Good morning. My name is Matt and I will be your conference facilitator today. Welcome to Chevron's second quarter 2008 earnings conference call. (Operator Instructions) I will now turn the conference over to the Vice President and Chief Financial Officer of Chevron Corporation, Mr. Steve Crowe. Please go ahead, sir. Steve J. Crowe: Thanks, Matt. Welcome to Chevron's second quarter earnings conference call and webcast. Jim Aleveras, General Manager of Investor Relations, is on the call with me. Our focus today is on Chevron's financial and operating results for the second quarter of 2008. We will refer to the slides that are available on the web. 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. I’ll begin with slide 3, which provides an overview of our financial performance. The company’s second quarter earnings were a record $6 billion, or $2.90 per diluted share. Our second quarter 2008 results were up 11% from the second quarter 2007. Higher crude oil prices benefited our upstream performance but had a negative impact on our downstream business. The second quarter of last year included a $500 million net gain on the sale of an investment and redemption of debt. Second quarter 2008 earnings rose over 15% compared with the first quarter of 2008, which Jim will discuss shortly. Return on capital employed for the trailing 12 months was 23%. The debt ratio was below 8% at the end of June. Capital and exploratory spending was $5.2 billion for the quarter. In addition to the $2 billion of stock buy-backs, we increased the second quarter dividend 12%. Jim will now take us through the quarterly comparisons. Jim.

