雪佛龍 (CVX) 0 Q0 法說會逐字稿

Good morning.

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

Welcome to Chevron's fourth-quarter 2009 earnings conference call.

(Operator Instructions).

As a reminder, this conference call is being recorded.

I will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr.

John Watson.

Please go ahead.

Thanks, Sean.

Welcome to Chevron's fourth-quarter earnings conference call webcast.

It is good to be back on the calls.

With me today are Pat Yarrington, our CFO, and Jeanette Ourada, General Manager Investor Relations.

Our focus today is on Chevron's financial and operating results for the fourth quarter of 2009.

We will refer to the slides that are available on our website.

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

We ask that you review the cautionary statement on slide two.

Turning to slide three, I'd like to provide a brief summary of our operational performance in 2009.

We had a number of very significant accomplishments during the year.

We again set a new record for safety and are among the best in the industry.

We continued to operate with excellence and increased both production efficiency and refinery reliability.

We grew production by 7% in 2009, reflecting the startup and ramp-up of major capital projects and strong performance in our base business.

Project execution was, of course, key to these results.

Projects that started up between 2007 and 2009 contributed over 450,000 barrels a day of net production in 2009.

Our continued focus on cost management delivered very positive results, lowering our operating expenses by 15% compared with 2008.

Finally, in the face of a global economic downturn, we maintained our strategic focus on the key drivers that will ensure growth and superior returns to our stockholders in the years ahead.

This consistency, in my view, in our strategy is one of our great strengths.

Slide four summarizes our strategic accomplishments for 2009.

In the Upstream we had another year of successful exploration with key discoveries in Australia, the United States and Africa.

On a preliminary basis, we estimate that we replaced 112% of our production through net reserve additions in 2009.

Absent price effects, the 2009 reserve replacement ratio was 145%.

We started up three major Chevron operated deepwater projects; Tahiti in the Gulf of Mexico, Frade in Brazil and Tombua-Landana in Angola.

There were also production gains from major capital projects started in 2008 that ramped up to name-plate capacity in 2009; the Tengiz expansion in Kazakhstan, Agbami in Nigeria, and Blind Faith in the Gulf of Mexico, all were significant contributors to our 2009 production growth and will generate value for years to come.

Continuing our progress in the deepwater Gulf of Mexico, we entered front-end engineering and design work on our Jack/St.

Malo, and Bigfoot developments.

We also made significant strides in advancing our gas business.

In Australia we reached a final investment decision for Gorgon in September, a true legacy project for the Company and the largest in our history.

We have also signed long-term sales and purchase agreements and heads of agreement for about 90% of our Gorgon equity LNG offtake.

Also, in Australia we entered FEED on our Wheatstone natural gas project in July.

Since that time we have welcomed equity partners in to the project, bringing additional gas supplies and establishing Wheatstone as an LNG hub.

We have also entered into heads of agreement with buyers to deliver almost 60% of the total LNG offtake from the first two trains.

In Africa construction continued at our Escravos Gas-ToLiquid project in Nigeria and our Angola LNG project.

Both facilities are expected to start up in 2012.

In China, we received government approval for the first stage of the Chuandongbei sour gas project, and in Vietnam we signed a heads of agreement that will allow us to begin front-end engineering and design work for this offshore natural gas development in the Gulf of Thailand.

Looking at our Downstream business, refineries ran at strong levels of reliability for the second consecutive year, and we have cut unplanned unit outages in half over the same time period.

Finally, portfolio rationalization continued, and we successfully completed 13 market exits in 2009.

We received good value for these assets.

The exits contribute to lowering costs and capital employed in the Downstream and align with our strategy to focus on markets of competitive strength.

Slide five provides a brief overview of our financial performance.

The Company's fourth-quarter earnings were $3.1 billion or $1.53 per diluted share.

Comparing the fourth-quarter 2009 to the same period a year earlier, our earnings were down 37%.

The Upstream business benefited from higher crude oil prices and increased net oil equivalent production, while our Downstream results fell, reflecting weaker product margins.

Return on capital employed for the year was 10.6%.

The debt ratio at the end of the year was 10.3%, and net debt was below $2 billion underscoring Chevron's financial strength and flexibility.

Dividends were $5.3 billion for the year, and 2009 marked our 22nd consecutive annual dividend increase with an annual average growth rate over that period of 7%.

Finally, Chevron's 2009 TSR of 8.1% was the highest of the U.S.

majors.

When taking a longer view, Chevron has held the number one ranking in the peer group for both the three-year and five-year averages and outpaced the S&P 500 return by more than 10% in both comparative periods.

Pat will now take us through the quarterly comparisons.

Pat?

Thanks, John.

My remarks compare the results of fourth quarter 2009 with the third quarter of 2009.

And, as a reminder, our earnings release compares fourth-quarter '09 with the same quarter a year ago.

