雪佛龍 (CVX) 2005 Q4 法說會逐字稿

Good morning.

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

At this time I would like to welcome everyone to the fourth quarter 2005 Chevron's earnings conference call.

All lines are currently on a listen-only mode.

After the speakers' remarks there will be a question-and-answer session. [OPERATOR INSTRUCTIONS].

I will now turn the conference over to the Chairman and CEO of Chevron Corporation, Mr. Dave O'Reilly.

Please go ahead, sir.

Thank you, Dennis.

And welcome to Chevron's fourth quarter earnings call.

Today I'm joined by Steve Crowe, our Vice President and CFO, and Irene Melitas, Manager of Investor Relations.

Our focus today is on Chevron's financial and operational results for the fourth quarter of 2005 and I'll refer to the slides that were e-mailed to you this morning and are available on the Web.

Before we get going, please look at the Safe Harbor Statement on Slide 2 and be reminded that today's presentation contains estimates, projections, and other forward-looking statements.

Turning to Slide 3, which provides an overview of our financial performance, the Company ended the year with record quarterly earnings of $4.1 billion, or $1.86 per diluted share.

Full year results of 14.1 billion marked a second consecutive year of record earnings for Chevron.

The earnings improvement between quarters reflected a few key drivers.

Downstream earnings benefited from higher marketing margins in the U.S. and the resumption of our Pascagoula refinery operations following the Gulf of Mexico hurricane disruptions of the third quarter.

Increases in natural gas prices in the U.S. and a full quarter of earnings from the former Unocal operations, which were acquired in August, also contributed to our fourth quarter results.

These benefits outweighed the ongoing adverse effects of last quarter's storms.

There were no special items for the quarter or for the year.

Return on capital employed over the trailing four quarters was 22% and our balance sheet at the end of the year reflects our Company's financial strength and flexibility.

Debt-to-capital ratio, as at the end of the year, was 17% and our net debt was under 3%.

Cash and marketable securities at the end of the year totaled $11 billion.

Stock buybacks in the fourth quarter were $755 million, amounting to $3 billion for calendar year 2005.

The $5 billion buyback program initiated in 2004 was concluded in November after 20 months, and in December we announced that our Board of Directors had authorized a similarly sized follow-up repurchase program of up to $5 billion over three years.

Turning to Slide 6 -- 5 -- sorry, 4, I'm way ahead of myself.

Slide 4 shows our capital spending in the past two years and our '06 budget, which we announced in a press release in mid December. 2005 capital spending was $11.1 billion and that includes expenditures of about 800 million related to Unocal for the last five months of the year.

Upstream spending accounted for $8.4 billion of the total, $700 million of which was for Unocal operations.

Our cash C&E, which excludes our equity share of affiliate outlays totals $9.4 billion for the year.

Our announced capital program for 2006 of $14.8 billion represents an increase of $3.7 billion over 2005. $3 billion of this increase is for our upstream business.

About a third of the increase is attributable to more capital intensive phases of our long-term growth projects, which are under way.

Another third is attributable to a full year of expenditures on Unocal properties versus a partial year in 2005.

And finally, the third -- the third, third or close to $1 billion, is for rising costs for materials and services, which we are experiencing of course throughout the industry.

The other $700 million of the increase is aimed at downstream in chemicals and geared to expanding production; for example, we announced recently an expansion project at our Korea affiliate refinery to upgrade heavy oil to light products.

Steve will now take us through the quarterly comparisons.

Steve?

Thanks, Dave.

My remarks compare the fourth quarter 2005 to the third quarter 2005.

Bear in mind that our earnings release compared fourth quarter 2005 to the same quarter a year ago.

Turning to Slide 5, net income was up 15% to $4.1 billion in the fourth quarter.

Starting with the left side of the chart, lower crude prices worldwide reduced upstream results and were only partially offset by the effects of higher natural gas prices in the U.S.

A positive net margin variance in downstream reflects stronger marketing margins in the U.S. and the resumption of operations at the Pascagoula refinery, which outweighed the general decline in refining margins.

Fourth quarter earnings benefited from increased volumes, reflecting three months of Unocal operations and higher refining volumes of high value products in the downstream.

Curtailed oil and gas production due to the Gulf of Mexico hurricane activity offset some of this benefit.

Earnings from chemicals improved on stronger ethylene margins.

The residual "other" bar includes the net of everything else, including the effect of a favorable swing in tax items between quarters.

Turning to Slide 6, as we had previously advised, the 2005 storms in the Gulf of Mexico had significant adverse effects on our operations and financial results in both the third and fourth quarters.

The chart on the right summarizes the effect of Hurricanes Katrina and Rita on our fourth quarter results by business segment.