Thanks, Steve. My remarks compare results of the second quarter 2008 with the first quarter 2008. As a reminder, our earnings release compared second quarter 2008 with the same quarter a year ago. Turning to slide 4, second quarter net income was $800 million higher than the first quarter. Starting with the left side of the chart, higher crude oil and natural gas realizations benefited the company’s worldwide upstream results. At the same time, the significant increase in crude oil prices adversely affected the downstream segment. The variance in the residual other bar primarily reflects higher charges at the corporate level for environmental remediation and tax adjustments. Slide 5 summarizes the results of our U.S. upstream operations, which improved by about $590 million between quarters. Higher crude oil and natural gas realizations benefited earnings by $775 million. Chevron's average U.S. crude oil realization was up about $24.30 per barrel between consecutive quarters. This was less than the nearly $26 increase in WTI’s spot prices between quarters, since much of our Gulf of Mexico crude oil production is priced on a lagged basis. Production volumes were down 2% between quarters, largely due to operational downtime and normal fuel declines. This reduced earnings by $30 million. Higher operating expenses reduced earnings by $70 million. Fuel, steam, and utility costs increased, as did maintenance expenses. The other bar is the net of everything else, including various gas marketing effects. Turning to slide 6, international upstream earnings for the second quarter were about $1.5 billion higher than the first quarter’s results. Higher oil and gas prices increased earnings by nearly $1.3 billion. Our average unit realization for liquids rose by $24.30 per barrel between sequential quarters, about the same as the average brent spot price increase. An increase in liftings contributed $130 million to the second quarter. Liftings were up primarily in Tengiz, the U.K., and China. Overall liftings were roughly in balance for the first half of the year after our under-lifted position in the first quarter. Operating expense reduced earnings by $90 million, mainly in the U.K., Kazakhstan and Indonesia. The other bar reflects the net of many unrelated items. The largest item was a favorable swing in foreign exchange effects. Among the offsetting items, exploration expense was higher in the second quarter. Slide 7 summarizes the change in worldwide oil equivalent production, including volumes produced from oil sands in Canada. Production fell by 62,000 barrels per day, or 2% between quarters. U.S. production declined 13,000 barrels per day due to operational down time and normal field declines that I mentioned. Outside the U.S., overall production dropped 49,000 barrels per day in the second quarter. However, we estimate that the impact of higher prices reduced production by about 75,000 barrels per day between sequential quarters. So absent price effects, volumes would have been up between quarters. I’ll elaborate on this in a moment. Indonesia production was impacted by prices but the largest effect was the absence of the one-time benefit of a favorable gas unitization agreement that we discussed on the conference call last quarter. While gross production at Tengiz continued to ramp up with our expansion project, both Tengiz and Karachaganak net volumes were affected by higher prices. Turning to our production outlook for 2008, total OEG production for the first six months of 2008 was 2.57 million barrels per day. During this period, WTI prices averaged just over $110 per barrel. Our production target for 2008, which assumed $70 per barrel WTI, was 2.65 million barrels per day. Absent the price effects under production sharing and variable royalty agreements, our production for the first half would have been on track with our full year production target of $2.65 million barrels per day. This production level reflected strong base business performance without significant contributions from several 2008 major project start-ups. Our project start-ups will increase production during the second half of the year and, adjusting for price effects, we expect to meet or exceed our volume target for the year. Steve will provide a brief update on our major projects at the end of our presentation. We reviewed our rule of thumb as prices have moved far above $70 per barrel, and we believe the rule of thumb is still applicable at the current price level. That is to say, a $1 per barrel increase in prices leads to about a 2,000 barrel per day reduction in our net production volumes for the year. However, I would like to reemphasize the caveats we’ve given you about this rule of thumb. The calculation of price impacts includes many variables, including the interaction of prices and costs, very specific contract thresholds and terms and so forth. The rule of thumb is our best estimate of the impact for 2008, but results will vary when making comparisons between periods. For example, because certain thresholds were met in the second quarter, the rule of thumb does not work when comparing the first and second quarters of 2008. Each dollar change in price had an impact of over 3,000 barrels per day in this particular comparison. We’ll continue to update you as we move through this very volatile environment. Turning to slide 8, our U.S. downstream operations moved from break even to a loss of about $680 million in the second quarter. Industry refining margins improved in the second quarter, although marketing indicator margins weakened, particularly on the west coast. On balance, indicator margins suggest a $305 million benefit. WTI prices rose more than $38 per barrel from the end of the first quarter to the end of the second quarter. This compares to an increase of less than $6 per barrel during the first quarter. This truly extraordinary crude price spike in the second quarter reduced the U.S. downstream earnings by $490 million between quarters. The $490 million is shown on the bar labeled timing effects. Of the $490 million, about $280 million reflected the impact of provisionally priced foreign crude. This crude is priced on a delivered basis, although we take title to it when it is lifted. We typically have about 13 million to 15 million barrels of provisionally priced crude in transit to the U.S. west coast. These barrels are effectively marked to market at the end of each period. A second timing effect accounted for $110 million of the $490 million change between quarters. We used derivatives to convert crudes, including crudes that are not provisionally priced, from the acquisition price to the price at the time they are run. As prices went up dramatically during the second quarter, this resulted in derivative losses. The balance of timing effects between quarters reflected a number of supply related activities, including mark-to-market losses on derivatives related to a long-term contract. Moving to the next bar, we had an unfavorable variance of $300 million between quarters, due to refinery shut-down effects. Almost all of these were planned shutdowns and we previously cautioned that 2008 would be a heavy planned shutdown period