Malcolm Theobald – Vice President of Investor Relations Andrew Gould – Chairman and Chief Executive Officer Simon Ayat – Chief Financial Officer

Kurt Hallead - RBC Capital Markets Charles Minervino - Goldman Sachs Michael LaMotte - J.P. Morgan [Allan Block] – Bank of America Ole Slorer - Morgan Stanley J. David Anderson - UBS William Herbert - Simmons & Company Intl. Byron Pope - Tudor Pickering & Co. Securities James Crandell - Barclays Capital Michael Urban - Deutsche Bank Securities Geoff Kieburtz - Weeden & Co. Brad Handler - Credit Suisse Kevin Simpson - Miller Tabak & Co. Pierre Conner - Capital One Southcoast, Inc. Robin Shoemaker - Citigroup

Ladies and gentlemen, thank you for standing by and welcome to the Schlumberger earnings conference call. (Operator Instructions) I would now like to turn the conference over to your host, Mr. Malcolm Theobald, Vice President of Investor Relations for Schlumberger Limited. Please go ahead sir. Malcolm Theobald : Thank you [Shelly]. Welcome to today’s fourth quarter and full year 2008 results conference call for Schlumberger Limited. Before we begin I’d like to review the logistics and format of today’s call. Some of the information in today’s call may include forward-looking statements as well as non-GAAP financial measures. A detailed disclaimer and other important information are included in the FAQ document which is available on our website or upon request. And now for the call participants and format. Sitting with me for today’s call are Andrew Gould, Chairman and Chief Executive Officer; and Simon Ayat, Chief Financial Officer. Prior to Andrew’s overview of the results and his comments on the outlook, Simon will first review the financial results. After the opening comments, we will open the call for questions. And now I’ll turn the call over to Simon.

Thank you Malcolm. Ladies and gentlemen thank you for participating in this conference call. Schlumberger’s fourth quarter income from continuing operations, excluding charges and credits, was $1.03 per share, down $0.22 sequentially and down $0.08 compared to the same quarter of last year. As announced, we are taking actions to reduce our global workforce as a result of the recent decline in activity in the Oilfield Services sector. We therefore recorded an exceptional charge of $0.08 per share during the quarter primarily to reflect these actions and create a solution relating to a client with liquidity issues. Depending how the market situation evolves, further actions may be necessary. Turning to the business segments, Oilfield Services fourth quarter revenue fell by 2% sequentially while WesternGeco revenue dropped 33% sequentially. Oilfield Services generated $1.6 billion in pretax operating income, down $100 million sequentially with margins slipping by 117 basis points to 25.6%. By area, Oilfield Services pretax operating margin highlights were as follows. My comments are on a sequential basis. North America pretax margin improved by 115 basis points to 22.3% with a strong offshore recovery in the Gulf of Mexico after the hurricane impaired third quarter and strong activity in U.S. land west and in Alaska. These increases were partially offset by the impact of pricing pressure in the U.S. land central and U.S. land north geo-markets. Latin America pretax margin declined 211 basis points to 18%, with lower activity levels in the Venezuela, Trinidad and Tobago geo-market, and unfavorable activity mix in the Peru, Colombia, Ecuador, and Mexico central geo-market. In Europe/CIS/Africa, pretax margin reduced 295 basis points to 26.1% as Russia experienced its seasonal decline in activity offshore in Sakhalin combined with significant reductions in activity in other areas due to lower customer spendings. Less favorable revenue mix in the North Sea and Nigeria and Gulf of Kenya geo-markets also reduced area margin. Finally, Middle East/Asia pretax margin declined 199 basis points to 33.5% on lower oil activity and less favorable technology mix in the Arabian and India fuel markets. WesternGeco pretax income of $88 million reflected a decline in pretax margins of 25.1 percentage points to 14.7%. Marine decreased from direct third quarter results through lower vessel utilization and a high number of transits while the low level of multi-claim sales depressed margins significantly. Now turning to Schlumberger as a whole, the effective tax rate before the impact of the exceptional charges was 21.5% which was in line with last quarter. The ETR is expected to be in the low 20’s for 2009. Net debt was $1.1 billion at the end of the quarter, presenting a sequential improvement of $600 million. Further we ended the quarter with approximately $4.2 billion of cash and investments on hand. In addition, $1.8 billion of committed debt facilities with commercial banks remain unused and were available at the end of December. This compares to short term debt of only $1.6 billion reflecting the continued strength of our balance sheet and leaving us with more than enough liquidity to meet all corporate and operational requirements. Significant liquidity events during the quarter included $154 million of the stock buyback program; $234 million of pension funding; and $1.25 billion of CapEx including $83 million multi-client surveys capitalized. During the quarter we bought back 2.7 million shares for $154 million at an average price of $57.05. Given the current credit and economic environment, we anticipate that the total dollar amount of stock repurchases in 2009 will be significantly less than the $1.8 billion spent during 2008. This anticipated reduction will serve to increase Schlumberger’s financial flexibility during these uncertain times. Our stock buyback activity during 2009 will continue to be targeted to offset any dilution caused by our stock-based compensation programs. Oilfield Services CapEx is expected to approach $2.2 billion in 2009, while WesternGeco CapEx is expected to reach $800 million in 2009. This includes $385 million relating to the construction of seismic vessels. And now I turn the conference over to Andrew.

