雪佛龍 (CVX) 2004 Q3 法說會逐字稿

Good morning, ladies and gentlemen, and welcome to the ChevronTexaco third quarter 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 today's presentation.

It is now my pleasure to turn the floor over to Mr. John Watson, VP and CFO of ChevronTexaco Corporation.

Sir, you may begin.

Thank you.

Welcome to ChevronTexaco's third quarter earnings conference call.

As indicated I'm John Watson, the CFO of ChevronTexaco.

Today on the call I am joined by Randy Richards, our Manager of IR.

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

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

Please review the safe harbor statement that you have with you on slide 2.

Turning to slide 3 I'll start with an update on our strategic progress.

Our portfolio high grading activity has move forward rapidly in the last two quarters.

Proceeds from asset sales were 1.6 billion in the third quarter, and over 3 billion for nine months.

Upstream sales closed in the third quarter included U.S. producing properties, Canadian mid-stream business, and offshore producing properties in the Democratic Republic of Congo.

In the downstream, sales of service stations under a program announced last year reached 1100 sites out of a targeted 1500.

Most sold stations keep a ChevronTexaco brand so we are reducing invested capital, while maintaining our branded market share.

And after regaining the right to the Texaco brand on July 1st we added over 800 new Texaco sites in the southeastern United States in the third quarter building our share in that part of the country.

Our exploration program has had a number of recent successes.

In the Gulf of Mexico we announced an oil discovery at the Jack prospect which tested the same trend as the earlier Saint Malo discovery.

In Australia we discovered gas with the Wheatstone well located in shallow water in an area between North West Shelf fields and Barrow Island.

In Nigeria Usan 5 was the fourth successful appraisal on OPL 222 and encountered oil in previously untested reservoirs.

In the deep water area shared between Angola and Congo, high quality oil flowed from two reservoirs discovered with Lianzi-1 well which is on a trend of previous ChevronTexaco discoveries in Landana and Tombua in Angola's block 14.

In our first exploratory well at Platforma Deltana block 2, offshore of Venezuela was with significant gas discovery.

We're following up with two more wells before the end of the year.

Recent milestones included completing construction and start up of the Hamaca upgrader in Venezuela.

At capacity the upgrader can process 190,000 barrels per day of heavy crude and send out about 180,000 barrels per day of 26 degree oil.

We've recently seen first oil in projects from China's Bohai Bay and the U.K.

North Sea.

And finally, last quarter we noted the phase start-up of LNG train 4 at the North West Shelf project in Australia.

And the first two cargos from that project were loaded for sale in September.

Moving on to financial performance on slide 4, the company had another strong quarter with earnings totaling $3.2 billion.

Nine months earnings reached almost $10 billion.

And while our performance was good our relative competitive performance was adversely impacted by our portfolio weighting this quarter.

U.S.

West coast refining and marketing margins declined between quarters.

And U.S.

Gulf of Mexico Shelf oil and gas production was impacted by the hurricanes that swept through the region.

Thesis are proportionately large businesses for us.

Nonetheless our preliminary analysis shows our nine month annualized return on capital employed on either a reported or operational basis was number one amongst our large peers.

We continue to strengthen the balance sheet and our debt to capital ratio ended the quarter at 22%, with a net debt to capital down to 2% as our cash balances including marketable securities of about 11 billion is approaching our debt level.

We also increased funding to our primary U.S. pension plan adding $600 million this brought the nine month total of funding to all ChevronTexaco pension plans to nearly $1.2 billion on top of the $1.4 billion contributed in 2003.

Now, going forward we expect contributions to be more modest on the order of $250 million per year.

With a strong balance sheet and cash flow we've taken action to return cash to our stockholders through both dividends and stock repurchases.

We increased the quarterly dividend 10% in the third quarter and we bought back $750 million of our stock in the third quarter compared to $600 million in the second quarter.

You'll recall that our stock buyback program was launched back in April.

Now Randy will take us through the quarterly comparisons.

Randy.

Thanks, John.

Slide 5 shows third quarter net income per diluted share was $1.51.

During the quarter the company recorded special items for gains related to asset sales in the U.S., Canada, and the Democratic Republic of Congo.

These gains totaled $486 million or 23 cents per share.

Foreign currency effects were a small negative, a penny per share.

Now my remarks on the variance slides will be comparing the third quarter of 2004 to the second quarter.

Keep in mind that the earnings release compared third quarter 2004 to the same quarter a year ago.

Slide 6 shows that net income dropped more than $900 million compared to the record level recorded in the previous quarter.

Despite higher oil prices a number of factors caused the earnings decline.

The special item gain on sale of Canadian upstream assets recorded in the second quarter was $585 million, nearly $100 million higher than the total special item gains in the third quarter.

Foreign exchange bookings swung from a modest positive in the second quarter to a modest negative in the third quarter.

The profit impact of higher upstream realizations was $325 million, reflecting higher crude oil prices.

However, this was more than offset by lower downstream margins including a particularly sharp drop in refining and marketing margins on the U.S.

West coast.

Lower volumes caused a $300 million earnings reduction.

