Good Morning. My name is Matt and I will be your conference facilitator today. Welcome to Chevron's third quarter 2008 Earnings 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.

Thanks, Matt. Welcome to Chevron's third quarter earning conference call and webcast. On the call with me today are George Kirkland, Executive Vice President, Global Upstream & Gas; and Jim Aleveras, General Manager, Investor Relations. Our focus today is on Chevron’s financial and operating results for the third quarter of 2008. We’ll 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 third quarter earnings were a record $7.9 billion, or $3.85 per diluted share. Our third quarter 2008 results were more than double our third quarter 2007 earnings. Higher crude oil and natural gas prices contributed to our upstream performance. Our downstream operations benefited from improved margins, strong refinement utilization, and from timing effects related to the substantial drop in the price of oil during the third quarter. Third quarter 2008 earnings rose over 30% compared with the second quarter 2008, which Jim will discuss shortly. To recap the balance of slide 3: Return on capital employed for the trailing 12 months was 27%. Capital and exploratory spending was $5.5 billion for quarter. Stock buybacks were $2 billion during the period. Underscoring Chevron’s financial strength the debt ratio was below 8% at the end of the quarter and cash balances exceeded debt by $4 billion. Jim will now take us through the quarterly comparisons. Jim?

Thanks, Steve. My remarks compare the results of the third quarter 2008 with the second quarter 2008. As a reminder, our earnings release compared third quarter 2008 with the same quarter a year ago. Turning to slide 4, third quarter net income was $1.9 billion higher than the second quarter. Starting with the left side of the chart, lower crude oil and natural gas realizations and lower volumes reduced worldwide upstream results by more than $1 billion. At the same time, the significant decrease in crude oil prices during the quarter benefited the downstream segments, which improved nearly $2.6 billion in the second quarter’s loss position. The variance in the residual other bar largely reflects the absence of charges at the corporate level that were taken in the prior quarter. Slide 5 summarizes the results of our U.S. upstream operations, which were essentially unchanged between quarters. Lower crude oil and natural gas realizations reduced earnings by $130 million. Chevron’s average U.S. crude oil realization was down $1.75 per barrel between consecutive quarters. This was less than the roughly $5.50 per barrel decline in WTI spot prices between quarters since much of our Gulf of Mexico crude oil production is priced on a lagged basis. Production volumes were down 8% between quarters, primarily due to hurricane related shut-ins during September, these reduced earnings by $195 million. Additionally, as we mentioned in the interim update, expenses related to the hurricanes reduced earnings by roughly $400 million. These included incremental cost to abandon toppled platforms, asset write-offs and initial repairs. George will discuss our hurricane recovery efforts in more detail in a few minutes. Asset sales added about $350 million to third quarter profits. These included a non-operated interest and a K2 property along with other smaller property sales. The other bar on this chart is the net of everything else. The largest single item was higher earnings in our natural gas marketing division including gains and derivatives related to gas contracts. The magnitude of these gains was directly related to the drop in natural gas prices during the quarter. Turning to slide 6, international up stream earnings for the third quarter fell about $1.1 billion from the second quarter's results. Lower oil and natural gas prices reduced earnings by $250 million. Our average unit realizations for liquids fell about $7.70 per barrel between sequential quarters. Roughly, $1.50 per barrel more than the average brand spot price decline. Lower liftings had a $635 million adverse impact on the third quarter earrings. The largest reduction was in Kazakhstan reflecting lower production, which I'll cover in the next slide. Liftings were also lower in Azerbaijan, Angola, Congo, and China. Overall, third quarter liftings were about 2% less than production, while we were slightly over lifted in the second quarter. Through the nine months liftings in production were roughly in balance. More than half of the adverse change in the DD&A and OpEx bar on the chart reflected impairments of several matured fields in the North Sea. Operating expense was higher due to labor and transportation costs and start up costs of our Agbami project. The bar is the net of the foreign exchange effects partly offset by the absence of favorable prior quarter tax items and numerous unrelated matters. Slide 7 summarizes the quarterly change in worldwide oil equivalent production, including volumes produced from oil sands in Canada. Production fell by 94,000 barrels per day or nearly 4% between periods. U.S. production declined 55,000 barrels per day chiefly as a result of shut-ins during September for hurricanes Gustav and Ike. Outside the US, overall production dropped 39,000 barrels per day in the third quarter. In Kazakhstan most of the 55,000 barrel per day reduction reflected completion of TCO's second generation plant and concurrent annual facility maintenance. These had a larger impact than we had expected at the time of last quarter's call. Lower production at Karachaganak was also a factor. The increase in Nigerian volumes was due to the start up of our Agbami project in late July. George will provide the outlook for production in the fourth quarter and full year 2008 shortly. Turning