The total exceeded $700 million.

The impact reflects a combination of direct costs and lost profit opportunity from reduced oil and gas production and lower-than-normal output at our Pascagoula refinery.

The Gulf of Mexico production offline due to the storms averaged about 140,000 oil equivalent b/d, or about 45% of our 300,000 daily oil equivalent production pre-Katrina.

In refining, average crude runs were reduced by about 20,000 bpd for the quarter, since Pascagoula ramped up to resume normal operations by the end of October.

The carry-over effects on the first quarter of 2006 results are expected to be lower as approximately 70% of our pre-Katrina production in the Gulf of Mexico is now back online.

Slide 7 summarizes the results of our U.S. upstream earnings, which increased by $17 million between quarters.

Lower liquids realization dampened earnings by $35 million.

The $0.90 per barrel decrease between quarters was less than the decline of industry benchmark prices, while quarterly average prices for WTI declined by $3.15 per barrel, the Gulf of Mexico benchmark trade month prices, which are on a lag basis, increased $4.25 per barrel.

The decrease in San Joaquin Valley heavy oil mirrored the decline in spot WTI.

Higher natural gas realizations resulted in a $240 million profit effect.

Our average realizations increased $2.88 per Mcf, less than the average increase in bid week prices, reflecting the shut-in of volumes from the Gulf of Mexico storms and its effect on our production mix.

Driven by the lingering adverse effects of the storms, lower volumes disadvantaged earnings by $80 million and more than offset the benefits of including former Unocal operations for a full quarter.

The variance in "other" includes higher exploration expenses, higher operating expense, and the unwinding of losses related to former Unocal hedges.

As shown on Slide 8, international upstream earnings for the quarter were $90 million lower than the third quarter's earnings.

Lower realizations reduced earnings by $220 million, as lower liquid prices more than offset modest gains in gas realizations.

Liquid realizations declined about $4 per barrel, slightly less than the $4.60 per barrel decline of spot Brent prices.

The positive variance in volume effects between quarters was primarily attributable to the integration of former Unocal operations for a full quarter versus two months.

The other variance bar includes higher exploration expenses and other miscellaneous items, partially offset by certain favorable tax benefits and a favorable swing in foreign exchange effects between quarters.

Slide 9, 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.

The volume increase between quarters was 135,000 bpd and included adverse storm-related effects and a 132,000-bpd contribution from an additional month of Unocal operations.

Excluding the Unocal barrels between quarters, Gulf of Mexico storm effects and price effects on production sharing contracts, the underlying worldwide volumes increased about 2%, or 56,000 bpd.

U.S. production declined 18,000 bpd, as the impact of storms in the Gulf of Mexico and normal field declines more than offset the 34,000-bpd quarter-over-quarter addition of Unocal volumes.

Storm activity curtailed this quarter's production by about 140,000 bpd, compared to 80,000 bpd in the third quarter.

Absent storm effects and Unocal's incremental production, volumes were essentially flat.

Outside the U.S., oil and gas production increased 153,000 bpd between quarters.

Excluding incremental Unocal volumes of 98,000 bpd and the effects of price on cost recovery volumes, Chevron's underlying production was 3% higher, primarily due to the absence of plant maintenance in the U.K. and in Tengiz, and the positive effects from inventory movements in Indonesia.

Turning to Slide 10, looking ahead, worldwide oil equivalent production in 2006 is expected to average between 2.7 and 2.8 million barrels.

This increase over 2005 volumes is attributable to the inclusion of Unocal properties for a full 12 months and new project start-ups that are expected to help offset normal field declines and the effect of last year's hurricanes on the base business.

As a cautionary note, actual production will depend on the rate of recovery of storm-related properties in the Gulf of Mexico, possible future shut-ins due to new weather-related events, and the effects of civil unrest or other disruptions to our daily operations.

Turning to Slide 11, U.S. downstream net income improved by about $245 million between quarters on higher realized margins and the resumption of our Pascagoula refinery operations after the third quarter storms.

Margin effects of $260 million contributed favorably to earnings relative to the third quarter, reflecting stronger marketing margins in the East and West, including a positive $60 million swing in the final pricing adjustments for long-haul crews.

Despite the fall in benchmark refining margins, the restoration of operations of the Pascagoula refinery mid quarter also contributed to the improved results.

In the West, the Los Angeles motor gasoline dealer tank wagon to spot indicator margin increased by $9 per barrel, while in the East, the Houston rack to spot indicator margin rose by $6.73 per barrel, as the decline in spot product prices outpaced the decline in DTW and rack prices.

Benchmark refining margins were down significantly relative to the third quarter, both on the West Coast and on the Gulf Coast.