Upstream volumes were affected by asset sales, Gulf of Mexico storms, and a negative swing in cargo liftings at a number of international locations.

Now looking at the other bar on the right-hand side of the chart you may recall that last quarter this was a positive variance of nearly $300 million, mainly due to a $255 million benefit in the second quarter due to certain changes in international tax laws.

This quarter we see the reverse.

A negative variance of over $400 million.

In addition to the absence of the foreign tax item, third quarter additions to environmental reserves, lower Dynegy results, and several litigation related bookings contributed to the negative variance in 'other.'

Slide 7 shows U.S. upstream earnings which increased more than $200 million to nearly $1.2 billion.

Higher earnings were driven by third quarter gains on asset sales which we've identified as special items.

These gains totaled $279 million in the third quarter with over $230 million related to the mid-August closing on the sale of a large onshore package.

Excluding the special items earnings were down about $70 million.

Higher liquids realizations boosted earnings about $100 million.

Quarterly average prices per WTI increased $5.60 per barrel while San Juan (technical difficulties) Valley heavy rose about $3.40 per barrel.

Our realizations rose about $3.60 per barrel which was less than WTI, reflecting pricing lags in the Gulf of Mexico and the heavy California crudes in our production portfolio.

Our natural gas realizations averaged about 30 cents per 1,000 cubic feet lower reflecting the movement in bid week and spot price.

Lower volumes reduced earnings $100 million, with about 40% the result of shut-ins due to hurricane Ivan in September.

The remainder reflected the impact of asset sales and natural declines.

Exploration expense was modestly lower after being above trend in the second quarter.

The variance in the 'other' bar primarily reflects FAS 133 mark-to-market accounting for several long-term gas contracts and bookings related to litigation issues.

Before leaving this slide, I'll remind you that there will be a significant impact on our fourth quarter net income due to the follow-on effects of hurricane Ivan.

After tax profits foregone due to loss production volumes could be more than $100 million ,with the calculation of course dependent on oil and gas prices.

Casualty losses repairs and other maintenance costs potentially will be affected by insurance recoveries but could easily be more than $50 million.

On slide 8, international upstream earnings fell more than $600 million.

Special items were $378 million lower.

The third quarter included gains of over 200 million on sales of a Canadian mid-stream subsidiary and our interest in producing fields off-shore Democratic Republic of Congo.

The second quarter included a large gain on sale of mature oil and gas properties in western Canada.

Foreign exchange effects caused a negative variance mainly due to strengthening of the Canadian dollar in the third quarter.

Higher realizations provided an earnings gain of about $255 million.

Liquids realizations increased nearly $5.30 per barrel, which was about $1 per barrel less than average brent prices.

And that's because of the heavy crudes we have in Indonesia, Venezuela, and the partition neutral zone between Saudi Arabia and Kuwait.

Lower volumes accounted for about $180 million of the earnings decline.

Well over half of this variance reflects quarterly swings in cargo liftings or actual sales volumes.

Liftings were substantially higher than the underlying production volumes in the second quarter but lower than the underlying production volumes in the third quarter.

Most of the rest of the decline was due to sales of producing assets in western Canada which closed on the last day of the second quarter, and in the Democratic Republic of Congo which closed on the first day of the third quarter.

Exploration expense increased $30 million due to higher well cost in Europe and seismic and other costs in Nigeria.

The 'other' bar is down reflecting the previously mentioned second quarter benefit due to certain changes in international tax laws.

Slide 9 summarizes the change in worldwide oil and gas production including 'other' produced volumes.

Volumes were off 5% between quarters, mainly due to asset sales, the Gulf of Mexico storms, U.S. declines, and cost well effects.

U.S. production fell 68,000 oil equivalent barrels per day.

The storm impact was about 25,000 barrels per day, and the effect of asset sales, about 17,000 barrels per day, with the rest due to declines in operational factors.

Outside the U.S., oil and gas production also fell 68,000 oil equivalent barrels per day.

The impact of asset sales was about 46,000 barrels per day.

Other factors included the effect of higher prices on cost oil volumes and interruptions in Angola to tie in sania (ph) condensate facilities.

In comparing the third quarter versus the same quarter last year the impact of asset sales was 30,000 oil equivalent barrels per day in the U.S. and 69,000 oil equivalent barrels per day outside the U.S..

Excluding asset sales and storm effects U.S. production fell about 7%, slightly higher than our 6% guidance.

Outside the U.S., production increased more than 2% when asset sales are excluded, and about 4% if we also adjust for the effect of higher prices of cost oil volumes.

The most significant contributors were new production from Chad and higher Kazakhstan volumes compared to the prior year period when there was extensive planned maintenance at Tengiz.

Looking ahead to the fourth quarter we anticipate the Gulf of Mexico production remaining off-line after the hurricane will have a fourth quarter impact in the range of 50,000 to 60,000 barrels per day, that's both oil and gas.

U.S. volumes will also feel the full quarters effect of property sales which occurred during the third quarter, subtracting more than 20,000 barrels per day compared to the third quarter.

On the positive side, average production is expected to increase in Chad, at the Karachaganak project in Kazakhstan.

