Good morning. My name is Sean and I will be your conference facilitator today. Welcome to Chevron's second quarter 2009 earnings conference call. (Operator Instructions) I will now turn the conference over to the Vice President and Chief Financial Officer of Chevron Corporation, Ms. Pat Yarrington. Please go ahead. Patricia E. Yarrington: Thanks, Sean. Welcome to Chevron's second quarter earnings call and webcast. On the call with me today are George Kirkland, Executive Vice President Global Upstream and Gas; and Jim Aleveras, General Manager of Investor Relations. Our focus today is on Chevron's financial and operating results for the second quarter of 2009 and we will refer to the slides that are available on Chevron's 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 2. Slide 3 provides an overview of our financial performance. The company’s second quarter earnings were $1.7 billion, or $0.87 per diluted share. Our second quarter 2009 results were down 71% from the second quarter 2008. Second quarter 2009 earnings fell 5% compared to the first quarter of 2009, which Jim will discuss shortly. Return on capital employed for the trailing 12 months was 17%. The debt ratio was 12% at the end of the quarter. While debt balances were relatively flat during the second quarter, cash balances ended the period approximately $2 billion lower than the prior quarter. The cash change reflects working capital effects unique to the second quarter. For example, nearly half of the cash consumption in the second quarter pertains to a full-year 2008 foreign tax obligation that was accrued last year but was paid in May 2009. The amount is particularly distortive because it was based on the much higher earnings level of last year. And finally, as we announced on Wednesday, Chevron's Board of Directors approved a $0.03 per share, or 4.6% increase in the common stock dividend payable on September 10, 2009. Jim will now take us through the quarterly comparisons. Jim.