Thank you Simon. Good morning everybody. Oilfield Services full year 2008 revenue of $24.28 billion increased 20% versus 2007, driven by area growth of 28% in Latin America; 24% in Europe/CIS/Africa; 18% in Middle East/Asia; and 11% in North America. All technologies experienced double-digit growth, most notably in well services, drilling measurements and wireline. Sequentially, however, Oilfield Service revenue declined in the fourth quarter, largely due to the weakening of many local currencies against the U.S. dollar, as well as to lower activity in Russia and with the exception of North America generally weaker activity around the globe. This general weakness was partly due to seasonal weather affects and partly to initial client curtailment of spending. As a consequence, with the exception of North America, pretax operating margins declined. Looking at the areas in more detail, sequential performance in North America was led by the U.S. Gulf of Mexico geo-market, as activity recovered from the slowdown of the hurricane season in the third quarter and as higher, ultra deep water rig comp led to strong demand for wireline well testing and well services technologies. On land, revenue in the U.S. land west geo-market increased on demand for well services and drilling and measurement services and artificial lift products, while the Alaska geo-market saw a seasonal build-up in activity that resulted in robust demand for well services and drilling and measurement technologies. Also on the positive side, Schlumberger Information Solutions experienced growth from seasonally strong year-end software and hardware sales. These increases however were partially offset by the U.S. land central and northern geo-markets, where the reducing rig comp that accelerated in the [courser] end resulted in lower revenue. In Canada, revenue was lower primarily due to the weakening Canadian dollar. Sequential revenue in Latin America fell, with activity for wireline and well services technologies and completions products in the Venezuela, Trinidad and Tobago geo-market decreased and as the Mexico/Central America geo-market suffered lower activity and integrated management operations. These decreases however were partially offset by strength in the Brazil geo-market from higher offshore expiration related demand for wireline, well testing and drilling and measurement services, and in the Peru/Colombia/Ecuador geo-market from strong demand for artificial lift and information solutions products. Overall area revenue was reduced by an estimated 4% due to the weakening of local currencies against the U.S. dollar. In Europe, CIS, and Africa, sequential revenue declined by 5% due to the weakening of local currencies against the U.S. dollar, particularly in the North Sea, continental Europe and Russia. Russia also saw significant reductions in activity from lower customer spending, in addition to the seasonal slowdown in Sakhalin. Activity however increased in the Libya geo-market with strong oil demand for artificial lift products and for drilling and measurements, well testing and wireline services. The continental Europe geo-market also grew with higher demand for wireline and drilling and measurements technologies. In the Middle East/Asia area, revenue decreased as a result of seasonal weather related effects in the Australia/Papua/New Guinea/New Zealand and in the China/Japan/Korea geo-markets. Lower activity in [Gata] as projects were completed and less favorable activity mix in Brunei/Malaysia/Philippines, and reduced customer spending in China, Japan, and Korea in the Arabian geo-markets all affected revenue. While these declines primarily affected wireline drilling and measurements and well services activity, they were partially offset by growth in the Gulf geo-market for artificial lift products, well services, and drilling and measurements technologies. At WesternGeco the sequential 33% decline in quarterly revenue was largely due to decreases in marine which was affected by vessel transit, dry docks and project start ups. Multi-client revenue also decreased significantly as customers reduced discretionary spending. Margins suffered in consequence. At the end of the year, however, WesternGeco benefited from an all-time record backlog of $1.8 billion, underpinned by a number of long term contracts. The sharp drop in oil and gas prices due to lower demand, higher inventories and the belief that demand will erode further in 2009 as a result of reduced economic activity, is leading to rapid and substantial reductions and an expiration in production expenditure. At current prices most of the new categories of hydrocarbon resources are not economic to develop. It would also take time for inflation to be removed from the system and to bring refining and development costs more in lower with lower oil and gas prices. We therefore expect 2009 activity to weaken across the board, with the most significant declines occurring in North America natural gas drilling, Russian oil production enhancement, and mature offshore basins. Expiration of offshore will be somewhat curtailed, but commitments already planned are likely to be honored. Seismic expenditures, particularly for multi-client data, are likely to decrease from last year and pricing erosion will compound these effects on revenue. In this market we are taking the necessary action to adjust our operating cost base while preserving our long term commitment to technology to element, key skill sets, and service and product quality. The key indicator of future recovery in Oilfield Services activity will be a stabilization and recovery in the demand for oil. The recent years of increased expiration and production spending have not been sufficient to substantially improve the supply situation. The age of the production base, accelerating decline rates, the smaller size of recently developed fields will mean that any prolonged reduction in investment will sow the seeds of a strong rebound. We have no doubt that Schlumberger will emerge from the current downturn a stronger company, better positioned to participate in the subsequent upturn. And I will now hand the call back to Malcolm.