And at the Hamaca project in Venezuela and we recently saw first oil at smaller projects in China and the U.K..

On slide ten, U.S. downstream net income fell more than $400 million.

Refining and marketing margins fell sharply on the west coast.

The west coast refining margin was down 23% compared to a very strong level in the second quarter, while the gasoline marketing margin fell nearly $5 per barrel to a negative $2.50 per barrel.

The Gulf Coast spread between light and heavy product prices widened but our realized margins suffered due to hurricane-related down time at our refinery in Pascagoula, Mississippi, which necessitated open market purchases to fulfill sales requirements.

The margin bar includes also a negative variance of $30 million related to foreign crude pricing adjustments.

There was a significant quarter-to-quarter variance represented by the 'other' bar.

Caused included increased environmental reserves, primarily for marketing sites, lower trading results, and lower pipeline earnings due to an exchange settlement and a second quarter gain on an asset sale.

The variance due to volumes was minimal as the negative impact of lower refinery runs at Pascagoula was largely offset by positive trade sales effects.

Overall, trade sales were flat, but total mogas (ph) sales were up 7% and branded mogas up 6%.

The offset was largely in feed stock fuel oil.

Over half of the increase in branded gasoline sales reflected new Texaco sites in the southeast with the remainder due to seasonality.

And although high quality competitive data is only available with a lag of several months, it's worth noting that through the first half of 2004, the data shows that the Chevron brand increased volumes in the west, gaining market share compared to major competitors.

Turning to slide 11, international downstream earnings also fell in the third quarter but to a much lesser degree than was the case in the U.S..

Foreign exchange effects were positive but lower than the previous quarter.

Refining and marketing margins were down $80 million.

Refining margins in northwest Europe were sharply lower, in part because the economics for product exports to North America cooled off.

Our global marine fuels and aviation business has also experienced lower margins.

These factors more than offset refining margins in Asia which rose modestly and remain at a healthy level.

There was a small negative volume effect between quarters due to lower refinery runs.

The most significant reduction was in Korea, due to a strike, since resolved, at our affiliate LG-Caltex.

Refineries in south Africa and Europe also had lower crude input volumes.

Volumes were higher in Singapore due to our purchase of a greater equity interest from one-third up to one-half which took effect at the end of the second quarter.

And the 'other' bar is down because there were several favorable tax items in the previous quarter.

On slide 12, results for chemicals were $106 million in the third quarter, nearly $15 (ph) million higher than the second quarter.

This was a good quarterly result for our chemicals interest.

Our share of the results of Chevron Phillips Chemical Company provided most of the improvement.

Olefins results rose $24 million as ethylene production returned to normal after a second quarter turn around at Cedar Bayou.

Polyethylene earnings also increased on higher volumes in prices.

Aromatics added $22 million largely due to higher benzene prices.

The all other segment is covered on slide 13.

There was a modestly favorable swing in foreign exchange in part reflecting our limited cash flow-based currency hedging at the corporate level.

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

These P&L businesses were off $75 million between quarters mainly due to an additional impairment charge related to Dynegy's sale of Illinois power company assets in September.

Gasification earnings were lower as the second quarter included a gain on sale of the company's gasification technology assets while power earnings were seasonally higher.

The 'other' bar reflects positive corporate tax items partly offset by an increase to environmental reserves for inactive sites which are not included in the 'other' business segments and other corporate charges.

The result in this segment is better than our guidance range which calls for net quarterly charges in the range of $120 to $150 million, excluding Dynegy.

Much of the out performance relates to corporate tax bookings which were not easily predicted in terms of either timing or amount.

For the time being we are reiterating our current guidance.

And that completes our brief analysis of the quarter.

Now I'll turn it back to John.

Thanks, Randy.

And finally slide 14 is our customary total shareholder return slide that we have shown you many times to track performance since the beginning of 2000.

Our stated goal was to be number one in TSR over a five-year period compared to our super major competitors.

We're in first place as we near the end of that fifth year.

Now that concludes our prepared remarks.

As a quick reminder we'll host an analyst meeting in New York on Tuesday, December 14th beginning at 10:00 a m.

We'll look forward to seeing many of you at that meeting, and I hope those not attending the meeting will be able to take advantage of the webcast or listen-only phone arrangements.

We'll now take your questions.

Consistent with our prior practice we ask you to limit your questions to one per turn so we can get to as many of you as practical.

We'll plan to wrap up at the top of the hour.

Operator, please open the line for questions.

(OPERATOR INSTRUCTIONS) Our first question is coming from Paul Ting of UBS.

Question on the (technical difficulties) related effects.

You gave us a very good rundown on upstream, $100 million impact in the upstream with 50,000 barrels per day volume effect.

Can you comment a little bit more on the downstream, where do we stand on that, what the earnings impact might be in the third quarter, and are you fully up and running right now?

Expected that volume impact in fourth quarter, shedding any light in that area?

That's one question, I hope.

Sure, Paul.

Well, I think the first part of your question cut out a little bit but I think what you asked was about the effects of the storm and the hurricane on Pascagoula refinery going forward.