Turning now to slide six, fourth-quarter earnings were down $760 million from the third quarter.

Starting from the left side of the chart, higher crude oil and natural gas realizations, as well as increased production volume, benefited the Company's worldwide Upstream results.

Downstream earnings were sharply lower on poor refining and marketing margins and resulted in a loss for the fourth quarter.

The variance in the other bar reflects higher corporate charges and lower Chemicals earnings.

On slide seven, our U.S.

Upstream earnings for the fourth quarter were about $170 million higher than the third quarter's results.

Higher crude oil and natural gas realizations benefited earnings by $295 million.

Chevron's average U.S.

crude oil realization was at $7 a barrel between consecutive quarters, about $1 less than the increase in average spot price of WTI.

Natural gas realizations also increased between quarters, in line with Henry Hub spot prices and represented about $75 million of the positive variance.

The absence of a settlement gain of certain hurricane insurance claims recognized in the third quarter resulted in a $110 million negative variance between periods.

The other bar here is comprised of a number of offsetting items.

Turning to slide eight, International Upstream earnings were up about $200 million compared with the third quarter.

Higher oil and gas realizations increased earnings by $435 million.

Average realizations for liquids rose 11%, in line with the increase in Brent spot prices.

Natural gas realizations were also higher in the fourth quarter, contributing about $60 million to earnings.

Higher liftings, primarily in Kazakhstan and Australia, benefited earnings by $100 million.

Recall that the third quarter included a net benefit of about $400 million triggered by the formal approval of the Gorgon project.

The absence of this benefit was partly offset by gains on certain small equity sales resulting in a net $300 million variance this period.

The other bar includes several items and netted to a charge of $38 million for the quarter.

The largest components here were operating expense and tax items which mostly offset.

Slide nine summarizes the quarterly change in worldwide oil equivalent production, including volumes produced from oil sands in Canada.

Production increased 76,000 barrels per day or nearly 3% between quarters.

Higher prices reduced volumes under production sharing and variable royalty contracts by an estimated 12,000 barrels a day.

The external constraints bar shows the benefit of 44,000 barrels a day, largely reflecting a return to normal operations in Nigeria for the full fourth quarter.

Base business production declined roughly 29,000 barrels a day, primarily due to storm-related shut-ins in the Gulf of Mexico and China, as well as normal field declines.

And, as shown on the green bar, increased production from major capital projects benefited fourth-quarter production by 73,000 barrels a day, largely driven by higher volumes at TCO and a favorable adjustment related to a deepwater Gulf of Mexico royalty settlement.

Slide 10 compares full-year 2009 OEG production to that of 2008.

Production rose 7% or 174,000 barrels a day.

Price impacts from production sharing and variable royalty contracts increased production by an estimated 55,000 barrels a day.

WTI prices, as you know, averaged $62 a barrel in 2009 versus $100 a barrel in 2008.

For the year, external constraints, including security disruptions in Nigeria, OPEC-related curtailments early in the year, and lower natural gas demand in Asia, essentially offset the volumetric impact of lower prices.

Base business production declined by 130,000 barrels a day.

Strong base business performance limited our decline rate to slightly more than 5%, ahead of the 6% or 7% guidance we provided earlier.

And finally, major capital projects contributed an incremental 305,000 barrels a day to 2009 oil and gas production, reflecting a ramp-up of key 2008 projects and new project start-ups in 2009.

On slide 11, you see our full-year outlook for production in 2010 is 2.73 million barrels a day, 1% increase over 2009 levels.

The outlook does assume a $62 per barrel price range, the same average price as in 2009, and it does not assume OPEC curtailments, material security or market-related impacts.

Recognizing the reduced base business investments in 2009, we project base business declines to average approximately 6% or 164,000 barrels a day.

While we have increased our planned 2010 base business investments, there is a lag between the timing of investment and the associated production benefit.

In 2010 we will continue to limit North America natural gas development activities due to current market conditions.

The growth from major capital projects is projected to be 190,000 barrels a day.

Now keep in mind that the smaller percentage growth in 2010 is also a result of accelerated ramp-ups that led to higher than expected production growth in 2009.

In other words, growth has been achieved earlier than planned, which is a good thing.

Turning to slide 12, U.S.

Downstream earnings fell about $380 million in the fourth quarter.

Indicator margins were down sharply, resulting in a $170 million negative variance.

Refining margins declined, especially on the West Coast, due to seasonal decline in gasoline demand, high product inventory levels and rising crude prices.

Lower volumes in the fourth quarter largely reflected planned maintenance at our El Segundo refinery in California and lowered earnings by $40 million.

Operating expenses were $65 million higher between periods, largely due to the El Segundo planned shutdown and a non-recurring charge related to a previously announced exit of certain US East Coast markets.

Multiple components made up the other bar, including lower trading results and unfavorable tax variances.

On slide 13 International Downstream earnings decreased about $430 million from the third quarter's results.