for us. The adverse $300 million variance reflects both the direct operating expense and the lost margin capture as we purchased more expensive feed stocks and intermediates during the refinery shutdowns. Most of the difference between quarters was due to our Pascagoula refinery, where both the number one crude unit and coker were down during the second quarter. Planned shutdowns at El Segundo and [Hawaii] were much smaller factors. Our 2008 maintenance schedule indicates that essentially all of our major U.S. planned shutdowns were completed in the first half of 2008. Excluding the operating expense related to refinery shutdowns, other OpEx was $145 million higher in the second quarter. Many factors were involved here, including higher fuel costs. The other bar on the chart is an unfavorable variance of $56 million, which primarily reflects minor pipeline impairments. Turning to slide 9, international downstream earnings fell $300 million from the first quarter’s results. Refining indicator margins improved while marketing margins were mixed across our international geographic areas. On balance, company margins were a $185 million benefit between quarters. Volumetric effects were a $25 million adverse variance. This primarily reflected the unplanned shutdowns at the Pembroke refinery in Wales. We estimate the overall impact of all international refinery downtime between quarters to be an unfavorable variance of $32 million, which reflects OpEx as well as volume and feedstock impacts. As we saw in the United States, international downstream timing effects were a major factor in the adverse change between quarters, as the price of crude and petroleum products increased very significantly over the course of the second quarter. Two-thirds of the $225 million shown as timing effects was related to long haul sales of equity crude and refined products. For select cargos, we often use derivatives to lock in a margin above the cost of transportation. During periods of rapidly increasing prices, this can lead to derivative losses. The majority of this timing effect is related to delivered sales of partition neutral zone equity crude and exports of refined products from our Pembroke refinery to third parties. The balance of the timing effect is primarily due to losses on derivatives used to convert crude pricing to the time of refinery run. There was also a factor involved here regarding the changes in inventory. The next bar shows operating expense was a $140 million unfavorable variance between quarters. A number of different items affected the various geographic regions. There was not a pattern to the components of the $140 million change. The other bar shows a $95 million reduction between quarters, and this primarily reflects lower foreign exchange gains, as well as an adverse swing in tax items. Slide 10 shows that earnings from chemical operations were $41 million in the second quarter, compared with $43 million in the first quarter. Results for olefins fell on lower margins and volumes, as well as higher expense. Aromatics results were also affected by lower volumes and higher operating expenses. Additionally, shutdown activity reduce aromatics results. The other bar on this chart shows a favorable $26 million variance between quarters. This reflects the absence of a $40 million environmental provision we mentioned on last quarter’s conference call, partly offset by lower additive margins. Turning to slide 11, which covers all other, second quarter results were net charges of $580 million compared to net charges of $255 million in the first quarter. The $210 million variance reflects environmental provisions related to legacy Texaco and Unocal downstream assets. Since these assets were sold prior to Chevron acquiring their parent companies, the impact was included here rather than in the downstream segment. Tax items were an $80 million unfavorable variance. The other bar reflects the net of many unrelated items. Before I turn things back over to Steve, I would just like to briefly recap the second quarter’s results. First, upstream results were very strong, in line with the indicators in our July 10th interim update. Second, we experienced a sharp decline in downstream performance due to timing effects and refinery downtime, as we discussed in the interim update. Finally, as we projected, chemical results were flat between sequential quarters and our all other charges were significantly higher than the standard guidance range due to environmental remediation charges. That completes my variance analysis for the quarter. Back over to you, Steve. Steve J. Crowe: Thanks, Jim. Before opening the call to questions, I would like to highlight the significant progress we’ve made on some of our major capital projects. Please turn to slide 12. First up is our Agbami project, offshore Nigeria. Yesterday, we announced that Agbami had begun production. Chevron is the operator with a 68% interest in this world class deepwater project. Agbami’s initial gross OEG production is expected to quickly ramp up to more than 100,000 barrels per day. We anticipate this reach 250,000 barrels per day by the end of 2009. In the U.K., our partner recently announced first production for the Callanish-Brodgar fields, also known as the Brittania satellite development. At the Tengiz field in Kazakhstan, our phased expansion remains on schedule for full facility start-up this quarter. The first phase, which began late last year, added nearly 90,000 barrels per day of total production during the second quarter. The second phase of production is now complete and we’re doing the major turnaround, final tie-ins, and commissioning. As a result, there will be a brief drop in production of about 25,000 barrels a day in the third quarter. With full facility start-up, we anticipate the project will add 240,000 barrels a day of production, increasing Tengiz’s total capacity from 300,000 to 540,000 barrels per day. In the Gulf of Mexico, we completed our plan to retrofit and tension all eight mooring lines on our Blind Faith facility. We are continuing with commissioning work, having installed all four of the risers. We expect start-up later this year. It’s difficult to be more specific about the timing as weather could impact our commissioning efforts. In Australia, the Northwest Shelf fifth train, fifth LNG train is in the midst of commissioning with an anticipated first cargo in the fourth quarter. In Brazil, our Frade project is on track for a 2009 start-up. At our Tahiti facility in the Gulf of Mexico, the production spar has been moored, the installation of sub-sea flow lines and risers is nearly complete, and the first of three major topside modules was installed last week. We expect to install the other two topside modules this quarter. The Tahiti project remains on schedule for first production in the third quarter 2009. In Angola, our Tombua Landana project is also on schedule for first production next year. In summary, our major projects are on track to deliver significant new volumes. That concludes our prepared remarks. We’ll now take you questions. One question and one follow-up per caller, please. Matt, would you open up the lines for questions?

