雪佛龍 (CVX) 2006 Q3 法說會逐字稿

Good morning.

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

Welcome to Chevron's third-quarter 2006 earnings conference call. (OPERATOR INSTRUCTIONS).

As a reminder, this conference is being recorded.

I would now like to turn the conference over to Vice President and Chief Financial Officer, Steve Crowe.

Please go ahead, sir.

Thank you, Mat, and welcome, everyone, to Chevron's third-quarter earnings conference call.

Today on the call I am joined by Paul Siegele, the Vice President of our Gulf of Mexico Deepwater Exploration, and Irene Melitas, our Manager of Investor Relations.

Our focus today is on Chevron's financial and operating results for the third quarter of 2006.

We will refer to the slides that are available on the Web.

Before we get started, please be reminded that today's presentation contains estimates and projections and other forward-looking statements.

We ask that you review the Safe Harbor statement on slide two.

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

The Company reported results of $5 billion or $2.29 per diluted share for the quarter.

Our earnings were up 40% compared to the third-quarter 2005 as noted in the earnings press release.

Third-quarter results were up 15% from the second quarter of 2006, which Irene will discuss shortly.

Return on capital employed over the trailing four quarters was 23%.

Our balance sheet continues to show financial strength and flexibility.

The debt ratio remained at 13% at quarter-end.

Our capital and exploratory spending was $4.1 billion for the quarter.

Stock repurchases were $1.4 billion for the quarter.

We had cumulative purchases totaling $3.8 billion.

We expect to complete the current $5 billion program by year-end.

And finally, our year-to-date total shareholder return is running about 22%.

Irene will now take us through the quarterly comparisons.

Irene?

Thanks, Steve, and good morning, everyone.

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

As a reminder, our earnings release compared third-quarter 2006 to the same quarter a year ago.

Turning to slide four, net income was about $660 million higher in the third quarter.

Starting with the left side of the chart, higher realizations benefited upstream results in the US but were largely offset by the effects of lower commodity prices internationally.

The positive margin variance in downstream reflects stronger marketing margins, particularly in the US.

Third-quarter earnings benefited from higher upstream volumes, mostly due to higher international upstream liftings.

The variance in the residual other bar is the net of everything else and reflects the absence of last quarter's $250 million abandonment charge associated with last year's Gulf of Mexico storms, as well as higher chemicals results.

Offsetting these favorable variances are an increase in environmental reserves, a negative swing in tax-related items and other miscellaneous items.

Slide five summarizes the results of our US upstream earnings, which were roughly $370 million higher between quarters.

Higher realizations, particularly for liquids, benefited earnings by $65 million.

The $1.92 per barrel increase for liquids between quarters was more favorable than the change in industry benchmark prices and contributed to a favorable $60 million variance between quarters.

While the average quarterly price for WTI was about flat between quarters, the Gulf of Mexico benchmark trade month price, which is on a lagged basis, rose by $5.60 per barrel.

Slightly higher natural gas realizations resulted in a positive $5 million profit effect.

Though Henry Hub bid week prices declined, our average realizations improved by $0.04 per thousand cubic feet reflecting our regional production mix.

The effects of storm recovery volumes in the Gulf of Mexico and one additional producing day benefited earnings by $30 million.

The positive variance in the abandonment bar represents the absence of last quarter's charge of about $250 million for higher abandonment costs associated with structures and wells damaged from last year's hurricane.

The variance in other is the net of everything else and includes a favorable swing in FAS 133 effects of about $20 million.

Turning to slide six.

International upstream earnings for the quarter were about $140 million lower than the second quarter's earnings.

Lower realizations reduced earnings by about $45 million.

While Spot Brent prices rose $0.33 per barrel, unit realizations on liquids declined by $0.34 per barrel, reflecting country mix effects.

Higher liftings during the quarter, particularly in Australia and Azerbaijan, resulted in a positive earnings variance of $250 million.

At the end of the quarter, liftings were essentially in balance with production.

The variance in tax-related items reduced earnings by $240 million between quarters.

As highlighted in our interim update for the quarter, a negative swing primarily reflects the effects of recently enacted UK tax increases on North Sea oil and gas producers, as well as the net of other tax-related items.