Lower realized margins reduced earnings by $175 million between quarters.

This was particularly evident in the Asia-Pacific region where Singapore cracking margins fell by almost 50%.

Timing effects resulted in a $260 million negative variance between periods, in part reflecting higher price volatility in the quarter.

The timing effects bar includes inventory and mark-to-market effects, as well as impact of lagged aviation contract pricing.

The other bar was a small benefit for the quarter.

Slide 14 shows that earnings from Chemicals operations were about $65 million lower in the fourth quarter.

Results for the Olefins, Aromatics and Oronite additives all reflected lower margins.

Now please note that starting in 2010 our Chemicals business will be reporting to Mike Wirth, and we will combine the Chemicals and Downstream segment beginning with our first-quarter results.

Slide 15 covers All Other.

Fourth-quarter net charges were $418 million compared to a net $167 million charge in the third quarter.

The $250 million increase between quarters is primarily due to unfavorable variances in tax items and other corporate charges.

The All Other charges in the fourth quarter were above our typical guidance range of $250 million to $350 million per quarter, though I would note that the full-year results were below guidance.

On slide 16, I would now like to summarize our cost management efforts.

I will start first with the cost efforts.

In the second quarter, we announced our goal to reduce 2009 operating and SG&A costs by 10% or $2.5 billion.

This target excluded the benefit associated with lower cost of purchased fuel.

We were able to exceed that target and deliver a 15% reduction totaling almost $4 billion.

All business segments contributed to the reduction, and the savings were delivered in a year that saw our Upstream oil and gas production grow by the 7%.

About one-third of the reductions were market-related such as lower transportation expenses.

Another third were discrete items, primarily due to the absence of significant hurricane charges realized in 2008.

And the final third was the result of deliberate actions taken across the Company, which lowered expenses in most cost categories and included portfolio actions, efforts to increase efficiency and reliability, to curtail or eliminate discretionary spending and to renegotiate contract terms with suppliers.

We were very diligent on every element of our cost structure this year, and we are pleased with this progress in 2009 and expect to see further positive results from our efforts.

And on slide 17, capital spending.

Total capital spending for 2009 was $22.2 billion compared with our budget of $22.8 billion.

Upstream spending accounted for $17.1 billion or 77% of the total.

Our cash C&E, which excludes our equity share of affiliate outlays, was $20.6 billion.

Our announced capital program for 2010 is $21.6 billion, a 3% decrease compared to 2009 actual expenditures.

Excluding one-time concession payments in 2009, our 2010 budget represents an increase of approximately 15% in Upstream spending.

Of the overall 2010 capital program, 80% is for Upstream activities, primarily related to the large multi-year projects consistent with our Upstream growth strategies.

These include projects in Western Australia, the deepwater U.S.

Gulf of Mexico, Africa and the Gulf of Thailand.

Another 16% is earmarked for Downstream investment, a reduction of 23% from 2009 levels.

The majority of the 2010 planned Downstream investment is related to major projects under construction.

John will now provide some thoughts on 2010.

John?

Thanks Pat.

Please turn to slide 18, if you would.

As we enter 2010, in the Downstream we continue to see challenged economic conditions.

We are certainly not satisfied with our Downstream results in 2009.

We are shifting to a simpler and less costly organization to improve returns and remain competitive in this difficult environment.

We intend to cover our efforts in much more detail in March at our regularly scheduled meeting.

In the Upstream we are on track for start-up on three major capital projects; the Perdido regional hub in the deepwater Gulf of Mexico, the first expansion of the Athabasca Oil Sands Project in Canada, and the Escravos Gas Project Phase 3A in Nigeria.

In addition, we expect to sanction four other major capital projects; Papa-Terra in Brazil, which was announced earlier this week; as well as Tahiti Stage 2; Jack/St.

Malo; and Big Foot in the Gulf of Mexico.

We have had consistent strategies over time, and they have served us well.

They are the right strategies and will keep us competitive now and into the future.

Underlying our efforts will be a continued focus on execution, investing in the right opportunities, completing our projects on time and on budget, ensuring safe and reliable operations, effectively applying technology and maintaining vigilance on our cost structure.

In summary, rewarding our stockholders, continuing our disciplined growth and maintaining our financial strength, are objectives we will continue to pursue in 2010 and beyond.

I look forward to further discussing our future plans at our security analyst meeting on March 9 in New York City.

(Operator Instructions).

Robert Kessler, Simmons & Co.

Good morning everyone.

A couple of unrelated questions for me.

The first is, I wondered if you could give some more color around your reserve replacement for 2009.

It sounds like a good figure all-in.

I'm wondering how much specifically might have come from oil sands, mining, bookings or reclassifications.

I seem to recall you being at 0 on the footnoted reserves for mining as of 2008.

So I'm wondering did you add back that 400 million barrels there and reclassify them?