Thanks, Pat. My remarks compare results of the second quarter 2009 with the first quarter 2009. As a reminder, our earnings release compared second quarter 2009 with the same quarter a year ago. Turning to slide 4, second quarter earnings were down $92 million in the first quarter. Starting with the left side of the chart, higher crude oil realizations increased the company’s worldwide upstream earnings. However, upstream results were adversely affected by a foreign currency variance of about $500 million between quarters. Second quarter downstream results were sharply lower than the first quarter. This decline reflects lower margins in the second quarter, along with lower gains on asset sales. The second quarter included a $140 million benefit from asset sales compared to the $400 million gain recorded in the first quarter. The other bar largely reflects improved chemical earnings and a favorable swing in corporate tax items. On slide 5, our U.S. upstream results for the second quarter were about $250 million higher than the first quarter’s results. Combined crude oil and natural gas utilizations benefited earnings by $310 million. Chevron's average U.S. crude oil realizations increased about $16.35 per barrel between consecutive quarters, almost the same change as average spot prices of West Texas Intermediate. Natural gas realizations, however, fell between consecutive quarters, offsetting about $75 million of the benefit of higher crude oil prices. Production volumes increased more than 4% between quarters. The start-up of Tahiti, the ramp-up of Blind Faith, and continued hurricane restoration efforts in the Gulf of Mexico more than overcame natural fuel declines. The other bar includes the benefit of lower operating expenses but these were more than offset by impairments of several small fields which flowed through DD&A and some other items. Slide 6 summarizes the result for our international upstream operations, which were essentially unchanged between quarters. On a combined basis, liquids and natural gas realizations improved earnings by $625 million. Our unit realizations for liquids improved by 35% compared with a 33% increase in brent spot prices. Natural gas realizations, however, were lower in the second quarter, offsetting about $100 million of the benefit of higher liquids realizations. Exploration expense increased $90 million between quarters, reflecting well write-offs spread among a number of countries. The FX and other bar shown largely reflects a swing of more than $500 million in foreign currency affects between quarters. Slide 7 summarizes the change in worldwide oil equivalent production, including volumes produced from oil sands in Canada. Production increased slightly between quarters. Higher prices reduced volumes under production sharing contracts and variable royalty provisions by 24,000 barrels per day. Based on the $16.50 change in average West Texas Intermediate prices between the first and second quarters, this translates into a roughly 1,500 barrel per day impact, compared to the rule of thumb we provided six months ago of 1,200 barrels per day for each dollar WTI price change. In the interim, we have looked at all of our production sharing agreements and variable royalties and this study reemphasizes our earlier caveats, that the effects are non-linear and any rule of thumb is very rough. Given the volatility in crude prices, no single rule of thumb is appropriate as forward guidance. Therefore, we will continue to quantify our price and volume effects for you each quarter. Moving on to the next bar on slide seven, the decline of 44,000 barrels per day shown under the caption base business and external constraints, includes a number of items. First, the total base business decline was 58,000 barrels per day but over 40,000 barrels per day of this amount was due to planned turnaround activity in Kazakhstan, Canada, and other countries. The same bar also reflects a 20,00 barrel per day benefit of Hurricane restoration, partly offset by a 14,000 barrel per day change in Nigerian production due to local disruptions. External constraints, such as OPEC, [inaudible] whose government limitations, and Asian gas market factors were slightly less limiting than in the first quarter. This change was minimal, about 8,000 barrels per day. As shown in the next bar, increased production from our new major capital projects benefited second quarter production by 75,000 barrels per day, primarily reflecting Agbami, Tahiti, and Blind Faith. George Kirkland will provide a more detailed discussion of our major projects in production in a few minutes. Turning to slide 8, U.S. downstream earnings declined about $230 million in the second quarter. The overall impact of refining and marketing indicator margins was an adverse $75 million. The average change in our total margins between quarters was $130 million in addition to the $75 million amount reflected by the indicator margins. The major factor was refining mix effects due to a decrease in distillate refining margins, a decrease in light heavy crude spreads, and other factors such as higher refinery feedstock costs. As these impacts were not fully captured by the indicator margins, our realized refining margins were more unfavorable than suggested by the indicators. Additionally, lubricant base oil margins were lower due to weakness in the industrial and commercial transportation markets. Higher sales volumes increased second quarter earnings by $75 million. This improvement is about the same amount as the adverse volume variance we showed in the prior quarter. We completed the planned turnaround maintenance at our El Sigundo California refinery that I mentioned last quarter and this accounts for the difference. The other bar reflects timing effects and a number of minor variances, including higher fuel costs due to higher prices. Timing effects represent about half of this variance between periods. WTI prices rose about $20 per barrel from the beginning to the end of the second quarter compared to a $5 per barrel increase during the first quarter. The changes we’ve discussed before, including phasing out provisional pricing for our major supply contracts, have reduced the volatility of our U.S. downstream earnings to changes in commodity prices. However, we will continue to experience timing effects related to market factors, such as lag pricing terms for aviation fuel, along with inventory and supply effects. Turning to slide 9, our international downstream earnings fell about $435 million from the first quarter’s results. On balance, refining and marketing margins reduced earnings by $55 million between quarters. Both refining and marketing margins were lower in Asia, our largest international region. Timing effects represent a $90 million adverse variance between quarters. On an absolute basis, timing effects reduced first quarter earnings by about $140 million, while the second quarter effect was about $230 million. The largest single component of the $90 million quarterly change was a $60 million impact of lagged aviation pricing terms. During the second quarter, we closed the previously announced sales of our fuel marketing operations in Cameroon and Kenya. However, the gain of $140 million was $260 million less than the amount recognized in the first quarter for the sales of marketing businesses in Nigeria and Brazil. Various items, including lower trading profits, partly offset by lower foreign currency losses, made up the majority of the $29 million variance shown in the other bar. Operating expense, which dropped substantially in the first quarter, and stopped slightly in the second quarter, partly on higher fuel costs. Slide 10 shows that earnings from chemical operations were $108 million in the second quarter, compared with $39 million in the first quarter. Results for oliphants, aromatics, and [oranite] additives all reflected higher margins. Oliphants and [oranite] additives also benefited from higher volume. Slide 11 covers all other. Second quarter net charges were $43 million, compared to $294 million in the first quarter. All other charges were below our typical guidance range of $250 million to $350 million. This reflects favorable corporate tax items, a swing from foreign currency losses to gains, and lower corporate and service company net charges. Before turning the call over to George Kirkland, I would just like to briefly recap the second quarter. First, upstream earnings benefited from higher crude oil prices but these were largely offset by substantial adverse foreign currency effects, in line with the interim update. Downstream results reflected weak margins, adverse timing effects due to the increase in commodity prices, and lower asset sales gains, also mentioned in the interim update. As we projected, all other net charges were below the guidance range. Finally, and most importantly, our operational results were strong, upstream production to refinery utilization. George Kirkland is now going to provide an update on our production outlook for 2009 and further discuss our upstream projects. George. George L. Kirkland: Thank you, Jim. It’s good to be back to discuss upstream performance and our outlook for the remainder of the year. I am very pleased with our progress through the first half of 2009, particularly in the areas of project execution, production, and cost management. And I am going to address each of these areas. Let’s now move to slide 13. Production performance from our major capital projects in the first half of this year has been strong. 