The variance in other is the net of everything else and includes higher exploration and operating expenses.

Slide seven summarizes our worldwide oil equivalent production volumes during the last three quarters.

The figures include volumes produced from oilsands in Canada and production under an operating service agreement in Venezuela.

Production has trended up this year with the second-quarter volumes being 25,000 barrels oil equivalent per day higher than the first and the third quarter about 30,000 barrels above the second.

A steady increase has occurred in both our US and international operations.

During the third quarter, the volume increase in the US of 4000 oil equivalent barrels per day was attributable to the restoration of volumes shut in due to last year's storms in the Gulf of Mexico.

Partially offsetting this increase were the effects of maintenance activities and normal field declines.

Outside the US, oil and gas production increased by 27,000 oil equivalent barrels per day in the third quarter.

The improvement was driven by production in Eurasia, following an annual turnaround at Tengiz and the full-quarter effects of the BTC Pipeline in Azerbaijan, in Canada, following planned turnaround at Athabasca during the second quarter, and in Angola, due to the continued ramp-up of the Benguela Belize Lobito fields.

These increases were partially offset by lower production elsewhere, particularly in Denmark due to seasonal requirements and a planned shutdown.

During last quarter's conference call, we discussed the estimated effects on production volumes for the second half of the year arising from the anticipated conversions to Empresa Mixta in Venezuela.

The actual conversion took effect during the first half of October and is expected to reduce fourth-quarter production levels on the order of 90,000 barrels per day.

Turning to slide eight, US downstream net income rose by about $275 million between quarters led by stronger marketing margins, lower crude costs and improved refinery operations.

Our realized margin effects of $260 million contributed favorably to earnings relative to the second quarter, reflecting more robust marketing margins, particularly in the West and the lower cost of supplying crude oil to the US refineries, including a favorable swing in final pricing adjustments for long-haul crudes.

Lower refining margins partially offset the results.

In the West the ANS Refining Indicator margin declined by $9.70 per barrel between periods, and in the East the Gulf Coast Light/Heavy Differential Indicator declined by $2.94 per barrel.

In the West the Los Angeles Dealer Tank Wagon to Spot Motor Gasoline Indicator improved $9.43 as the decline in spot prices outpaced the decline in dealer tank wagon prices.

In the East the Houston Rack to Spot Indicator margin rose $2.35.

Improved margins for aviation fuels, asphalts and lubricants also contributed to marketing results.

The other variance reflects higher earnings in pipeline, partially offset by higher fuel price effects and other miscellaneous items.

Turning to slide nine, international downstream earnings of $610 million were higher than the second quarter's by about $165 million.

A realized downstream margin increased earnings between quarters by about $100 million and was driven by improved marketing margins in most regions and beneficial inventory effects that were partially offset by weaker refining margins.

Sales volumes resulted in a positive variance between quarters of $15 million on higher seasonal demand and less refinery downtime relative to the second quarter.

Finally, the variance in other includes higher shipping results, improved petrochemical margins in Korea and other miscellaneous items.

Slide 10 shows chemicals results were $168 million in the third quarter compared to $94 million in the second quarter.

Chevron Phillips Chemical Company's stronger performance for the quarter was primarily due to higher ethylene and benzene margins.

The other bar includes our Oronite additives business whose earnings were higher in the third quarter due to improved margins and lower non-manufacturing expenses and a favorable swing in foreign exchange results.

Slide 11 covers all other.

The third quarter's variance was largely due to the absence of a second-quarter gain from the redemption of the Company's investment in Dynergy's preferred stock reflected in the P&L businesses bar.

The variance in other is the aggregate of all other items and includes an $80 million increase in environmental reserves as mentioned in our interim update guidance for the quarter.

The effects were partially offset by several discrete items, including various beneficial tax-related adjustments, favorable changes in interest income and interest expense and other miscellaneous items.

Our third-quarter interim update guidance for the segment calls for net quarterly charges in the range of $160 to $200 million, excluding Dynergy.

Actual net charges for the quarter were lower.

That completes our brief analysis for the quarter.

Back over to you, Steve.

Thanks, Irene.

