is settlement losses which are essentially acceleration of underfunding when someone chooses to take a lump sum when they leave the payroll.

Obviously we don't know whether people will choose to take lump sums when they leave the payroll.

But I would say that the 35 million dollar number is - which is what it was -- the first quarter pension expense was up over the average of 2002 is reasonable guidance for now.

John, can you talk about fuel you say the majority of the increases in the fuel because absolutely the company has no control.

Can you give us a number how much is the increase year over year on that.

Paul this is Pierre.

We show the fuel and utilities in our variance chart.

They're both explicit in the U.S. upstream and the US down stream segments.

We also in our interim update provide very specific guidance on the impact of higher natural gas, higher natural gas cost increase our operating expenses by 10 to 15 million dollars after tax on an annual basis for each 10 cent increase.

Now that includes both the natural gas that we purchase and the natural gas that we produce and consume ourselves.

So I think those are the numbers that - that's the direct impact of higher natural gas on our income statement.

Thanks, Paul.

You know we're out of time.

I'd like to thank you all for your questions and you know if you have further questions please don't hesitate to call myself and Teresa in the investors relations group.

Thank you all very much.

Appreciate it.

Thank you all for your participation.

That does conclude your teleconference.

You may disconnect your lines at this time.

Have a great weekend.