(Operator Instructions) Our first question is from Arjun Murti of Goldman Sachs.

Thank you. Thanks for the project update. I was wondering if you could provide a similar update on some of your exploration plans, I guess in particular the status of some of the key lower tertiary projects, Jack in particular, St. Malo. If you could provide an update on exploration in general but most notably the lower tertiary, that would be helpful. Thank you. Steve J. Crowe: Well, we’re looking at Jack and St. Malo presently. We have another well that will be completed later in the year. We’re giving consideration as to whether or not we can tie back those two projects, Jack and St. Malo, one of which came from Unocal and one of which is a legacy Chevron one, and consider developing the two of them in tandem. We’ll have more to say about the progress of the lower tertiary as we get a little deeper in the year and can probably give you a more definitive update on our next conference call. Arjun, did you have a follow-up question?

Are those expected to be sanctioned this year, and does the fact that you are considering a joint development speak to any disappointment or update in terms of the resource potential of either or both together? Steve J. Crowe: I think the consideration of joining those two projects together really speaks to the opportunity to reduce costs in the current environment and produce them in tandem as a more efficient way of developing the resource.

It’s an efficiency consideration? Steve J. Crowe: Primarily.

And I’m sorry, do you think we’ll be expecting a sanction decision this year or is that an ’09 or later kind of a thing? Steve J. Crowe: That will be outside of 2008.

Thank you very much.

Our next question is from Neil McMahon of Sanford Bernstein.

Just really on some of the numbers in today’s call that Jim ran through on the variance analysis; looking at the OpEx reduction both in the U.S. but more importantly in international, which is a bit strange, given higher royalties and an inflation environment. I was wondering to what extent -- well, first of all really why that OpEx reduction took place from the first quarter to second quarter, and in particular related to what’s going on in Kazakhstan with some of your partners in the Karachaganak field seeing increased charges associated with changes in the fiscal terms in that country. Steve J. Crowe: Well, let me give a first correction, I think, Neil. As Jim was going through the variance analyses say on the U.S. upstream, we indicated on our, on slide five that operating expense was higher in the second quarter in comparison to the first quarter by about $70 million after tax, mainly reflecting, as you would expect, higher fuel costs and utility costs, along with higher maintenance. So actually the costs were higher in the second than in the first quarter.

Neil, with regard to the international upstream, you will see OpEx down a little bit but the biggest factor there was simply a number of different things in our various U.K., Kazakhstan, and Indonesia operations.

I’m just sort of struggling why it’s dropped, given the fact that BG on their conference call were talking about the fact that under duress, or -- maybe that wasn’t the word they used but they were paying new taxes associated with the fiscal change in Kazakhstan. That’s all. It seems strange that you have gone down whereas they went up.

Neil, perhaps it’s a semantic issue here. When we’re showing OpEx as a negative, what we’re saying is it’s a negative to P&L. We start with our income from the first quarter and we end with our income in the second quarter, so when OpEx is a negative, what it means is it’s a detraction from our earnings in the second quarter.

Right, I understand that but you did say that it went down. That’s all.

No, we said OpEx was a negative. If you look at the international upstream chart, it’s a negative $90 million to earnings, so that’s OpEx actually going up. It’s reducing earnings by $90 million.

