Good morning, my name is Sean and I’ll be your conference facilitator today. Welcome to Chevron’s fourth quarter 2009 earnings conference call. At this time all participants are in a listen-only mode. After the speakers’ remarks, there will be a question-and-answer session, and instructions will be given at that time. (Operator instructions) I’d 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 and webcast. It is good to be back on the calls. With me today are Pat Yarrington, our CFO, and Jeanette Ourada, General Manager of 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 gets started, please be reminded that this presentation contains estimates, projections and other forward-looking statements, we ask that you review the cautionary statements 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 continue to operate with excellence and increase 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 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. The slide 4 summarizes our strategic accomplishments for 2009. In the upstream we had another year of successful exploration with key discoveries in Australia, United States and Africa. On a preliminary basis, we estimate that we replaced a 112% of our production through net reserve additions in 2009. Absent price effects, the 2009 reserve replacement ratio was a 145%. We started off three major Chevron operated deep water projects, Tahiti in the Gulf of Mexico, Frade in Brazil, and Tombua and Landana in Angola. There were also production gains from major capital projects started in 2008 that ramped up to nameplate 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 deep water Gulf of Mexico, we entered front-end engineering and design work on our Jack/St. Malo in Big Foot developments. We also made significant strides in advancing our gas business. In Australia, we reached a final investment position 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 off-take. Also, in Australia, we had a exceed Wheatstone natural gas project in July. Since that time we are welcomed equity partners in to the project, brining 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 off-take from the first two trains. In Africa, construction continued at our Escravos gas-to-liquid project in Nigeria, in Angola LNG project. Both facilities are expected to start up in 2012. In China, we received government approvals for the first stage of Chongdong Bay [ph] is our gas project. In the Vietnam we signed heads of agreement that will allow us to begin foreign engineering and design works 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. We have cut unplanned unit outages in half over the same time period. Finally, portfolio rationalization continued and we successfully completed 13 market exists in 2009. We received good value for these assets. The exists contribute to lower in costs and capital employed in the downstream and the line with our strategy to focus on markets of competitive strength. Slide 5, provides a brief overview of our financial performance. The company’s first 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 increase 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 a 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 realization as well as increased production volumes benefited the company’s worldwide upstream results. Downstream earnings were shortly lower on core refining and marketing margin, 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 quarters result. Higher crude oil and natural gas realizations benefited earnings by $295 million. Chevron’s average US crude oil realization was up $7 a barrel between consecutive quarters, about a $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 $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 to 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 lifting, 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 a quarterly change in worldwide oil equivalent production, including volumes produced from oil sands in Canada. Production increased to 76,000 barrel a day or nearly 3% between quarters. Higher prices reduced volumes under production sharing and variable royalty contract by an estimated 12,000 barrel a day. The external constraints bar shows a benefit of 44,000 barrel a day, largely reflecting a return to normal operations in Nigeria for the full fourth quarter. Base business production declined roughly 29,000 barrel a day primarily due to storm related shut-in in the Gulf of Mexico and China as well as normal sale decline. And as shown on the green bar increased production for major capital projects benefited fourth quarter production by 73,000 barrel a day, largely driver 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 contract, increased production by an estimated 55,000 barrel a day. WTI prices as you know average $62 a barrel in 2009 versus $100 a barrel in 2008. For the year, external constraints including securities disruption in Nigeria, OPEC related curtailment early in the year and lower natural gas demand in Asia essentially offset the volume metric impact of lower prices. Based business production declined by 130,000 barrels a day. Strong based business performance limited our decline rates 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 startups 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 curtailment, 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 had 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 for 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 riding crude prices. Lower volumes in the fourth quarter largely reflected plant 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 plant 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 a $430 million from the third quarter’s result. Lower realized margins reduced earnings by a $175 million between quarters. This was particularly evident in the Asia Pacific region or 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 affect bar includes inventory and mark-to-market effects as well as impacts of flagged [ph] aviation contract pricing. The other bar was a small benefit for the quarter. Slide 14, shows that earnings from chemical operations were about $65 million lower in the fourth quarter. Results for the Oliphant’s 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 chemical and downstream segments beginning with our first quarter results. Slide 15 covers all other. Fourth quarter net charges were $418 million, compare 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. So I would note that the full year results were below guidance. On slide 16, I now like to summarize our cost management efforts. I'll start first with the cost efforts. In the second quarter, we announced our goals to reduce 2009 operating and SG&A costs by 10% or $2.5 billion. This target excluded the benefit associated with lower cost to purchase fuel. We were able to exceed that target and deliver the 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 delivered actions taken across the company which lowered expenses in most cost categories and included portfolio actions, effort to increase efficiency and reliability to curtail or eliminate discretionary spending and to renegotiate contracts 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 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 investments, 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’re 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 schedule meeting. In the upstream, we are on track to startup 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 Tahiti Stage 2, Jack/St. Malo in 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 would 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 and our security analyst meeting on March 9th in New York City.