The Gulf Coast light-heavy differential indicator fell by $8.19 per barrel for the quarter and the ANS refining margin by $8.61 per barrel.

Higher refinery input volumes and high-value product production at Pascagoula on the recovery from storm-related downtime drove the improvement in volume effects.

Partly offsetting this benefit was lower light product production on the West Coast, largely attributable to scheduled downtime at our Richmond refinery.

Branded motor gasoline sales fell between quarters on normal seasonality.

The variance in "other" primarily includes the impact of higher operating expense, reflecting higher fuel usage at Pascagoula, refinery turnaround and other costs.

Turning to Slide 12, fourth quarter international downstream earnings of about $420 million were slightly below the third quarter's.

Refining and marketing margins resulted in a negative variance between quarters of $50 million.

In refining, spot product prices subsided following the market's initial reaction to the hurricanes and generally led to lower margins in all regions.

In Europe, seasonally lower demand also contributed to the decrease.

The Brent margin fell by $0.50 per barrel and the Dubai cracking margin dropped by about $2 per barrel.

Partially offsetting the impact of lower refining margins were improved marketing margins in most regions, due to reduced product supply costs following the hurricane effects of the third quarter.

Volume effects resulted in a negative variance between quarters of $35 million on lower high-value product refinery production.

Refinery input was down by about 50,000 bpd for the quarter, due to scheduled downtime.

The difference in various tax effects benefited earnings by about $90 million between quarters.

The variance in "other" includes the impact of higher operating expenses, including costs related to December's explosion and fire at our 40%-owned product terminal in the U.K.

An increase in trading margins and improved shipping results on higher freight rates partially offset the higher operating expense.

Slide 13 shows chemical results were $71 million in the fourth quarter, compared to $6 million in the third quarter.

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

The "other" bar includes our Oronite Additive Business, whose earnings were flat in the fourth quarter and the negative effects of certain income tax adjustments.

Slide 14 covers all other.

The fourth quarter results show a positive variance from the prior quarter, mainly due to the Company's share of a gain recorded on the sale of Dynegy's Midstream Business, net of costs related to a settlement by Dynegy of a tolling arrangement, which is reflected in the P&L businesses segment.

The tax bar relates, or reflects the aggregation of minor variances for tax.

The variation in the "other" bar is due to the absence of last quarter's environmental provisions and the fluctuations of certain corporate items between quarters.

Our fourth quarter interim update guidance for this segment called for a net quarterly charges in the range of 160 to $200 million excluding Dynegy, and the actual net charges for the quarter were at the low end of the guidance.

That completes our brief analysis for the quarter.

I'll turn it back to Dave.

Thank you, Steve, and before we turn to your questions, let me just recap some of our progress in recent months and I'll begin with upstream activities on Slide 15.

In the U.S., we announced two deepwater oil discoveries in the Gulf of Mexico.

The first was the 60%-owned Big Foot discovery in Walker Ridge.

The second was the Knotty Head discovery located in Green Canyon, in which we own a 25% interest.

Additional testing will be performed on both these fields in the near future before determining their full commercial capability.

We also announced that construction of a floating production facility be installed at the 58%-owned and operated Tahiti field in the deepwater Gulf of Mexico have begun.

This facility is designed for daily production capacity of 125,000 bpd of crude oil and 70 mmcf of gas.

Now, we anticipate that Tahiti will come onstream in mid 2008.

In Angola, first oil production commenced from the deepwater Belize field offshore Angola.

The Benguela, Belize, Lobito, and Tomboco fields, which collectively comprise one of our big five projects, we call it BBLT, are being developed in two phases.

The ramp-up in production will occur over the next two years, as additional wells and fields are brought online.

Finally, our 50%-owned Tengiz Chevroil affiliate in Kazakhstan was awarded -- has awarded commercial contracts that will enable increased crude oil exports to a southern route across the Caspian Sea, offering Tengiz Chevroil additional export capacity.

This is important, as it will be available for production from our Tengiz expansion, which is a combination of a Sour Gas Injection project and a Second Generation Sulfur Recovery Plant.

These integrated projects will cost $5.5 billion to construct, which is higher than earlier estimates and are expected to increase Tengiz Chevroil production capacity from the current 300,000 bpd to somewhere between 460 and 550,000 bpd; upon completion in the third quarter of 2007.

Note that this range is a higher 30 to 50,000 bpd higher increase relative to previous estimates.

Turning to Slide 16, our preliminary estimate, and -- I emphasize "preliminary" of 2005 crude reserve additions is shown on Slide 16 and it equates to approximately 175% worldwide oil equivalent production replacement during the year.