Certainly, you know, we feel very good about the Pascagoula refinery but the storms really tracked very close to it and that refinery is in Mississippi, for those that don't know.

And we did shut down that refinery and sustain some damage in the third quarter.

Now, fortunately, as we get into the fourth quarter, that refinery is back up and running.

Now, there were some minor effects at the beginning part of the fourth quarter, so we don't expect big financial impacts in the fourth quarter.

We do have some continuing start-up issues that we had related to some shipping operations, but for the most part the refinery has been up and running most of the month of October, and I would tell you that the financial effects will be relatively modest in the fourth quarter from Pascagoula.

Third quarter impact, if you have any?

Well, the third quarter impact, it's a tough number to quantify, as you can imagine, because you've got, as Randy indicated, you've got really kind of an opportunity cost concept but I would say it's a minimum of $20 million, and that's what's easily calculable.

I can tell you that when you go out and buy product it's a little bit of a judgment as to what the price impacts should have been had you not been - - had you not been down.

But it's a minimum of $20 million and if you really looked at the all-in cost throughout the system in the U.S., it would be higher than that along with some effects in our Caribbean business as well.

Great.

Thanks a lot.

Our next question is coming from Robert Kessler of Simmons & Company.

Question on production.

How much of an effect on volumes did asset sales have in Africa specifically?

Looking at 3Q volumes versus 2Q looked like volumes declined by about 16,000 barrels a day.

The impact of asset sales in the third quarter was really just, really just one big sale in Africa which was the Democratic Republic of the Congo, 9,000 barrels a day.

Now bear in mind at the end of the second quarter we also had asset sales in Canada that impacted our international upstream business in the third quarter but your question was about Africa.

And, Robert, remember we mentioned that in Angola there was an effect as we tied in some of the sania condensate facilities, not related to sales.

How much was that effect?

I don't have an exact number on that, Robert.

We can chat later.

But, you know as John said it was 9,000 barrels of day for the sale in the Democratic Republic of Congo, so that's another factor that helps you look at the whole Africa total.

It's less than 10,000 barrels a day is the impact of sania.

And the rest of the effect on international volumes was just Canada?

Primarily Canada, yes.

Thank you.

Okay.

Next question.

Thank you.

Our next question is coming from Mark Flannery of Credit Suisse First Boston.

Please go ahead.

Hi there.

I have a question on west coast marketing.

I wonder if you could tell us if you're still having trouble passing through feed stock cost increases to the marketing in your California system particularly?

In other words, have you managed to negate the negative impact in the third quarter on west coast marketing particularly?

Fair question, Mark.

As most of you know the west coast is a very tightly balanced market, and oftentimes margins can be volatile on the west coast, generally on the positive side is what we've seen over the last few years.

What we saw during the third quarter was just the opposite of that, and as we highlighted in our interim update we put out in September, and then as we've seen in the actuals, the margins have been quite weak, particularly in the marketing area.

What we've seen in early October is that margins actually got worse in the early part of the month.

Fortunately, as the month has worn on, as you get to last week, the average margin was pretty close to break-even, if you want to try and segment out the marketing piece of it, the difference between spot prices and the prices to dealers.

But the average for the month is still negative.

So it appears that the markets have returned to a more of an equilibrium type of mode versus what we had seen through latter part of the third quarter, early part of the fourth quarter.

Thank you very much.

Thank you our next question is coming from Doug Leggate of Smith Barney, please go ahead.

Good morning.

My question is on tax.

I don't think will classify as two questions so hopefully you won't think so.

We've heard a lot in the press that given the environment we were in the moment, quite a lot of areas or governments appear to be getting more vocal about tax changes.

Renegotiating PSCs, for example, and the most recent one we're aware of is coming from Nigeria.

But we've also heard this from (technical difficulties), and of course we had slightly different kind of move from Venezuela.

Could you just give us your take on where you see, what kind of messages you're being given by, particularly in Nigeria, where you see the risk of existing contracts and what your stance is there?

In the same context, second stage of that question is your tax rate was actually quite high in the quarter.

Maybe you could give us the moving parts behind that as well please.

Fair question.

I think in general what you're seeing is contracts and agreements and tax rates and legislation that was passed many years ago when oil prices were lower gave the government a certain level of take that they felt was appropriate.

And now what you're seeing is as we enter an environment where some think we will be at a much higher level of sustained prices, I think governments are reflecting on the terms that they have and are considering what the appropriate combined royalty tax take might be.

Now, we're fortunate that we've actually had very good luck with virtually every government that we deal with in terms of transparency and consistency and honoring contracts.

In the case of Nigeria, we've actually had very good success.

We have a number of different fiscal regimes there in the government, and for some of our base operations, the incremental tax rates are already quite high, and I haven't heard any discussion of higher rates.

Now, some of the deep water arrangements are production sharing operations that have a different set of fiscal terms, but in general we've had very good luck with the Nigerian government.

Now, when it comes to the specific tax rates that we incur in any given period, that's going to reflect on, you know, a number of things, including one-time tax items and other factors.

