雪佛龍 (CVX) 2006 Q1 法說會逐字稿

Good morning.

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

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

After the speakers' remarks, there will be a question-and-answer session, and instructions will be given at that time. (OPERATOR INSTRUCTIONS).

As a reminder, this conference is being recorded.

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

Please go ahead, sir.

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

Joining me on the call today is Irene Melitas, our Manager of Investor Relations.

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

I will refer to the slides that were e-mailed to you this morning and that are available on the Web.

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

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 $4 billion or $1.80 per diluted share for the quarter.

Our results were up nearly 50% compared to the first quarter of 2005, mainly due to higher commodity prices but also helped by volume additions from the Unocal acquisition.

First-quarter results were down about 4% from the fourth quarter 2005, which Irene will detail shortly.

There were no special items for the quarter.

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

The balance sheet continues to reflect our company's financial strength and flexibility.

The debt-to-capital ratio at the end of the quarter was 16%.

Stock repurchases in the first quarter totaled $1 billion, reflecting an accelerated buyback pace.

Irene will now take us through the quarterly comparisons.

Irene?

Thanks, Steve.

My remarks compare results of the first quarter 2006 to the fourth quarter 2005.

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

Turning to slide four, net income was about 150 million lower in the first quarter.

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

The negative margin variance in downstream reflects weaker worldwide refining and marketing margins, particularly on the US West Coast, Asia-Pacific and Europe.

First-quarter earnings benefited from increased volumes from higher international upstream liftings and higher net production in the US, resulting from the ongoing restoration of shut-in volumes from last year's storm activity.

In the downstream, higher refinery input and volumes of high-value products in the US were partially offset by declines in Asia and Europe.

Earnings from chemicals improved on lower operating costs and higher sales volumes.

The residual other bar is the net of everything else.

Our first-quarter earnings of 4 billion were adversely impacted by the lingering effects of Hurricanes Katrina and Rita, which reduced our results by almost 300 million, compared to about $700 million in the fourth quarter.

The impact primarily reflects lost profit opportunity from curtailed oil and gas production.

Slide five summarizes the results of our US upstream earnings, which were essentially flat between quarters.

Higher liquids realizations benefited earnings by $35 million.

The $2.12 per barrel increase for crude between quarters was less than the rise in industry benchmark prices.

While quarterly average prices for WTI improved by $3.29 per barrel, the Gulf of Mexico benchmark trade month prices, which are on a lagged basis, declined by about $1.35 per barrel.

The increase in San Joaquin Valley heavy oil was also lower than the increase in spot WTI.

Lower natural gas realizations resulted in a negative $250 million profit effect.

Our average realizations declined $2.76 per thousand cubic feet, less than the average decline in bid-week prices, reflecting our regional production mix.

Storm recovery volumes more than offset natural fuel declines and the effects of two fewer producing days and benefited earnings by $50 million.

Lower operating expense favorably impacted earnings by about 100 million and was generally attributable to lower storm-related expenditures and third-party fuel and steams costs.

Included in other are higher natural gas trading margins and more favorable FAS 133 results, along with other miscellaneous items.

Turning to slide six, international upstream earnings for the quarter were over $200 million higher than the fourth quarter's earnings.

Foreign exchange effects, particularly related to Thailand and the UK, negatively impacted profits.

Higher realizations improved earnings by about $250 million and were largely attributable to the rise in liquid prices.

Liquid realizations rose by $4.87 per barrel, in line with the comparable increase of spot Brent prices.

The positive variance in volume effect between quarters was driven by higher liftings, particularly in Europe.

The other variance bar includes the net effect of various items, including tax adjustments in both periods.

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

Volumes were down by about 1% between quarters.

US production increased 33,000 barrels per day between quarters on the restoration of volumes shut in due to the storms in the Gulf of Mexico, which were only partially offset by normal field declines.

Storm-related activity curtailed this quarter's production by about 80,000 barrels per day, compared to 140,000 barrels per day in the fourth quarter.

Outside the US, oil and gas production decreased 72,000 barrels per day between quarters.

Excluding the effect of cost recovery volumes under certain production sharing agreements and storms in Australia, production was 2% lower.

The decline was primarily due to downtime at Tengiz for maintenance and Indonesia, reflecting inventory storage movements that affects our net production figures.

These were partly offset by increases in the UK following planned maintenance activity in the fourth quarter.