Just yesterday Chevron announced its decision to participate in the first phase of Shell Canada's planned expansion of the Athabasca Oil Sands Project in Alberta, Canada and the sanctioning of the Perdido regional project in the US Gulf of Mexico's ultra-deep water to develop the Great White Tobago and Silvertip fields.

Earlier in the quarter, we also announced the results of the Jack well tests in the deepwater Gulf of Mexico.

As mentioned at the start of our call, here with us today is Paul Siegele, Vice President of our Gulf of Mexico Deepwater Exploration, who will discuss this prospect and put it in the context of our overall Gulf of Mexico portfolio.

Paul?

Thank you, Steve.

Let me start by saying a few words about our broader Gulf of Mexico activities, which are shown on slide 12.

The Gulf of Mexico is a core producing asset for Chevron, and we produced 223,000 barrels of oil equivalent per day Chevron share.

This position in existing infrastructure will be an important enabler in bringing on our future deepwater production.

Chevron is the largest leaseholder in the deepwater Gulf of Mexico, is currently developing our Tahiti and Blind Faith discoveries, and as just mentioned by Steve, has recently sanctioned the Perdido project operated by Shell.

Tahiti and Blind Faith have expected first oil deliveries in 2008, and Perdido is expected to start up around the turn of the decade.

In addition to our capital projects, we are actively engaged in appraising other discoveries, and we have key exploratory wells to be drilled over the next several years.

Our position in the deepwater Gulf of Mexico will be an important contributor to the Company's future growth.

On the next slide, turning to Jack, Chevron announced the original discovery in September of 2004.

The appraisal well Jack 2 was drilled a year later in 2005.

An extended well test was conducted on the appraisal well.

This test was critical because the rocks in this part of the Lower Tertiary have low permeability, and there was uncertainty about the flowrate.

The test was conducted during the second quarter of 2006 and was designed to evaluate a portion of the total pay interval.

During the test, the well sustained a flowrate of more than 6000 barrels of crude oil per day.

This is encouraging news.

Because of that flowrate, the prospect of a commercial discovery has improved.

There's a lot of oil in place in the Jack structure, and Chevron has a leading exploratory position in the trend.

More than a half-dozen world records for test equipment pressure, depth and duration were set during the Jack tests.

For example, the perforating guns were fired at world record depths and pressures.

Additionally, the test tree and other drilled stem test tools set world records.

The team achieved these records with no days away from work and no spills.

Our next steps are to incorporate the flow test data into our reservoir simulations and optimized development scenarios.

This work will take the better part of next year, and we also will have to decide if we will need additional appraisal drilling to move the project forward.

It is too early to set first production dates until we complete our appraisal assessment and our simulation work.

The capital required is likely to exceed $3 billion, consistent with other Gulf of Mexico deepwater projects.

Jack is located close to the Saint Malo discovery, and synergistic development of both fields is a possibility.

Turning to slide 14, Chevron is the number one operator of Lower Tertiary Wilcox discoveries with interest in six to 12 discoveries in the trend.

The Jack well test results and evaluations are key to unlocking the potential of this trend, and Chevron is in the position to utilize these advantages and our expansion of this emerging trend.

In our estimates, the Lower Tertiary trend could contain 3 to 15 billion barrels oil equivalent estimated ultimate reserves.

The lower end of that range has probably already been discovered, leaving an upside here of over 10 billion barrels oil equivalent.

Again, these rocks are tight.

They are buried very deeply and located a long way from existing infrastructure.

The Jack well test results, combined with Chevron's technical capabilities, will be a key to unlocking the potential of this trend.

With participation of six of the 12 discoveries, Chevron has built a knowledge base and a lease base that is a leader in the industry.

It is still early days with lots of work ahead of us, but this is a very exciting and promising prospective trend.

Back over to you, Steve.

Thanks, Paul.

Well, that concludes our prepared remarks.

Paul will join us for the Q&A if you have additional questions about the Jack well test or the Lower Tertiary.

We will now take your questions.

One question per caller please.

And we will try to wrap up at or before the top of the hour.

So, Matt, will you please open the lines?

(OPERATOR INSTRUCTIONS).

Bruce Lanni, A.G. Edwards.

Good quarter.