This represents an addition of more than 1.5 billion barrels of oil equivalent, including the effects of sales of acquisitions, primarily impacted by the Unocal acquisition, resulting in total year end proved reserves of 11.9 billion barrels.

These amounts exclude volumes associated with the Company's interest in Canadian oil sands and an operating service agreement in Venezuela.

Additional details on reserves will be available in the 10-K that will be filed with the SEC in very early March.

Turning to Slide 17, in Global Gas we made some progress during the quarter that's notable.

We committed an additional -- to an additional liquefied natural gas pipeline and terminal capacity at Sabine Pass.

Our commitment for natural gas transportation is for 1 bcf/d of pipeline capacity and a new build pipeline, and 700 (correction: should be 600) mmcf/d of interconnect capacity to an existing pipeline, providing us access to the Henry Hub network.

In December, we exercised our option to increase capacity at the Sabine Pass LNG terminal by 300 mmcf/d for a total of 1 bcf/d.

So in summation, we'll have a billion cf/d of regas capacity at Sabine Pass and plenty of capacity to transport gas in the Louisiana region, including connections to Henry Hub.

In Australia we've announced the signing of three preliminary Heads of Agreements for the sale of liquefied natural gas from the Chevron-led Gorgon project in Australia into Japan, the world's largest LNG market.

Preliminary agreements have been signed with Tokyo Gas, Osaka Gas and Chubu Electric, large Japanese utility companies for the aggregate purchase of 4.2 MMTPA of Gorgon LNG.

Commitments for a 2.7 MTPA will begin in 2010 and the third commitment for an additional 1.5 MMTPA begins in 2011.

So this essentially takes care of the vast majority of our equity interest in the first two trains at Gorgon.

In downstream, a major upright project by our 50%-owned, GS-Caltex affiliate, was approved to be built at the Yeosu refining complex in South Korea.

The facilities will increase the yield of higher value refine products and reduce feedstock costs through building capability to process heavier oils.

The total cost of this project is about $1.5 billion, our equity share is about 50% of that and start-up is expected by year end 2007.

In chemicals, our 50%-owned Chevron Phillips Chemical Company entered into an engineering procurement and construction contract in Qatar for the Q-Chem II complex located adjacent to our existing Q-Chem I operation.

Chevron Phillips holds a 49% interest in the Q-Chem II complex.

The complex will include a 350 metric-ton-per-year polyethylene plant and a 345,000 metric-ton-per-year normal alpha olefins plant and it's expected to start-up in late 2008.

And, of course, we're also participating in a major ethylene plant, which will be built in Qatar also, which provides feedstock to this new chemical operation.

Turning to Slide 18, clearly 2005 was a year in which we achieved significant milestones and overcame a number of challenges, not the least of which were a couple of major hurricanes.

We've attained the second consecutive year of record earnings, and successfully completed the acquisition of Unocal.

Our exploration activities resulted in several important discoveries and we've made noteworthy progress in building our gas business.

Thanks to the dedication of our hard work of our employees, we're making headway in our business recovery efforts in the Gulf of Mexico, and as we enter 2006 I'm looking forward to a year hopefully without storms and one that we can continue to make substantial progress.

That includes our prepared materials and I'll take your questions now.

We'll try to answer all of them and we'll plan to wrap-up about the top of the hour.

So if you could line up your questions, Operator, please open the lines, Dennis.

Thank you.

(OPERATOR INSTRUCTIONS) The first question is from the line of Arjun Murti with Goldman Sachs.

Thank you.

My question was on the reserve replacement.

If I'm looking at it correctly it, looks like the organic; i.e., excluding purchase and sales replacement, was close to zero.

Wondering if I do have that right, and if so, were there some major negative revisions or just no major project adds?

Chevron going back in time has had terrific organic reserve replacement.

Last year was a little disappointing and then this year looks to be a material step worse.

But I just wanted to make sure I have that correctly.

Arjun, the -- you're close to being on the mark, but let me explain.

First of all, there were no significant write-offs.

The main issue in the basic underlying organic sense is two-fold.

One, is no major projects and we have some very big ones that we'll book, that will create major increases in reserves, when they are ready and fully ready for booking, and the second point is price effects.

At the beginning of the year we were at $45 a barrel; the end of the year $61 a barrel; gas at $8 (mcf), finished the year at $10 (mcf), began the year at $6 (mcf).

So we've had some significant price effects on some of our reserve calculations.

And that's by far the biggest factor in the organic underlying reserves analysis.

So our reserves replacement will be low.

It won't be zero, but it will be low and I emphasize that we still have some work to do before we actually, get all the I's dotted and T's crossed.