to slide 8, U.S. downstream operations moved from a $680 million loss in the second quarter to a $1 billion profit in the third quarter. Industry margins reduced earnings by $180 million. Chevron’s actual margin capture and higher volumes in the third quarter increased earnings by $100 million and partly offset the decline in industry indicator margins. Due to significantly less planned refinery downtime in the third quarter, earnings improved by $380 million. Chevron’s U.S. refineries operated with minimal downtime. Given the extraordinary volatility of crude oil and refined product prices, and their impact on our downstream earnings, we've highlighted timing effects during the last few quarterly calls. [West Texas] immediate prices fell more than $39 per barrel from the end of the second quarter to the end of the third quarter. This compares to an increase of over $38 per barrel during the previous quarter. The unprecedented swing in prices during each period resulted in an earnings changes of $1.3 billion between sequential quarters. Of this $1.3 billion favorable variance shown in the bar about $700 million reflected the impact of provisionally priced foreign crudes, which lowered second quarter earnings on an absolute basis by $340 million, and increased third quarter earnings by $360 million. About $200 million of the $1.3 billion total was the swing from losses to gains in mark-to-market derivatives related to a long-term fixed price crude purchase contract. Over $120 million of the $1.3 billion reflected the absence of second quarter derivative losses related to converting crudes from the acquisition price to the price at the time we were on. We discontinued most of our derivative use for crude price conversion in the U.S. in early June. The balance of the timing effects primarily resulted from a favorable change in derivative impacts related to the sales of refine products and from gains due to the timing of aviation fuel pricing and all other supply related timing effects. We have revised our primary long haul crude supply agreement for our West Coast refineries. Beginning with October liftings all barrels will be priced at the average price during the month of lifting rather than at the time of discharge. This change will eliminate provisional pricing on these crudes and we expected to significantly reduce the timing effects in our U.S. downstream earnings. However, fourth quarter earnings will include the impacts of final pricing adjustments for October and November deliveries that were lifted during the third quarter. Returning to the chart, the other bar is largely due to better lubricant margins and the absence of pipeline impairments, I mentioned last quarter. Turning to slide 9, international downstream earnings improved to $817 million in the second quarter's loss. Margins were a minor favorable item, as improved marketing margins overcame weaker refining margins. Volumes benefited slightly following completion of repairs at our Pembroke Refinery in the U.K. As in the U.S., international downstream timing effects were major factor in the favorable change between quarters, as the price of crude and petroleum products fell significantly. Of the $860 million favorable timing effects shown in the bar, more than half was related to derivative gains on sales of long-haul equity crude and refined products, such as, partitioned neutral zone crude and Pembroke product exports. As I mentioned last quarter, we often use derivatives to lock in a margin above the cost of transportation, which can result in gains when prices decrease and vice versa. More than $100 million of the 860 million total shown in the bar reflected gains in the third quarter as compared to losses in the second quarter and derivatives used to convert crude pricing to the time of refinery run. The balance of the timing effects is primarily due to favorable inventory impacts, gains due to the timing of aviation fuel pricing, and all other supply-related timing effects. Going forward, we're taking actions as appropriate, to reduce the volatility of this segment, the price fluctuations. The other bar on the slide shows a $51 million adverse variance between quarters. This is the net of foreign exchange gains, offset by operating cost and tax items. Slide 10 shows that earnings from chemical operations were $70 million in the third quarter compared to $41 million in the second quarter. Results for olefins improved on higher margins along with lower operating expense. Aromatics results fell somewhat, due to startup costs, for the Jubail Chevron Phillips Styrene operation. The other bar reflects lower additive earnings. Slide 11 covers all other. Third quarter results were net charges of $190 million compared to net charges of $580 million in the second quarter. $190 million of the swing reflects lower environmental charges, and $110 million stems from a favorable variance in tax items. The other bar on slide 11 includes the net of many unrelated items which were favorable variants between sequential quarters. In total, the third quarter net charge was less than our standard guidance of $250 million to $300 million. For the various reasons stated in the interim update. Before turning it over to George, I'd just like to briefly recap the third quarter. Upstream earnings and volumes were down somewhat inline with the interim update. We experienced a strong improvement in downstream performance, due to timing effects rising from sharper declining crude and product prices and less refinery downtime also as outlined in the interim update. Fine line, as projected chemical results benefited from higher margins. George Kirkland is now going to provide an update on our production outlook for 2008, our hurricane recovery plans, and our upstream projects status through 2009. George?