I have actually -- well, I have more than one question, but I will just ask my one question.

Any thoughts about what the potential financial impact could be if Proposition 87 is passed in California as far as on the producing assets?

Have you --

Well, thanks, Bruce.

As another Californian, I hope you will vote appropriately come election day.

For those of you who may not be familiar with it, here in the state of California, there is a Proposition 87, that would impose up to a 6% severance tax on production here in the state.

As the largest producer in the state of California, while a lot the of particulars concerning the actual application of this proposition have yet to be finalized, we could see at current prices and current production levels a penalty on Chevron on the order of $200 million.

The last we have seen of the external assessments as to the status of this proposition is that it is essentially in a dead heat.

So it has been moving back and forth between the proponents and the opponents, but right now statistically it is too close to call.

So that is one proposition that could have a bearing on Chevron.

Clearly there have been other tax effects in this high price environment over the last year that have affected us and other companies in differentially sort of ways.

There was an increased tax in the state of Alaska that had a fairly minimal impact on Chevron.

It was effective the first of April, as I recall, and there are other things that are occurring.

So just to reiterate, the impact on us for the state of California if this proposition were to pass is about $200 million.

That is a before tax number, and so we will see how it plays out.

Paul Sankey, Deutsche Bank.

I'm trying to work out how to mix my series of questions into one question, but I will give it a go.

I have every confidence that you will be able to achieve that.

Okay.

It is a question for Paul really, and it starts firstly with more on the Great White project.

I don't think you gave a CapEx number.

If you could give us that and confirm that you said that Jack was $3 billion in your expectations, if you could go on to talk a little bit about the returns that you expect relative to conventional deepwater, if you will as opposed to the ultra deepwater that we are talking about here, and if you could then address why Trident has not been mentioned in the development plan for Great White, that would be interesting.

And finally, if you could talk about relinquishments and the potential loss of acreage from what seems to be a lower-level of exploration activity for you guys, that would be great.

You managed to succeed in getting (multiple speakers) as many items as you possibly could (multiple speakers).

I think it ended up not being a question after all.

I tell you what I'm going to go through what I remember -- (multiple speakers)

Before turning it over to Paul, as I recall, I don't believe any development cost has been quoted with respect to Great White, and any such specifics probably should be addressed by the operator rather than ourselves.

But, as to some of the other parts of your question, I will ask Paul to respond.

Yes, so that is right.

I think anything specifically about the Perdido ought to go to Shell.

The $3 billion figure, and I think it is important to state that at this point everything is still on the table in terms of development options at Jack.

And so that could be something as low capital as an FPSO early production system.

The $3 billion would be kind of a standard spar, which is close to what it is costing us at Tahiti.

The returns in the ultra-deep, they can still be pretty robust, although we're seeing cost increases continuing to rise even though crude oil prices have stabilized.

So typically they are still north of 20%, 25% even in the ultra-deep.

As to Trident, we have two discoveries in the Perdido, Trident and Tiger, both that were not committed to the regional host, and that was partially due to optimization for the facility size.

And that is to say that the incremental costs to bring them on in the first phase were not economic.

So we are planning to bring them on later on, and in fact, there is a kind of key exploratory well to be drilled just north of Tiger that might serve as a separate outlet for that discovery.

Did I catch everything, Paul, or was there something else?

The final thoughts of that single question was, firstly, if you could just clarify the north of 20% you are talking about for returns, is that off a $50 oil or --?

Yes, $55, though.

$55, great.

And the final part was that we have got the significant relinquishments issue (multiple speakers) in the Gulf of Mexico and the tightness of rigs and the potential for you to lose acreage I guess if you don't explore in the context of a very tight rig market.

It would be very interesting to hear what you have to say about that.

Yes, so we will be faced with quite a turnover in the next three years.

We have three rigs under long-term contract, and we have contracted for two additional new builds.

So while we will see a lot of churning in our acreage, I'm not concerned at this point about letting good prospects go.

We will see smaller things or things that were picked up for different trends.

For instance, in the Walker Ridge/Keathley Canyon area, a lot of that acreage was picked up for a Miocene play 10 years ago prior to the emergence of this lower tertiary play.