Turning to slide eight, US downstream net income declined by $175 million [Misstated as $170 million on call] between quarters on lower realized margins, which were only somewhat offset by volume and other benefits.

Margin effects of $325 million contributed negatively to earnings relative to the fourth quarter, reflecting weaker refining margins in the East, lower marketing margins on the West Coast and unfavorable $70 million swing in final pricing adjustments for long-haul crudes.

On the Gulf Coast, benchmark refining margins were down significantly relative to the fourth quarter.

The Gulf Coast light-heavy differential indicator fell by $5.40 per barrel between periods.

In the West, the ANS refining margin improved by $2.32 dollar per barrel.

However, market mix effects adversely impacted our actual results.

In the West, the L.A.

Mogas DTW to Spot Indicator margin dropped by almost $8 per barrel, as the quarter saw strong motor gasoline inventory drawdowns causing increases in spot product prices.

In the East, the Houston Rack to Spot Indicator margin declined by roughly $1.60 per barrel, driven by the decline in rack prices following hurricane-related disruptions of the fourth quarter.

Higher refinery input volumes and high-value product production, both at Pasagoula and El Segundo, drove the improvement in volume effects following fourth-quarter production downtime.

Refined product trade sales were up 6% between quarters, led by higher motor gasoline and gas/oil sales.

The variance in other includes the favorable impact of lower storm-related costs, lower fuel costs and other miscellaneous items.

Turning to slide nine, first-quarter international downstream earnings of $370 million were lower than the fourth-quarter's by about 50 million.

Weaker refining and marketing margins, particularly in Asia-Pacific and Europe, resulted in a negative variance between periods of $180 million.

In refining, rising crude costs outpaced increases in light product prices.

The Brent Margin fell by almost $2.70 per barrel, and the Dubai Cracking Margin dropped by about $1.60 per barrel.

Lower marketing margins in most regions also contributed to the weaker results, reflecting rising product costs.

Refining product and marketing sales volume effects resulted in a net negative variance between quarters of $20 million, reflecting an already well-supplied market in Asia-Pacific and operational issues at our Pembroke refinery.

The difference in operating expense benefited earnings by about $95 million between quarters, and reflected the absence of certain fourth-quarter turnaround costs and charges associated with the fourth quarter's Buncefield terminal incident in the UK.

The variance in other includes favorable tax-related swings and other miscellaneous items.

Slide ten shows chemical results were $153 million in the first quarter, compared to $71 million in the fourth quarter.

Chevron Phillips Chemical Company's stronger performance for the quarter was primarily due to declines in operating expenses and higher sales volumes.

The improvement in earnings related to additives was mainly due to a combination of higher sales volumes and margins and lower operating expenses.

Slide 11 covers all other.

First-quarter results show a negative variance from the prior quarter, mainly due to the absence of the Company's share of gain recorded on the sale of Dynegy's midstream gas business, which is reflected in the P&L business segment.

Our first-quarter interim update guidance for this segment called for net quarterly charges in the range of $160 to $200 million excluding Dynegy.

Actual net charges for the quarter were within this guidance.

That completes our brief analysis of the quarter.

Steve, back to you.

Thanks, Irene.

And now, a brief recap of our strategic progress in recent months.

I will begin with our upstream activities on slide 12, where we have announced the successful addition of several acreage positions that enhance our exploration and development portfolio.

These include the acquisition of five heavy oil leases in the Athabasca region of northern Alberta in Canada, covering 75,000 acres with prospects for significant volumes of oil; exploration rights to a large offshore block located in the Carnarvon Basin, offshore Western Australia and adjacent to the company-led Gorgon project; six blocks awarded to us in the 19th Norwegian licensing round, located in the Nordkapp East Basin in Norwegian Barents Sea; and two exploration concessions in the Gulf of Thailand, one located near existing Chevron fields.

Turning to slide 13, in downstream we recently announced the purchase of a 5% interest in Reliance Petroleum Limited, a company formed by Reliance Industries to construct, own and operate a 580,000 barrel per day refinery on the West Coast of India.

The refinery will be the world's sixth-largest.

The agreement includes a provision which grants Chevron the right to increase its equity interest in Reliance Petroleum to 29% in the future.

Chevron has also signed two memoranda of understanding with Reliance Industries to jointly pursue other downstream and upstream business opportunities in this key growth market.

And in corporate, we increased cash flow to our shareholders through our dividends and share repurchases.

