Welcome to Chevron's fourth quarter 2007 earnings conference call. (Operator Instructions) I will now turn the conference call over to the Chairman and Chief Executive Officer of Chevron Corporation, Mr. Dave O'Reilly. Please go ahead, sir. David O'Reilly: Thank you, Matt, and welcome to Chevron's fourth quarter earnings conference call and webcast. I am joined by today Steve Crowe, our Chief Financial Officer; and Jim Aleveras, General Manager, Investor Relations. Our focus today is on Chevron's financial and operating results for the fourth quarter and will refer to the slides that are available on the web. Turning to slide 2, before we start, please be reminded that this presentation contains estimates, projections and other forward-looking statements. I ask you to review the cautionary statement on this slide. I'll begin with slide 3, which provides an overview of our financial performance. The company's fourth quarter earnings were $4.9 billion or $2.32 per diluted share. Full year results of $18.7 billion mark the fourth consecutive year of record earnings. Our fourth quarter earnings were 29% higher than the fourth quarter of 2006, reflecting higher crude prices, which more than offset weaker downstream results. Fourth quarter earnings rose 31% compared to the third quarter of 2007, which Steve will discuss in detail shortly. Return on capital employed for the year was 23% and our debt ratio at yearend was 8.6%. Stock buybacks during the quarter were $2 billion and $7 billion for the year in total. Total shareholder return for the year was over 30%. Turning to slide 4, our total capital spending for 2007 was $20 billion. Upstream spending accounted for $15.5 billion or 78% of the total. Our cash C&E, which excludes our share of equity share of affiliate outlets totaled $17.7 billion for the year. Our announced capital program for 2008 of $22.9 billion represents an increase of $2.9 billion over 2007 expenditures. About $2 billion of the increase is earmarked for upstream, reflecting the capital-intensive phase of some of our long-term growth projects. The change in downstream spending is due to a number of investments to operate our refining network. Steve will now take us through the quarterly comparisons. Steve?