2009 production growth from these projects will likely exceed the 300,000 barrel a day forecast we provided at the fourth quarter earnings call, and shows both the strength of our major capital project queue and our ability to execute. The bulk of the production increases come from four major capital projects. Tahiti achieved first oil on May 5th and reached peak production within three months. That was six months ahead of schedule. Current production is at full capacity of 135,000 barrels of oil equivalent per day. The ramp-up of Agbami has reached 220,000 barrels of oil a day and is ahead of our schedule to reach peak production of 250,000 barrels of oil per day. SGI/SGP at Kazakhstan is performing above the nameplate capacity of 240,000 barrels a day. De-bottlenecking activities are currently underway that should allow for higher oil production by year-end. And finally, blind faith reached peak production of 70,000 barrels of oil equivalent a day in late March. Due to the performance of these major capital projects, combined with lower OPEC and market constraints, and lower base business declines, which averaged about 6%, we now expect the full-year outlook for 2009 to be about 2.66 million barrels a day, an increase of 30,000 barrels a day from our previous guidance. This translates to a 5% increase over 2008 levels of 2.53 million barrels a day and includes both the impact of security related disruptions in Nigeria that have caused -- excuse me, includes both the security related disruptions in Nigeria that have caused significant shut-ins. This revised outlook is based on an average oil price of $50 per barrel, and of course changes in price will impact this outlook. Other progress to be noted in the first half of 2009 is as follows -- Frade achieved first oil on June 20th. This is Chevron's first operated asset in Brazil. We expect Frade to reach peak production of 90,000 barrels a day in 2001 [sic] as additional development wells are drilled. And Mafumeira Norte in Angola block zero achieved first oil in July, once again ahead of schedule. Production is currently ramping up and forecasted to reach a peak production of 35,000 barrels of oil equivalent a day in 2011, as additional development wells come online. Turning now to slide 14, I would like to discuss some of the other significant achievements that occurred during the first half of 2009. Yesterday we announced that Wheatstone and Wheatstone L&G project in Australia entered feed as a two-train development. This significant milestone demonstrates our progress towards sanction. It follows the announcement in February of a successful seven-well exploration and appraisal program that underpins the two-train development. Also in Australia, we received a conditional recommendation from the Western Australian Environmental Protection Authority on the expanded Gorgon project. This is excellent news and we are on schedule to sanction the project later this year. In Nigeria, we remain on schedule to sanction stage two of the Agbami field. Stage two development wells will extend the peak production plateau of 250,000 barrels of oil a day. In the partition neutral zone between Saudi Arabia and Kuwait, steam injection the large scale steam flood pilot began in late June, with pilot success a full field development of the [WAFRA EOCENE] reservoir will follow. This field contains over 12 billion barrels of oil in place and would be the first commercial application of a conventional steam flood in a carbonate reservoir. In Angola, we now forecast Tombua-Landana start-up during the third quarter of 2009. Hook-up and commissioning is about 90% complete. It is expected that three wells will be available at first oil. Tombua-Landana is projected to reach 100,000 barrels a day by 2011 with development drilling. And finally, in Indonesia, the start-up of the non-operated South [Natuna] Sea North Belut field remains on schedule for the third quarter of 2009. Let’s now take a look at slide 15. I would like to talk about our upstream cost structure, which includes production expense, DD&A, and other expenses. This chart shows the competitiveness of our cost structure and has been updated since our securities and analysts meeting in March. For 2008, we had industry-leading up-stream costs for $20.05 per barrel. During the first half of 2009, this has improved to $19.87 a barrel. Lower production expenses and higher DD&A charges almost offset each other. On a unit of production basis, DD&A charges increased by $2.22 per barrel during the first half of 2009, compared to full-year 2008. This was principally driven by the investments associated with new project start-ups at Agbami, Blind Faith, Tahiti, and [Moho Belondo]. Although the DD&A associated with these new project start-ups is high, this is to be expected and is a function of how crude developed reserves are booked over time. Let me offer an example -- take a deepwater project like Blind Faith. DD&A rates at start-up are calculated based on the project investment but only a small portion of the resources booked as crude reserves under SEC guidelines. However, as additional crude reserves are booked and the capital depreciated, the associated DD&A rate will significantly drop over subsequent years. Early in the project’s life, earnings may be impacted due to the higher DD&A but cash margins are generally at their highest levels. And remember, we base our investment decisions on cash flow. Now let’s turn to production expense, because DD&A is only part of the story. In the upstream through the first half of 2009, production expenses were $2.52 per barrel, less than full-year 2008. This is a function of lower operating expenses and taxes other than on income. This reduction has more than offset the increase in DD&A. I am pleased with our progress on managing our production costs and this will remain a key focus for us. Pat will provide further insights on Chevron's cost management activities and with that, I would like to turn it over to Pat. Patricia E. Yarrington: Thanks, George. Slide 16 provides a progress report on our aggressive company wide efforts to reduce cash costs of running the business. We’ve targeted a $2.5 billion reduction in operating, selling, general and administrative expenses in 2009 compared to 2008. The target excludes the benefit associated with lower costs of purchase fuel. All areas of the company are working to reduce costs -- upstream, downstream, corporate departments, and our internal service and technology organizations. And at mid-year, we were ahead of pace to meet the full-year objectives. Some key areas of focus in our push for cost reduction are listed on the slide -- materials and supplies, transportation expenses, and contract labor and third-party services. Our recent downstream asset sales, notably in Brazil and several West African countries, removed costs relative to the prior periods and this was anticipated in our target. On the upstream side, particularly in North America, we have reduced activity related to well work-overs and are contracting fewer rigs at lower rates. This makes good business sense given the economics of these activities, in particular in relation to natural gas prices. As a note of caution, please keep in mind that the operating expenses will not be perfectly ratable throughout the year due to seasonal and other effects, such as turnaround activities. Nevertheless, we are very pleased with our progress. I would like to wrap up our prepared remarks with a recap of Chevron's operational performance through the first half of the year. This is slide 17. As George discussed, our up-stream production remains on track for a good year-over-year increase with our major capital projects performing on plan or better. Our year-to-date refinery crude utilization remains a strong 93% of capacity. We’ve had no significant unplanned shut-downs and the [thoman] utilization rate for our operated refineries is right at plan level. George described our up-stream project execution, which is on track. And Jim mentioned that our downstream portfolio upgrading continued last quarter and we expect further progress on this initiative in the quarters ahead. As I just outlined, our cost management efforts are progressing quite well. And finally, we are maintaining our strategic focus on the factors that will ensure growth and superior returns to our stockholders in the years ahead. In addition to funding the long-term growth components of our capital program, we are continuing our strategic staffing initiatives to ensure that we have the future technical expertise in Chevron to remain a top performer. That concludes our prepared remarks. We’d now like to welcome your questions. Please try to limit your follow-up questions so that everybody has an opportunity to participate. So Sean, please open the lines now for questions. Thank you.