Okay, I thought you said a few minutes ago that things got better in Kazakhstan, but that’s fine. Maybe as a follow-up then, just on the environmental charge under corporate, maybe you could just walk through that, since you did say you had disposed of those assets, or maybe my hearing has completely gone. Steve J. Crowe: Well, as we had foreshadowed in the interim update on July 10th, certain of the environment provisions or obligations that we have that are connected with legacy operations of Texaco or Unocal, we still are obliged per certain of the contractual arrangements to effect the environment clean-up or remediation. It so happened that here in the second quarter, for primarily the Unocal but also Texaco operations that are no longer operating, they’ve been disposed of, certain events have occurred where we thought it was appropriate for the accounting rules to recognize the increased liability. So that was the fundamental driver for that increase of $210 million between the first and second quarters of this year.

Steve, can you tell us where they are or what the chances are that this sort of thing is going to happen again on some of those assets? Steve J. Crowe: Well, there were a variety of things, some of which were marketing related. Operations that Unocal had that have since been sold twice. Some of them are connected with refinery and terminal locations, both legacy -- primarily legacy Texaco. And those things occur driven by events, but you will have noticed I think over the last year or so that our recognition of environment expenses, whether it be for currently owned and operated operations or those previously disposed of are a bit more -- occur more regularly during the course of the year. But it’s very hard to give you a prediction as to what the ratable pace would be because it’s driven by events and they tend to come based on the situation.

Okay, thanks.

Our next question is from Paul Sankey of Deutsche Bank.

Good morning, gentlemen. I got a little bit confused regarding your overall statements about volumes for the year. You said you at 2537, 2.5 million and that you would otherwise have been at your target but for the PSC and other effects of 2650. You then subsequently said that you expect still to meet the target by the end of the year, was it, or could you just clarify? I didn’t quite understand what you were saying. Do you mean that you are going to still be at 2537 by the end of the year, or are you going to hit -- Steve J. Crowe: I’ll let Jim cover that.

Paul, what we are saying is that we expect to meet or exceed the 2.65 that we talked about at $70 a barrel oil at our March meeting, but that’s adjusted for prices. Right now, we’re in a very volatile pricing environment so if prices stay above $70, we’ll come in below that but we’ll give you a reconciliation back to that that will explain the PSC effects that cause it.

But the point I was making was that you said that at the current level, effectively but for those effects, the 2.5 level but for those effects amount to the 2.6, if you like, which would then to me suggest that there’s no growth in the second half.

No, we expect to meet or exceed, and I’ll put exceed in italics, if that helps, Paul.

Okay, I’ve got you, I think. Steve J. Crowe: So what we’re saying again, for those on the phone, is we are reaffirming our production guidance earlier in the year that we’ll have net production of 2.65 at a $70 per barrel average price for the year. And Jim also mentioned that it still looks appropriate as you make those adjustments because of higher print prices, a two-to-one ration, such that for every dollar increase above the $70, you could anticipate roughly a 2,000 barrel a day reduction in net production.

Okay, if I could take my follow-up, you were very clear on Agbami. On Tengiz, you mentioned that you will be down in 3Q. Could you just give us the overall levels? You mentioned you’d be down I think 25,000 a day. Could you just give us the overall levels, even at the Kazakhstan level, that would be fine. And then if you could also just clarify the exit rate for ’08, because you said there the capacity I think is 240 a day. But if you could just clarify where you think you’ll be by the end of the year, that’s great. Thank you.

Well, let’s take the first one first. Paul, we mentioned the 25,000 barrel a day reduction in the current quarter simply to alert people that as we tie in the facilities and we bring the second generation plan on stream, we will have to reduce production a little bit as we are tying everything back together.

And that will be down to what level, Jim?

Right now, we’re running close to 400,000 barrels day on a gross 100% basis.

And that’s pre the 25, right?