But in this year's case, we've had a reserve -- most of our reserve replacement has been the Unocal acquisition.

Now, I'll remind you that if you look over any five-year period, you're going to see that even with these relatively low numbers in the last year or two, that our average over the last five years has been about -- its still over 100% of reserve replacement and we have confidence that we're going to continue that trend.

But I've mentioned to you last year, all of you, that it's going to be lumpier.

We're adding much bigger projects and when they become effective, obviously they will materially impact our reserves.

And when we don't have a big project, we have a result like we had this year, particularly with rising prices.

Dave, if I may ask a related follow-up with full respect to your normal one-question rule, do you become more dependent on acquisitions going forward, or is it really just the lumpiness that you're describing and in future years we'll get the projects booked?

Now we have a strong queue of projects, Arjun, and we're going to be booking some substantial reserves from our projects.

But if you look at our history, we've always had a blend of organic by exploration growth and acquisitions.

One of the major reserve components of our current portfolio is Tengiz, of course.

And remember, that started off as an acquisition.

So it's a combination of both.

But we're going to see, I think, a swing towards more organic reserve addition in the next couple of years.

Arjun, this is Steve.

I would simply add that as we look forward to future bookings from our organic projects, Gorgon will be a big one.

Angola LNG and Nigerian LNG, Aparo and expansions in Tengiz, these will all have some lumpiness to them when they occur, but they certainly will add to our reserve base.

Just expanding on Dave's comment, if you look longer-term and go out as far as 10 years, both the total reserve replacement and reserve replacement excluding sales and purchases, both are above 100%.

Thank you very much.

Thanks, Arjun.

Thanks, Arjun.

Your next question comes from the line of Robert Kessler with Simmons & Company.

Good morning.

A couple of -- or I guess one question relating to follow-up on the reserves slide and your response to the prior question.

On the projects you listed, correct me if I'm wrong, but I don't think you listed Blind Faith and Tahiti, two Gulf of Mexico projects sanctioned in 2005.

Is that to imply that those had been added in prior years or will those be added in 2006 or 2007?

Both of those have had reserve additions, but at the kind of 10% probability level, Robert.

So we would expect that we will not be booking any further reserves in either of those projects until we've actually got them up and running.

But if we are successful we would fully expect to add additional reserves in both those areas, post-operation.

Okay, thank you.

Your next question is from the line of Nickie Decker with Bear Stearns.

Thank you.

Good morning.

Just continuing on the theme of reserve replacement, could you quantify what the pricing effect might have been, the revisions related to that, and also, talk about what finding and development cost might look like?

Nickie, I don't have the numbers for finding and development right now, so we'll give -- we'll talk to you offline on that.

But as far as the estimate for the price effect, as Dave had mentioned, at the end of 2004, the prices were $43.46, at least for WTI, and at the end of 2005, it was $61.04.

So there was a substantial increase in price.

Our roughhouse estimate is that if you were to have exclude sales and purchases and exclude the impact of price effects, our replacement ratio would be somewhere maybe in the 40 to 50% range relative to last year's production.

Oh, okay.

And --.

Nickie, we're going to be having an analyst meeting in early March and questions on the impacts of, on F&D and everything else, I think it's premature because we will be having those numbers fully disclosed in our 10-K and we'll be in a much stronger position to talk about all those detailed impacts in early March.

Fair enough.

Thank you.

Your next question comes from the line of Doug Leggate with Citigroup.

Thank you.

Good morning, gentlemen.

Good morning, Doug.

Good morning, Doug.

I wonder if I could touch on the production guidance that you've given for this year.

Obviously, the PSC impacts have an impact on reserves, but year-over-year could you quantify first of all the Q4 versus Q4 hit on production as a result of the higher prices on an entitlement basis?

I'm looking at the guidance for 2006, are you assuming any recovery in terms of production entitlements, or are you assuming the status quo so that the PSC effect is brought to neutral?

Well, Doug, looking forward into 2006, we won't disclose specifically what our pricing assumptions are with respect to our view of this year.

But broadly speaking, we don't expect any major PSC effects affecting our Indonesian or Tengiz royalty.

So the price effects as it relates to that range that we gave you of 2.7 to 2.8 is fairly neutral as it relates to price.

I think if I--let me build on that just a little bit.

We've tried to factor that out in this estimate, the real issue is the impact of -- the other real issue is the impact of storms and currently we think that that's at least 35,000 b/d for the year.

So our estimate, is that we've recovered the easy-to-recover portion in the Gulf of Mexico and going forward will be very much more difficult.

Of that 35,000 bpd there could be as much as 20,000 b/d that we just won't ever get to recover because it will be uneconomic.