(Operator Instructions) Our first question comes from Paul Sankey with Deutsche Bank.

Good morning, everyone. You mentioned the $500 million variance in the forex, which seems and correct me if I’m wrong but it does seem to be somewhat bigger than your rivals. I think [inaudible] yesterday was less than -- well less than $600 million, obviously off a bigger base. Could you just help us understand how much of that is, if you like, an accounting effect and how much is an operational effect? Thanks. Patricia E. Yarrington: Paul, these are balance sheet translations and it reflects where we have -- where we do our business and the relationship of the currencies from period to period. So a lot of this occurred in Australian dollars, Canadian dollars, the Pound, et cetera and we had currency appreciations there, local currency appreciations versus the dollar between 8% and 16% in the quarter.

Okay, so essentially the entirety of it is a balance sheet item? Patricia E. Yarrington: Yes, it’s a book item.

Okay, and conceptually, if the dollar -- I don’t want to be too negative here but if the dollar continued weakening forever, would you just continue to -- is there a limit to how much this can be or can it just keep going on forever?

Paul, it would fluctuate based on our relationship between liabilities and assets. Patricia E. Yarrington: Right.

Depending on whether they are a net liability position or a net asset position, we can see a larger, smaller, or no effect from strengthening or weakening of the dollar. Patricia E. Yarrington: Yes, of your monetary assets.

Monetary assets.

Okay, I’ve got the general idea so maybe we’ll follow-up. If I can have an upstream one as well, please, and what -- you had several different moving parts in -- where it included your base business decline. Could you, to make it simple, just strip out what you think your base business decline was for the quarter? And then I have just a follow-up on up-stream and I’ll leave it. Thanks. George L. Kirkland: Paul, let me try to do it in the context -- we try to give a view of where we think base business is going to be for the year. Through the first half of the year, it has been significantly below our 7% guidance. It’s been more in the 5% range, 4% to 5% range as best we can track it. Once again you have to take a lot of ins and outs with turnarounds and everything else and security and everything else going on. Our present forecast for the full year is we were going to average about 6%. Now, if you go back to our analyst meeting in the first quarter, or the January call, we said at that point that we were basing our outlook for the year based on a 7% base business decline and at this point, we see that decline as going to be less than we had earlier forecasted, by 1% at least.

And any idea for next year, George? Would that go faster again, or -- George L. Kirkland: Paul, I really hate to talk about next year until we get our capital program put in place.

If it was the same capital program as this year? George L. Kirkland: It would probably be more in line with the 7% because we reduced our base business capital significantly and that’s driven heavily in the United States around our investments in the gas side of the business. Just to give you a little more color to that, I expect by the end of the year, we will not have a single gas land rig running. We are redeploying our efforts to where we can within our ability to move equipment around and contracts around to really focus on oil in the United States. Gas prices, it doesn’t make sense for us right now to be drilling those gas well.

So the [inaudible] of the incremental decline would be basically U.S. gas? George L. Kirkland: I think it’s going to be heavily U.S. gas. We’ll be able to tell you a lot more after we get through our business plans so first quarter call, I guess January call next year and analyst meeting, we’ll be able to give you a lot more color on that.

Great, that’s very helpful. Thank you.

Your next question comes from Paul Cheng with Barclays Capital.

First, Jim, I want to say thank you for all the help over the past couple of years and wish you a happy retirement.

Well, thank you very much, Paul.

We will miss you. I think I have two questions -- one, Pat, you talked about the cost savings is now ahead of pacing at mid-year. How much of the benefit so far that you’ve seen is related to FX, and how much is really just coming from the [vendor] or raw material costs coming down? Patricia E. Yarrington: Good question, Paul. Really from an FX standpoint, it’s a factor but it’s not a significant factor. And I guess the second component you were asking about is sort of the energy related drivers?