Thanks, Jim. Before I update you on the major capital projects, I'd like to review our production. Please turn to slide 13. This graph compares net OEG production through the first nine months of 2008; first is the first nine months of last year. Total OEG production through the third quarter was 2.53 million barrels per day. Although production is down 95,000 barrels per day about 80,000 barrels per day of this loss is attributable to price effects on the net entitlement barrels and 17,000 barrels a day is attributable to the disruptions from hurricanes Gustav and Ike in the Gulf of Mexico. I’ll discuss the hurricane impacts in just a few moments. Despite these losses, we have been very successful in managing our base business declines and capturing gains for major capital projects that have recently come online. The low base business decline is a positive indicator of our base business efforts, where we have experienced improved reliability across the enterprise. Adjusting for favorable gas market conditions in the Asia-Pacific region, and the Indonesian unitization settlement, our base business decline rate is approaching the low end of our 4% to 5% decline guidance. Now, I'll update you on the production outlook for the remainder of the year. Please turn to slide 14. Assuming fourth quarter prices will average approximately $70 a barrel, and thereby, approximately $100 a barrel for the whole year. Our 2008 production outlook is estimated at 2.55 million barrels of oil equivalent per day. This graph compares the 2008 outlook to year-to-date third quarter actuals, and our fourth quarter production outlook. The last bar on the right shows the 2008 guidance provided last January. Absent the yearly price effects of about 60,000 barrels per day and hurricane disruptions, which we estimate to be about 35,000 barrels per day, the full year net production would be in line with the prior guidance. The fourth quarter production forecast is estimated at 2.62 million barrels per day, significantly higher than year-to-date actuals. This is driven by two factors; the continued ramp up of our major capital projects, principally, Agbami and the Tengiz expansion and lower prices. Project ramp ups are estimated to add approximately 170,000 barrels per day during the quarter. The impact of lower prices on net entitlement barrels, associated with production sharing contracts will likely increase production by about 45,000 barrels per day during the quarter. Offsetting these gains are hurricane disruptions, which are estimated at 65,000 barrels per day for the quarter and the continued base business declines which includes ongoing operational difficulties in Azerbaijan. I would like to now spend a few moments to provide additional details on the hurricanes. Please turn to slide 15. This slide shows the trajectory of hurricanes Gustav and Ike with respect to Chevron leases in the Gulf of Mexico. The leases are shown in yellow. The wind field for hurricane Gustav is shown in red and for hurricane Ike in green. We are pleased to report that there were zero safety incidence associated with the evacuation of personnel from our offshore facilities. 3500 personnel were safely evacuated for Gustav and 1500 for Ike. We did sustain damage from the storms. Overall, there were 13 toppled structures, four leaning structures and three missing well heads. The long term impact of this damage on production is not great. It is estimated that between 6,000 to 10,000 barrels a day will be permanently lost. In the deepwater areas there were some minor damages sustained at Petronius and Genesis where production is now being restored. There was no damage to the Blind Faith facility and only minor damage to Tahiti. I'd now like to share an update on the current restoration effort and forecast, if you would please turn to slide 16. This chart shows the anticipated net OEG production restoration profile by month. The actual restored production to date is shown on the solid blue line and the outlook is in the dash line. Pre-Gustav production from the Gulf of Mexico averaged about 190,000 barrels of oil equivalent per day. As of this week, total restored production is 55% of pre-storm levels. Of the remaining production to be restored, about three quarters is dependent on the timing of third party pipeline repairs. Let me assure you that we have a dedicated team of professionals actively working with our partners and stakeholders to keep our restoration efforts on track. I'd like now to provide an update on our major capital projects. Please turn to slide 17. Chevron has reached some critical major capital project milestones in 2008. So far this year six projects have started up. It is also anticipated that another two will start up in the fourth quarter, North Duri Area 12 in Indonesia and Blind Faith in the Gulf of Mexico. On July 29, our Nigerian affiliate commenced crude oil production from the Agbami field, this is a significant accomplishment. Agbami initial gross oil equivalent production has ramped up to more than 110,000 barrels per day. We anticipate the ramp up to continue reaching 250,000 barrels per day by the end of 2009. Well, September 22, our Tengizchevroil affiliate completed a major expansion at the Tengiz field in Kazakhstan that has nearly doubled production capacity to 540,000 barrels per day. Remember that the first phase of this expansion started up during the fourth quarter of 2007. All phases are now complete and commissioned. In Western Australia on the September 1, the fifth Train at the North West Shelf’s Venture liquefied natural gas facility became operational. This production facility is expected to increase the joint venture’s export capacity by about four million metric tons of LNG annually to 16.3 million metric tons. During the second quarter, in conjunction with our joint venture partners, first oil was achieved from the Moho-Bilondo field in the Republic of Congo. Please turn to slide 18. Other projects that have achieved first production during the first three quarters of 2008 are ACG Phase III in Azerbaijan and Brodgar-Callanish in United Kingdom. I’ll now touch on the remaining project startups for 2008. In the Gulf of Mexico, the last stages of commissioning are taking place at the Blind Faith facility, and first oil is anticipated in November. There was no damage to the facility during Hurricane Ike, but it did disrupt commissioning activities. In Indonesia, the next phase development at the heavy oil Duri field remains on schedule; it is also expected to start up in November. Now, let’s turn to slide 19. Looking forward to 2009, I’d like to provide you with a status on the major capital project milestones that are anticipated next year. Let’s start in the Gulf of Mexico deepwater with our Tahiti project. The project is progressing on schedule. The spar hole was installed during the first quarter and the topside modules during the third quarter of this year. The facility sustained minor damage during hurricane Ike and will be repaired during ongoing hookup and commissioning activities. However, this will not delay the projects and we still anticipate first oil by the third quarter of 2009. In Brazil, at the Frade field construction of the FPSO is 85% complete with a sail-away from Dubai expected in late December. First oil is expected during the second quarter of 2009. In Angola, the Tombua Landana project remains on schedule, to meet first oil during the second half of 2009. The hurricanes in the Gulf of Mexico, did not significantly impact the schedule for sail-away of the various compliant pile tower components. The Large Scale Steam Pilot in the Partitioned Neutral Zone also remains on schedule. If this pilot is successful, it will lead to a full-field development at Wafra. First steam injection is expected during early 2009. Finally, I would like to provide a summary of other key 2008 upstream highlights. Please turn to slide 20. For September 10, we announced the extension and amendment of the Partitioned Neutral Zone operating agreement with the Kingdom of Saudi Arabia. This agreement extends the existing arrangement for 30 years through 2039. In Canada, at the Hebron field, formal binding agreements were signed in August between Hebron project proponents and the government of Newfoundland and Labrador. These agreements paved the way for the project to proceed. During the third quarter, Chevron transferred operatorship to ExxonMobil following ratification by co-venture partners. In Australia, our LNG projects are progressing toward key milestones. At Gorgon, the joint venture is pursuing a project scope of 3-5 million metric tons per annum LNG trains. A final investment decision is expected after environmental approvals have been provided by the State and Commonwealth for the third train proposal and following the completion of engineering and design. Wheatstone, which represents a tremendous growth opportunity for Chevron Australia is progressing towards FEED. It builds on our extensive natural gas resources in Western Australia and is expected to make our company a leading natural gas supplier and operator of LNG facilities in the Asia-Pacific region. We announced our attention during the first quarter to develop Wheatstone as a grain field onshore LNG and domestic gas project. And finally at Chuandongbei, we expect the initial FID by the end of this year. The appropriate engineering and design work required to sanction the project work. The project is on track. We assumed operational control of the existing operations in August. This concludes the project update and now I will turn it back over to Steve. Steve J. Crowe: Thank you, George. That concludes our prepared remarks. We will now take your questions; one question and one follow-up per caller, please. Matt, open the lines for questions. Thanks.