Earlier this week, we announced a 15.6% dividend increase, raising our overall quarterly dividend to $0.52 per share.

This represents the 19th consecutive annual increase.

And as I mentioned at the beginning of the call, share repurchases totaled $1 billion for the first quarter.

Our policy is to increase dividends and maintain a share repurchase program that is consistent, with sustainable earnings and cash flow.

Our recent actions are a consequence of our confidence we have in our company's prospects.

Well, that concludes our prepared remarks.

We will now take your questions.

One question per caller, please.

We will plan to wrap up at or before the top of the hour.

Please open the lines for questions.

(OPERATOR INSTRUCTIONS).

Doug Terreson, Morgan Stanley.

Congratulations, guys, on your results.

During the past year, maybe 18 months or so, cost for manpower and materials and other things that are used in a new energy infrastructure have experienced some inflation.

And that's true whether it relates to the upstream or the downstream project.

And on this point, while I realize that the record speaks for itself for the Reliance guys at Jamnagar during the past decade.

I wanted to see if you would highlight some of the financial or design advantages that may be present for the proposed new plant, in that it appears to be extremely competitive on a variety of comparable economic measures as it relates to investment cost for the plant.

Well, the refinery, as I mentioned, in which we are taking an initial 5% interest, or the partnership in which we are taking an initial 5% interest, will be a 580,000 barrel a day refinery.

There's a companion refinery that Reliance Industries, Ltd. owns in the adjacent area.

It's somewhat larger, but this new refinery will be able to run a heavier crude slate.

The new refinery is projected to come onstream in late 2008, and part of the attractiveness is that their experience in constructing and operating refineries has been excellent, and they will be able to accelerate the design and construction process appreciably, relative to an operator that didn't have such a good experience in that same area.

So many of the engineering designs and contractors, I believe, that we used in the first refinery will be used in the second.

As a consequence, it will be coming onstream fairly promptly.

The arrangement that we have with Reliance calls for these other memoranda that we have signed with them.

And if the discussions that will occur pursuant to these memoranda of understanding lead to definitive agreements, then Chevron will have the opportunity to increase its equity stake in Reliance to 29%.

Some of these other agreements call for, in the downstream, the provision of feedstocks to the refinery in excess of our equity ownership, and also for the offtake of products, since this will be an export refinery that can then move into appropriate locations including the Chevron supply value chain.

There will also be negotiations as part of the memoranda of understanding to find opportunities for Reliance Industries, Ltd. and Chevron to cooperate in the upstream side of the business as well.

The refinery does look quite attractive if you look at the cost on a daily barrel comparison to grassroots and even brownroot refineries that have occurred from data that I have seen from the API.

So I think we're very pleased to establish this relationship with Reliance and to really have this option to expand a position in the downstream in a very important and growing market.

So I couldn't agree more with you;

I think this is an excellent opportunity for Chevron.

And we look forward to a very productive relationship with our new partner.

Neil McMahon, Sanford Bernstein.

I just would like to dive in a bit more into the upstream side of the business.

I appreciate the refinery is a great way to get an export market or an export chain going into the US and around the world.

But I'm actually quite interested in the upstream positions Reliance has developed over the last few years, and their exploration discoveries that they have made as well.

How much in terms of the MOU, maybe you can go into this in a bit more detail in terms of how locked in is it?

Potentially, you could participate in a joint venture with Reliance or, indeed, is there any idea about spinning off their upstream division and for you to take a stake in that?

Basically, I'm trying to get a feel for how much of their existing discoveries or exploration acreage you will be able to tie in with them and, therefore, really get a significant foothold in India, more than just refining.

It's a fair question, but it's a little premature for us to discuss the type of things that you were alluding to.

We have agreed to discuss collaborating with Reliance on opportunities in the upstream sector, but the exact parameters have not been decided.

So, while some of the things you are alluding to may come to pass, we're just simply not in a position at this point to speak very definitively.

Over this next period of time, as these understandings in the memorandum of understanding take the form of definitive agreements, we can really addressed the type of thing that you are alluding to.

But at this juncture, it's just a bit premature.

Bruce Lanni, A.G. Edwards.

Congratulations on the quarter.

Just quickly, in the news release, you commented on the Unocal transaction and stated that the acquisition, the economics even looked more favorable.

Can you provide any more color on that, and exactly where you are in the timing of the integration process?

Well, let me talk about it in a couple of different ways.