And the other portion of it, it's not clear that we're going to get to it entirely in 2006 because you've got to remember that we've got to handle a number of simultaneous issues.

We've got our own drilling program for new prospects in the shallow water.

We've got reworks and then we've got to fit in these recovery projects into that queue and it's just a little bit unclear as to how much of that we're going to get.

So that's one of the reasons why we've established a range here.

And, of course, the other one is we're not quite sure what the weather impacts will be at the back-end of the year in this area where we've got to do the extra work.

So it is, it's established as a range for a reason and we think we have a pretty high degree of confidence at the low-end and we've kind of established a range depending on our success rate, I guess.

Doug, let me expand a little bit.

There's so many moving parts with the comparisons that you have 4Q to 4Q, 3Q to 4Q year-over-year, the big moving parts being the effect of price, the impact of the storms, and the inclusion of Unocal in some periods and absent in other periods.

But if you step back and look at the full year, excluding the impact of storms, asset sales and the Unocal barrels, U.S. production fell about 7% as best we can figure compared to 2004 and it was due to natural field declines.

Outside the U.S. production was up more than 1%.

Again, if you exclude asset sales and PSC effects and Unocal barrels, and the increase came from Venezuela and Australia.

So lots of moving parts in the comparisons and Irene will be happy to go over any of the combinations you would like to chat about--but that's the general pattern between years.

Okay, Steve.

Let me maybe take the detail offline.

Thanks very much indeed.

Thanks, Doug.

Your next question comes from the line of Doug Terreson with Morgan Stanley.

Good morning, guys.

And congratulations on a strong result.

Thank you, Doug.

Dave, just to try and drill down a little bit more deeply on this last question that you answered and try to reconcile it a little bit further.

I think the press release suggests that the lost amount of production from hurricanes was around 140,000 bpd at year end '05 and that that number will decline to 100,000 bpd in '06.

And I think based on the comments that you just made about the rate of decline and that you may not get to 20,000 bpd for whatever reason, which may be that it's not economic, can we work on the assumption that over maybe a two- to three-year period that 50,000 bpd of pre-Gulf production probably won't return?

Is that reasonable, or --?

Well, you're in the ball park, Doug.

Okay.

Because we have natural declines in any event and if you were to take the Gulf of Mexico, even with the full rework program, it's by -- we were at 300,000 b/d before the storms.

By the end of this year under a normal -- if that hadn't -- if the storms hadn't occurred and by the end of this year, we would have probably been down in the 250 to 260 range --.

Right.

-- just under normal circumstances, by the end of 2006.

So the question really is, how much can we get from between the 200 we're at now, or the low 200s back to 250.

How much of that can we capture in the intervening period this year and 2006 and beyond.

So your point is a good one.

We're never going to get back to 300 on this existing set of assets and we would had experienced normal field declines.

So what we're trying to do is compare two moving parts.

How much can we get back and, of course, we're fighting that decline curve.

So that's why our estimate is as it is for this year.

Okay.

Now, that's a good clarification.

Thanks a lot.

Thanks for the question.

And, Doug, what we're looking at in terms of permanent loss is still an estimate as the folks are doing the work and it's somewhere between 10 and 20,000 b/d.

Okay, okay.

Great.

Your next question is from the line of John Herrlin with Merrill Lynch.

Yes, hi.

Doug got my main question, but getting back to the Gulf of Mexico, are you trying to lock up more equipment to get after all the remedial, as well as the new projects?

Yes, well, they are kind of -- just a minute I want -- I don't want -- let me just be careful that I don't overgeneralize here.

From the deepwater perspective, we have -- even though the rig market is tight we have our own committed deepwater rigs for our deepwater program and that's kind of being managed in one separate organization.

My referral to rigs, of course, was in the shallower water and where most of the damage has been and where most of the recovery efforts are.

We do have a good -- we do have good quality rigs and we will probably have to try to acquire a few more if we're going to execute the program.

And part of the uncertainty about our production recovery rate here is recognizing that that rig market is tight and that we have to make sure that we have quality rigs, and also that the economics work.

So that -- I think we can get most of what we've planned to do, John, but at the margin we may not.

Does that answer your question?

Yes, it does.

Thanks.

Okay.

Your next question is from the line of Mark Gilman with The Benchmark Company.

Dave, Steve, good morning.

Good morning, Mark.

Good morning, Mark.

I wonder if I could ask you about upstream and international liftings in the fourth quarter and the variance versus production?

I believe that we were looking at a fairly significant underlift in the third quarter and I'm wondering what the relationship between lifting and production was in the international upstream in the fourth quarter.

It was about the same, Mark, as in last quarter.