And also all the other raw material costs and everything. Patricia E. Yarrington: Well, it’s -- clearly it’s a factor in there. We haven’t segregated it out on a raw materials component factor uniquely or discretely. We have cost reductions, I think as I mentioned on the call last time, that depending upon the commodity or the product category, you can get price reductions here or cost reductions here that have ranged from 60%, the more commoditized the service or equipment is, to 10% or 20%, the less commoditized it is.

Maybe I have missed it -- Pat, have you said an exact number that how much you think that your cost-saving is at this point? Patricia E. Yarrington: We said that we -- you mean on a year-to-date basis?

Yes. Patricia E. Yarrington: Yeah, we are down more than the 10%. We said we are ahead of pace. The 10% is our target for the year. We said we are more than 10%. We noted in the press release on a quarter-to-quarter, second quarter this year to second quarter last year, that on a recurring basis we were down 15%. We did have some non-recurring items in the second quarter of last year that we didn’t have in the second quarter of this year. They were not repeated, so timing effects like this can occur but they typically even out over the year. So I just encourage you to look at the 10% target and to know that so far we are ahead of pace.

So so far, you are about $1.8 billion, $1.9 billion? Patricia E. Yarrington: Well, you’ll see it when we put out the 10-Q, and just know that there some non-recurring elements in there.

Okay. If I could have one quick upstream, George, in Iraq, when you are looking at the opportunity set and the risks associated and the kind of terms that they offered in the first round, if that maintains, is that really a pace that you guys will be very keen on to invest? Also, if you look at the security situation on the ground, has it improved sufficiently for you to feel comfortable to put your people on the ground at this moment? George L. Kirkland: Paul, I think you can tell that -- or maybe not. We didn’t really submit a bid on the first round in Iraq. We could not see a conforming bid at that point work for us on an economic basis. We like Iraq when you think about the resource side, phenomenal resource. We look at it, we would like to be there but we need to have confidence both in the economic viability of the investments and the security side. So you’ve got to look at both elements of that and we weren’t able to see that in this first round. And the way the first round has ended up, really not -- really the bid did not prove to be that successful.

In the first one, you didn’t put a bid -- is it more of an economic concern or is there a security concern from your standpoint? George L. Kirkland: I would say at this point it was more an economic concern.

Okay. Thank you.

Your next question comes from Evan Calio with Morgan Stanley.

Good afternoon. Thank you for taking my call and also, congratulations, Jim, on your retirement. I have just a quick question on Gorgon. I listened to your comments on the conditional improvement. Could you walk me through, walk us through exact details on the path to FID for Gorgon? George L. Kirkland: I will give you some of the color. There’s a whole lot of things that must happen. First, most critical item is of course getting our EPA approval. We need to get our environmental permit to build Gorgon on Barrel Island. That’s critical step one. Of course, we have to have all our partners between now and that period have their own internal approvals. We need from the government all the leases ratified, I guess I think would be the best word. So we’ve got to put in a -- our development plans for production. They have to be approved. But I think the most critical items is one, the environmental permit -- nothing can happen until we get the environmental permit. And then second is of course all the partners in Gorgon to give their financial approval to move forward. Those are the two critical steps. There are a lot of other little steps that go with it. We think we are very, very close on the environmental permit and we’ve done all our due diligence and all the project due diligence I think to be ready on the decision-making around the economics.

Excellent. Do you -- another question on the up-stream -- are there any hurricane volumes that remain shut in or any color on timing of bringing back those volumes on-stream? George L. Kirkland: I think we are at about 87% of our volumes that were impacted. We will bring another 5% to 8% on. We’ve always been telling everyone that we didn’t see maybe as much as 5% that would ever be restored and I think most of this remainder will be on by the end of the year.

Okay, great. Just one other follow-up on the decline issue, if I understand, and I know it’s CapEx related -- your 7% decline versus the lower 4% at prior CapEx level, you know, is really U.S. gas-driven event. George L. Kirkland: Predominantly.

Is that fair? George L. Kirkland: It’s a predominantly -- we’ve cut down all base business. We’ve got some issues around the world too where we have base business that could be impacted by OPEC constraints that we would look at very similarly to what we are looking at U.S. gas.

Okay. George L. Kirkland: I mean, it doesn’t make sense to spend the money and build capacity where we are not going to be able to produce it.

Sure, but I mean also, you get a higher decline base meaning that that 7% could taper lower over time, if you -- there’s a lot of variables in that, the math, but is that the -- kind of the correct thinking? George L. Kirkland: Well, the big thing that is going to happen over time is more and more of these large projects come on, they do not see the decline in the early periods. Many of them have multi-year, five years some of them, and some of them longer, flat lives. You look at a -- like TCO, [Tengeze], and the investment we’ve made in SGI/SGP, that second generation plant there, that is almost a flat line. It is not a function at all of the reservoir. It’s only a function of the plant capacity and the plant capacity doesn’t go down. It stays up, so you have to look at each one of them but more and more as we get more and more of these large new assets on, that base of production has very, very low to no decline rate, so it will change over time. And we’ll have to give you updates on that at least a couple of times a year on what we are seeing happening.