Thank you Andrew. We will now open the call for questions.

(Operator Instructions) Your first question comes from Kurt Hallead - RBC Capital Markets. Kurt Hallead - RBC Capital Markets: Andrew, I was wondering in your view how does this cycle compare to other cycles you’ve experienced in your career? Would you put this more closely aligned with the ’97 to ’99 period or more like the ’80 to ’86 period?

Actually I think it’s a bit different from both because the precipitous drop in the oil prices combined with the contraction of the general economy. So actually the biggest difference I see from both sort of the mid-80s and as well as ’97, ’98 is the speed with which everybody’s reacting. Our customers are reacting at a much faster pace than they probably did even in ’97, ’98 which was a very sharp cycle. I mean my general comment is these cycles as I experience them are getting much sharper in their amplitude and shorter in their duration. Now of course that depends on the general economy. But I would say the big difference that I see so far is the speed with which everyone’s reacting. Kurt Hallead - RBC Capital Markets: Just in the prior periods it always had taken longer for the international markets to adjust to the changes relative to North America and a lot of that has to do with long term contracts, but again on what you just said about your customers acting more quickly, do these contracts still provide that chance that the international markets could bleed lower and extend out into 2010? I don’t want you to get specific but just trying to get a general – I’m trying to handicap it myself, so I don’t know if we’re going to bleed lower like we did the last couple cycles or if you think ’09 is really the ultimate trough here.

I think the simple answer is I don’t know. I think that our customers they are not going to break contracts but they are going to pressure us to swap price for volume or price for duration or things like that. So where they have an opportunity they’re definitely going to act on price. But I don’t think that they’re going to break contracts.

Your next question comes from Charles Minervino - Goldman Sachs. Charles Minervino - Goldman Sachs: Andrew, I was wondering if you could talk to us a little bit about your conversations with the national oil companies. I know they all probably have different goals and breakeven points on various projects, but if you could generally just talk about what you’re seeing from them. They’ve obviously accumulated a lot of cash over the last few years. How are you seeing them spending through this cycle?

Well, I don’t think there’s – it’s very difficult to generalize on them like that. But you know the ones that are mixed, in other words they have some private ownership, I think they will react to very much as private industry does. The ones that are entirely state owned, if they have cash I think they will spread out their programs but I doubt they will cancel them, because they don’t want to really compromise their long term position in this industry. So I think that there’s a very mixed reaction. But if I had to generalize it, if they can spread their programs over a longer period of time they’re likely to do so. Charles Minervino - Goldman Sachs: And can you just give us a sense globally or internationally? You talk about a little bit at the markets that you see, and you mentioned earlier Russia slowing down. Can you touch a little bit on Latin America and the different parts of Europe where you see maybe holding up a little bit better versus slowing down a little bit more?