Thank you, sir. (Operator Instructions). Our first question is from Mark Flannery from Credit Suisse. Your question please?

Thanks. Yes, just a question for George, while coming into budgeting season, things are looking very different on the commodity side. Nobody really knows what’s going to happen in 2009 of course, but given what’s happened to oil prices. Could you tell me what you’re thinking about when you think about the ’09 CapEx budgets for the upstream, particularly with regards to the more capital intensive end of the spectrum? I’m not looking for a number, because I know we won’t get one, but just what’s your thought process around that right now?

Let’s just first start off that we haven’t finished our budgeting process we’re going through the approval process, we’ve been working through that. Our thought processes on any project that has already moved into construction of past FID, those projects will move very much through their cycle would never slow those down. And we anticipate trying to hold our capital spending pretty much in line of where we’ve been this year. We don’t like fluctuating our capital spend up and down. Our long-term view on pricing has not changed. So I would look at this point at capital spending very similar between years and recognize if we have something different, we want to change. We have flexibility on near-term projects not our long-term projects. We really can’t back-off for long-term projects.

Mark, let me just expand a little bit on just the mechanics that George alluded to. We're right in the middle now of finalizing our business plans and the capital spending for 2009, and per our normal practice it would be our intention to have a release and provide the 2009 capital program sometime around the middle of December. So, about six weeks from now, I think, would be the approximate time you'll hear our final program for next year. Do you have a follow-up question?

I do and it's on the same topic. I wondered, George, could you characterize the capital expenditure program that you have or you are putting together for 2009. How much of that would you describe as fully discretionary i.e. not part of projects that have gone through FID, not part of projects about to meet FID, that kind of thing. What's the wiggle room would you think in the budget?