Excellent. Thank you for taking my question.

Your next question comes from Arjun Murti with Goldman Sachs.

Thank you. Thanks for the color on the DD&A rate. Were there any charges or other things that ran through DD&A in the first half, if I take that 220 a barrel you mentioned, there still seems to be a little bit of a gap. I was just wondering if the $3.1 billion rate in 2Q is sort of a run-rate going forward.

Arjun, that’s a good question. If you look at the information in our press release, you can see that our six-month 2008 DD&A was about $4.5 billion versus almost $6 billion for six months of 2009. The major capital projects account for about 55% of that but then there’s a lot of other things that I mentioned last quarter that do impact DD&A, things such as impairments that run through that, accretion expense. So there’s a lot of different items, as well as base business, that impact DD&A in addition to our major capital projects but I do want to say the major capital projects were the largest single item and accounted for more than half of the increase. But if you look at overall DD&A, the increase is all in the up-stream segment?

That’s great. That’s very helpful. And just a final one -- any update on how you are thinking about stock buy-back at this point? Patricia E. Yarrington: Arjun, as we’ve expressed several times here, the stock buy-back piece is really the most discretionary component of our uses of cash and the priorities are for the dividends, which you saw the board increased, funding the capital program, and keeping a good balance sheet. And for the moment, that’s where our priorities are and I don’t -- we’re not reinstating the share repurchase program at this time.

You guys clearly have an exceptionally strong balance sheet and I’m not a die-hard stock buy-back person but maybe in this challenging economic environment, you just want to keep an even stronger balance sheet than even is normally considered strong? Patricia E. Yarrington: Well, I think we just -- you know, we have a lot of organic opportunities here and maintaining flexibility, financial flexibility is important to us.

That’s great. Thank you.

Your next question comes from Neil McMahon with Sanford Bernstein.

Hopefully you can hear me, the line is not great -- maybe a few for George. I didn’t pick up when Tahiti was going to hit peak production, if it hadn’t done so already. And also on that, being of the upstream, just wondering when you were going to start to think about drilling in the sub salt in the [campus] basin around Frade, if there was an opportunity to do that going into 2010. And then I’ve got a final follow-up. George L. Kirkland: Well, Tahiti, I tried to make that in the early comments, we have reached peak production, the facility is really designed for about 135,000 barrel equivalent per day. We’ve reached that already. We ramped up all the wells very, very quickly to that, so it’s going very positive. Like all cases, we’re always looking to see if we can get a little more efficiency out of our facilities but we will reach the nameplate capacity and like I say, very, very quickly. Frade, I think it’s too early for us to start thinking about the sub-salt there. We don’t have a lot of opportunities for us in the basin at this point. We have some but it’s -- we are limited with our lease holdings there so we are going to have to look to the future and future opportunities in Brazil.

Okay, and then just a very general question again for yourself -- a number of your competitors this week have come out with statements that have suggested that one company’s got the best set of assets in the industry and another one has -- is the industry leader in terms of its options set and the upstream going forward. Just wondering how you would classify your upstream position, given the fact that obviously you are, based on your competitors, you are at least third in the rankings for some reason. George L. Kirkland: There’s been a lot of good work done by analysts and consultants out there and I think almost consistently they have always said Chevron has if not the best, one of the very best queues of project in the industry. I think you can look back at the number of projects that we brought online in 8 and 9 and what we are bringing on in 10 and see the steps we also are taking going forward with Gorgon and Wheatstone and the quality of those assets, the next generation facility that we will bring to [Tengeze]. We’ve got a 400,000 barrel a day expansion that we can do there, and our position in the deepwater Gulf of Mexico and the lower tertiary, the first one of those projects come on in Perdito early next year. We just moved Jack St. Mallow into feed. We announced the discovery of Buckskin earlier this year. We’ve got a great queue of projects there so these -- and all of the projects I have just mentioned have very, very attractive development costs. So I am not aware of any other company that’s got a better queue of projects.

Maybe we need to look into it a bit more but thanks for those comments.

Your next question comes from Doug Leggate with Howard Weil Inc.

Good morning, folks. Jim, you are going to be missed -- the changes you’ve made over the years have been really appreciated and I will miss working with you.

Thank you very much, Doug.