The question was --.

I'm not sure what that means.

Were you underlifted again in the fourth quarter --?

Yes, we were.

-- or did you make up for the underlift in the third quarter?

We were underlifted in the fourth quarter as well.

Mark, the variance in liftings between the fourth and third quarters, the fourth quarter was about 10,000 b/d higher.

Does that help?

I'm not sure to be honest with you.

If the third quarter was underlifted by about 50, which was my recollection, that means the fourth quarter is underlifted by 40?

No. [multiple speakers].

Is that what you're saying, Steve?

I was referring to the absolute liftings between the fourth and third quarters when I quoted the 10 to you.

Yes.

Okay, thanks.

All right.

Your next question comes from the line of Paul Sankey with Deutsche Bank.

Hi, good afternoon, gentlemen, and ladies, for that matter.

Could I just ask a downstream question.

In fact, firstly, volumes were weaker in the quarter.

If you could say anything to further enlighten us on that in terms of sales, I was thinking that would be great?

And secondly, it's notable that Asian refining margins are negative now despite very cold weather in Asia.

I wonder if given your position there you could expand on any thoughts you had on that?

Thank you.

Well, the overall volume effect that we've talked about on the international business, first, Paul, is a blend of both refining, as well as sales activity and the amount that we had chatted about on Slide 12, the negative 35 million, is really driven by scheduled maintenance that we had at our refineries, both the one in South Africa, as well as our joint venture one in Thailand.

As far as volume effects in the U.S. downstream operations, what we had discussed was a profit effect of about $80 million and the lion's share of that was, again, attributable to the Pascagoula refinery coming back online in mid October and by the end of the period was up to normal operation.

You recall early in the third quarter, we also brought the Pascagoula refinery down as Hurricane Dennis came close by.

So we were down a fair piece of the third quarter.

As far as some of the sales activity here in the United States, we're seeing the normal seasonal decline that is characteristic of the end of the driving season as we look at the fourth and compare it to the third quarters.

If I might just make a general comment on the state of the markets, the markets are actually reasonably well-supplied.

In Asia-Pacific, there was pretty warm weather late in the year.

Now it's turned cold right now, but the inventory levels, I think, improved substantially over what might have normally occurred had the weather not been quite as warm.

So I think the markets actually around the globe are relatively well supplied and one of the issues that's obviously weighing on the market is this whole issue of security and concern for the future.

And I think that's – er..so, I think you're see some of the flow-through of higher inventory impacts and healthy inventories to the prices in some of these markets.

Similarly in Europe, even though the weather has been cold, Europe has, refining margins have dropped considerably, and I think the question of supply has kind of -- near-term supply has moved away from being top-of-mind, except for this overhang of geopolitics.

If you're still listening in, Mark, I would encourage you to call Irene so we can get a good answer to you on the specifics of those comparative overlift questions.

I think we finally understand your question and she'll get to you on it offline.

Paul, is that okay?

Okay.

Next question, please.

Your next question is from the line of Neil McMahon with Bernstein.

Hi.

I just kind of got a bit of an overview question.

It's basically you have mentioned that no main projects coming on really at the minute and you're looking forward with the Unocal portfolio and your new major projects in the next few years.

I was wondering, when you sit back and you look at the global portfolio, how do you feel about the balance you've got at the minute between OECD and non-OECD production, and gas versus oil?

And secondly, has anything that's happened in both Venezuela and Argentina, you're not in Bolivia obviously, within the last quarter to make you feel differently about those areas?

And I was wondering if you're going to, based on any of the changes there, how that's going to impact your reserves in those countries?

Okay, a lot of big questions, Neil.

Thanks.

Well, let me just kind of refer -- our portfolio is actually very, very well-balanced in the sense that we don't have all of our eggs in one basket.

And I would -- it's easy to simplify by looking at OECD and non-OECD and that's certainly one way of measuring how you view production and the profitability of production.

We don't -- we can't quite do it that way because even in the non-OECD countries, there's a wide range of terms.

Some countries have terms that are very similar and structures very similar to those of, say, the OECD countries.

So as we look around the world, we have a well-balanced portfolio with reserves in the U.S. and Kazakhstan and a number of countries in Africa, Latin America, Indonesia, and Thailand and other parts of Asia and so forth.

So our portfolio, we think, is very well balanced.

And just because production is non-OECD doesn't mean that it's automatically low margin.

There's quite a variance in our portfolio and it's -- and we think it's well balanced.

As far as Latin America is concerned, there are -- again, we have a large portfolio.

We're in these countries for the long-term.

The pendulum tends to swing back and forth.

I can never think of a time where everything was going perfectly everywhere all the time around the globe.