Just an estimate without numbers in front of me and recognizing that probably 75%, 80% of our project expenditures are related to projects that are post FID, so, those are pretty far along at this point. So there is not a lot of wiggle room in the first year. Our wiggle room in capital spending is much greater in the second year of our budget cycle, and of course, very large amount in our third year of our budget cycle.

That's very helpful. Thank you very much.

Thanks, Mark. May we have the next questioner please?

Our next question is from Paul Cheng of Barclays Capital. Your question please?

Hi, gentlemen.

Hi.

Hi, Paul.

My question is related to the CapEx. I know you are not going to talk on numbers, so I am not asking that. But, George when you are looking at with potentiality, oil surfaces cost and the raw material cost [next year] everything are coming down. Is that a trade-off, there is certain project, if you delay it even if they are already FID delayed, you may be able to get a much lower cost structure. So, want to see that, I mean, how you view on that?

Well, there is no doubt for projects that have not reached FID where you don't have contracts with and what we are expecting is we are expecting that the cost of goods and services are going to come down. So, we would I think look very strongly at slight movements on projects that made sense. From the cost of building them, if it's going to come down we would look at sliding those a little bit. I actually see this as a real opportunity for companies like Chevron. I do expect the cost of goods and services to come down. I think the financing is going to hurt others to move projects forward. So my expectation is shipyards and equipment manufacturers, there'll be less pressure on them than there has been. So, I think, there is going to some benefit for some of our future big projects with cost reductions.

Paul, do you have a follow up question?

Yes, if I could. Yes, actually, somewhat unrelated Tengizchevroil now you said 540,000 barrel per a day. I think there is a long time objective, when they get to a 700,000 barrel per day plus. I want to see if George has any update on where we are in that process?

Well let me deal with the expansion. Our expansion, the name plate on it was 540. We've reached that and we don't yet know if we can get a few more barrels out of it, but my expectation is we are probably going to be able to get a few more barrels, and maybe by our March meeting with the analysts that we'll have a little more word on that to see if we’ve been able to increase the capacity further. I believe, I mentioned that our Analyst Meeting earlier in March this year that we were looking at the next expansion for Tengiz. We’d like to move that engineering work forward as fast as we can. We’ve learned an awful lot about what we can do on big, big projects in the Kazakhstan area of where we operate Tengiz. So, it's a good time to be ready to move forward with the next expansion, and I know a little more information about the performance, of course, on the gas injection as the year plays on out. So, I think, all of those things line up for us to want to move the next expansion forward, of course, we have to get all of our partners on board with that.

George, can I put in a quick question in here? For 10-Q with the [SEC], you guys will be able to put more reserve this year?

I think it's a little premature to talk about reserves; we’re just in the process of going through our reserve reviews around the world, and I’d really rather wait to talk about reserve bookings preferably actually to the March meeting, when by that time we’ve done all our work.

Thanks, Paul. And I would just add that the current SEC rules are still in place, although they’ve come out with a proposal for modification of the definition, but it’s still using prices at a point in time at the end of 2008. And as George mentioned, we may have some preliminary numbers that we can share with you in terms of reserves in the January call, but we don't really finalize all of our work until February and have it available then for the 10-K and then further discussion at the March '09 Analyst Meeting.

Thank you.

Thanks, Paul. May we have the next questioner please?

Your next question is from Neil McMahon from Sanford Bernstein. Your question please?

Hi, I've got questions related to your project timing. Just moving on to some of your previous answers, George, you mentioned that Gorgon, you're not planning 3 million - 5 million ton trains and one presumes since it hasn't gone to FID, yet. But there is scope to discuss materials costs and contractor costs. Do you have any rough idea, what timing you would expect Gorgon to come on and at? And if the current credit markets or falling prices for products and services may delay that a little bit?

I think may be in a earlier question, I was trying to foreshadow that I actually see a potential advantage for big LNG projects that have not reached FID. The cost reduction of goods and services is really I think, very, very good news for those kind of projects, so, very positive from that point of view. Our long-term view of prices of oil and gas, have not changed, which is how we always looked at our economics. So in some ways with cost of goods and services, I think potentially coming down, it's a benefit to those large projects. And once again it reinforces this financial crisis, reinforces the advantages that companies like Chevron have, we have very, very strong balance sheets and are not, I think, held hostage or to getting loans to do our projects. So, from that perspective, I think, it may actually be a benefit for us in some of our very, very large projects.

I'll just add. We have the advantage of having a very strong balance sheet and we got to this point because we look a long-term view of the commodity price cycle, strengthened our balance sheet when commodity prices were rising, so as to whether a downturn or advantage ourselves of opportunities. We also have the other aspect that George mentioned, and that is, we have a great project queue. So, tremendous strength, but also tremendous opportunities. Neil, do you have a follow-up?