Thanks, Dave. My remarks compare results of the fourth quarter 2007 to the third quarter. As a reminder, our earnings release compared fourth quarter 2007 to the same quarter a year ago. Turning to slide 5. Fourth quarter net income was almost $1.2 billion higher than the third quarter. Starting with the left side of this chart, significantly higher oil prices and slightly higher natural gas prices benefited the company's upstream results worldwide. Higher international liftings were also a factor. Downstream results fell from the prior quarter. The third quarter included a $265 million gain on the sale of our fuels marketing assets in Belgium, Luxembourg and the Netherlands. The variance in the residual "Other" bar is the net of everything else. Slide 6 summarizes the results of our US upstream earnings, which improved by about $240 million between quarters. Higher realizations, primarily for liquids, benefited earnings by $400 million. Chevron's US crude oil realizations were up roughly $13 per barrel. While the average quarterly price of WTI increased more than $15 per barrel between quarters, much of our Gulf of Mexico crude oil production is priced on a lagged basis and rose about $11 per barrel. Production volumes fell 1.5% between quarters largely due to operational downtime and field declines in the Gulf of Mexico. The $90 million DD&A benefit primarily reflects the absence of the third quarter's provision for asset retirement obligations. Exploration and operating expense increased about $165 million between quarters. Exploration expense was up about $90 million mostly on higher well write-offs. Operating expense was $75 million higher due to higher production taxes and maintenance costs. "Other" primarily reflects lower gas marketing margins. Turning to slide 7. International upstream earnings for the fourth quarter were almost $1.2 billion higher than the third quarters' results. Higher oil and gas prices increased earnings by about $700 million. Unit realizations for liquids rose by $13 per barrel, in line with the percentage change in Brent spot prices. Higher liftings during the quarter, particularly in Azerbaijan, Kazakhstan, Australia and Nigeria, improved earnings by $280 million. Tax items benefited earnings by $210 million between quarters. This mainly reflects the absence of adverse tax adjustments last quarter along with net favorable adjustments spread across a number of countries in the current period. The variance in "Other" reflects the absence of asset impairment charges recorded in the third quarter, which were offset by higher operating expenses. Slide 8 summarizes the change in worldwide oil equivalent production, including volumes produced from oilsands in Canada. Production rose by 22,000 barrels per day between quarters. During the fourth quarter, US production decreased 11,000 barrels per day compared to the prior period, mainly due to operational downtime and field declines in the Gulf of Mexico. Outside of the US, oil and gas production increased 33,000 barrels per day between quarters. The increase reflected the absence of third quarter shutdowns in the UK and Azerbaijan. The Tengiz expansion project in Kazakhstan came on stream late in the fourth quarter and was gradually ramping up. Partially offsetting was a drop in Canadian volumes due to the November fire at the Athabasca upgrader and lower Hibernia production. Turning to slide 9, we'll now briefly discuss our 2008 production outlook. As a reminder, during our fourth quarter 2006 conference call a year ago, we estimated that total 2007 production would be about 2.6 million barrels a day. That estimate assumed an oil price of about $60 per barrel. Despite the impact of higher crude oil prices on net production, we were able to exceed our estimate by 19,000 barrels a day. The increased volumes came from major capital projects, fewer storm-related shut-ins and lower base business decline rates. As we look to 2008 production in a $70 per barrel price environment, we are estimating a production increase of a little more than 1%. If prices were to remain at the current $90 level, production would be on the order of 50,000 to 60,000 barrels a day lower. As noted in the slide, the 2008 production reflects an overall base business decline rate of 4.5%, which is consistent with our historical experience. We anticipate that the start-up of major capital projects in 2008 and the ramp-up of volumes from projects begun in earlier years will had about 150,000 barrels a day. These projects include the Tengiz expansion in Kazakhstan, Agbami in Nigeria and Blind Faith in the Gulf of Mexico. We also anticipate continued production growth from our Bibiana field in Bangladesh. Looking beyond 2008 production, we reaffirm our objective to grow production volumes from 2005 to 2010 by an annual rate of 3%. Before moving on to the downstream, I'd like to briefly address our reserves replacement for 2007. At the end of February, we'll file our Form 10-K with the SEC, which will have considerable detail on our oil and gas reserves. We haven't yet completed all of our governance reviews, but I can tell you today that we anticipate the 2007 reserves replacement ratio on an oil equivalent basis will be in the 10% to 15% range. This low replacement rate was affected by three primary factors. First, SEC rules require that reserves be calculated using yearend prices. The price of WTI increased $35 per barrel from the end of 2006 to the end of 2007. This large rise in commodity prices reduced our reported reserves under production sharing contracts and variable royalty arrangements that are common in international operations. We estimate the impact of higher prices reduced our replacement ratio by about 30%. Second, sales and acquisitions during the year reduced the replacement ratio by about 10%. And third, although we made a great deal of progress on our major development projects, the timing and circumstances were such that we were unable to book large reserves additions for these projects or for contract extensions in 2007. The timing of reserve recognition for these types of events vary significantly from year-to-year. Given the number of major projects in development, we anticipate a meaningful impact on reserve additions in