In addition, as we've had higher prices and more income has shifted overseas where tax rates tend to be a little bit higher, particularly in the upstream, we'll tend to get - - the average tax rate can tend to go up under those circumstances.

But it's a function of many things including the equity share of affiliates.

Relative to last quarter we did have a fairly low tax rate in the second quarter because of some of the benefits that we booked in Australia.

But other than that, perhaps the best detail I can give you on taxes - - our Q is going to be out next week and I think that will give you a little bit of detail on some of the specifics of taxes both internationally and domestically.

Would it be possible to quantify the contributions from the equity affiliates in the upstream this quarter?

Well Doug, why don't you and I chat about the tax components on a separate call.

Sure.

Our overall tax rate actually for the third quarter doesn't look too high to me on a reported basis, but I know you're adjusting and looking at different segments, so let's do that separately.

Thanks a lot.

Thanks.

Next question.

Thank you.

Our next question is coming from Bruce Lanni of A.G. Edwards.

Please go ahead.

Yeah, good morning, John and Randy.

Hi, Bruce.

Quick question going back to the Gulf of Mexico if you don't mind.

The 50,000 to 60,000 barrels a day shut in for the fourth quarter, it's kid of two fold, but you said the impact, if I'm not mistaken will be $100 million, and you also commented that there's some insurance, about 50 million.

So could you first clarify that?

So is 100 million going to be offset somewhat by the insurance coverage?

Then the second part of the question is do you see this going into the first quarter of next year any of the production shutdowns?

Yes.

Couple of comments just to be clear.

Our - - the production impact in the third quarter was about, on average for the quarter, about 25,000 barrels a day.

And what Randy indicated is that the production impact would be about 50,000 to 60,000 barrels a day depending upon how fast fields come back on stream.

It's likely that we'll have continuing impacts from lost production into the first part of next year, which could be in the neighborhood of into the first quarter of perhaps 30,000 barrels a day for part of the first quarter.

In terms of the financial effects, really what Randy was saying is the lost production impact in the fourth quarter from that 50,000 to 60,000 barrels a day could be, depending on what prices are, could be $100 million.

In addition you've got some costs that will be incurred which could be up, you know, $50 million plus.

That number will depend on the insurance - - on the net insurance coverage that we have.

Now, it's a little early for to us assess that.

We're working with our insurance carriers now and trying to evaluate that.

We do have some retention or basically self insurance and over time we have gradually increased the deductibles associated with that insurance.

But it's a little early to assess, but what we're trying to say is the net expense after tax that we might book could be $50 million or more in the fourth quarter.

Okay.

Terrific.

Thanks for clarification.

Sure.

Thank you.

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

Hey, John and Randy, quick question it may not be that quick.

Capital spending, we have seen the industry, the causes going up, wondering if you can comment, whether the same impact that you're seeing and what may have an effect on your spending level as a percentage, maybe 5% higher, 10% high, or whatsoever.

Also, if we look at your capital spending after your merger with Texaco (technical difficulties) on a pro forma basis is substantially lower than what the two companies combined in the past, and with your restructuring and merger integration pretty much behind you, and that you have some pretty large project over the next several years still going to come on stream we presume your capital spending level is going to go higher.

I think the question is that if your organization capability that can handle a substantially higher capital spending level from the current - - from the current stage based on your existing headcount and everything?

I think that was one question, but I think it had parts A through E, but let me see if I - - (multiple speakers).

We try.

No, it's a fair question.

Your premise starting out was are you seeing some increases in costs and spending, and I think the short answer to that is the industry is seeing some cost pressures, and whether it's the price of steel or other raw materials, service cost, et cetera, when you get into a period of heavy activity that the industry has, along with high demand from other industries on commodities such as steel, certainly there are some pressures on cost.

So I think that trend is certainly true and we and others are feeling that.

In terms of our specific spending I think you characterized it well.

Our capital spending over the last five years on a combined base, pro forma basis, has ranged from a high of $12 billion back in 2001 to a low of $7.3 billion in 2003.

And so that number will vary depending upon the level of activity, the timing of projects, as well as the overall cost structure of the business.

In terms of the more recent time periods, our capital budget for this year is 8.5 billion, and we still think that for the full year, that's as good a number as any for to us estimate for the full year 2004.

Now, bear in mind that 8.5 billion includes our equity share of affiliates.

The number 6.7 billion on sort of a cash basis, plus close to $2 billion for our equity companies.

So that's a total of 8.5 billion this period.

And as you correctly observe, we have gone through somewhat lower period of capital spending following the mergers.

We were rationalizing operations.

And you also observed we do have some growth projects ahead.

As you've seen we're in a flat spot from our production, and we expect volumes to grow starting in 2006 and moving forward and obviously to achieve that growth we'll incur some additional capital expenditures.

In terms of guidance going forward, on December 10th Dave O'Reilly and others will be in New York and we'll give you more detail certainly for 2005 and some indications of where spending is likely to be.

But what I can tell you is at this point is probably looking in the middle of that historical range over the last five years is as good an estimate as any for 2005 type of spending.

But we'll certainly give you more detail when we come back in December.

Thank you.

Sure.

Thank you.