Yes, Steve and I appreciate all of that, and that's good to hear. It was really, again on Gorgan, just a rough timing on when that project would be coming on, I am presuming the second half of the next decade? And then, as we are talking about projects, maybe George could give an update on Jack and St. Malo, as well?

Let me deal with Gorgan saying our target is FID in the second half of 2009. So, sometime mid-year or little bit after we would like to be the FID. I would then like to come out as we approach FID and then give a definitive date. I don't think it's quite as long as what you mentioned, I'd pull it back a little bit from there. But, I would much rather talk about that in detail once we get closer to the FID point. Okay, and then on Jack and St. Malo. We still have appraisal wells to complete on both Jack and St. Malo and until we get those appraisal wells drilled and evaluated, we really can't comment on further timing. I would anticipate that we would be able to make pretty strong views on timing for Jack and St. Malo, between the analyst call in late January to the time we get together in March; somewhere in that timeframe, we should have a pretty good idea of our path forward.

Right, thanks.

Thanks, Neil. May we have the next questioner, please?

The next question is from Paul Sankey of Deutsche Bank. Your question please?

Hi, guys. Just one on upstream, and one on finance, if I could, I’ll slip in a few thoughts to it. Firstly, George you mentioned 2650 would be your production level for 2008 at $70 oil. Could you indicate what level you would expect for 2009, given the impressive list of projects you’ve listed? Secondly, the decline rate towards 4% is what you said. Would that be sensitive to the oil price being lower in terms of how hard you defend that number? And finally, on the upstream side, if you could talk about exploration and any highlights that you’ve got coming up over the coming year? Thanks.

It’s a long list there. Let me…

That was one question, George.

Very well strung together. The 2009 production number, I’m much preferred to talk about that at the January or have Steve or others talk about it at the January meeting. And I hope everyone recognize that there’s an awful lot of moving parts going on right now. Hurricane restoration has potential significant swings, and as I mentioned in my comments today, three-quarters of the remaining barrels that we have off there are not dependent on what we do; they’re dependent on third-party pipelines. So we have that concern. We have all these projects coming on, and including Tahiti and the timing of all these big projects when they come on, one quarter, one month, all of these make a significant difference. A lot of these points will be nailed down by the end of the year. We are going to know an awful lot about where we are on hurricanes, we're going to know ramp up on Agbami to a much better extent. Blind Faith was going to be owned by then, so we'll have some performance data on it and we'll have a pretty good idea of exact timing of Tahiti, which is a bunch of big barrels for us, so another project where we have high working interest. So from that perspective, we typically give our guidance for 2000 or that year in the January meeting. So we're going to hold with that and we'll give that guidance at the next quarter's call.

I'd just add on top of George's comments for all the reasons that he cited. As we've done year, when we give the guidance for 2009, net of O&G production, we'll ping it off a specific crude price recognized in the workings of various contract agreements overseas can affect net production. I think you had another question on…

Yes, sorry. You mentioned that you implied that it was close to 4% decline rate based on higher activity levels in defending the base. I just wondered if with the lower oil that’s going to be still defendable, I guess it's really a follow-up to the CapEx question in some ways.

Well, we've tried to take the price effects out our decline rate analysis and give you numbers that really don’t reflect the price itself. We try to pull the price effects out of there to the best we can.

No, I'm thinking more about activity levels, George? You know are you going to do less, because fuel price is lower?

Once again you got to remember, a lot of contracts for rigs you're already set for a year and six months. So there is limited change that you are going to make in a short-term program. And I would tell you, typically, the very strongest returned projects, when you look at rate of returns on your investment tend to be those projects that are off of current infrastructure and tie-ins, so those development wells and workovers tend to have the very, very best economics. I would tell you that we will make decisions during the year for certain contracts as they are coming up if it looks to be advantageous for us to decide to go out to the market and bid for a rig in lieu of doing a contract extension we will do that to make sure we attract the best prices to do our work. So we will make some choices like that, very tactical choices during the year. I can't at this point in time speculate how that will play out, it could have some minor effect on our base decline. But it is just way too early to speculate.

George, the third part of…

Third part of one…

Third part of the first question (inaudible)…

Our exploration focus is still very much, in those focus areas I've talked about, we have been drilling wells in Australia, we haven’t made any announcements, but we have been doing quite a bit of work in Australia. And I expect we will cover that later through some announcements. We are just starting several wells in the lower tertiary, in the deepwater Gulf of Mexico, it's too early to make anything of a report expect the wells have been spuded. And we’re continuing to drill some expiration wells in the focus area of West Africa, but I don’t really have any specific updates beyond that. We’ll give a very broad update and I’d say detailed update once again in our analyst meeting in March.