the years ahead. Besides the information that will be presented on reserves in the 10-K, George Kirkland will discuss this topic and our outlook in more depth at the meeting with security analysts and it's webcast on March 11. He will discuss not only reserves, but also the success we've had in adding resources last year. Moving to the downstream on slide 10. US downstream operations posted a loss for the second consecutive quarter. Refining and marketing indicator margins on the West Coast improved slightly in the fourth quarter, while there was small declines on the Gulf Coast. On balance, this effect was a favorable $35 million between quarters. Higher volumes on like product for refinery production benefited the fourth quarter earnings by $50 million compared to the prior quarter. In our conference call last quarter, we mentioned the adverse impact of timing effects, such as provisionally priced foreign crude as crude prices increased $11 per barrel during the third quarter. Over the fourth quarter, the average price of WTI increased by $15 per barrel, adding to the adverse impact of this timing effects as shown on the chart. The other variance reflects higher operating expenses partly stemming from shutdowns of the Pascagoula and El Segundo refineries. Also included in this amount are the costs for provisions for litigation offset by a gain on the sale of our proprietary credit card businesses. While this slide accounts for the change in earnings between quarters, the fact remains that our US downstream business operations lost money in the fourth quarter. On an absolute basis, two major factors cause this. First, our Pascagoula refinery's crude unit was down and our El Segundo refinery was undergoing a coker upgrade to process heavier crude. This raised our feedstock costs, so our actual margins were less than the indicator margins. It also increased our operating expenses. The second factor was the sharp rise in crude oil prices. This caused us to incur loses on provisionally priced crude and to have derivative loses under mark-to-market accounting along with inventory effects in the period. These combined effects amounted to roughly $400 million in the fourth quarter. Turning to slide 11. International downstream earnings fell $228 million from the third quarter's results. Refining indicator margins were generally higher, while marketing margins were mixed across our internationally geographic areas. On balance, higher overall fourth quarter margins offset a small adverse volume effect to produce the $40 million favorable variance shown on the chart. Most of the timing effects, which reduced earnings by $80 million, were associated with inventory accounting. The third quarter included a $265 million gain on the sale of our Benelux fuels marketing operations. The $77 million benefit shown in the "Other" bar includes favorable variances in foreign exchange as well as other items that were mostly offsetting. Slide 12 shows earnings from chemical operations were $69 million in the fourth quarter compared with $103 million in the third quarter. Results for olefins declined during the quarter primarily due to lower ethylene and polyethylene sales volumes and margins. The decline in aromatics was also largely due to lower volumes and margins. Included in the "Other" bar are tax benefits and the absence of the third quarter environmental provision, partly offset by lower additive earnings. Slide 13 covers all other. Fourth quarter results were net charges of $237 million compared to net charges of $193 million in the third quarter. The absence of third quarter environmental provisions was largely offset by a decrease in net interest income. The "Other" bar includes the impact of tax benefits offset by higher yearend corporate expenses. Fourth quarter net charges for this segment fell above our standard guidance range of $160 million to $200 million as we had indicated in our interim update. That concludes our brief analysis of the quarter. So Dave, back to you. Dave O'Reilly: Okay. Thank you, Steve. And before I get to your questions, let's have a brief recap of our strategic progress in recent months. So please turn to slide 14. With our partners, we made the final investment decision to construct a $.2 million metric ton LNG plant in Angola, in which Chevron holds a 36% interest. We signed a 30-year production sharing contract with China National Petroleum Corporation to assume operatorship and hold a 49% interest in the development of the Chuandongbei natural gas area in Central China. As Steve mentioned, we initiated production from the first phase of expansion at our 50% owned Tengiz field. And although this phase did not add significantly to fourth quarter production, earlier this week we announced the milestone of increasing daily crude oil production capacity by 90,000 barrels to about 400,000 barrels per day. The addition of full facilities in the second half of 2008 is expected to further increase daily crude production capacity to 540,000 barrels per day. We signed an agreement to increase daily sales of natural gas in Thailand by 500 million cubic feet to 1.2 billion cubic feet by 2012 from company-operated offshore blocks 10 through 13, and in late October we had received 10-year extensions for these concessions to the year 2022. Our 50% owned Yosu refinery in South Korea completed its major upgrade to process heavier crude into light products. And in December we completed the second phase of modifications at our refinery in El Segundo, California, also enabling the processing of heavier crude oils into light products. In summary, 2007 was a very successful year for Chevron and our shareholders. We achieved record earnings, investors are in excellent queue of capital projects, increased our annual dividend payment for the 20th consecutive year, and repurchased $7 billion of shares, and our total shareholders return was the best among our peer group. As we enter 2008, we look forward to the completion of several major growth projects and further progress on our strategic goal. So that concludes my prepared remarks and Steve's as well, and we'll now take your questions. One question and one follow-up per caller please, and Matt, please open the lines for questions. Thank you.