Well I think Latin America will be a mixture. There are at least two geo-markets in Latin America that will remain very healthy and two that will probably weaken fairly dramatically. So I think overall there is a good chance that Latin America will be flat, flattish over the whole year. But it’s very early for me to commit to that, but that’s the way we would see it today. If you look at Europe then you know parts of central Europe will hold up, the North Sea will weaken, a lot of weakness – actually almost all of our weakness is quartered in North Sea came from the devaluation of the pound against the U.S. dollar. But it will weaken over the year. If you look at Africa we see some Bolivia, Nigeria, North Africa access will hold up pretty well. And offshore West Africa the big guys will hold up really well, but some of the small independents who were doing expiration will probably drop off. So you know there is a reasonable – I think overall I have to – I hate to go on being negative, but overall I suspect Europe, Africa, CIS will be down. And there will be pockets of strength with the big customers offshore, Algeria, Libya, but the rest will be fairly weak.

Your next question comes from Michael LaMotte - J.P. Morgan. Michael LaMotte - J.P. Morgan: Andrew if I could ask you to clarify your comment on the inflation and the unwinding of it, particularly I think when we think F&D inflation we tend to think oilfield pricing and clearly the biggest components there were rigs and steel, two businesses you’re not in. So first I guess clarify that with respect to oilfield pricing. And then secondly, how you could be actually benefiting from inflation unwinding in terms of Europe.

Well, actually my remark was you don’t drill without a rig and you don’t build a platform without steel. So the really high inflation ticket items in projects are undoubtedly what our customers are going to want to come down. Now the traditional arm wrestling with the rig contractors and how they run one, I know what that’s like, will take some time to work itself through the system. That’s what I meant, Michael, okay? Michael LaMotte - J.P. Morgan: Okay.

The steel stuff, the input to our manufacturing be it steel, [kanel], chrome, copper, the pricing effect is fairly immediate. As soon as we’re through our inventory we see the pricing effect come in very quickly. In fact we have some of our IPM contracts with the tubular element price has been dropping by a very substantial amount on a monthly basis. So I think – but for it to really work its way through our system, in terms of material costs you’re probably looking at a year. Michael LaMotte - J.P. Morgan: I’m not putting words in your mouth then to say that this was not a statement about your own pricing structure?

No. No. Our pricing structure will be negotiated, renegotiated as I explained in answer to an earlier question. But for my customers it’s getting the cost of the really big ticket items down that’s going to make projects become economic again or not.

Your next question comes from [Allan Block] – Bank of America. Allan Block – Bank of America: In a slowdown the next kind of focus usually moves to the receivables. I wanted to know if you could comment on recent pressure the Port of Vaasa owing somewhere near $8 billion and they stopped paying. Are there other areas in the world where you’re seeing this type of pressure from your customers where they’re running out of money and extending you on the receivable side?

No, not significantly. I think there’s a bigger risk from some of the smaller independents than there is from the other international companies. Terms will undoubtedly extend, they always do in a downturn. But since I’ve been in this business we’ve never not been paid by anyone. Allan Block – Bank of America: When they stretch out they do – usually they catch up on them –

Well, never say never but when I first joined Schlumberger one of the NOC’s didn’t pay us and they paid us seven years later. But Simon we’ve never not been paid, no?

No, I confirm. As a matter of fact in the Q4 we improved our receivable situation. That’s part of the improvement in net debt that I spoke about. Allan Block – Bank of America: Your expectations are then that most will stay current right now, or there like I said before are there areas in the world where you’re worried about this happening as well?

We’re not, no we’re not. We haven’t seen any – well we’ve seen an improvement as Simon said. But if we look at specific companies I don’t think we’ve seen any significant deterioration yet that leads us to worry. I have to say that we put our field people on credit watch back in September, so they have been doing a lot of quality operating of the customer exposure since last September. Allan Block – Bank of America: Given the changes in the dynamics of demand, are you changing your marketing or pricing strategies at all in any particular markets?

Well, I wouldn’t want to say that over the phone. My competitors are undoubtedly listening. But yes everybody has to adapt to the current market circumstances.