But the development here, it feels like a quiet year for expiration.

Our exploration program, I will tell you, we try to keep it very consistent. We try not to yo-yo it up and down, that’s my expectation again for next year. We always like to drill anywhere from 15 to 20 high impact wells around the world and then of course our large number of appraisal wells and delineation wells. So my expectation would be a program similar to what we’ve done in the last few years. Once again, we don’t like to yo-yo them up and down. We’ve got rig contracts, we plan for the long-term and we try to maintain even this in those programs.

Paul, you had one more question.

Yes, very quickly, one for you Steve, and that would be pension, anything to say about pension funding and the outlook there. Thanks, so I’ll leave it there. Thank you.

Thanks, Paul. Certainly the market value of our Pension Trust Fund obviously has gone down with the market in the last several months. We don’t have any required funding requirements under the PPA or [RISSA]. As you may recall, particularly earlier in this decade, we have an approach towards funding that we call opportunistic funding. When we have sufficient cash or cash flows and can assure ourselves of tax deductibility and making a contribution. I guess, I would say at this juncture the disclosures that Chevron’s made in its 10-K and 10-Q still pertain, including our ongoing economic review to fund more than we have there, indicated in our SEC filings. So keeping in mind that the PBO obligation under PPA discount rules results in higher discount rates. The magnitude of the funding is better than you might think just looking at the reduction in the asset values. So I guess, I’d take you back to our disclosures that we have made in earlier 10-Qs and the one that you will see in our 10-Q next week. May we have the next questioner please?

The next question is from Michael LaMotte of JPMorgan. Your question please?

Thanks. Good Morning, guys. I’d like to follow-up on this base decline number George, if I could quickly. In slide 13, 55,000 barrel a day number implies a 2.1% rate, at the analyst meeting in March, the same slide showing ’07 versus ’06 was about 1% decline. And I know a 1.6%, I guess. In your remarks you mentioned operating challenges in Azerbaijan is one of the reasons for the base decline. The question I am asking is, is it all Azerbaijan? Are there issues related to that, that explain that whole delta and can 2% hold?

I keep going back and we track this base business very closely, because we have good success, it has been lower for now, I think probably 4-5 quarters less than the 4% to 5%. I would tell everybody, remember those barrels are in the bank, moved our production up and held our production. So that’s a real positive, but I tried to also give a little color on this 55 that there were other things going on in there, that benefited our base and reduced that decline. One of those was a unitization agreement in Indonesia that we highlighted in an earlier call; I believe that was a first quarter call.

It was first quarter.

First quarter call and that had an impact, and we've also had better marketing results, gas sales in the Asia-Pacific region that in effect has raised the amount of base production we've had there. So, it's not really a fair comparison on base decline without taking that into effect, and when you add those pieces back, it gets back to the low end of this. It gets back in the 4% range, approximately. So, we feel good for planning purposes. We're going to continue to hold this 4% to 5% as kind of our planning model. But then, when we look at our actuals and the processes we put in place, we're hopeful that we're going to continue to see, that we're able to do a little bit better than that. So, we're going to look back at performance and we're going to plan forward, at least for some period of time, still in this 4% to 5% range.

Mike, do you have a follow-up?

I do. Thank you for that color, George. If you wouldn't mind expanding a bit on the impairment to North Sea assets, as well?

Jim, do you want to feel that one?

Yes. We had impairment of number of very small fields in the Dutch North Sea, as well as the U.K. North Sea, these are mature fields, and they are very small partially, in terms of production. So, those are not tremendously material to us.

They were all reaching the end of their productive lives. So, we took the asset values down.

Okay. Very good. Thank you.

You bet. May we have our next questioner, please?

Your next question is from Erik Mielke from Merrill Lynch. Your question please?

Good morning, gentlemen. I have two questions, the first one for George, and the second one for Steve, probably. Firstly, on the partition neutral zone in Saudi, and I understand that you are not willing to get into a huge reserve discussion at this point. But can you clarify whether the extension of the contract would automatically lead to additional reserves being bookable for you?

Our normal reserve process only allows us to book reserves through the existing contract life; the contract life without the extension would have been ending in February of 2009, and now it will go to 2039. So, with that extended period, there will be proved reserves that will be booked as a part of that extension.

It's very clear. Thanks.

And do you have another?

Yes. My second question is more on cash management. If I hear you correctly, it sounds like CapEx is something that you intend to keep at current levels, and even if prices were to go let's say $10 lower than where they are today. And for the rest of your cash management, how do you balance between holding cash, accelerating buybacks, or scaling back buybacks, and potentially increasing dividends? And then also, can you clarify where are you going to keep your cash?