At the time we announced the deal a year ago, we commented that the transaction would be economic from a cost-of-capital perspective.

And certainly, with the events that have transpired, with respect to commodity prices in the last many months and looking forward certainly in the next few years, the economics are even more attractive, given just the movement of crisis.

But we are very pleased with the access and the way they have performed.

We have not been disappointed.

And we are right on track with the integration of the two companies.

In fact, just from a financial point of view, we will be integrating this month all of the North America Unocal operations into Chevron systems.

So we're going to lose some capability of separately identifying Unocal from Chevron.

But the integration is going on very smoothly, and I think it reflects our experience, having gone through the Chevron and Texaco merger just a few years ago.

On the synergy side of things, you recall we announced at the time of the deal $325 million of synergy opportunities.

Those are tracking right on.

As we had mentioned at our analyst meeting last month, about 60% of that has been captured on a run rate basis at the end of 2005, and about 80% here in the middle of 2006.

So we see an end in sight, and that will be well-received.

About 45% of the synergies are in the upstream and gas business, a little over 20% in the technical side and services, and then about 35% or so in the corporate side.

We have been integrating the people, and certainly have found that the Unocal employees bring a lot to the Chevron organization.

At the time of the transaction, there were about 6300 or so Unocal employees, and we will probably see 5200, 5300 of them coming forward with the Company when all is said and done, by the end of this year and next.

But, as mentioned at the analyst meeting last month, in addition to the synergies, which are mostly cost-related, we're also seeing tremendous benefits in the value creation side for drillings and completions, as we bring the best of the two companies together.

We're seeing additional optionality in transportation routes out of the Caspian area with Unocal's interests in the pipeline.

And we're also seeing, as advertised, a lot of optionality in our global gas business with the two companies coming together in Southeast Asia.

So we are very optimistic as to this transaction.

And were it to be done today, it would be much more expensive than it was a year ago.

So we are very pleased and all of the things we had anticipated are coming in.

Mark Gilman, The Benchmark Company.

I have a question about CPC and the Tengiz expansion.

It's beginning to look as if the expansion at the field level is going to come on before there can be any Russian-approved expansion of the pipeline.

Can you give me an idea whether CPC is running full as we speak, and what the roughly incremental transportation cost will run on the additional Tengiz volumes if, in fact, alternate transportation routes have to be pursued?

I don't have those specific numbers, but as far as I know, CPC is running full.

And as the projects in TCO, the Tengiz fields come onstream, we will have to look and are looking at alternate routes for moving the crude to market.

As to the incremental difference in transportation costs for these alternate routes in relation to CPC, we will have to get back to you off-line.

But it's a fair question, and we will cycle back to you.

Nicki Decker, Bear Stearns.

You talked about accelerating the pace of your buyback program.

Is this the pace that we can expect to see for the coming quarters?

And could we expect additional authorization next year?

Just for background for everyone, the first program that was authorized and commenced on April of 2004 resulted in $2.1 billion worth of Chevron shares being acquired in 2004.

Last year, we acquired $3 billion worth of Chevron shares, and in November of that year, the first $5 billion program that had been authorized by our Board was completed.

They authorized a follow-on program of similar size and duration that we commenced in December of last year.

We consciously had the Board authorize us a dollar amount and a timeframe so we can adjust the pace during the course of the period authorized to fit the circumstances of the Company's cash flows and the market.

Certainly, given the conditions that we have in the first quarter, $1 billion seemed to be a very reasonable amount.

It was about a third higher than the average quarterly pace during 2005.

And it's not unreasonable that if conditions stay as they are today, that that pace might move forward for the balance of the year.

If that pace does move forward, we will be completing a program early next year.

Here again, though, I don't want to mislead you.

We could move it up and move faster or we could slow it down, depending on conditions.

Jennifer Rowland, JPMorgan.

I wonder if you could just give us an update on where things stand with your production in the Gulf of Mexico, and whether or not your estimate for volumes that may not get recovered has changed at all?

That's a good question.

Let me give a little background for those on the phone.

When the second of the storms came through last year, by the time it got to October 1, our Gulf of Mexico production was about 60,000 barrels a day, OEG.

And our capacity prior to the hurricanes was around 320,000 barrels a day.

From that low point on October 1, we then started ramping up our production as oil that had been shut in came back on.

Much of it was shut in because of infrastructure problems.

The average production during the fourth quarter was 160,000 barrels a day, and here in the first quarter, as we have noted, it's about 200,000 barrels a day.