(Operator Instructions) Our first question comes from Paul Cheng of Lehman Brothers. Your question please.

Hi, good morning guys.

Good morning, Paul.

This is either for Steve or Dave. You talked briefly on the reserve replacement, and you're saying that you have not been able to book any reserve from the major project. Just your sense on the Angola LNG, and you have a contract extension in Thailand, Gulf. You also started with Tengiz, none of those that has been able to allow you to book any reserve in 2007? Dave O'Reilly: Thank you, Paul. That's a good question and a fair question to ask. For the Angola LNG, we are very confident in the resource base as the plant owners have the rights to virtually all the associated gas in offshore Angola. However, before booking reserves from properties owned by others, we are securing third-party certifications. We anticipate those reserve adds in 2008 and in future years as the offshore Angola properties are developed. With respect to Thailand, we're also very confident of 1 billion barrel probable reserve base. We'll move into the P1 reserves as we delineate the field and the projects mature. But at this point at the time of signing the concessions, we don't meet the requirements for P1 for the SEC definition. Do you have a follow-up question Paul?

How about the Tengiz that the solid gas [re-injection] presume that that would improve the recoverable rate? Dave O'Reilly: I think where you see our 10-K, you'll find that we have a lot more detail, Paul, on increased recoveries where they are appropriate. But I think getting back to the year, I would like to emphasize the point that the reserves are there, the resources are there, but because of the fact that we have to go through a certification process because of the complexity of the Angola situation as well, technical reasons. We booked reserves in Thailand on an incremental basis because these are multiple small fields and small compartmentalized resources that you must actually develop a plan to drill and have the drillbit involved before you book the reserves. So we're confident that the resources are there. But it's a matter of timing for booking these reserves. Thank you.

Thank you.

Paul, I'd also mentioned that in about five weeks when we have our Analyst Meeting and webcast in New York, George Kirkland, our EVP of Upstream, will talk more about the reserves booking, but he will also talk a good deal about the success we've had with the drillbit and the resource adds that we've had in 2007. So, you and others will be able to get a lot more detail on this subject at that point. Thanks very much for your question though, Paul.

Thank you.

Our next question is from Arjun Murti of Goldman Sachs. Your question, please.

Thank you. I had another question on the reserves. I think we certainly appreciate that Chevron does have a sizeable resource base that we call 3P reserves, and in any one year there can be volatility and one of these get booked to crude reserves. We understand the SEC pricing effects and we appreciate those disclosure, we appreciate the asset sales. But I guess it's now four years we're decently below 100%, and Chevron especially, both as a merged company or legacy, had such a long track record of exceeding 100% that something has meaningfully changed here in the last four years, despite you all actually having very good exploration success in signing a number of contracts. Is it just that, in the old days the legacy assets, North Sea, US and so forth, Indonesia, you were more predictably able to book the reserves in crude year-in, year-out, and we're in a transition to these new reserves, were the timings is more extended or has something else changed that's just causing now so many years of sub 100% even if we make some of the pricing adjustments in the asset sale adjustments? Dave O'Reilly: Arjun, this is Dave. I'll take that question. First of all, I think, well, your observations are good one, but I think that if you go back, say, to the '90s, back over the last 20 years or so, the configuration of our portfolio has changed quite a bit. In those days, we were adding multiple, multiple small amounts of reserves over a multiple, multiple smaller fields when we get thousands of fields and thousands of developments. Our portfolio has deliberately shifted, of course, over the last 10 years or more, and now we are looking at significantly bigger projects that are much more lumpy. So you will see choppiness here in the reserves bookings. Now having said that even over the transition period over the last 10 years, our reserve replacement has been in excess of 100%. But, you're right. In the last few years, it has been much more choppy. So I expect you are going to see years when we are significantly above 100% on a one-year basis as things come together, but you're also going to find years when we're below it. And of course, all of that has been exacerbated by the pricing effects that you've talked about. I think if we look over the last few years alone, 600 million or 700 million barrels of oil have just disappeared. Actually it's a result of a fairly good thing and that is higher prices, higher earnings and higher cash flow. So you are going to see a more choppy period ahead some years when we're below, some years when we're substantially above, and it's a matter of timing. But we are adding the resources. And the examples that we cited in our response to Paul Cheng's question, I think are very good examples of projects that are complicated, particularly in the case of Angola. That required third-party certification because we don't actually, in the case of Angola, own all of those reserves. But we are entitled to them and we are entitled to book them as we are certified and following SEC rules. So thank you for the question.

Did you have any follow-up you'd like?

That's a very full answer, I appreciate it. Dave O'Reilly: You're very welcome. Thanks very much for your question.

Our next question is from Robert Kessler of Simmons & Company. Your question, please.

Good morning, gentlemen. I wanted to see if we could look a little bit more closely at your 2008 updated production outlook. If I go back to what you were expecting in the March 2007 Analyst Meeting, I want to say the number was closer to 2.8 million barrels a day, so roughly 150,000 barrels a day higher than what you've got in your slide today. I know a lot has changed since then. Prices have certainly increased, Tahiti has slipped, but I wanted to see if you could provide some sort of reconciliation between those two figures?