Your next question comes from Ole Slorer - Morgan Stanley. Ole Slorer - Morgan Stanley: Andrew, just going back to what you said about coming after this downturn and a stronger company, what is your reflections of how the whole cycle is playing out? And is there any specific Schlumberger there relative to competitors? And will there be consolidation or market share gains into that?

I think it’s much easier for companies with very strong balance sheets to operate in this environment because we can still make investments that we think are going to pay off in the long term. As I said last October we will be more opportunistic in acquisitions than we’ve been perhaps during the period when we felt that valuations were out of hand. And generally we will not – we never adjust our R&D in any significant way during these downturns which means that when you turn up again, you have been able to renew a considerable part of your product and service portfolio. So if that recipe still works, that’s what I meant, Ole. Ole Slorer - Morgan Stanley: What do you think of the terms that when we come out of this downturn that the competitive landscape will have meaningfully changed?

I don’t know. I mean I think that – you can see already that some of the smaller companies that went with private equity are struggling, so they may get snapped up. Whether there will be a larger consolidation I don’t know, Ole. Ole Slorer - Morgan Stanley: If I can just move onto block 31, it was kind of buried in the middle of the press release. And by the way your press release seems to be particularly aggressively sprinkled with the contract awards on technology this time around, so just wondering if we should read anything into that specifically. But particularly block 31, could you talk a little bit about just you seem to have gone sort of full house there on the service side and what part of that was incumbent and what was new awards?

I actually don’t know off the top of my head. I certainly know that wireline was incumbent. I’m not sure about drilling and measurements, and well services we were partly incumbent. I would say we were incumbent on quite a lot of this. But don’t forget, this is moving to the development stage so the scope is very different. Ole Slorer - Morgan Stanley: And then you’ve been successful in completion in deport in West Africa versus some of your previous competitors. Has completion been awarded yet on block 31?

Yes. Ole Slorer - Morgan Stanley: Has that been announced? Andrew Gould : I don’t know. But it’s not in our press release so it’s not us, Ole.

Your next question comes from J. David Anderson – UBS. J. David Anderson – UBS: Andrew getting back to some of the past downturns, I’m just wondering if you could just elaborate a little bit on applying some of the lessons you learned during the last downturn to now. Just curious if that was a factor in the timing of your decision to cut your workforce. I guess my question is did you move the timing up because your outlook is really becoming more negative and your looking at the past and you decided to make a decision here?

Actually when I compare the way we’re managing that to ’97, ’98 we actually today have much, much better data. That’s the first difference. The second difference – and data about our own workforce, I mean. Where it is, who it is, you know – what the loading is, all the rest of it. The other thing is that in previous cycles, including ’97, ’98 we used to listen to our customers about what we thought was going to happen in the market. And since then where we suffered really badly from listening, we make up our own minds. So I would say that the decision that we had to make a workforce cut was probably made in November. And you know the actual – we don’t make press releases about these things but the cut actually concerns about 5,000 people worldwide. J. David Anderson – UBS: So have you become incrementally more negative over the last two months?

Yes. J. David Anderson – UBS: You also talked about the speed of the spending cuts being faster than in past downturns.

Yes. J. David Anderson – UBS: Do you see much of a difference between the IOC’s and the NOC’s reacting right now? And is this more of a credit issue? I mean I’m hearing it seems like credit can be more of an issue than commodities. I don’t know if there’s any way you can comment on that.

I think credit is an issue for the sort of ecosystems that grew up, particularly in the London A market, maybe in Russia a bit and also in the U.S. where people spend. You know I don’t have any cash flow like the expiration companies in London who traditionally spent 125% or 150% of their cash flow as the case in North America. So obviously the credit crunch has had an effect on the speed of the contraction, yes. J. David Anderson – UBS: With regards to the offshore sector you talked about a lot of contracts in place, you keep that work out there. Just wondering if the customers have their rig rates locked in already and they’re looking to cut costs in other ways, does that mean it comes down to you guys? Are you guys starting to get a lot of pushback on your pricing right now? And how is your pricing structure offshore? I mean, how flexible is that?

Well I mean of course we’re going to get pushback from the pricing. But the factor in the pricing of an offshore development is tiny compared to some of the other ones. And what they will do is some of the big, new expensive rigs that were slated for expiration will be moved to development if they can’t get out of their contract. Because an expiration rig does not produce cash flow. A development rig does.