Data that I've seen recently for the month of April looks like we're moving a little bit above that level, maybe in the neighborhood of 215,000 barrels a day or so.

Our expectation is, as we bring on production that had been shut in, it will be largely offset, though, by normal field declines that will occur during the year.

So, on average, probably for 2006, we're looking at about 200,000 barrels a day.

What you need to keep in mind is, from that pre-storm level, the decline rate was going to be pretty steep, regardless.

Our current thinking is from that pre-storm levels, we probably have about 20,000 barrels a day that has been permanently lost, simply because it is uneconomic to bring back on.

So that looks to be the pattern as we see it right now, Jennifer, and I hope that helps.

Doug Leggate, Citigroup.

My question is on disposal, Steve.

I don't want to harp back to much about the Unocal acquisition, but when you did the deal, I think you had suggested somewhere around $2 billion of disposals.

And you promptly did that in Canada, or I guess Unocal did.

The strip price, however, was substantially below where it is now.

And my question really is, are you done with disposals?

Are you tempted to high-grade any further with the current oil price environment?

And is there anymore high-grading to be done within the Unocal portfolio itself?

Your recitation of the facts are correct.

At the time of the transaction being announced, we gave an indication that we thought we would sell about $2 billion worth of assets.

With the sale of Northrock Westfall in Canada, about 1.7 to 1.8 was achieved.

We are continuously looking at our operations as to assets to acquire and assets to divest, whether they be legacy Unocal or legacy Chevron, for that matter.

And at this time, most of assets that we have seen from the Unocal side look to fit in very well with our operations.

So we don't anticipate any major divestments that we're inclined to announce at this juncture.

But we are always looking at our portfolio, adding things when it's economic to do so, organically or otherwise, and disposing of assets when we feel it will attract more value than it would be from attaining it ourselves.

Philosophically, you recall a couple of years ago when we described the Chevron portfolio -- again, this was before Unocal -- we characterized some assets as being strategically or core and others as being non-core.

Being non-core didn't necessarily mean that they would be sold, but rather that they would not draw an inordinate amount of capital, and they would be retained if we felt that they were worth more to be owned and operated than to be sold to another party.

In all instances, our decisions are based on economics and not based on any financial metrics underpinning the appearances of gain on loss.

Thanks for the question.

Michael Young, Fidelity Investments.

The question is to provide an update on your most recent conversations with Venezuela, particularly with respect to potentially higher royalty rates on the heavy oil project.

And also, could you quantify the amount of the tax claim settlement in the first quarter?

The tax situation in Venezuela has been in the press for a number of months.

Some of the information is accurate, and much of it isn't.

But on March 9th of this year, the Venezuela tax agency proposed an oil reform tax.

And the proposed reform could increase the current tax rate from 34% to 50% for all of the extra heavy oil crude projects in the Orinoco Belt.

The reform must be first approved by the Finance Minister and then submitted to the National Assembly for discussion and approval.

It's way too early to speculate about what will happen and what the impact of that will be, particularly if it entails any conversions, as it had been for the lighter oil projects to the mix companies.

But having said that, if you were to simply try to get a handle on the tax implications of going from 34 to 50%, Hamaca's earnings are reported separately in Chevron's 10-K, and it's relatively easy to estimate the ongoing impact of the tax increase from 34 to 50%.

So that just takes a few clicks on the calculator, and you would be able to determine that.

But again, I would like to emphasize it's way too early to speculate on what might happen with respect to extra heavy oil.

William Ferrer, W.H.

Reeves and Company.

You forgot to tell Mike Young that he had to take his shoes off to do those calculations, but that's okay.

I'd like to offer my congratulations on the dividend increase.

Certain shareholders certainly find that to be very important.

My question relates to the first-quarter exploration expense.

Historically, for several years, first-quarter exploration expense, US and generally foreign -- not always, but generally foreign -- has been the low point or a low point within the year.

And both US and overseas kind of spiked in Q1.

I'm wondering if that is specifically a consequence of the Unocal acquisition being fully folded into the Company, or if there is an unusual dry hole component associated with the first quarter, especially because there are so many key Gulf of Mexico wells that people are watching and waiting for.

So perhaps, if there wasn't a dry hole component, maybe there were other expenditures taking place?

First of all, let me just comment on the dividend item for a moment.

We have been very conscious of trying to return cash to the shareholders.