A couple of questions -- I am going to take advantage of George being there, if that’s okay. The color on the cost is much appreciated, particularly on depreciation, given the substantial changes we’ve seen. However, George, is it possible to just give a general kind of overview as to the new projects that are driving the growth, how do the underlying F&D and [by read-through] the future DD&A compare to the base business to try and strip away the timing effects? I’m just trying to understand when we can expect to see some incremental reduction again, or a reversal of this increase that we’ve seen in fairly substantial depreciation? That’s my first one. I’ll have a quick follow-up. George L. Kirkland: I think it does vary between projects and the type of projects. I would tell you the deepwater projects are the ones that typically see the highest DD&A rates at the beginning. I will tell you they ramp down pretty quickly. The first year with the barrels that have been booked have extremely high DD&A rates. We tend to, during the start-up period, every six months look at reserves and look at reserve bookings, so we often actually make mid-year updates on the reserve picture on these new projects. My expectation in most cases by the third year, we will have seen a significant drop in the DD&A rates. We see it move pretty quickly as we book these additional barrels. So normally I would say within two booking cycles, we’d probably have those down and I would tell you at that point in time, they will be very attractive on a DD&A basis. But the other side of it, and I think what’s really important to recognize, is these projects tend to have the lowest OpEx, operating expense of any barrels we have in the system, and that’s typical for new projects. You don’t make water. Chemical costs typically are low. You have a lot of barrels per person, in effect, so it’s a really good time and you really need to -- what we really look at, of course, is the margin and the cash margin, which is very, very good in those -- on those projects. Does that help a little bit?

It does. George, if I could push you just a little more on that particular issue, would you characterize the profitability, let’s say -- call it unit margin on an all-in cost basis, that is when fuel reserve [inaudible] are in place, as being incrementally better than the base portfolio? In other words, is your capture rate going to start to improve as you deliver these obviously very substantial [inaudible] visibility over the next year or two, in your opinion? George L. Kirkland: I would think on average it will improve. I think those barrels are better barrels in total on a margin context. But it does -- for us to see it flow on the book side, on the earnings side, it’s going to take us probably in some of the projects, the second or third year to really see that. And once again, it varies greatly between projects. You get a project that’s like [Tengeze], you don’t see the big impact of it because you really have characterized the reservoir and the reserves are a lot more straightforward in the booking. For most of our deepwater projects, the actual performance, the well performance is needed to book additional barrels and that’s why the first couple of years are so important.

Great. My follow-up was actually related to Wheatstone -- the two or three in development going to feed as you mentioned in your remarks, can you just give us some color as to whether you are going to bring in partners to supply the feed gas for those two developments, or is this a 100% Chevron or -- where are we in the process of securing the gas? George L. Kirkland: Well, I think it starts with we have with our expiration and appraisal work, we know we have enough gas with Wheatstone and Iago to under-write a two-train, two 4.3 million ton per annum trains -- so that’s 8.6 tons per year of LNG that can be covered by the Wheatstone and Iago projects. We would like, and like in all LNG projects, we would like to have a much bigger footprint, more trains. We’ve got other expiration opportunities in Australia, so we’d like to be able to bake a bigger footprint, i.e. more trains. So we are very interested in moving forward with others to open up a bigger opportunity set for the Wheatstone project, or the Wheatstone LNG. So it’s both but I think what’s really important is we’ve got enough gas to get to the two trains ourselves and -- and we’d like to get bigger, because there’s always the -- the money to be made in LNG is all in getting more and more trains and more and more gas through it.

I guess where I am going with this, George, is would you expect to fund both trains 100% Chevron and any incremental trains would involve partners? Is that a fair way of thinking about it or is it not as straightforward? George L. Kirkland: I don’t believe it’s that straightforward and it’s in the early stages. Once again, we’ve got enough gas to under-write it. What happens commercially between now and the next 24 months could shape what we end up with there. I hate to leave it open-ended but it is a little bit open-ended on that piece.

No, that’s great color. Thanks very much indeed.

Your next question comes from Michael LaMotte with J.P. Morgan.

George, if I could ask on Nigeria quickly -- can you give us an update on your perspective on the state of clay there with respect to the physical changes? And really where I am going with the question is thinking longer term how you think about allocating capital in light of the risks of change in fiscal terms. George L. Kirkland: Well, capital allocation everywhere is a function of the economic returns that we will receive. If fiscal terms, either future or retroactively changes to contracts which once again, like everyone we really want to see contract sanctity. But if you look at the go-forward case, if the economic and fiscal terms change, the capital will flow somewhere else. We are not short of capital investment opportunities and the challenge is always making sure we put our capital to those best opportunities and we try to be very, very rigorous in doing that and if the terms in one country in the world become inferior, you can bet that the capital will flow to another opportunity somewhere else in the world.

Is that true in terms of the incremental CapEx on the same project that’s in queue but hasn’t gone to feed or FID? As well as any expenses you would have on the maintenance or operating side? George L. Kirkland: You are getting to a detail level where the economics are really pretty difficult to tell, so you are starting to get into those ones where there’s some grey in there and it depends on the impact, the amount of investment, and the amount of risk.

And we just don’t know enough yet on any of that yet? George L. Kirkland: That’s correct.

Okay. If I could shift gears quickly, just a couple of clean-ups on the numbers -- 40,000 in maintenance in Q2, is all that back up? Any maintenance plans for the third quarter?