And then also on Gorgon.

Unrelated to that, on this Downstream restructuring that you are moving through, I'm wondering if the reporter out in California kind of got over his skis in suggesting that Richmond was going to close in an absolute sense.

Did he do so, and what, if any, refinery closures or divestments might you be contemplating?

On reserves your memory is good.

We didn't have reserves booked for the Athabasca Oil Sands Project in 2008, and so we did have an initial booking there.

That is some 460 million barrels, and the Gorgon booking is a little bit over 700 million barrels.

You would expect as we went to FID that, of course, that we would bring in barrels for that.

So our overall booking with other additions and price revisions was 112%.

I will emphasize that this was one -- it is preliminary, and so it is still being finalized.

But I would also mention that without the price revisions we would have been at about 145%.

So we think it was a good year.

With respect to your second question on the Downstream and prospective closures of refineries, it is quite premature to talk about closing refineries.

I said earlier that we are certainly disappointed with the results in the Downstream.

Industry conditions are very tough right now, and we lost money in both the U.S.

and our International Downstream business, which I expect is a pattern for the industry.

So those results were weak.

So we are on a path to improve those results.

Now we are building on a position of some strength in the reliability end of our business at the refineries, and based on the competitive refinery stacks that we look at, our refineries are quite competitive.

But they need to stay that way, and these conditions are very difficult.

So we are taking a look at all of our Downstream operations, and I expect you will see some changes in organization going forward.

You will see some changes in costs and an emphasis on maintaining some of the operational momentum but doing it at lower costs.

Most of our divestitures up to now have focused primarily on the marketing side of the business.

You have seen us continue to rationalize markets that are distant from our key supply points.

But I wouldn't want to advertise any particular refinery closures that we are contemplating at this time.

Okay, thanks for the color, John.

Doug Terreson, ISI.

John, I wanted to ask another question on refining, too, and this is more of a strategic bigger picture question I think, and it really involves how you envision placement of your global refining business, Chevron's global refining business in the overall mix.

Meaning pre-Texaco and even earlier, you guys were historically much heavier in the Upstream than the Downstream on an absolute basis and relative to the peers, and this basically even shifted further during the past decade, as you know.

And so the question becomes, will this shift -- is it likely to continue towards the Upstream as it has in the past, and is it -- is the thinking here as profound as considering re-characterization of entire regions maybe to less strategic categories, or is it too early to know yet?

Doug, I think your observations are right about how we viewed the business historically.

If I reflect back a decade or more, we have had a view that the Upstream business over time provides better returns.

Now part of that is philosophical.

The Upstream business has a decline curve, and there is always a need to replace volumes behind it.

And so market conditions tend to correct themselves quickly.

In the Downstream, of course, particularly the refining business, you need demand growth, and where you don't have demand growth or you see overbuilding, it takes more time to rationalize that.

And we are in one of those periods right now when the conditions are difficult on the refining side.

With that overall view and reflecting on the particular individual strengths that we have in our Company, we have favored Upstream investments for more than the last decade.

And that has been a pattern that I think you will see continuing going forward.

As we preferentially invest in the Upstream, we will become more weighted to that business.

What I would tell you, though, about the Downstream are several points.

One, over the course of the cycle, we think the Downstream can earn good returns, certainly in excess of 10%, and we expect to be in excess of 10% over the course of the cycle.

The second and probably more subtle aspect of the Downstream business is the value that integration of that business brings to us.

If you look at plants like the GTL plant in Nigeria, upgraders in Hamaca, even the Tengiz plants in Kazakhstan, those plants would not operate without a lot of Downstream expertise because, as you know, they look a whole lot like refineries.

And so, one, we have that expertise.

We also have the expertise that our trading and supply people bring as increasingly we are producing disadvantaged crudes or crudes that need a market and facilities that can get full value out of the raw material.

And so for a number of reasons -- maybe a long answer here -- for a number of reasons, I think we will be in the Downstream business going forward, but we are going to be very measured about where that footprint is.

Okay.

Thanks for the elaboration, and I think I get the message.

Good, thank you.

Doug Leggate, Bank of America.

John, it is good to hear you back on the call.

I'm afraid I'm going to flog this horse a little bit more.

I actually have two questions if I can squeeze them in.

First of all, generally on the Downstream, I think you have been pretty clear about where you are going with this.

But obviously you have got a number of plants -- I know you do not want to be too specific -- but you have a number of fairly small plants and minority interests and so on.

It is hard to imagine that those are bringing in the big strategic benefits that you just described.

So you could you generally characterize where you see the focus on this restructuring effort moving?

My second question is -- I kind of hate to bring this up -- but your competitor obviously has -- your large competitor here in the U.S.

-- has made a fairly big bet in U.S.

gas.

Obviously you have just taken over the helm here, and I am just wondering where your head is in terms of longer-term investments U.S.

gas market on the whole?