Yes, that’s correct. So there will be a slight reduction in overall production just as we tie everything together and get the plant up and running. In terms of the exit rate from 2008, going into 2009 it’s a little too early to tell yet. We certainly have achieved, as we promised, the 90,000 barrel a day improvement from the first phase of the project, the sour gas injection. Steve J. Crowe: But it will be ramping up to the expected 540,000 barrels a day on a total project -- just don’t want to quote an exact number as we exit out 2008 and go into 2009.

But we’re certainly going to expect a pretty prompt increase once we get out of the third quarter into the fourth quarter. Steve J. Crowe: That’s correct. Thanks very much, Paul.

Our next question is from Paul Cheng of Lehman Brothers.

With Agbami coming on stream and also a number of projects, can you maybe share with us the kind of return and profitability on those new projects compared to your existing one? It looked like Agbami should be extremely profitable, so I’m wondering if you can shed some light. Steve J. Crowe: Well, we typically wouldn’t talk about the economics of a specific project, which obviously get into a lot of the fiscal terms that we have in each of those operations, but Agbami will be a very profitable project for us. It will be returning cash to us on a prompt basis. As you know, it’s a light oil condensate project and ought to have a very handsome rate of return. Our expectation, sort of harkening back to an earlier question on ramp-up is that we probably will see as the wells come on production reaching 100,000 barrels a day in the early part of next year, and then as we mentioned before, moving up to the 250,000 barrels a day by the end of 2009. But I think a takeaway from that last chart that I showed in the prepared remarks is we’ve got a long and healthy list of projects, some of which have come on, some of which are right in the midst of being commissioned, and some are coming on and right on schedule for 2009. So I think our production, which of course net production will be influenced by prices and the way variable royalty mechanisms work and production sharing agreements, but these large projects are all lined up and as you can see, it’s quite a long list and probably will differentiate Chevron versus a lot of our competitors. I think it’s a major difference. We’ve been talking about it for a couple of years now, but they’re ready.

Steve, what’s your current production in Agbami at this point? Steve J. Crowe: Well, Agbami started up literally on Tuesday of this week, as I recall, and so as the wells come on it will be ramping up. The last I saw, and it changes all the time, Paul, but the last I saw was a day or so ago and it was about 20,000 barrels a day. But it ramps up over time, so don’t put any specific number -- it’s a function of when the wells come on. But as I mentioned, as they do come on, we anticipate about 100,000 barrels a day in early 2009.

Can I ask a follow-up and maybe conceptual question about the timing effect losses in your downstream operation? Steve J. Crowe: Sure.

I understand the price finalization impact related to long haul crude supply in Saudi Arabia and -- so that’s really no big deal on that. What I’m not quite sure I understand why we even use a derivative for -- let’s say if your own equity crude oil you sell, I think -- based on what you guys describe is that you use derivative to hedge whatever is the price during that journey, that shipping time, whether it’s 20 days or 40 days, given that no one really can foresee what is the price direction for the next 20, 40 days, so arguably you have 50% of the time you make money; 50% of the time, you lose money in that derivative trade. And given Chevron has no concern about liquidity or anything, why we even bother to do that?

The reason we did that was to match the cost of crude that we purchased to the time that it’s run in the refinery to get the margins for the day.

But why do we even bother, Jim? That’s my question.

Well --

I mean, over time, it makes no difference.

But Paul, what we are trying to do there is just lock in a refining margin, which historically refining margins have fluctuated and we want to get refining margin of the day. As we have done this, especially in the second quarter during a period of very, very rapid price changes, we’ve seen that this added volatility to our earnings. That volatility is something that we don’t find acceptable and we have curtailed that program to a considerable extent in the second quarter. So going forward, you can expect to see much smaller effects from this.

Okay. Thank you. Steve J. Crowe: Let me just reiterate a couple of points; in as much of the timing effects were significant in looking at our results, in light of our second quarter results, we’re looking at everything that impacts our downstream performance. But let me make it clear -- our strategy for the downstream business hasn’t changed. We are continuing to work on rationalizing our portfolio to eliminate less profitable assets and to reduce the capital employed in our marketing network, while maintaining our brand uplift. We are absolutely focused on refinery reliability and selective investments to improve refinery performance. But we are also looking at the tactical issues, as Jim mentioned, like the use of derivatives and other factors that sometimes add perhaps unnecessary volatility to our reported results. Thanks for your call and questions, Paul. May we have the next question?