(Operator instructions) Our first question comes from Robert Kessler with Simmons & Company.

Good morning, everyone. A couple of analytic 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 am wondering how much specifically might have come from oil sands, mining, bookings or reclassification. So I seem recall you being at zero on the sort of footnoted reserves for mining as of 2008. So wondering did you add back $400 million barrels there and reclassify them? And then also on Gorgon, and related to that on this downstream restructuring that you're moving through, I'm wondering if the report on California, can I got over risky and suggesting that Richmond was going to close in an absolute sense. Is that let you do so and what if any refinery closures or divestments might you be contemplating?

Sure, Robert. Thanks. 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’s some $460 million barrels. And the Gorgon booking is a little bit over $700 million barrels. You would expect as we went 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'll emphasize that this was one, it's pulmonary and so it's 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 perspective closures of refineries it's 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 US and in international downstream business, which I expect as a pattern for the industry. So those results were weak. So we are on a path to improve those results. Now, we're building on a position of some strength and 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 our downstream operations, and I expect you’ll see some changes in organization going forward. You’ll see some changes in cost and an emphasis on maintaining some of the operational momentum but doing at lower cost. Most of our divestitures up to now have focused primarily on the marketing side of the business, you’ve 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’re contemplating at this time.

Okay thanks for the cover, John.

Thanks.

Our next question comes from Doug Terreson with ISI.

Hi Doug.

John, I want 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-tax you quote [ph] even earlier, you guys were historically much heavier on the upstream and the downstream on an absolute basis, and relative to the peers than, and it makes the shifted further drill [ph] on 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 if the thinking here is profound of considering recharacterization of entire regions maybe to less stage of category or is it too early to know yet?

Well, Doug, I think your observations are right about how we view the business historically. If I reflect back a decade or more we have had a view that the upstream business overtime provides better returns. Now part of that is philosophical on – the upstream business has a decline curve.

Yeah.

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 will become more weighted to that business. What I would tell you, though, about the downstream are several points. One, over the course of 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 GTL plant in Nigeria, upgraders in Hamaca, even the Tengiz in Kazakhstan, those plants wouldn’t operate without a lot of downstream expertise because as you know they look a whole lot like refineries. And so, when 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, a number of reasons, I think 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 got the message.

Okay, good. Thank you.

You are welcome.

Our next question comes from Doug Leggate with Bank of America.

Thank you, good morning, John. It's good to hear back in the call. I am afraid I'm slow [ph] this source 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've been pretty clear about where you are going with this, but obviously you've got a number of trends, I know you don’t want to be too specific, but you have a number of fairly small plans in minority interest and so on. It's hard to imagine that those are being in the big strategic benefice you just described so. Could you kind of generally characterize where you see the focus on the restructuring efforts are moving? And my second question is I kind of hate to bring this up, but your competitor obviously has, your large competitor here in the US just made fairly big bet in US gas. Obviously you've just taken our the helm here and I'm just kind of wondering where your head is in terms of longer-term, investments US gas market on the whole and if you were to offer any comments on how you see Chevron as whole [ph] in future consolidation, I would appreciate that as well? Thank you.

Sure. Those are both of your 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 largely -- are predominantly held through joint ventures. So whether it's GS Caltex or refinery in Thailand or 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 comparative. In the United States of course and our small plant in Canada those are 100% owned refineries. So the structure of the ownership isn’t necessarily the issue, it's 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’ll be looking to be sure that we can maintain the reliability but do it at a lower cost. Our refineries are competitive on the net cash margin, but we think that we can improve them – 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 we’ll improve our results regardless of what happens to margins. As far as the U.S. gas business goes certainly I’m aware that 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 the shales, and tide [ph] 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 a million acres in Poland. So we do have a presence in the shales. But frankly we've 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 haven’t 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, and we have – we are always screening the opportunities in the upstream business, it’s a resource business, and we are in the business of acquiring leases, individual assets and companies, and have demonstrated that we are 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. It’s a very full answer. Thank you.

Sure.

Our next question comes from Paul Cheng with Barclays Capital.

Thank you. Hi, John welcome back?

Thanks, Paul.

This maybe a little bit of the first I have two questions. One, I am just not sure on this, if I look at the industry I think there is debate [ph] among the investors talking about the big guys like you Exxon or BP or other companies, is this possible on a sustainable basis that to grow their resource and the production base organically? I don’t know whether you will be able to comment that whether you actually think the resource is not a 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 acquisition are unavoidable -- for the industry 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 risk and opportunity, I am wondering that, John, if you will be able to maybe that help us understand what is the major area of the potential upside and the potential downside risk? Thank you.