Thank you, Robert. In our Analyst Meeting back in March of last year, you could interpolate from the bar chart that our anticipated production for 2008 would be on the order of 2.8. And as we had mentioned today at a $70 price environment, we were guiding you folks that it's 2.65. So your math, Robert, is about right. It looks to be about 150,000 barrels a day difference. We describe in the neighborhood of 95,000 to 100,000 barrels of that to a major capital project delays. As you pointed out, it's Tahiti slipping out of 2008, and it's a little slower ramp-up particularly for our TCO expansion this year. The other big component that's on the order of about 40,000 barrels a day or thereabouts would be attributable to higher prices that we're basing our production profile on this year versus the information that we showed at the Analyst Meeting. So that accounts for the lions share. But I would tell you that, as we go forward, we still expect that between 2005 and 2010, our standing guidance of increasing our production by an annual rate of 3% still holds. This timeframe will have that production more backend loaded, but we're very confident that over the next couple of years we're going be able to increase production and achieve that production growth rate. I hope that helps you, Robert. Do you have follow up on that?

That helps. Thank you very much.

You are very welcome.

Our next question is from Doug Leggate of Citigroup. Your question, please.

Thanks. Good morning, gentlemen. Dave O'Reilly: Good morning, Doug.

If I could just get some clarity on that last answer, Steve, if you don't mind, because the implication of the original target was about 400,000 barrel per day increase over the five-year period. The price tag has obviously moved up. So, just to be clear, is this your consistency with that guidance even though we've had a substantially higher move in the oil price?

That is correct. The guidance that we're giving still pins off now a $70 price tag. You recall though, Doug, back at the time that we first gave the guidance, we said our production profile from '05 to '10 would be in excess of 3%. So we think we still have some ability to accommodate the higher prices. Dave O'Reilly: But I think, Doug, just following up on Steve's point, if prices were to go to $90 or $100 and stay there then we have to reevaluate, I think, at least at the margins some of those assumptions. But our assumption here is we're just using $70 at the moment. The reason we pick $70 on this chart that you're seeing is that it was about $70 in 2007. So we're trying to take out the impact of prices in this analysis.

Doug, I also mentioned when I also mentioned when I was talking about our outlook for 2008, I kind of gave you some manner by which you could adjust when I commented that if prices for 2008 would be, say, in the $90 per barrel level that the production would be on the order of $50,000 to $60,000 barrels a day lower. So I have to tell you though that the price effect associated with our various contracts overseas is it varies with the price range and which those changes occur. So it's not totally linear. So the guidance that I gave you was moving, say, from a $70 per barrel environment to that of, say, a $90 per barrel environment.

Great.

Doug, did you have another question?

Thank you. I've got just a short follow-up, it's on the decline rate guidance or I think you've kind of declared that for everyone to see. A lot of the projects you have, however, are coming on are arguably quite long life. Would you expect that decline rate to moderate as these new barrels come on stream?

Yes, we would, Doug. Now, we actually did better than 4.5% during 2007, and while we're not confident enough yet in the certainty of what we're accomplishing to forecast that that's a permanent shift. But you're correct. As you move forward with longer life projects, we expect that that will make a transition at some point in the future. And that's something we'll address when we feel confident that we can forecast something that's better than 4.5%. So, at the moment we're sticking with our 4.5% guidance. Thank you.

Thank you very much.

Next question, please.

Our next question is from Mark Gilman of Benchmark. Your question, please.

Dave, Steve and Jim, good morning.

Good morning. Doug O'Reilly: Good morning, Mark.

I want to see if I could just try to get a better understanding of the economic structure of the Angola LNG project. I mean I think I hear what you're just saying that because you have "rights to the gas" it allows you to book the reserves. But it's my understanding that you are still buying the gas from Sonangol, and therefore this is not a typical integrated West African LNG project. Can you share any light on this issue at all? Dave O'Reilly: Let me just put it this way. The plant owners are entitled to this gas under Angolan legislation. So this is legislated, but it's not all coming from one field. There are multiple fields involved. So, there is legislation in place. All of it has been fully vetted through the government. So there are other rights to this gas, and under SEC rules, we will be able to book those gases. But because not all of them fall into our gas fields, if you will, our gas production, these have to be certified, and that's what underway right now. Other than that, that's about as far as I can go in answering your question, Mark.

But Dave, aren't you buying the gas from Sonangol even in those fields where you have a working interest and an applicable production sharing timeframe? Dave O'Reilly: It's not a purchase arrangement. It's a dedication to the plan arrangement. And that's about as far as I can go.