Our next question is from Kate Lucas of J.P. Morgan.

Good morning, gentlemen. Can you just comment a little bit on how, on the progress of the steam flood technology that you are using or implementing in the neutral zone? Specifically, any challenges with the steam flood or the carbonate reservoir? And then, can you comment on whether you are able to source the natural gas and water without any issues? Steve J. Crowe: Thanks, Kate. As you know, we are in a pilot project in the PNZ to see if the technology would be applicable to carbonate formation. As far as I’m aware, good progress is being made and as you’re also aware, we’re doing that early pilot in the partition neutral zone, which has its concession ending in the early part of 2009. This is a 60-year concession and we’re very optimistic that that concession will be extended but it’s too early at this point on the call to confirm it definitively. But all indications are from the pilot steam project that things are progressing as we had anticipated.

Our next question is from Erik Mielke of Merrill Lynch.

We’ve been through most of my questions; just a couple of quick follow-ups. In the discussion earlier with Neil on international operating costs during the second quarter, I recognize that there was an increase during the quarter but the rate of increase was perhaps less than we would have expected. Is that because of the volume mix effect or is it part of underlying cost improvements that you’ve previously discussed?

It’s a combination of a number of things, Erik. If we look at our operating expense, what we are seeing is higher costs in a lot of areas, but we did have some work over costs in West Africa that affected the prior period that are not in the current period. Steve J. Crowe: Hope that helps.

It does indeed. And then finally, just looking at politics and the fact that by the time we have the next call, we’ll be right in the middle of the elections, we’ve had an announcement today from one of the two candidates that they are considering windfall taxes to finance a so-called energy rebate. What are you hearing from your contacts in Washington when it comes to the outlook for taxation on U.S. oil companies? And if you have any comment on what the impact will be for the different proposals on CO2 cap and trade for your business. Steve J. Crowe: Well, it’s again very early with respect to the measurement of the impact of the various CO2 proposals that have been floated around for the last year or so. As far as windfall profits tax is concerned, we have over the last year seen a number of proposals tabled, some were windfall profit tax, some were related to use of foreign tax credits, some were connected with the sustained usability of LIFO. At this juncture up to this point, those have all not passed muster but again, it depends on the nature and terms of any legislation that might be forthcoming in a new administration down the road, so it really much depends on the form of any additional taxation. Hard to speculate until you know all the details. Erik, do you have any other questions?

No, that’s it for me. Thank you.

Our next question is from Jason Gammel of Macquarie.

Thank you. Good morning, guys. I just wanted to ask a question about the timing of the Pascagoula coker turnaround. From an historic margin capture standpoint, the second quarter would seem to be counterintuitive for planning a two-month turnaround on a coker. Can you shed any light into that decision-making process?

Let me take a swipe at that. The whole issue of bringing a coker down is a very, very complex issue that we’re very conscious the timing is important in terms of scheduling a turnaround because of the impact on margins. If we look at the light heavy differential as a key proxy for coker profitability we don’t find that it follows a consistent pattern between the first and second quarter. So in the 2003, 2005 period, light heavy differentials were actually higher in the first quarter than the second quarter. You just can’t change a major refinery turnaround once you see actual margins coming through the market on a weekly or a monthly basis. In Pascagoula, for example, the crude unit and coker shutdowns during the second quarter were very major undertakings involving thousands of temporary workers. And the Pascagoula coker had run five years since its last scheduled turnaround. We simply were not in the position to second-guess the market as the market evolved in 2008 to get the timing exactly where you would have liked to have gotten it in hindsight to capture the best margins. Steve J. Crowe: I think I would add as well two other points, Jason; one, there was a lot of activity with respect to bringing back the other crude unit in the first quarter, so there really wasn’t an opportunity to accelerate it by a quarter or two if you had perceived a different light heavy differential in the short-term. But the other point that I would make is, as Jim had alluded to, almost all of our schedule maintenance here in the U.S. for 2008 is behind us, so we would expect to have increased refinery availability during the second half of the year.