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

Wondering if you can give us some help on what the impact of the asset sales may be on oil and gas production in '05 and '06?

Sure.

We can try to do that.

In general what we've talked about, if you look at our production profile going back to the chart that Dave showed back in August of 2003, is that production would be more or less flat in 2000 - - kind of in the 2004 to 2005 period.

Production capacity would be more or less flat.

And the actual production would be a function of a number of things, including the exact timing of asset sales along with, you know, cost oil effects and other factors.

So giving you an exact estimate for next year at this point is a little bit difficult.

We'll come back in December and give you a more precise estimate for 2005, but let me just give you some of the asset sale figures for this year, then I'll talk generally about some of the positives that you're likely to see going forward.

In 2004, on an as-sold basis, we had about 58,000 barrels a day that were sold in the first half of 2004, and another 50 in the third quarter.

And so you'll have the full-year impact of some of those sales.

We've had a partial year impact thus far.

So, for example, the asset sales this year, while on an as-sold basis were at 58 and 50, the actual impact on production through nine months was more like 60,000 barrels a day or so.

So you'll have an increment to loss production next year from asset sales.

I won't speculate on the impact of cost oil in Indonesia in particular but certainly that can have an impact depending upon which way prices go.

And then we have some additional production that we'll see from the full-year effect of production in Chad, the full year effect of the project in Hamaca, and other projects that are coming on stream.

As far as a more precise estimate going forward, why don't I defer until December, and we'll be able to give you a little bit more information at that point.

Very good John.

Thanks.

Sure.

Thank you.

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

This is a exploration question on West Africa can you update us on how you're progressing on Block-1 JDZ in terms of the production sharing arrangement?

Has that been pretty much been put to bed, or is it an onerous situation yet for you?

I don't think we'd characterize it as an onerous situation but we're still working on final agreements at this point.

But we're comfortable with the award that's taken place but there are some - - there are final agreements to sign.

George, just to follow up on the drilling aspect, I think it's a seismic this year, and drilling the first well would be in 2005.

Something by around mid-year, do you think?

I don't have an estimate as to what time in the year.

It's not in the near month or two.

Okay.

And just quick, can you talk about tanker rates per barrel, how they've changed in the last six months to a - - or year to date, in terms of your cost structure coming into the country?

Well, certainly the tanker rates were higher in the third quarter than the second quarter, and that has a dual effect.

It increases our transportation costs but we also have our own fleet which does some out charters and makes more money as a result.

So we had higher transportation costs and higher shipping earnings in the third quarter relative to the second quarter.

So that didn't negatively impact your margins on U.S. downstream?

Well, did it have an effect on our margins in U.S. downstream, but again, elsewhere, outside of the margins, there was a bit of an offset from positive shipping earnings which are actually mostly in the international segment.

Okay.

Thank you.

Okay.

Thank you.

Our next question is coming from Neil Mcman (ph) of Sanford.

Please go ahead.

Good morning.

Could you give us a feeling for what you are saying in the Far East product demand, both in terms of the demand per product type and also the location of the demand?

And maybe you could just also comment if there's any lag effect in terms of margins or pricing on the quarter, as the numbers this quarter looked a bit light on what they could have been given the margins in the Far East in the third quarter.

Well, let me - - I'm not sure if I'm going to be able to satisfy with you the commentary other than to say we're continuing to see strong demand in Asia, and I think what everyone has been watching for is to see if there is some demand response to the high price environment.

And while anecdotally there could be, you know, you hear about some impacts, we haven't seen those on demand.

In terms of our specific results that we had, we had the impact of the Korea strike, which adversely impacted our volumes and earnings to a degree, both in the margin and in our petrochemical business.

Going forward.

So I think that's probably the biggest effect.

And also, as you look at our international downstream business we also have some business in Europe and certainly refining margins were weaker in Europe.

In terms of specific demand information by product I think we'll have to follow up with you off-line on that one.

Apologize.

Just a really quick one just on - - you mentioned last quarter distillate demand.

Are you still seeing that?

I have no different information about distillate demand from last quarter.

In general, demand has been strong.

Thank you.

Again, maybe we can help you off-line.

Thanks.

Okay.

Thank you.

Our next question is coming from Paul Sankey of Deutsche Bank.

Please go ahead.

Good morning, gentlemen.

Hi, Paul.

On Venezuela, could you talk about the impact of the tax changes that are proposed there?

And further to that, could you also comment on an announcement during the quarter about a $6 billion investment in Venezuela in heavy oil?

Okay.

It's a little early to assess the precise impact of the increase in royalty rate from - - I think you're referring to from 1% to 16%.

I think it's worth noting that the hydrocarbon law under the Hamaca project that was approved, initially was the 16%, and the government has notified Ameriven and ChevronTexaco of the increase to 16., 16.7% rate.

In terms of its exact effect I'm going to not quantify it precisely because we're still talking with the government about the exact timing and impact.

Bear in mind that royalty release granted was over a variable period of time depending upon level of capital spending and the cost recovery of that capital spending.

So it's somewhat of an analytical question at best, but I'll defer on the precise calculation until we get a little more clarification from the government on the exact terms of that royalty increase.