And if you were prepared to offer any comments on how you see Chevron's role in future consolidation, I would appreciate that as well.

Sure.

No, those are both fair questions.

First, with respect to some of the joint venture refineries that we have, the way our business is structured our refineries outside the United States are predominantly held through joint ventures.

So whether it is GS Caltex or a refinery in Thailand or a refinery in Singapore, those are held through joint ventures, as well as our interest in Caltex Australia.

So our focus is really on keeping the facilities competitive.

In the United States, of course, and in our small refinery in Canada, those are 100% owned refineries.

So the structure of the ownership is not necessarily the issue; it is whether the facility can be competitive, and we think our major facilities are competitive.

And they have been very reliable, which, as you know, has been our focus over time.

I think the key is making sure that we get that reliability at the right cost.

And so we will be looking to be sure that we can maintain the reliability but do it at a lower-cost.

Our refineries are competitive on a net cash margin, but we think that we can improve them further.

And a lot of the effort that we are focusing on is continued work in the marketing area and our interface at the customer level and through the delivery chain from the refinery to the ultimate customer.

Mike Wirth will talk a lot more about this at our meeting in March as we do have plans and work underway that we think on a standalone basis will improve our results regardless of what happens to margins.

As far as the U.S.

gas business goes, certainly I'm aware of the big acquisition that our major competitor made in the U.S., and I would start by telling you that we do have a position in shales and tight gases.

We have a presence in the Piceance.

We have a nice presence in the Haynesville.

We picked up acreage recently in Canada and nearly 1 million acres in Poland.

So we do have a presence in the shales.

But, frankly, we have been in a position where we have a very strong portfolio worldwide, and we can see growth out through the rest of this decade.

And so we haven't been particularly needy, if you will, to do a large transaction.

And so we have not felt that the opportunities that are out there compete with other things that we have in our portfolio.

Now you know me and you know us pretty well.

We are always screening the opportunities in the Upstream business.

It is a resource business, and we are in the business of acquiring leases, individual assets and companies and have demonstrated that we're willing to do so when the conditions are right.

We just haven't felt that they are right in the shales or otherwise in the very recent past.

John, thanks.

A very full answer.

Thank you.

Paul Cheng, Barclays Capital.

Thank you.

John, welcome back.

This maybe is a little bit of a curveball, I have two questions.

One, not just for Chevron but if I look at the industry, I think there is a big debate among the investors talking about the big guys you Exxon or BP or other companies.

Is it possible on a sustainable basis that to grow the resource and the production base organically?

I don't know if you will be able to comment on that whether you actually think the resource is not an issue that you do have the capability or that the opportunity you can see in the industry for you guys and not just you guys but for the industry to grow, or that acquisitions were unavoidable for the industry, if not necessarily for Chevron but for the industry to become a bigger piece of the pie.

And secondly, that if we look at your production guidance in 2010, always that there is a risk opportunity and I'm wondering that, John, if you will be able to maybe help us understand what is the major area of the potential upside and the potential downside risks?

Thank you.

Okay.

Thanks, Paul.

I think I'm going to answer yes to both parts of your first question, at least for Chevron.

Ultimately everyone has to continue to add resources to the queue going forward.

And so over time every company has to add either exploration acreage, companies or otherwise.

And so I think longer-term we always have to be looking for new opportunities.

I think when you look a little bit shorter term, we can look out for the better part of this decade and see growth in our portfolio.

And so we feel very good about the queue that we have, and we will give you a little more information about that as George gives his run-through in March on some of the specifics of our projects.

But we have a good queue going out over the course of this decade.

I think the upside in the near term and the opportunity over time is how rapid and quickly we can develop and advance new technologies so that we can increase recoveries.

For example, if you look in the San Joaquin Valley, initial recoveries there were 10% or 20% of oil in place.

Now at Kern River and other fields, we are nearing 70%.

No one would have thought that, and, of course, we are leader in steam technology.

The ability to add to the portfolio going forward is going to be a function of having an offering that host governments value.

And I think our technology in seismic imaging, reservoir management, deepwater developments are highly valued, including sulfur handling, and I think we have excellent relationships with those host governments going forward.

That has helped us recently in China and the PNZ.

So I think my answer to your question is we have some length in our portfolio with the assets that we have, but we are going to need to capture new opportunities either through new acreage or through the acquisition side over time.

Okay.

And how about 2010 production guidance, any major area of potential upside or major area of potential risks where we need to see for the downside or need to monitor for the downside?

Well, one of the challenging areas for us to forecast is in the base business area.

For example, last year initially George gave guidance of about a 7% decline, and we over-achieved last year.

We only had a 5% decline.

This year because we consciously cut back some of our spending in base business in 2009, we have upped that implicit decline in the numbers that we have given you to about 6%.

And so depending upon how rapid the declines are or not in that base business, that number could be a little bit different.