Thanks, Paul. I think I am going to answer yes to both parts of your first question, at least for Chevron. Ultimately, every has to continue to add resources to the queue going forward, and so overtime 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 ques [ph] that we have and we'll give you 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 [ph] going out over the course 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're 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 government 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 in those with those host governments going forward. That’s helped us recently in China and the PNG. So I think, my answer to your questions 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, that’s in guidance. The major area of potential upside or major area of potential risk we need to see for the downside or we need to monitor for the downside?

One of the challenging areas of us to forecast is in the base business area. For example, last year initially George gave guidance of about 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’ve sort of up that and put some decline in the numbers that we've 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 don’t 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’s great. John, can I just squeeze in one quick one for Pat? In terms of cost reduction, Pat, for the next two years what is the potential target that you guys may have and from what major area? Thank you.

Yeah Paul. We don’t have the same target that we are going to handout 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’s likely to be sustained or not, I’ll take you through each of those. Number one from a self-help standpoint, we said about a third of the reduction that we’ve 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’s an absolute must have to get our downstream cost structure to an affordable level. So highly focused there, we've 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 really 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 costs categories that we would suggest that cots increases are not likely, and I will just take you through the transportation sectors, for example. There is 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 the 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 part way 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 an even improve on our cost structure going forward.

Thank you, very much.

Our next question comes from Arjun Murti with Goldman Sachs.

Thank you. John, just a couple of upstream questions. I wondered if your small competitors has had some interesting success in California, a variety of different exploration place. You are obviously a large California producer, just wondering if you see kind of upside to California beyond this sort of EOR enhancements stuff you have been doing? Are there new concepts you are considering on your logic which position and then unrelatedly there has been some talking about Kazakhstan looking at tax terms and contract terms, so I am wondering if you could either confirm or deny that they are looking to potentially change their tax terms for your Tengiz contract? Thank you.

Arjun, that’s a interesting concept talking about what’s going on in Southern California; it doesn’t get a great deal of attention, I assume you’re talking about some of the work that going on around Elk Hills and we are a participant there. We do have about a 20% interest. So we are there. In general, the declines that we've seen in that business, obviously it's a mature business but the declines we’ve seen been limited and they have been limited because we've been pretty clever in how we apply steam that’s 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'll get George to give you a little bit further update when we get to March. In term 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 that our relationship in Kazakhstan has always been excellent, and we have a very strong contract there and have done a good job living up to that contract. In my recent visit and discussions with the President Nazarbayev, he was very pleased with the performance of Chevron and the 10 gees in particular, and then 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’s great. If I can ask, a quick follow-up on the balance sheet, you all will run essentially net debt free balance sheet, I think '04 it's been five or six years obviously has served you all well during the challenging economic time. Now that you’re CEO John, any change for 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 some different number better or worse. Thank you.

Well, Arjun, within a range we’re 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 in cash will 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 double AA credit ratings that we have out there. So I wouldn’t look for any change in terms of how we manage our balance sheet.

That’s great thank you very much.

Sure, thank you.

Our next question comes from Mark Gilman with Benchmark.

Folks good morning, I had a kind of 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 [ph] interest in Devon’s sale to Maersk. Secondly, I was hoping that you might be able to regarding Kazakhstan. John, give us an idea, given some of the uncertainties which were referenced in the prior question. Will you proceed with the expansion project that you’ve been evaluating in the environment as it stands currently? The more general question relates to L&G 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 kinds of changes in contracts you are seeing as it relates to either to duration, structure or price formulas.

Sure, Mark. Those are all good questions. On the first one, we have exercised our pre-emptive drive around St. Malo and not for Jack. And those that’s primarily around aligning our equity interest in those two opportunities, I won’t 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, launching some design concept et cetera. We do have more work to do on the commercial side and on the transportation side and that work is under way. But I would tell you I am 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 characteristic, the way I would describe, it’s obviously competitive information, but I would say number one, we are producing gases at prices that look a lot like oil. We’ve got high slopes on these contracts and we’ve 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 Northwest Shale and we think that these are among the strongest and best and sophisticated buyers of LNG. And we have signed them at good terms that underpins the project. So we haven’t seen -- there is speculation about the condition of the worldwide LNG market, but from our -- certainly our recent experiences it's been very good for those two projects.

Okay, John, thanks very much.

Okay, Mark.

Our next question comes from Jason Gammel with Macquarie.

Thank you. Maybe one more on the production profile, John, I appreciate your comments about growth through the end of the decade and clearly 2014 plus with Gorgon Wheatstone and perhaps more treasury, those have quite a bit visibility. How should we think about the interim period between 2010 to 2013 seemed to be more or less or flattish environment?