So a lot of it is going to go back into release, but it is not -- we are not concerned at this time that we will not get to the key prospects in time.

Just any observations on rig markets and then I will leave it, I promise.

That is it.

Thanks.

Well, they are tight as you know, and particularly for this play, there is probably only a half dozen to a dozen in the world that can drill to these depths in these water depths.

So that is part of what led us to committing to the two new builds.

But I guess what I would say, though, is it is a tight market.

We feel like we've got adequate rig needs.

What we really have is kind of a short-term crunch in the next year or so as we have got our rigs tied up with developing Tahiti and Blind Faith.

We are having to go out and do deals for the exploratory portion of our program.

But we think it's really more of a year or so, year and a half tight market for Chevron in particular.

Doug Leggate, Citigroup.

Steve, I'm going to try and bolt a couple together as well, and it is basically on production guidance.

Clearly your guidance in the second quarter was 2.6 for the second half, and Venezuela obviously has helped you in the third quarter.

With seasonal recovery in the back end of the year, would we be right to think in the range of 2.7 for the second half?

And the bolt-on is to just bring us up-to-date with the key drivers for 2008, and if we could talk specifically about how you see incremental margins changing as, let's say, we see the Tengiz sour gas project come on versus some of the declines that you have?

As was the case in the second quarter call, we advised that for the second half of the year production would run about 2.6 million barrels a day working on the premise that the Empresa Mixta would take effect in the early part of the third quarter.

As Irene had mentioned in her remarks, the Empresa Mixta has taken effect during the first half of October, and that is part of the reason or the main reason why the production levels in the third quarter were 2.7.

The impact of the Empresa Mixta on our OSAs at LLC 652 and Boscan would be about 90,000 barrels per day.

So, Doug, I would expect for the fourth quarter the production to be something north of 2.6.

We are seeing additional production coming on BBLL portion of the BBLT large project.

But, as close as we can measure it, that would be a reasonable estimate.

In essence, I'm taking the third-quarter volumes and adjusting it for Empresa Mixta.

You pointed out as to next year, I think the volume projections that we see would probably still after allowing for the Empresa Mixta be not dissimilar to what we had talked about at our analyst meeting in March.

We will be -- we are in the throes of reassessing the production guidance that we will be giving for 2007.

And you also had alluded to the fact that we have new production coming on for the TCO expansion.

Current indications are that that would start up for the combined two phases of that project in the middle of 2007, and that will be a very profitable prospect.

So we are looking forward to increasing production, and as we look forward, each of these large projects that we have been talking about for the last couple of years are progressing as expected and coming on stream.

Jennifer Rowland, JPMorgan.

I have a follow-up question on the Lower Tertiary.

Can you give us a sense of how active you plan to be there in '07, and maybe you can tell us the number of exploration wells that you're targeting in '07?

That would be helpful.

Let's see exploration wells in '07.

You know, I don't have the rig queue in front of me.

I know that there is at least one or two.

I mentioned before '06 and '07 we have got our three rigs tied up with the developing -- excuse me, Tahiti and Blind Faith.

So we're planning to do additional drilling at Saint Malo and Jack, although we still have to decide if that is going to be required.

But for '07, I'm guessing we will have one or two in the Lower Tertiary exploration wells.

Paul Cheng, Lehman Brothers.

I'm wondering, Steve, can you comment that any progress in the neutral zone license extension, and since you guys have already mentioned the pilot project there, without an official extension, will you be able to book any reserve?

Thank you, Paul.

Well, we are in the throes of negotiating with the Kingdom an extension of the project of our concession.

No reserves would be booked until that concession has been agreed to and the extension agreed upon.

But you're quite right.

We are moving forward with the pilot projects to demonstrate our capacity to increase production in the area.

Steve, can I just ask one quick follow-up, a quick question on a different subject?

You're talking about refining and marketing versus the second quarter, can you break down for us how much is the increase in marketing, and how much is the decrease in the refining margin between US and non-US?

Thanks, Paul.

Chevron has one business segment that covers refining, marketing and transportation, and we geographically split it between the US and international.

We don't have separate segments for refining and marketing, but certainly using indicative margins if you want to arrive at prices at the refinery gate, you can directionally get some flavor as to how the refining side of the house is performing relative to the marketing side.