The 40,000 barrels a day of maintenance is partly back up, not fully back up and I do not have our next quarter’s plans yet. George L. Kirkland: I can just give a little bit of color on it -- the second and third quarter for us are always the heaviest hike, the heaviest turnaround quarters. That’s when you have typically the best weather, so we do have some turnarounds in the U.K. sector, I know, and I do believe we have some additional work that might fall in [Tengeze] later this year, so there is some more work to come but I think we’ve got a lot of the big stuff done.

Okay, and then lastly on the SGI de-bottlenecking, where is that going to go from the 240 nameplate? George L. Kirkland: I think our opportunity is in the 10% to 15% increase and maybe even 20%, so we’re pretty confident of 10% to 15% and we may get as high as a 20% bump on that. What we are doing there is the sulfur plant is really what controls the amount of crude that we can put through. We can’t change or increase the sulfur plant capacity so what we have really been able to do is we’ve got a little bit more capacity on the front end of the plant, on separation, and the ability to inject higher H2S gas into the reservoir. And that flexibility is how we are able to get this higher rate.

Interesting. All right, thanks. That does it for me.

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

Does your conservatism on U.S. natural gas production later this year have any assumption built in for shut-ins, whether due to economic reasons or -- and want of transportation capacity to get your gas to the market? George L. Kirkland: No, it’s --

Okay. George L. Kirkland: Decline rates on U.S. gas are pretty high and we are pulling the trigger, reducing the amount of investment in that arena and it’s going to start responding and declining. Maybe even to give you a little additional color, we have -- in the [Peonce] Basin we have a facility that will be coming on. We have a nice area of development up there -- 30,000 plus acres. We’ve drilled a large number of wells and will be starting up a facility there but we are shutting down all drilling in the [Peonce] and we had plans at one time to be up to even six or eight rigs running there, so we are going to shut down the last rig. We’ve been running to there for a couple of years and we are going to shut that down.

Beyond shutting down to zero on the incremental drilling is there a price below which you would actually turn off the taps? George L. Kirkland: That gets more into the supply and demand balance. Of course there’s a price at some point that you are not going to supply gas. I’ve done no work or seen any work that we’ve done in that arena.

Okay. Separately on [Tengeze], just trying to think about going forward -- now that you’ve got the capacity there, what sort of utilization rate should we think about for those facilities? Obviously you had quite a bit of maintenance last year. I imagine more than normal to tie-in the new facilities but if we think of a normal run-rate utilization, say 2010, 2011 and onwards, how should we think about that? George L. Kirkland: Mid-90s.

Okay. Good. Thank you very much.

Your next question comes from Paul Cheng with Barclays Capital.

George, I just want to make sure I heard you correctly -- you said you are not going to have any more active gas rigs at all in the lower 48 by year-end? George L. Kirkland: That’s correct on land rigs -- land gas rigs.

Right, land gas rigs. George L. Kirkland: Land gas rigs by the end of the year, I expect the --

So no [inaudible] or anything? George L. Kirkland: No development gas drilling, I’ll go that far. I wouldn’t hazard to say that far on -- we would have anything with regard to workovers.

Okay, no new development drilling? George L. Kirkland: Right.

Okay. And [inaudible], I think several years ago that at one point you guys were pretty interested, trying to expand your footprint. In the last two or three years, I think you have been pretty quiet or not totally crazy about that. I mean, where are we from a company standpoint? What is your strategy or what is the priority of the oil sands in your portfolio at this point? George L. Kirkland: Paul, you know we are investing in the expansion of the Albion oil sands with Shell, the Athabasca oil sands project up there. That expansion should come online in 2010. That’s -- on a gross barrel basis, that’s about 100,000 barrels a day and our working interest share is 20%. That will make the footprint we have in Canada, that will give us over -- that with the existing production will give us over 50,000 barrels a day of oil sands production. We like oil sands in the sense of the resource and the location, so that’s a positive. At this point though, the cost of developing it and operating it, it’s tough to make money in a $50 world, so the challenge for us, and we’ve got opportunities participating with our partners to expand up there but we see it needs to happen when we can control the capital costs, bring the capital costs down and when we have a view of higher oil prices. So that’s what’s important for us. With inside our project queue, oil sands makes up a pretty small piece of it and when you look at the economics of it, it’s the weakest set of projects with inside our queue of projects -- weakest in an economic sense.

Very good. Thank you.

Sean, do we have anymore callers?

I am not showing any further questions, sir. Patricia E. Yarrington: Okay, then I’ll just go ahead and close up. Thank you, Sean. Before ending completely here, I just want to reiterate couple of key messages here. Operations ran very well, are running really very well. Project execution is very strong. You heard from George about the volume increases that we are seeing year over year, as planned. We have a strong focus on cost management, a $2.5 billion target, 10% target reduction for year over year. We’re running ahead of pace on that and we are very intent on sustaining that momentum. I appreciate -- we appreciate everybody’s participation on the call today and I want to thank everybody on the call on behalf of everybody on the call for the analyst questions. Thank you very much.

Thank you. Ladies and gentlemen, this concludes Chevron's second quarter 2009 earnings conference call. You may now disconnect.