Yeah, Jason what I prefer to do and I'm going to punch just a little bit. We want to give you some guidance on 2010 and your observation about middle of the decade and Gorgon Wheatstone is accurate. What I would like to do is maybe differ until March where we'll give you a little longer, a little more complete look at both the interim period and we see coming project by project and in a lot more detail fashion rather than treat that today. So if you’re listening till March we'll be happy to give you more information.

Fair enough. Maybe one if I could then. Three more successes during the quarter and Australia obviously a great drilling environment there. Can you talk about the volume metric objective that -- what you're drilling in Australia right now on these TCF cost type structures and maybe give an update on the overall resources space that you believe you’re having a great bargain [ph] area at this point?

I will say yes, yes and no. We have announced some five discoveries this year in Australia, and I would say in an overall sense despite these discoveries have been a little bit smaller than some of the very large ones in the past, but they have a nice additions and will augment the supply that we have for both Gorgon and Wheatstone. And in fact what you'll 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 Wheatsome [ph] is a hub, which we’ll be starting at two trains and we’ll have the capacity to bring in actually several more trains over time. So these discoveries really do underpin some of that, some of that future growth. In terms of our aggregate gas resources we've talked in terms of 70 Tcf in the Asia Pacific region. So we have a lot of gas in that area. And we’ll give you a little more granular information on that in March.

Okay thank you, John.

Sure.

Our next question comes from Paul Sankey with Deutsche Bank.

Hi John, welcome back, John.

Thanks Paul.

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 haven’t baked in? I am trying to get to what the range of outcomes could be there, particularly with due to OPEC in Nigeria?

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 can bind all of them together.

Well, I mean, those are all very circumstantial elements, and I’d hate to, I’ll let you make your own forecast going forward about each and every one of those, frankly. That’s why said we didn’t put it in.

Predicting production plus or minus 1 or 2% as my upstream friends [ph] tell me as it's a very tough business given all the factors out there, but there is a range around to be sure, Paul.

Got you. And then if we just look at Q1 of ‘10 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?

Nothing.

Okay. Nigeria. Related question, could you just update us on your best [ph] customer of what’s happening in Ecuador and any headline risks around that? Thank you.

Sure. Well, Paul, as you know, we have made very significant disclosures and I know you’ve read the material that we have online. I guess what I would tell you is that the Court in Ecuador appears to be headed toward a verdict; I am not going to predict that but based on the pattern in the courts there and 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.

Yeah, I was really thinking if I look back a year now we were looking for, I think, way back for adjustments around October of last year. Do you have any sense when this might finalize?

Well, I think people are looking for a verdict around that time and then that little problem with the judge, as its may recall, was shown to not be impartial and we’ve captured on video and he had to be replaced and so there is a new judge there and I am not going to predict when he might produce a verdict and what that verdict might be.

Fair enough, John. I will leave at that. Thank you.

Okay. Thank you.

Our next question comes from Pavel Molchanov with Raymond James.

Hi, thanks for taking my question. First on your CapEx, can you give us a sense of the CapEx curve for Gorgon, just for example how you might spend there in 2010?

I mean Gorgon and Wheatstone spending for 2010 will be about $3.5 billion. And so it’s a sizable chunk of our capital spending both in 2010 and through to middle of the decade.

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

Yeah, the number that we have given for Gorgon for the 100% project amount has been $37 billion US, and that’s still the number. Interestingly enough we have placed a considerable number of contracts against that and so far it seem to be right on track. Of course now we can change a little bit as currencies move over time, but that project we are very pleased with. We had an outsiders in outside agency that looks at major capital projects and they've indicated that they feel that Gorgon is the best prepared mega project they ever seen. And so we are very encouraged and where that heading but we're gong to be very vigilant on that project. We of course have to get it right with that level spend.

Yeah, that’s 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 haven’t been here. I mean, we're heavily oversupplied 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 its – I don’t think imports are finding a welcome home here.

Thanks, that’s helpful thanks guys.

Okay I think we’ve got one more question.

Our final question comes from Paul Cheng with Barclays Capital.

Hey thanks for taking the follow-up. John, every management they have somewhat of a different philosophy, and I know you work closely with O'Reilly before. But from your standpoint is there any major change in how do the top 100 management they are performing and compensation is being review or being calculated or what is the most important driver under your administration? Thank you.

Well, in terms of compensation in 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've had a long standing instead of compensation practices that I think provide the right types of incentive and motivation. My priorities 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 serviced 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's not factory stuff, it's very direct things around capital stewardship, our continual reliability effort, systematic looks at cost. So that’s certainly number one. I would tell you that I’ve talked internally a lot about people in the organization. We have a great deal of debt, the industry is going through a crude 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 charge. And then the third thing that I have talked about with our employees is growth going forward, execution, of course, is part of delivering that growth in the near term. But maintaining our edge on key technologies is something that I will 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. Paul?

Okay, thank you.

And I think with that -- that concludes our remarks. I would like to thank all 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 look forward to see 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.