And on the $6 billion investment that was raised?

Sure.

I think it's a little early to comment definitively on that.

I think what I would say is that we've had a very successful project at Hamaca as a partner in the Hamaca project and we think there may be additional opportunities there and we're talking with the government, and if the economics are good we're certainly interested in participating in additional heavy oil developments in Venezuela.

But I guess it's too early for a time frame on that.

Absolutely

Can I ask you a cheeky quick question?

Would you consider a special dividend?

Or an increased buyback to reduce your cash balance now?

I think that qualifies as the second question but on the basis that it might be of general interest, what I'll tell you is, our board considers a variety of options when it comes to returning cash to shareholders.

We've had an unbroken string of 17 years in a row of dividend increases.

Periodically we've had share repurchase programs including the $5 billion program that we have in place right now.

And the board considers a variety of options in returning cash to shareholders.

And, in fact, in the distant past ChevronTexaco has paid special dividends but I think it's premature for me to speculate on whether we would strongly consider a special dividend.

For the time being what we're doing is repurchasing shares and considering periodic regular dividend increases when industry and company conditions warrant.

I'll leave it there.

Thank you, John.

Sure.

Next question.

Our next question is coming from Gene Gillespie of Howard, Weil.

Please go ahead.

Backing into your upstream cost structure, our arithmetic would suggest that excluding severance and exploration expense that costs moved up pretty considerably, over $2 a BOE from second quarter to third quarter.

Can you comment on that?

Well, I'm not exactly sure how the calculation - - how that calculation might be made.

What I can tell you is costs are a function - - cost per barrel are a function of two things.

They're a function of the barrels, obviously in the period, and they are a function of what might happen to cost.

A couple of things that we're seeing, earlier we mentioned freight rate increases, shipping costs.

There also were litigation and other costs that can get into operating expense lines.

I don't think I would say that we have seen a $2 per barrel increase in operating costs on any sort of normal basis, but between quarters.

I don't think that's - - I don't think that would be a fair characterization of our business.

But certainly there are cost pressures that we're seeing from service companies and others.

I think we'll - - in order to really dissect that well I think we'll need to wait until we take a look at both our operating expenses and those of our competitors in the oil and gas disclosures that come out at the end of the year.

But I don't think a $2 a barrel increase in OpEx would be a fair characterization of our OpEx.

Well, it isn't necessarily isolated to operating expense.

Do you have a DD&A number for the quarter?

Well, our DD&A between quarters was actually lower, if you look third quarter to third quarter, from last year, for a variety of different reasons.

I'm talking about second quarter of this year.

From second quarter to third quarter.

Our DD&A rates are generally calculated - - are generally calculated annually.

I don't have a DD&A per barrel rate, and it's highly a function of the mix of fields and properties that you have in those given periods.

Maybe the best thing to do on some of the DD&A commentary is to follow up with Randy off line, unless you've got anything handy, Randy.

I'll be happy to do that.

In absolute, the DD&A was lower, and I'm not tracking with some of your comments, but we can talk about it afterward and go through some of the details.

Thank you.

Thanks.

Our next question is coming from Michael Mayer of Prudential.

Good morning, guys.

Good morning.

Perhaps some of the confusion over the cost structure really relates to the various charges that were taken in the quarter but not enumerated as special items, which I'm all in favor of, by the way.

But notwithstanding that your earnings versus the second quarter were down while all the competitors were up.

And reading through press release, it seems that factors such as environmental charges and litigation provisions and the Dynegy impairment and et cetera, et cetera, could - - if would you please specify exactly what those figures were it would help us all in understanding the quarter and projecting the future.

So my question is could you kindly enumerate what those various charges, both plus and minus were.

We'll try - - I'll let Randy do that in just a second, but I appreciate your comment.

I know in the past you've asked about whether it would be more appropriate to have fewer special items and include them in the ongoing results, and we have done that.

You're correct, there are some ups and downs from those items that while perhaps recurring from time to time, may be a bit lumpy to the period.

Why don't I let Randy run through just a few of those to see if we can put a little bit of color on that.

Good.

Thanks.

Yeah, Mike.

We'll be happy to give some, at least close ranges.

On the environmental accruals for the company as a whole the variance between quarters was in the $80 million range, and the amount was small in the second quarter, so upwards of $80 million in the third quarter.

Might note that that's about 40 million in the U.S.

R&M, which is the area where perhaps people have focused on it.

Litigation items, a little bit more than $50 million in aggregate.

Not all in the same place.

The Dynegy impairment in the $60 million range.

How about the mark-to-market charge in the U.S.?

The mark-to-market charge in the U.S. comes about because of some long term gas contracts where we have to mark-to-market accounting.

They're partially hedged but the back end of them is not fully hedged.

The variance was about $40 million between quarters but you have to recognize that it was about positive 15 in the second quarter and negative 25 in the third quarter.

Okay.

Then the final, I guess, on the offsetting side, you mentioned some favorable tax effects in the corporate and other.

What was the absolute amount of those for third quarter?

Well, I'm not going to go into too much detail there because there's a bunch of offsetting effects in the 'other' category which is typical.