Again, we look at maintaining a sustainable dividend program based on earnings and cash flows.

This quarter is a 15.6% increase.

A year ago, second quarter of '05, it was a 12.5% increase.

And just nine months earlier than that, in the third quarter of '04, it was a 9.6%.

So we feel that's very appropriate and, as you mentioned, Bill, I think the shareholders appreciate it.

As for exploration expense, I presume you're commenting on comparisons between the first quarter of this year and the first quarter of last year.

And I'll ask Irene to comment on that, but I suspect a good part of the change is attributable to the inclusion of Unocal in the first quarter of '06, and it was not there a year ago.

And that is exactly correct, because the delta from the first quarter and fourth quarter -- it was pretty much flat between the two periods.

But for the first quarter this year versus last year, there is a spike, and it is largely attributable to Unocal.

Paul Cheng, Lehman Brothers.

If I could, going back into Venezuela for a moment, Steve, can you give us some guidance in terms of when your Boscan and LL-652 changed of the operating service contract to the joint venture?

What is the impact in terms of reserve amount you can book?

And in terms of production, how much production now that will be a reduction from -- and what kind of earnings impact?

Or did you get any compensation from that change?

Also, from a theoretical or conceptual standpoint, when you judge a particular country, whether you want to do business or not, what kind of criteria?

I mean, with Venezuela it looks like they continue to be in the midway, changing somewhat the rules of the game.

How do you judge that you want to continue to invest more money into a particular country, like in the case that you do the LNG or the natural gas exploration?

If you can share with us some kind of criteria, that will be great.

You have got about a half a dozen questions, I think, included in that.

Let me begin on the Empresa Mixta question.

At the end of March, Chevron signed an MOU with the government that specified terms for the conversion to an Empresa Mixta, which would be consistent with the 2001 hydrocarbon law.

And the EMs, as they are referred to, the Empresa Mixtas, as it relates to Chevron would pertain to our Boscan operations as well as LL-652.

At this point, the conversion is not finalized.

The terms now require the approval of the Venezuelan National Assembly.

So we are waiting for that to occur, and it's always conceivable that the terms could change in some way.

These agreements, however, are subject to some binding confidentiality agreements.

So at this time, we clearly can't disclose any of the specific details since, really, negotiations are still open.

Having said that, the empresa mixtas will have the rights to produce and sell oil and gas, and we'll have to look at those rights in relation to the FASB and SEC reporting requirements as to whether or not reserves can be booked.

As far as production is concerned, Chevron had been showing, up to this point, as other produced volumes, the gross production from Boscan as part of its OSA volumes.

We'll have to, then, when the agreement is finalized, take a look at equity production, which clearly will be less but it will be equity production.

Regarding the valuation issue, the Venezuelan government has stated publicly that it intends to preserve the OSA values of the Western oil companies, making these conversions.

Consequently, we don't expect to book any accounting loss on the OSA conversion when it occurs.

With respect to the criteria to be used for investments -- whether it be in Venezuela or Canada or the UK, United States or anywhere -- we take a look at all of the components, which very much include the fiscal terms, in making our assessment as to making an investment.

And the same or pertain to Venezuela as well.

John Herrlin, Merrill Lynch.

You are involved in a lot of deepwater developments or exploration wells that are high-profile.

I was wondering if you could give us a sense of timing of when we will hear things on Jack and also the JDZ.

And with Tahiti, can you give us kind of a status update?

On the JDZ, that well is still being evaluated.

And, although there has been things in the press offered, we are still evaluating it for the next several months, and don't plan on making an announcement until that evaluation has been completed.

As far as the other deepwater prospects projects that you have alluded to, I think they are still on track relative to the timetable that we had talked about at the analyst meeting last month.

If you have any specific things, though, please feel free to give Irene a call, and we will be happy to chat with you.

David Wheeler, Neuberger.

Can you tell us -- it sounds like Unocal -- this will be the last quarter where you have the financials separated internally.

Can you tell us how accretive and dilutive the Unocal was to Chevron in the first quarter for cash flow, earnings and returns?

You are right.

We're going to lose the capability here in the second quarter of at least -- from an accounting point of view of definitively identifying legacy Unocal operations from legacy Chevron.

Looking back at not only the first quarter but the last five months of 2005, we found Unocal, from an earnings point of view, to be slightly accretive to earnings and much more so accretive in terms of cash flow per share.