Looking at the US, for example, the refining margins as we showed in the interim update narrowed during the third quarter.

Simply the product prices at the refinery gate, their decline outpaced crude costs.

On the flip side, marketing margins would have widened in the third quarter as the product price at the refinery gate decline outpaced the decline of the prices to our customers.

That should not be terribly surprising as you would expect in a falling crude price environment.

Some stickiness with the price change to our customers.

In Chevron's case, a couple of other things to keep in mind as you look at our performance at least in the US.

We have a fair amount of long-haul provisionally priced crudes, which in a rising market penalizes results and in a declining market benefits them.

We also, as mentioned on the call last quarter, we are long in marketing relative to refining in the Eastern part of the United States.

But the key thing I really want to leave you with is the excellent operating performance that we had at our refineries here around the system.

In our earnings release, we commented on the fact that for the fuel refineries in the United States we were running at near design capacity for crude input.

And looking at a few other indicators in terms of the downstream units within the refinery, we have seen that our refinery utilization in the third quarter of '06 has been as high as it has ever been in darn near four years.

So operating performance was a key portion to our profitability.

I think by analogy you can make some similar comments looking at some of the indicator margins overseas, but clearly there are more dispersed markets, and it is harder to make a single generalization.

There are, as we pointed out in the last conference call, problems of being -- looking at what the industry indicated margins call for and what anyone company may ultimately realized.

I hope that helps for you, Paul.

Mark Flannery, Credit Suisse.

My question is about the UK tax changes.

I am sorry if you covered this in the prepared remarks.

I missed some of them.

But other companies have broken that number out into two or three pieces, one being the in quarter impact of the higher taxes.

The impact on the deferred tax items and the prior period, i.e. the catchup back to 2006 at the beginning of the year.

Can you do that for us so we can get better comparability between your results and others?

Sure.

Irene, do you want to cover that one?

Sure.

Yes, what we booked in the third quarter was roughly $230 million, and that was consistent with the guidance that we had provided in our interim update.

You're right, that is comprised of several different components.

We did have a onetime deferred tax adjustment which was in the order of magnitude of about $130 million, and then we had a catchup adjustment, if you will, for the first six months of roughly $75 million, and then the balance is the current tax.

Mark Gilman, Benchmark.

A Lower Tertiary question, and then further rules allowing, I want to sneak one other quick one in.

There has been no drill stem test or extended production test at all to my knowledge in the Perdido.

And I am wondering on what basis given that, Paul, that you're comfortable that the permeability in that portion of the trend will be comparable to that that you have observed in the Jack test?

That is a great question, and I'm glad you asked it because I think there is a confusion about the Perdido.

The whole trend is the same age.

It is Lower Tertiary.

But in the Great White area, there is a 100 foot interval or so that has excellent porosity and permeability unlike the rest of the trend.

So Jack and Saint Malo and really the greater Lower Tertiary trend is pretty much tight everywhere it has been penetrated.

But in that Great White area, there is a good porous and permeable zone, and that is serving as kind of the anchor for that development.

And we have had several penetrations there, and none of the partners felt that a flow test was required.

If I can follow that for just a second, my recollection, Paul, is that there were significant permeability-oriented concerns in and around the time Unocal was drilling and appraising Trident.

So I guess one could assume that is outside that sweet spot you alluded to.

It is interesting because Trident is -- I forget if it is slightly older or slightly younger -- it is a different rock, and it is again still in that Lower Tertiary.

But the difference in Trident is it is a channelized sand, which means it kind of comes and goes over the structure, whereas the rocks at Tiger and at Great White and Tobago and the others are all kind of a blanket sheet sand, and there really is not the same kind of problem. (multiple speakers).

That is one of the reasons why Trident did not get into the original commitment into the host.

Thanks, Paul.

Just one other quick one.

Tengiz, it appears there has been difficulties with sanctioning and approving the CPC expansion.

My understanding is that is running 80, 85% full.

What does that mean in terms of the sour gas expansion at Tengiz when it comes on?

Is there going to be room in CPC to move it, or do we go to a trains, boats, planes, cars and whatever else transportation alternative to move that to market?