Thanks, Erik. Well, I'll begin on a short-term issue. It's our intention here in the fourth quarter to maintain the share buyback pace at $2 billion in the fourth quarter, just as we've done for the last five quarters. In terms of cash management and balancing, I think first and foremost, we want to make sure we fund the capital program that we feel is such a robust program with a very deep queue. So that's our first and foremost use of operating cash. Secondly, we are mindful of our 21, 22 year record of increasing annual payouts and our dividend, and would fully want to maintain that progress overtime. Thirdly, as I had alluded before, we do want to maintain a strong balance sheet through the commodity price cycle and I think we're in enviable position, right now, as having one of the strongest balance sheets in the industry. As to share buybacks, we take all of the other considerations into account and make a determination as to whether or not there is enough of a cash flywheel to fund further buybacks. We take a look at economic conditions, market conditions going forward and would plan on giving guidance to the investment community, just as we're doing now at the call each quarter, for at least, one quarter, ahead. But as for right now, we're coming off two quarters of consecutive record earnings, a very, very strong balance sheet, strong cash flows, more cash than debt and we see another $2 billion here in the buybacks, in the fourth quarter. Can we have the next question, please?

Our next question is from Peter McNally from Galleon. Your question please?

My question has been answered. Thank you.

Thanks, Peter. Can we have the next questioner please?

Our next question is from Mark Gilman from Benchmark. Your question please?

Guys, good morning, good afternoon. George, I am wondering if you could tell me associated with the new concession of the partition neutral zone, did you benefit or would you benefit from any change in fiscal terms, should you decide to proceed with the full field steam flood there?

Mark, first off, it's an extension of the existing contract there and at this point in time, I will not discuss the terms of a future full field steam development. I would rather hold that off until we get closure to that decision point.

Okay. Let me turn to my follow-up. I believe you received approval to proceed with them across a straight development project or with respect to some of the resources that [UNICCO] had identified years ago. I am curious as to whether that gas is to go to Bontang or to be dedicated to the domestic market and is there an agreement to allow for [protomania] to participate as an equity partner.

Mark, that agreement to develop and the plan of development there has not been fully approved. So, we don't have all the approvals yet on that. So, at this point, I really can't talk about it because we don't have all the approvals. It has been reported in the press a couple of times but all the pieces have not been put together, so it has not been reported correctly.

Okay. Since I got two strikes, let me try one more quickly. George with respect to the production sharing contract impacts that you'd cited in several of your slides. Can you segment that between those losses that would be considered permanent associated with threshold return and/or full capital cost recovery versus those reductions that are associated more with operating cost and continuing capital cost recovery?

Mark, I can't do that at this time. That's a lot of detail. I will tell you, some of it has been related to triggers, in other words, return triggers that will change the distribution in effect of profit oil. So, we have that. We have some that is royalty pieces, which reach triggers with higher royalty rates. But, first off, I don't think we ever would try to share that kind of detail, that's an awful lot of detail. We'd rather try to give you each year kind of a guideline that kind of matches what we think is going to happen for the year at a price scenario or a price range. This last year, we've been telling you it's been about $2 for every dollar a barrel impact on price, it's about 2000 barrels per day change and that's kind of been what it has, we will update that again for the year 2009, which we will be once again looking-forward and look at price impacts and production impacts together.

Mark, what we will try to do on the January call then is, when we give our guidance for 2009 production at a specified price. Based on that specified price, we'll try to give the investment community a rule a thumb to use to know how to adjust that if prices are above or below that amount.

Okay, guys thanks. I'm taking my back and going back to the dugout.

Okay, Mark. May we have the next questioner please?

Our final question today is from Neil McMahon of Sanford Bernstein. Your question please?

Hi. Just not really a follow-up, something a bit different for you, Steve. What was the tax rate difference between the second quarter and the third quarter?

Of this year?

Of this year, yes.

In the third quarter our tax rate was just about 45%. And in the second quarter it was about 49% and below a rate for the third quarter of this year was associated with a greater proportion of income being earned in tax jurisdictions with lower tax rates. But we also have an impact in the second quarter of a reduction in the tax rate in Bangladesh. So, on an ongoing basis, as we have guided in the past, allowing for the different taxing jurisdictions and being an integrative company, our guidance would be to use sort of an average rate of about 45% or in that neighborhood at least.

Okay, that’s great. Thank you.

Thanks, Neil. Mark or Matt, are there any other questioners in line?

We have no further question as this time.

Okay. Well, thank you, Matt. In closing, let me say that we appreciate everybody’s participation on today’s call. And I especially want to thank each of these analysts on behalf of all the participants for their questions during this morning session. Matt, back to you.

Ladies and gentlemen, this concludes Chevron’s third quarter 2008 earnings conference call. You may now disconnect. Good day.