Thank you very much. Dave O'Reilly: Thanks, Mark.

Our next question is from William Ferrer of WH Reeves. Your question, please.

Yes. Good morning, gentlemen.

Good morning, Bill.

Couple of questions for Steve -- excuse me -- a question and a follow-up on the general issue of accounting. You mentioned that the US downstream, if I got this correctly, was burdened by $400 million in the fourth quarter roughly of inventory and derivative effects. Is that related to, say, foreign oil pricing effects, or is this different and would that go away in the first quarter, for example, or how permanent might that be? And my follow-up is also an accounting question. Without getting into the nuance of timing of reserve adds, does the formality of what you will have to report at yearend influence your book DD&A as we go forward? Thank you.

Thank you, Bill. Let me start off with the comments regarding the US downstream. As I had mentioned, in an absolute sense, we estimate that the fourth quarter US downstream results were adversely affected by about $400 million in the quarter, and there are main areas that account for this. Firstly is the downtime at our refineries. Order of magnitude, that's about $250 million impact. That reflects both planned downtime, as was the case in our El Segundo refinery when we have the coker down, as well as unplanned downtime that we had at Pascagoula as a result of the crude unit fire that occurred back in August. The components of those are both sort of a lost opportunity profit in the margin because we had to acquire more expensive feedstocks such as light, sweet crudes to input to the refineries. It also reflects that we have higher operating expense while those refineries were down. Roughly speaking, that impact of the refineries being down was about split equally between planned downtime and unplanned downtime. Now the balance of that $400 million or roughly $150 we would ascribe to, say, call timing differences, really driven by the rapid escalation in the price of crude oil from the beginning to the end of the fourth quarter. And as you pointed out, Bill, that affects both our contractual arrangements for the purchase of provisionally priced foreign crude, but also some of our derivatives that we have, which are mark-to-market at the end of each period whereas the physicals associated with that would be recognized in a different period. The inventory impacts for the fourth quarter in the US weren't all that great. There was a bigger impact overseas. So I hope that gives you and the another analysts a fix on trying to adjust to normalize, if you will, our fourth quarter US results, which are attributable, one, to the rapid rise in crude prices, and two, to the downtime that we have in our refineries. Now the second question I think you had was with respect to the impact on our DD&A rates as a result of reserve additions. And of course, that gets into the calculation for determining the DD&A rates. So it depends on where the reserve additions occur and where the decrements might occur, but it certainly influences the rate. The other item, Bill, that I'd mentioned to you is that, as we go forward, we'll be providing information in our 10-K that will address changes in our abandonment as well, and that will have impact prospectively on our DD&A rates going forward. So I don't want to go into a full accounting lesson on all of that. But your question is a good one and it will impact future years. Thanks very much for your question and your follow-up.

Our next question is from Neil McMahon of Sanford Bernstein. Your question, please.

I have a got an umbrella question on Nigeria, I guess it's the best way to put it. First of all, just after Shell's comments, about what's happening on the delta, obviously you've got a big position there as well and you have been affected by the outages. They suggested that potentially Olokola LNG will be significantly delayed. I just wanted to get an update from yourselves and also your Escravos GTL plant and how things are going there. Thanks. Dave O'Reilly: First of all, our total performance in the delta has not been that significantly affected on a current basis. I think my recollection is that the impacts of disturbances there in the swamp areas onshore is less than 20,000 barrels a day net to Chevron. And we've made some significant progress over the last few years in steadily improving our situation there from two or three years ago. Secondly, I think it's too early to predict the schedule for Olokola. We have a new administration. There is a new government. There is a restructuring going on in the petroleum sector to separate NNPC and make it a commercial entity, and put the regulatory function back on the government with a number of distinct compartments, kind of an upstream sector of the government regulatory sector and a downstream sector, and then there is whole new look being given to the gas business. So in light of all of the changes in the government and the policies around how this whole area is going to be managed, I think it would be unrealistic. I haven't heard what Shell has said, but I think anyone associated with something that's brand new there would take the same position that we've got to reassess the timing of this. And wait until we understand how these policies and regulations are going to impact the business before we move forward, and I think we're in that zone right now. Hopefully, some clarity will come this as we more through 2008. Now, having said that, our main focus in 2008 will be brining the Agbami on stream. And Agbami, the FPSO is now on-site, it's been hooked up. We're continuing to complete wells, and we expect that sometime in the middle of the year or so that Agbami will be coming on stream. So, that's a kind of a long winded answer to your question, Neil, but it's probably, I think, a realistic assessment of the situation there.