Okay, that’s very helpful, guys. Maybe as a follow-up, I could ask about the decline in branded gasoline sales? It looks to be down about 5% year over year. Is that purely a demand function or are there some divestitures that played a role in that as well?

It’s largely a demand function, Jason. What we are seeing is a higher amount of demand decrease in the U.S. West Coast than we are seeing in other parts of the country, and of course Chevron is disproportionately exposed to the U.S. West Coast. We’ve seen this in prior periods as well when California was disproportionately hit in the early 1990s as the defense contractors exited the state, and in the late 1990s as the dot.com bubble burst. In each case, we’ve seen California rebound. Right now, California is being disproportionately hit by the housing and credit crisis, and this has created what we feel is a negative consumer sentiment that’s causing people to do less discretionary driving. Long-term, we’re very bullish about California. We’ve seen California knocked down twice in the last decade. The exit of the defense contractors was a huge impact on California. The dot.com bubble was a huge impact on California, and California unemployment rates had run 1.5 times the national average. So there’s a lot of consumer sentiment going on here and we’re just in the midst of this for a short period of time. We don’t know what the future holds but in the past, California has wobbled around more than the country has but it’s always come back. So we’re optimistic about the future but for the moment, we are being disproportionately affected by our exposure to the U.S. West Coast. Steve J. Crowe: Jason, just to close that off, we really don’t have any divestments that are impacting the lower branded gas sales. It’s all a function of industry market demand.

Very helpful. Thanks, guys.

Our next question is from [Wasim Khalil] of HSBC.

I was just wondering if you could perhaps give us a little bit more information on the partition neutral -- I believe the lady earlier from J.P. Morgan was cut off and I was just wondering if you could just perhaps give us some more information on any updates that are going on regarding that. Steve J. Crowe: Well, I really don’t have a lot of additional information to offer up. I had commented on the status and successful progress of our steam flood in the carbonate rock, and also had mentioned that we’ve been having ongoing discussions with the Kingdom for an extension of the concession agreement, which is progressing and against which we’re very optimistic that we’ll have a successful resolution. Beyond that, I really don’t have any additional information to provide to you on the call here today.

Right, okay. I guess then if there’s no additional information, there’s no additional questions. Thank you very much.

Our next question is from Doug Leggate of Quandrum.

This is becoming a bit of a theme here -- on this partition neutral zone, I’m just curious; in the event that the concession is extended, can you give any kind of rough approximation as to what the period that you would expect it to be? Because I’m expecting you would be able to book the reserves here, right, if it gets extended? Steve J. Crowe: If the concession is extended, we would be able to book reserves. As you know, under current accounting rules, we’re only able to book reserves to the extent that production would occur under the existing contract. As far as any of the commercial terms that are in the midst of being finalized and negotiated, I’m clearly not at liberty to discuss those now but your fundamental premise about being able to book reserves is correct, Doug.

I guess as a related follow-up, would this be as long as the original concession, or would there be much shorter -- just, you know, ballpark would be really useful. Steve J. Crowe: Well, the existing concession was for 60 years and I am really not at liberty to talk about the terms of the successor, if it is concluded. We’ll give the investment community full detail, or as much detail as we can at the point of our announcement.

Great. Thanks, Steve.

(Operator Instructions) Steve J. Crowe: Matt, it looks like we’ve gone through the lists of analysts who had questions for us. I think in closing, let me say how much I appreciate all of the analysts participation, particularly asking questions on behalf of all of those listening, and thank you very much. Matt, back to you.

Ladies and gentlemen, this concludes Chevron's second quarter 2008 earnings conference call. Thank you for participating. You may now disconnect. Good day.