When the expansion comes on in the third quarter, as I mentioned middle to third quarter of next year, clearly the pipeline will not have been expanded at that juncture.

We have been in continuing negotiations for quite some time to achieve that.

So we have arranged and will be in a position to move the incremental crude out of Tengiz much as we had done in the early days before the pipeline came on, and as you described, we have got lots of railcars lined up and facilities to move it to market.

John Herrlin, Merrill Lynch.

Like other financial analysts, it will be multipart because I cannot count.

John, that is all because of Paul at the beginning.

Fire away.

With the Lower Tertiary for the tight portion, Paul, clearly it has got less permeability.

Do you have one interstitial cement?

Can you say that?

And then looking at kind of a subservice development, not a topside development, how many more wells would you have in that kind of play versus a Miocene play just to give us a sense of development?

Yes, another good question.

Let me make sure I understood.

Did you say, does it have one interstitial cement?

Well, I was wondering if you have interstitial cements where you have any cement at all in the sands? (multiple speakers)

No, the sands are well cemented.

They are very fine grained.

And they are also very uniform over long, long distances.

So I guess the answer to your question is we need more wells than a typical Miocene play.

One of the blessings of this play is the very thick oil column.

So all you have to do is slant the wells at a high angle, and you sort of get the same benefit of the amount of surface area exposed to the rock as a horizontal well.

So part of what is able to overcome this lower permeability is the tremendous volume of oil there and the tremendous rock that you have to work with.

But yes, we will need to have more wells than a Miocene development, and just how many wells is kind of the key work that we are doing now with the reservoir model.

In other words, do you do a few wells in the center as a sweet spot, or do you try to get the entire fringe to use horizontals, do you use multilaterals?

There are lots of different kinds of development options to consider.

Is it too early to determine the drive mechanisms of water driver depletion?

I don't know the answer to that.

Daniel Barcelo, Banc of America Securities.

A question if I could on California operations.

Firstly, maybe just to expand a little on Prop 87.

I don't know if you could quickly review for us your capital spending now in California, what would you think about in terms of decline rates?

And then what impact if any you would think that royalties could have on some future activity or production?

And the second thing, if you will permit me just on California, on downstream earnings, this quarter is clearly about marketing, particularly obviously the West Coast.

In the past, a lot of California dealers when they had some high pricing was often followed by some longer periods of very low margins.

Sometimes I think if I recall it even prices inverted to spot.

I don't know if you saw a similar situation coming up and basically what you're seeing now in terms of dealer margins in the fourth quarter.

Well, with respect to your Prop 87 related question, I don't have the information that is specific to our capital spending here in the state of California.

But if you want to follow-up with Irene off-line, we can see what information we can provide.

But typically we don't provide on them from a financial disclosure point of view that level of specificity.

In the West here in California, we really do have at least for Chevron very much integrated R&M margins, and with that arbitrariness that I had described earlier in response to Paul Cheng's question of establishing spot values at the refinery gate, from time to time we have seen inversions on the marketing side.

They usually don't last very long as you compare, say, in the face of motor gasoline dealer tank wagon prices to spot load gas prices, but they have occurred from time to time.

Obviously in the recent past here, we have seen integrated margins go south as we have progressed during the course of the third quarter and here into the early fourth quarter.

And that is about as far as I'm going to take you at this point.

Paul Cheng, Lehman Brothers.

Steve, can Irene maybe give us talking about the international inventory benefit and also the price finalization benefit, any kind of number that you can share?

And also I think for Paul, if you can talk about the deep shelf, the Gulf of Mexico is an area that you guys are interested.

Well, I'm not sure I fully understood your inventory question, but in the context of provisionally priced foreign crude, as I had mentioned to you, Chevron acquires crude.

It runs in the 12 to 15 million barrels as I recall of on the water at any point in time, and some of the conditions call for the price to be finalized a month and a half or so after or a little more after lifting.

So initially it is provisionally priced.

Then in a rising market, those cargoes that are provisionally priced will be revalued, and you will have a higher cost.

The converse happens in a falling market, and those are some of the benefits that I had alluded to in comparing the second quarter and the third quarter.