Maybe just a follow-up on that, I'm just wondering if your comments are the same for the GTL plant. And just also on Agbami, I'm surprised that when yourself and Steve mentioned about reserve replacement rate, you didn't have a bit more to add on Agbami. Have you effectively booked all of the Agbami volumes already because one presumes it's going to be on in the next few months? Dave O'Reilly: First of all, absolutely not, but let me remind you that that the regulations there. We've booked an initial quantity but the regulations there are very specific. You have to book the most conservative end of the range on a project like that until you actually have demonstrated oil flowing and production, and that, of course, you can't do until you start it up. So there will be more bookings on Agbami. It's an enormous resource base. But we've only booked the initial quantities there so far. Now on EGTL, it's under construction. It is still progressing and we'll give you an update on the timing for that in the March meeting. But it's still actively under construction.

Thank you. Dave O'Reilly: Thank you, Neil. Operator Our next question is from [Eric Wilke] of Merrill Lynch. Your question, please.

Good morning. Thank you for taking my question. My question relates to TCO. It's good to see that you're making progress on the expansion. You mentioned the second phase of the expansion. Can you give us some guidance on the ramp-up profile, perhaps the average contribution to second half or the anticipated exit for 2008? Dave O'Reilly: Eric, I'd like to hold that back until March. We are making progress month-by-month there. The SGI plant, the first phase of that is up and running and has been ramping up. So, we'll have a much better handle on this as we come out of the winter month. Winter months are difficult months from a construction perspective. The temperatures there went 30 below in recent weeks. So, if you'll hang on to that question until March, we'll have, I think, a better handle on where we think we will be on the second phase of expansion there.

Okay. Fair enough. Can I ask the second expansion though on the back evacuation route, I think you made progress on CPC expansion? Dave O'Reilly: Absolutely. Let me just, first of all, tell we have restructured the CPC arrangements to put the pipeline on a much more financially sound footing. And we're now in the phase of negotiating the terms for expansion of the pipeline. However, we're not depending on that expansion to move oil out of Tengiz. Then if you will recall that we had a long history of being able to move oil from Tengiz before there ever was a CPC pipeline from 1993 until about the year 2000. So, we have multiple options for movement of Tengiz oil. We have a very skilled and accomplished group that are capable of doing that by a number of different routes. While we obviously desire to expand CPC and believe it will be expanded, we are confident in our ability to continue to move the crude, even the additional crude from Tengiz even without the CPC expansion being in place. Thank you.

Thank you. Can we have the next caller or question please?

Our next question is from Mark Gilman of Benchmark. Your question, please.

Dave and Steve, I'm wondering if I can possibly get a little bit better handle on the base US capital spending '08 versus '07. If we take out of each year the major project elements, in other words, Tahiti and Blind Faith, what would that comparison look like? Dave O'Reilly: I think it would be rather flat, Mark, and in round numbers. It's a subtlety that isn't right at my fingertips right now, but I think it would be rather flat and it reflects the fact that we have a big resource base. We are continuing to see a lot of progress in other areas, which tend to skate on to the radar screen, for example, San Joaquin Valley, where we are continuing to make great gains in expanding our production there or at least moderating the decline. The Mid Continent area where we are beginning, of course, we've got plans to grow in the Piceance and expect to have production starting there around the end of the year. As to the specific numbers, let me call in Steve to kind of give you a little bit of a highlight.

Mark, I think Dave's response is right on, but let me give you kind of directionally on some of the big projects. If I take a look at, say, 2007 and compare it to 2008, the spending for Blind Faith will actually be lower in '08 than it was in '07. A little bit more money will be spent for say the Great White, Silvertip, Tobago area. In the case of Tahiti, our spending in '08 will be somewhat less than it was in '07. But as Dave pointed out in the Piceance area, we see spending ramping up there in ''08 versus ''07. And while I haven't racked up all the pieces, I think the underline comment that Dave made was right. If you pulled out the big projects that are sort of identifiable in both years, the underlying spending is probably fairly flat.