The number that sticks in my mind is in the neighborhood of 6 to 7%, from a cash flow point of view.

As we had mentioned, though, in the analyst meeting last month, we did take a hit through the workings of purchase accounting with respect to other deal metrics, that being the return on capital employed.

So we envision that will be off by maybe 1.5%, but we are committed to improving the returns on the overall enterprise.

In measuring the accretive nature from an earnings point of view, it really depends on the base from which you start, and what your expectations of Chevron would have been.

Certainly, from the point of last year to now, earnings performance has been -- from an earnings point of view is far better than I think the analyst community would have had 12 months ago.

So it's on that basis we do the measurement.

Thanks very much for your question; it's a good one.

Neil McMahon, Sanford Bernstein.

It's a follow-up on the Reliance deal again.

And maybe, if it's a quick answer, squeeze in a second one.

Do you have any exclusivity on the MOU with regard to Reliance?

I believe, Neil, as far as exclusivity, you are intending that can Reliance deal with other parties concurrent with dealing with us?

Yes.

I believe there is exclusivity, but I am hesitant to say definitively.

I do believe there is exclusivity, but I'm not 100% positive to that fact.

We'll have to confirm that with you.

Your problems in Kazakhstan -- you say they are equipment-related.

Could you just go into that, and on what field you are talking about, if that was Karachaganak or if it was Tengiz?

Well, we had weather-related problems, I think, at the end of the day at both -- in the Karachaganak, but the larger issue we had was with Tengiz.

In the middle of January, we had some heat exchangers fail in Train 1.

And that brought production down -- or limited production, I should say, for about two months.

The Train came back up in the middle of March, as I recall, and was back to normal production in March.

But that had an adverse effect on our production between quarters, I want to say on the order of maybe 45,000 barrels a day for TCO from the first quarter of this year to the fourth quarter of last year.

But as a consequence, we did have operating issues in Kazakhstan and some in our Athabasca project in Canada, and we had weather related issues in Australia as well, with some cyclones coming through.

If you take a look at those type of operating issues, which one would hope were not repeatable, they start to approach about 60,000 barrels a day downward.

And if we were to include those to the base of what we have seen here in the first quarter, it should put us back into the guidance range that we had offered.

Mark Gilman, The Benchmark Company.

As I do the arithmetic, the fourth quarter to first quarter delta on international BOE production is about a negative 70,000 a day.

Yet the international upstream slide shows a 40 million -- I think it was a 40 million number in terms of a positive variance on liftings.

Is this a mix issue?

Or in fact, did you overlift in the quarter, such that you're overlifted at the end of the quarter?

Mark, can you repeat your question again, please?

From a reported production standpoint, fourth quarter against first quarter, it is down 72,000 equivalents a day from the supplement.

On the international upstream income variance slide, Irene, when you discussed it, there's a positive volume variance of $40 million.

I'm wondering, is that strictly mix-related, or was there overlifting in the quarter such that you are overlifted as of March 31?

We are overlifted.

There was an overlifting in the quarter that benefited our -- relative to the fourth quarter, there were some benefits associated with lifting.

Paul Cheng, Lehman Brothers.

A month ago in your analyst meeting, when you gave the 2.7 to 2.8 million barrels per day, does that include the potential tax changes for converting the operating contract into a JV in Venezuela already?

The guidance that we had offered, for those of you who were not at the meeting, was an OEG production of 2.7 to 2.8 million barrels a day.

The wide range was intended to accommodate for any number of things, including weather that might occur this year, disruptions that might occur in any of our operations around the world, whether they be operating of nature or political in nature.

And inherent in the 2.7 to 2.8 range was the continuation of the existing OSA arrangement that we have with Venezuela for Boscan.

When the agreements are concluded and we have a good fix on where things stand, if need be, we will adjust the guidance.

But at this stage, we are still thinking that 2.7 to 2.8 is reasonable.

But clearly, with the conversion to the EM, it would be at the lower end of that range.

Thank you all very much.

In closing, let me say that we appreciate everyone's participation in the call, and I especially want to thank the analysts who asked questions on behalf of all the participants in this morning's session.

We will be filing the first-quarter 10-Q next Thursday, so you will be able to see more detail than we have been able to provide on the phone here and in earnings release as well.

So goodbye and, Matt, back to you.

Thank you, Sir.

Ladies and gentlemen, this concludes today's Chevron first-quarter earnings conference call.

You may now disconnect.

Good day.