So with that rule of thumb that I gave you and with your taking an estimate of what market prices might have been at the beginning of the second, the beginning of the third and now the beginning of the fourth, you can get a rough approximation.

Steve, is most of the benefit showing up in the US, or it is going to be split evenly between US and international?

Well, the situation that I described to you, Paul, is all a US item.

It is for the cost of goods for crude right here in the US.

Right.

And how about international?

I thought Irene saying that there would be some -- was also benefit from some inventory effect?

We saw some short-term inventory swings that benefited the comparisons between the second and the third quarter where they were adverse in the second quarter and favorable in the third.

Again, it is a function of our inventory methodology where we value inventories on a year-to-date average acquisition cost. (multiple speakers)

No, that I totally understand.

But do you have a number, a -- how much did you say, 50 million benefit, 100 million you can share?

It is about $100 million, the variance.

Jeffrey Jacobe, Fayex Sarofim.

Steve, I had a quick question on the balance sheet.

As of September 30, you've got close to $2 billion in net cash.

Any update on looking at that going forward in terms of how you get your balance sheet more efficient?

Thanks, Jeff.

Over the last couple of years, as Chevron and the rest of our industry has enjoyed high commodity prices and generated strong cash flows, we first and foremost use those cash balances to fund this very attractive queue of projects that we have in front of us.

We have been talking about a couple of them in the Gulf of Mexico.

We have also used those strong cash balances to increase the dividend in the last three years.

Earlier this year it was for about 15.5%.

A year earlier it was about 12.5% as I recall, and the year before that it was about 10%.

We have also had a first $5 billion share repurchase program that was completed in 20 months and now a second $5 billion share repurchase program that we expect will be completed in about 12 months.

Nonetheless, we still have a very strong balance sheet with 13% debt, ratio and from a net debt perspective, we are actually negative net debt.

But during these periods of strong commodity prices, we have taken advantage of the opportunity to husband our cash and keep our powder dry in the event of needing to weather any downturns in the market or avail ourselves of any opportunity.

In that regard, I point out that an opportunity which has proved to be extraordinarily successful was our acquisition of Unocal about a year ago.

And in effecting that transaction, we issued 169 million shares of Chevron stock.

By the time we complete the current program and looking back to the first program, we will have issued a repurchase to like amount of stock as a result of these two programs that total about $10 billion.

So we are comfortable with our current financial structure at this point.

We expect that the Board of Directors will consider an expansion of the current share repurchase program which should be completed by year-end and that we will continue moving forward to make share repurchases as the conditions warrant.

Maybe we will take one more question and then wrap it up.

Mark Gilman, Benchmark.

Steve, would I be correct if I estimated as a result of the conversion to Empresa Mixta in Venezuela that your non-Boscan volumes as a result of this would go up about 28 KBD, and are you still of the belief that from a profitability standpoint this conversion is a push?

When we looked at the conversion to Empresa Mixta for Boscan and LL-652, we felt that from an economic point of view, we were able to maintain value for the Company and its shareholders.

The OSAs were to run another 10 years, if memory serves me right, and the Empresa Mixta have a contractual term of 20.

So we doubled the term.

We have converted profitability on a larger number of barrels in an OSA to more profitable barrels, but a smaller number of them as an equity owner.

So we should see in the short-term lower profits as a result of that, but an extension in terms of their duration.

Overall we think we have maintained value.

Thanks very much, Mark.

Just in wrapping up, as I sit back and I take a look at the third quarter, I have got a few takeaways from my perspective.

I think we have seen some very solid and climbing production during the course of the year.

As a second item, I would say that we have got -- we have seen some excellent performance, some high utilization at our refineries, and that contributed greatly to our financial performance as well.

Finally, I had mentioned that the Unocal acquisition that I have alluded to, which was about a year ago, has proved to be a resounding success.

And then finally, we are progressing this terrific queue of high-quality projects as has been mentioned a couple of times during the call and as we have discussed previously.

So, in closing, let me say to everyone I appreciate your participation on today's call.

I especially want to thank the analysts who on behalf of all the participants had asked questions during this morning's session.

So, Matt, back to you.

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

You may now disconnect.

Good day.