And our Company has a long experience of being in what we would call difficult places, or some people would consider difficult places, such as Angola, Nigeria, some of the Latin American countries.

Indonesia in the past has gone through very difficult times, although in a much better shape today.

So I think you have to take a long-term view and our reserves exposure in places like Venezuela and Argentina is actually relatively low if you looked at our disclosures, particularly closely in the 10-K.

And so, you've got to take the good with the bad when you're in it for the long-term and I think we have a well-balanced portfolio and we don't put all of our eggs, or too many of our eggs in one basket.

So would that mean that with heavy oil operations getting deeper in, say, Canada, to increase on your existing Canadian position and Venezuela, that may be going a bit too far, or how should we think about that going forward, given your skill set, you're building up in terms of heavy oil?

Well, we're doing, we're doing both.

We're in Canada.

We're in the Orinoco Belt and, in fact, evaluating further projects in the Orinoco Belt with our partner there, Repsol at the moment.

And, of course, we have heavy -- a lot of heavy oil experience here in California and in Indonesia so, again, we have a balanced portfolio here.

And what we bring to the table, of course, is the technology and know-how to manage and handle heavy oil and convert it and recover it and so forth.

So I think we can do it all and -- but I think we have to recognize that you don't want to do it all in just one place.

You spread it around your portfolio so you're evenly balanced, as you can be, and take advantage of your know-how and skill.

That's something -- that's one of the differentiating features of an international oil company.

And, Neil, one of the things that we're pleased with is with the inclusion of Unocal for all the strategic reasons that we acquired it, the fit in the United States and the Gulf of Mexico, and particularly the natural gas in Asia gives us more options and I think we'll find their position that is now our position in the Caspian was -- will be a major [boon] as well.

So I think the combination of the locations and bringing more gas than Legacy Chevron had had helped to balance that portfolio that Dave described.

Great, thanks.

Thanks, Neil.

Your next question comes from the line of Paul Cheng with Lehman Brothers.

Thank you.

Good morning, Dave, Steve, and Irene.

Dave, I understand that the reserve replacement in any one particular or two years, that is not a very good measurement of the efficiency of the program.

To help us to better understand how well have you been doing in your exploration program, can you share with us what is the resource addition that you've been able to do for the drill bit in 2005 or perhaps that the average between 2002 to 2005?

Yes, Paul, well, our exploration program has, again, been very successful.

I think this year, 58% success rate, surprising us because we're targeting something closer to 40.

So it's been a good year for exploration.

Over the last few years, we've been averaging over a billion barrels of resource -- a billion barrels of oil equivalent resources.

Okay, that's 1 billion barrels of resources, oil equivalent.

And none of -- essentially none of that over the last four or five years since we've launched our kind of new exploration portfolio management process, essentially none of that has ever been booked yet.

But it bodes well for the long-term.

It's a very important measure and it's one, of course, that we'll be talking more about when we meet on March 6th (correction: should be March 7th) at our Analyst Meeting.

So it's been another good year for exploration and we are averaging in the range of a billion barrels of resource adds per year.

I want to emphasize resource adds is not proved reserves yet because you've got to do further evaluation and in some cases, in the case of gas, commercialization.

Certainly, certainly understand.

That's why, I think that to better understand how effective or efficient is your program, it’s better looking from that standpoint itself to prove the reserve, which is somewhat an accounting measurement.

Yes, and in fact, we'll be covering our exploration factory and how we see that migrating from resources to production in our upcoming analyst meeting.

Dave, can I ask a follow-up question, that's somewhat unrelated?

Okay.

On the -- when the--Venezuela forcing everyone on the….from the operating contract into the joint venture, wonder what is the financial and production impact for you guys in 2006 going to be?

Well, we won't know, but I -- we expect, I mean from our -- we expect from a value proposition that this will be a value neutral transition, but we don't know.

It's work that's in progress.

So I can't really comment on that until the work is complete.

But let me assure you that we will -- once we have reached agreement on this conversion to a joint venture, we'll be putting out something in public.

Paul, as you had seen, we had announced that we had agreed preliminarily to a mixed company, but those negotiations are yet to be finalized and as Dave said, once they are final, we'll announce the impact.

Let's --.

We're coming up to the top of the hour, so I want to thank you all for calling in and in closing let me just say I appreciate everyone's participation.

I want to thank you for participating, and I also want to look -- welcome you to come to our March 6th (correction: Should be March 7th) Analyst Meeting in New York.

We'll look forward to seeing you then.

And thank you, Dennis.

Appreciate you hosting the call.

This concludes today's fourth quarter 2005 Chevron earnings conference call.

You may now disconnect.