So let me leave that one to say that, you know, if you take the other parts of the equation that we've given you and look at that 'other' bar, clearly the tax items were bigger than the 'other' bar, and there's some offsets to the.

The only other comment I would give to maybe help you going forward is we'll reiterate our guidance in the other segment that we've had in the past, and I recognize that those results have been better than that guidance range, but we'll stand by that guidance at this point going forward.

So maybe that will help you understand the impact of taxes.

Would it be correct just to summarize, given the numbers that Randy read off, they add up to about 200, 215 million of lumpy unusual charges.

That's about 10 cents a share and that really accounts for the difference between what you reported as adjusted earnings and what the consensus estimate was.

Is that a fair statement?

I think your addition is right.

I'm not going to characterize - - because every analyst has a different view of each segment, I'm not going to comment on consensus.

Because some were in the rang, some were not, but I think your math is about right.

Thank you.

Appreciate it.

Thanks, Mike.

Next question.

Thank you, our next question is coming from Jennifer Rowland of J.P. Morgan.

Please go ahead.

I have a follow-up question on the asset sales.

Are there additional asset sales that you have targeted for the fourth quarter?

Seems like your asset sale number that you had originally targeted for 3Q, sounds like you came in a bit better than that.

Just wondering one, if there are additional sales we should expect in 4Q, and then two, where the overall program stand versus your original expectations?

Both upstream and downstream.

Sure, that's fair question.

If we go back to August of last year what Dave O'Reilly said is that our asset sales, on average, if you look at the last decade, between $1 billion and $2 billion a year, and that that's - - but obviously it's lower in some periods and higher in others, and that was reasonable guidance going forward.

And, in fact, we said that we might be at the upper end of that range for 2004.

In fact, what's happened, as you correctly point out, our proceeds have been substantially higher than we expected and that's really because of a couple of reasons.

One, we did elect to sell our Canadian business which we had not previously, back in August 2003, indicated, but also we're getting better prices than we might have expected because of the high commodity price environment that we've seen.

So the short answer is, yes, the number is a bit higher than expected, and there are a couple of those reasons for it.

In terms of the components of the asset sell program, in the third quarter about - - of the 1.6 billion about 1.4 billion was in the upstream.

So the vast majority - - and that's, the same is true for the 3.1 billion for the full year.

The vast majority of the asset sale proceeds, over $2.5 billion, are in the upstream.

Going forward, we have a few additional upstream asset sales in the fourth quarter but I would characterize those as relatively modest in amount, and while I won't say that our asset sales program is completed I will say that the large numbers are largely behind us.

In addition, we do have some additional service station sales that tend to continue and some smaller asset sales going forward.

So I would look for a number that's dramatically lower than the third quarter figure going forward in the fourth quarter.

Great.

Thank you.

Okay, sure.

Next question.

Our next question is coming from Mark Gilman of Benchmark.

Please go ahead.

Hi, Mark.

Wanted to talk a little about the environmental charges.

If my recollection is correct and my memory ain't great these days, we've revisited on this issue before.

And without, you know, talking about empirical numbers, I guess I'm interested in the process with which, you know, you're establishing your environmental reserves and whether or not such provisions going forward, you know, are likely to be a recurring feature or whether they're specifically associated, you know, more with the service station rationalization program and, therefore, are likely to cease when the program is completed?

Mark I wouldn't characterize the environmental cleanup cost as likely to cease after the service station program is completed.

I think as Randy pointed out, some of the charges were in the U.S. downstream, some of them were in other areas.

And I guess I would tell you is we periodically look at - - we have an environmental management company to manage the environmental remediation and other costs and we have, you know, businesses that come and go and new properties that are developed.

And as we find properties that have environmental costs and remediation associated with them based on the periodic studies we do we book a provision for them and so the best thing I can tell you is looking at - - is to look at history to some degree.

We have had some charges.

I think it's reasonable to conclude that at some future point we could have an accrual but if we had something that was estimatable at this point and reasonably certain we'd book it.

But we don't have that estimate and when we do we make the accrual.

So it's an ongoing part of the business and something that I don't think is likely to end going forward.

Okay, John.

Thanks.

Our final question is coming from John Hurlin (ph) with Merrill Lynch.

Please go ahead.

Thank you.

Encana today announced that they were going to get out of the Gulf of Mexico so I was wondering if you had more interest in owning a greater percentage of Tahiti?

Well, you've scooped me a little bit.

I missed that particular announcement but it's probably not appropriate for me to speculate on what we might buy or what we might be interested in but in general we feel good about the Tahiti project, but it's probably inappropriate for me to comment.

So sorry not to be of more help to you.

Okay thank you.

Okay, with I'll just make one final comment, reiterate for those of you that are interested we do have an analyst meeting in New York City that will be taking place on the 14th of December.

Dave O'Reilly, Peter Robertson, George Kirkland and Pat Woertz will be at that meeting.

And if you can't make it in person certainly you can access the information on the web.

So with that I'll conclude the conference and thank you all for listening.

Thank you.

This does conclude today's teleconference.

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