There is also a question of timing of some of the major capital projects that we've got.

We do not have a large number coming on right now.

We've got Perdido and the Athabasca Oil Sands Project, but certainly the timing of major capital project ramp-ups are there.

And then, of course, you always have the issue of price effects, security and market conditions for demand for gas in Asia and other markets.

So those would be the principal areas that I would highlight as both on the up and down side.

That is great.

John, can I just squeeze in one quick one for Pat in terms of the cost reduction?

Pat, for the next two years, what is the potential target that you guys may have and from what major areas?

Thank you.

We do not have a distinct target that we are going to hand out at this particular point in time.

But we do feel good about where we have closed out '09.

And if you look forward and think about what is likely to be sustained or not, I will take you through each of those.

Number one, from a self-help standpoint, we said about a third of the reduction that we had this year was self-help.

Going forward we still are aggressively looking for additional sustained ways to continue to get our cost structure down.

In the Downstream sector, as you can tell, that is an absolute must-have to get our Downstream cost structure to an affordable level.

So highly focused there.

We have shown you charts in the past, too, on Upstream, how competitive the overall Upstream cost structure is.

We want to retain that competitive ranking.

So cost is a very important part of our drivers going forward.

Secondly, on the market-related activities, I would say that there is still a tremendous amount of evidence out there where there is surplus capacity in some of those cost categories that would suggest that cost increases are not likely, and I will just take you to the transportation sector, for example.

There is an awful lot of surplus capacity out there, and even though you have a higher energy base, we are not seeing a lot of those costs being driven through into higher transportation costs for us.

And then finally, we talked last year about the contract renegotiations that we had done through the early part of the year.

Many of those new contract terms only came into place partway through 2009, and they carry on into 2010, and some of them even have longer terms than that.

So we are very positive about being able to sustain and even improve on our cost structure going forward.

Thank you very much.

Arjun Murti, Goldman Sachs.

Thank you.

John, just a couple of Upstream questions.

One of your smaller competitors has had some interesting success in California.

A variety of different exploration plays.

You all are obviously a large California producer.

I'm just wondering if you see upside to California beyond the EOR enhancement stuff you have been doing?

Are there new concepts you are considering on your large acreage position?

And then unrelatedly, there has been some talk again about Kazakhstan, looking at tax terms and contract terms.

I'm wondering if you could either confirm or deny that they are looking to potentially change the tax terms for your Tengiz contract?

Thank you.

It is an interesting concept talking about what's going on in Southern California.

It does not get a great deal of attention.

I assume you're talking about some of the work that is going on around Elk Hills, and we are a participant there.

We do have about a 20% interest, so we are there.

And, in general, the declines that we have seen in that business, obviously it's a mature business, but the declines we have seen have been limited.

And they have been limited because we have been pretty clever in how we apply steam.

It is one of the things that we do very well, and we do it at low cost.

But we also have diatomite and other holdings down there that have some promise for the future.

So California is a nice area for us.

In the Upstream we, of course, have environmental constraints that we work through.

But it's an encouraging business for us, and maybe we will get George to give you a little bit further update when we get to March.

In terms of Kazakhstan, there is a general environment out there where host governments are making sure that they feel they are getting full value out of the contracts and resources that they hold.

I would tell you that our relationship in Kazakhstan has always been excellent, and we have a very strong contract there and have done a good job of living up to that contract.

In my recent visit and discussions with President Nazarbayev, he was very pleased with the performance of Chevron and the Tengiz in particular and said that to me directly.

So I feel good about our relationship and confident we can work through whatever issues may surface there and in virtually every other area where we operate.

That is great.

If I could ask a quick follow-up on the balance sheet.

You have run essentially a net debt free balance sheet since I think '04, so it's been five or six years.

Obviously it has served you all well during the challenging economic times.

Now that you are a CEO, John, any change to running such a pristine balance sheet?

I'm sure you want to maintain balance sheet strength.

But is net debt free the right number for you, or is some different number better or worse?

Well, within a range we are going to keep some capacity on our balance sheet, and frankly we are heading into a period where we have -- we are making some big bets on some of our major capital projects with Gorgon and Wheatstone, and we want to be sure, of course, that we can continue to obviously pay our dividend and increase it as the pattern of earnings and cash flow permit and continue to fund these key projects as we go forward.

Just like this last year, when we saw prices dip, we want to be able to keep the momentum in our business and not have to stop and start operations rapidly.

So I think you'll continue to see us keep some capacity on our balance sheet, though I won't tell you that a specific number other than we do want to maintain our AA credit rating that we have out there.

So I would not look for any change in terms of how we manage our balance sheet.

That's great.

Thank you very much.

Mark Gilman, Benchmark.

Folks, good morning.

I had a couple of specific things and then one more general one.

Is it accurate the report that you have opted not to exercise your preemption rights regarding the Jack field and Jack interest in Devon's sale to Maersk?