So Dave and Steve, if we allow for inflation, it's actually down a little bit. Dave O'Reilly: Well, we're not seeing as much inflation there as you say. I mean the inflation in things like deepwater and that type of thing. But land rigs and some of the other things we're doing onshore, we're not seeing quite the same rate of inflation. So I don't think you can draw that conclusion that easily. We'll try to put more depth behind that in our March meeting, Mark, and see if we can get a better handle on it for you, okay.

Dave, one more quasi-related follow-up if I could. Without regard to the timing of the ramp-up on the Tengiz expansion, are you in a position yet to be able to assess reservoir response to the injections? I noticed, Dave, when you characterize the project in your summary comments that instead of using the range of potential increase in production, you really focused on numbers at the high end with your 540,000 a day comment. Dave O'Reilly: Well, the high end of the range, Mark, has to do with our belief in the capacity of the plant and the facilities. The reservoir response I think we're already demonstrating, because remember we've had a experience now with sweet gas injection dating over a year before we ever gone to injecting sour gas, which we've been doing now for a numbers of months. So we've already demonstrated that the reservoir is performing and we're confident that that part of it is well underway. And with time and with further expansion of facilities, we would probably be able to add further to our reserves. But the 540 is a reflection of our belief that that capacity is now demonstrably within reach. I think that's probably the best way to put it.

Okay, Dave. Thanks a lot. Dave O'Reilly: Thank you. Thanks, Mark.

Our next question is from Jason Gammel of Macquarie. Your question, please.

Good morning, gentlemen. I wanted to inquire about what you're seeing for refined product demand right now in the United States, maybe particularly in California, in light of the weak refining margin conditions that we've been seeing recently. Dave O'Reilly: Jason, let me take that. If I look back on the year, I think we're seeing a year-over-year gasoline demand actually '06 to '07 is slightly up and distillate demand up by about more than a 0.5%. Now having said that, there has been a downward year-over-year trend quarter-by-quarter during the year 2007. In the first quarter, we had year-over-year gains, in the second quarter they were somewhat less, in the third quarter -- and I am talking about nationwide -- we were seeing flat, and in the fourth quarter nationwide there was a decline in the demand, I think in the order of 0.5% to 1% with the comparable period the year before. And the West Coast [Pet 5] is no exception to that. We're seeing those same trends occur in the West as we're seeing throughout the nation. So there is no question there's been a softening industry-wide throughout '07. And I think as we start '08, its early days here, but we are probably experiencing a similar softness as we saw in the fourth quarter.

Okay. Thanks, Dave. And then, maybe as a follow-up, would you mind commenting on what you're seeing in the Asian markets that you're currently marketing in? Dave O'Reilly: The Asian markets are still doing very well. I was in 14 developing countries during the second half of '07, and I couldn't find any one of them that was growing at less than 7% GDP. So the markets, overall, there have been performing well. They may become off a little bit at these higher prices, but many of them have subsidized oil and gas prices, and you are not seeing the sort of demand impacts there that we have seen in the rest. If I take a macro view now and bring you right back up to 40,000 feet, if you look over the last few years, I think you'll see that aggregate demand in OECD has been relatively flat and the global growth that we're seeing has been driven essentially by the developing world. Developing Asia is a big, big engine here, and the Middle East itself, where a lot of the oil and gas demand is heavily subsidized, and there doesn't seem to be any real significant slowdown occurring there. So, that's it in a nutshell.

Thank you.

Thank you, Jason.

Our next question is from Eric Wilke of Merrill Lynch. Your question, please.

Thank you. Mine is just a quick follow-up on the fourth quarter US exploration expense. You mentioned that these remaining will write-off, if you can bit a more color on that that would be great. Dave O'Reilly: There were a few in the Gulf of Mexico. And I don't have all of the specifics at hand, but they were generally in the Gulf of Mexico. I just don't have all of that at my fingertips.

Eric, you can, after the call, give a Jim a call and he'll give you a little color commentary on that to the extent that we can talk about.

Okay, thanks.

Thanks very much. Dave O'Reilly: Okay. Well, I think it's coming up to the top of the hour. So I think it's a good time for us to wrap-up. I want to thank you all for participating in the call today, and I'll look forward to seeing many of you at our March Security Analyst Meeting in New York. So, thank you all again, and thank you, Matt, for hosting the call.

Ladies and gentlemen, this concludes today's fourth quarter 2007 earnings conference call. You may now disconnect. Good day.