Secondly, I was hoping that you might be able to regarding Kazakhstan give us an idea given some of the uncertainties which were referenced in a prior question.

Will you proceed with the expansion project that you have been evaluating in the environment as it stands currently?

The more general question relates to LNG contracting.

You folks have obviously been very active out there in the market, and I was wondering if at least qualitatively you could talk about what kind of changes in contracts you are seeing as it relates either to duration, structure or price formulas?

Sure, Mark.

Those are all good questions.

On the first one, we have exercised our preemptive right around St.

Malo and not for Jack, and that is primarily around aligning our equity interests in those two opportunities.

I will not say a lot more about the commercial aspects of those, but the answer to your question is basically yes on St.

Malo, no on Jack.

In terms of Tengiz expansion, we are optimistic that we will be able to move forward with that project.

But we have -- and we have, for example, settled on some design concepts, etc.

We do have more work to do on the commercial side and on the transportation side, and that work is underway.

But I would tell you I'm optimistic and see no reason that we won't move ahead with that project.

But we are not at FID today, so we have to work through the remaining issues.

In terms of the LNG market, we are very pleased with what we have been able to accomplish at both Gorgon and Wheatstone, and we highlighted that in our press release.

In terms of the specific characteristics, the way I would describe it, it is obviously competitive information, but I would say number one we are producing gas at prices that look a lot like oil.

We've got high slopes on these contracts, and we have got good terms with some of the best buyers in the world.

The history with our Japanese and Korean partners has been excellent over time in our relationships on the North West Shelf, and we think these are among the strongest and best and sophisticated buyers of LNG.

And we have signed them at good terms that underpin the project.

So we haven't seen -- there has been speculation about the condition of the worldwide LNG market, but from our recent experience, it has been very good for those two projects.

Great, John.

Thanks very much.

Jason Gammel, Macquarie.

Maybe one more on the production profile.

John, I appreciate the comments about growth through the end of the decade, and clearly 2014 plus with Gorgon, Wheatstone and perhaps Lower Tertiary does have quite a bit of visibility.

How should we think about the interim period between 2010 and 2013?

Is that going to be more or less a flattish environment?

Jason, you know, what I would prefer to do, and I'm going to punt just a little bit.

We wanted to give you some guidance on 2010, and your observation about middle of the decade and Gorgon and Wheatstone is accurate.

What I would like to do is maybe defer until March where we will give you a little longer -- a little more complete look at both the interim period and what we see coming project by project in a lot more detailed fashion rather than treat that today.

So if you will hold with me until March, we will be happy to give you more information.

Fair enough.

Maybe one more if I could then.

Three more successes during the quarter in Australia, obviously a great drilling environment there.

Can you talk about the volumetric objectives that -- what you are drilling in Australia right now?

Are these TCF plus type structures, and maybe give an update on the overall resource base that you believe you have in the greater Gorgon area at this point?

Well, I will say yes and no.

We have announced some five discoveries this year in Australia.

I would say in an overall sense the size of these discoveries have been a little bit smaller than some of the very large ones in the past, but they have been nice additions and will augment the supply that we have for both Gorgon and Wheatstone.

And, in fact, what you will see from George when he talks a little bit more about this, as we continue to accumulate volumes, it not only raises confidence in the existing project where we have ample resource, but it also starts to give us volumes that will help us underpin expansions there.

As you know, we have ambitions to produce more ultimately at Gorgon subject to regulatory and permitting considerations over time.

And Wheatstone is a hub, which we will be starting at two trains, and we will have the capacity to bring in actually several more trains over time.

So these discoveries really do underpin some of that future growth.

In terms of our aggregate gas resources, we have talked in terms of 70 TCF in the Asia-Pacific region.

So we have a lot of gas in that area.

We will give you a little more granular information on that in March.

Okay.

Thank you, John.

Paul Sankey, Deutsche Bank.

Welcome back, John.

Pat, you did address this in your comments, but if you could just remind me, going back to the volume outlook for 2010, what did you say about the external constraints that you have or have not baked in?

I'm trying to get to what the range of outcomes could be there, particularly with view to OPEC and Nigeria obviously.

Right.

We said that the outlook does not assume any OPEC curtailments or security constraints or even market constraints.

Fair enough.

And if I look backwards, it feels like the range of outcome there based on what you're showing for what happened in '09 is about, let's say, 100,000 barrels a day either way if we combine all of them together?

Well, those are all very circumstantial elements, and I would hate to -- I will let you make your own forecast going forward about each and every one of those, frankly.

That is why we said we did not put it in.

Predicting production plus or minus 1% or 2%, as my Upstream friends tell me, is a very tough business given all the factors out there.

But there is a range around them to be sure, Paul.

I've got you.

And then if we just look at, call it Q1 of 2010 to date, what is the size of that impact in Nigeria and OPEC right now?

We have about 20,000 barrels a day shut in for Nigeria.

OPEC, though?

Nothing.

Zero?

Okay.

The dreaded question, could you just update us on your best guesstimate of what is happening in Ecuador and any headline risk around that?

Thank you.

Sure.

Well, Paul, as you know, we have made very significant disclosures, and I know you have read the material that we have online.

I guess what I would tell you is the court in Ecuador appears to be headed toward a verdict.

I'm not going to predict, that, but based on the pattern in the courts there and the systematic reduction in the application of rule of law, there could be an adverse verdict.

And if so, we will vigorously defend ourselves, not only in Ecuador but in the United States or anywhere else that they might choose to go to seek enforcement.

Yes, I was really thinking if I look back a year now, we were looking for I think way back for a judgment around October of last year.

Do you have any sense for when this might finalize?

Well, I think people were looking for a verdict around that time, and then they had a little problem with the judge that you may recall who was shown to not be impartial and was captured on video, and he had to be replaced.

And so there is a new judge there, and I'm not going to predict when he might produce a verdict and what that verdict might be.

Fair enough, John.

I will leave it there.

Thank you.

Pavel Molchanov, Raymond James.

Thanks for taking my question.

First, on your CapEx.

Can you give us a sense of the CapEx curve for Gorgon?

So, for example, how much you might spend there in 2010?

Sure.

Gorgon and Wheatstone spending for 2010 will be about $3.5 billion.

And so it is a sizable chunk of our capital spending both in 2010 and through to the middle of the decade.

And just to refresh, have you given your total CapEx estimate for the overall project and how have they evolved as you have completed FID?

Yes, the number that we have given for Gorgon for the 100% project amount has been $37 billion U.S., and that is still the number.

Interestingly enough, we have placed a considerable number of contracts against that, and so far it seems to be right on track.

Of course, the numbers can change a little bit as currencies move over time, but that project we are very pleased with.

We had some outsiders -- an outside agency that looks at major capital projects, and they have indicated that they feel that Gorgon is the best prepared megaproject they have ever seen.

And so we are very encouraged at where that is heading.

But we are going to be very vigilant on that project.

We, of course, have to get it right at that level of spend.

Yes, that is helpful.

And just a quick Downstream question finally.

Can you give us any thoughts on what you're seeing on the import front in your West Coast market?

Frankly because of the absolutely dismal conditions in the West Coast, imports have found another place to go because the margins just have not been here.

I mean we are heavily over-supplied on the product side, gasoline inventories above the five-year averages.

Margins very depressed and, actually, continue to be so on the West Coast here through the early part of January.

So I don't think imports are finding a welcome home here.

That's helpful.

Thanks guys.

Okay.

I think we have got one more question.

Paul Cheng, Barclays Capital.

John, at the management they have somewhat of a different philosophy in that I know you worked closely with O'Reilly before.

But from your standpoint, is there any major change in how do the top 100 management their performance and compensation is being reviewed or being calculated, or what is the most important driver under your administration?

Well, in terms of compensation and management, I have had the good fortune to actually work very directly with everyone on our management committee, and we have a very strong group of people, and I feel very fortunate to have a great team around me both at a very senior level and down through the organization.

So -- and we have had a long-standing set of compensation practices that I think provide the right types of incentive and motivation.

My priority is right now, Paul, one, as I indicated in my remarks, you should see a great deal of strategic continuity.

The strategies that we have in place have served us very well.

If I could describe my emphasis early on, it would be ramping it up in terms of our focus on execution in the business, and it is not sexy stuff.

It's very direct things around capital stewardship, continuing our reliability efforts, systematic looks at cost.

So that is certainly number one.

I would tell you that I have talked internally a lot about people in the organization.

We have a great deal of depth.

The industry is going through a crew change, if you will, over the course of the next decade, and we are well prepared for that.

But we need to be sure that we are developing our people appropriately and making sure that the younger folks that we have been hiring over the course of this decade are going to be well prepared to take jobs.

And then the third thing that I have talked about with our employees is growth going forward.

Execution, of course, is a part of delivering that growth in the near term, but maintaining our edge on key technologies is something that I will be emphasizing particularly around seismic imaging, reservoir management and drilling where we are very good and a leader today and need to continue that and then capturing new opportunities.

I think our business model is the best in the industry where we have delegated authority and strong leaders in country, and we need to take advantage of that with our overall capabilities to continue to add to the portfolio and deliver growth.

So those are the things that I am emphasizing with our organization.

Very good.

Thank you.

And I think with that concludes our remarks.

I would like to thank all of the analysts for their good questions.

I will just remind you that we will come back and give you a lot more detail in March, and we will look forward to seeing you at our major meeting then.

Thank you.

Thank you, ladies and gentlemen.

This concludes Chevron's fourth-quarter 2009 earnings conference call.

You may now disconnect.