Your next question comes from William Herbert - Simmons & Company Intl. William Herbert - Simmons & Company Intl.: Russia not getting a whole lot of attention with regard to the potential I guess production response to the implosion and drilling activity that we’re seeing real time. Can you comment on that in terms of what you’re seeing ground level and what your expectations are as the year unfolds with the continued collapse in rig activity?

I think from the reports the production is dropping now. I think that were drilling activity to remain as low as it’s been coming for a year or so it would be a very significant decline in production. I don’t want to give a number, but a very significant decline though. William Herbert - Simmons & Company Intl.: Could you – again, a difficult question to answer because it’s about depth and duration, as you look out into 2009 what are your expectations with regard to a year-over-year decline in [inaudible] capital spending in Russia on a percentage basis, if you will.

Actually we haven’t – you don’t – so you have to divide the Russian market into three. The IOC’s particularly in Sakhalin there will be no decline. The small Russian companies that depended on credit markets will probably just not drill. And what we’re looking at at the moment the hypothesis we’re working on is that there will – I can’t give you this in money, but in the total meters drilled we’re looking at a drop of somewhere between 10 and 20%. Total meters drilled. William Herbert - Simmons & Company Intl.: That’s for the whole market.

Yes. For the – essentially for the western Siberia and southern Russia market. Let me put it this way, Bill, the mature market. William Herbert - Simmons & Company Intl.: I would suspect that the pricing pressure that the service industry is encountering in Russia is fairly acute, no?

Yes it is. William Herbert - Simmons & Company Intl.: We have a decent slug of new build [inaudible] vessels coming into the market this year, the eastern eco-boats. What is the plan with regard to your resisting fleets, your older vessels? Do we plan on stacking those or mothballing or do you not know at this stage?

No, actually when we bought Eastern Eco we made a contingency plan. We didn’t think we’d have to use it but we may have to use it. And if we do have to use it the first thing is we still have some leased vessels and luckily a lot of those lease vessels we can release in ’09. That would leave us with almost 100% owned fleet and in that case if we have to stack we will park them in a field somewhere. William Herbert - Simmons & Company Intl.: With regard to your receivable policy I hear you with regard to national oil companies eventually making a hole, but what is the policy with regard to the carrying value of these receivables on the balance sheet? Is there a certain threshold at which you have to start writing them down, call it six months to a year?

I’ll let Simon comment but we have a policy, yes.

So basically we have a policy where we look on an item by item basis. We don’t take general provisions. We do analyze our receivable divided by areas. Geo-markets have very good visibility. And we look at our receivables item by item basis. So we don’t take a general provision like we announced now. We took a particular provision that related to a specific client. And this is how we look at it. So we don’t have a general policy that based off on aging. It is more particular to the client and what we know from the client and the discussion with them and the timing to be paid. William Herbert - Simmons & Company Intl.: So for example if you were to have some vulnerabilities attended to NOC yet they historically have made you whole with regard to receivables, how would you – how would the carrying value of those receivables adjust if any?

We will look at our experience with the NOC, the discussion that’s ongoing with them. And we’ll make the decision on those basis. Now if it goes beyond a certain timeframe, yes, a prudent accounting approach we might take a provision. But this again would be dependent on the circumstances.

Bill, historically the payment patterns of our NOC customers tend to get reflected in the pricing we practice.

Your next question comes from Byron Pope - Tudor Pickering & Co. Securities. Byron Pope - Tudor Pickering & Co. Securities: Andrew you speak to pricing erosion and your U.S. land central and north geo-markets. I’m assuming that refers primarily to well simulation or are you also concerned we could see it in some of your other product and service lines in those specific geo-markets?

Well essentially those. It would be pressure pumping. Byron Pope - Tudor Pickering & Co. Securities: With regard to your Oilfield Services CapEx being down roughly 28% year-over-year, historically your CapEx spend has been fairly consistent with kind of your revenue mix. As we think about that decline year-over-year is it fair to think about North America bearing more of the brunt of the reductions? Or is that not a fair characterization?

Yes, I think that’s probably a fair characterization. Yes. The brunt no, but proportionately more yes.

Your next question comes from James Crandell - Barclays Capital. James Crandell - Barclays Capital: Two questions. One, I understand that Pemex intends to move forward with as many as eight, 500 well packages that Chicontepec in 2009. Could you comment on that? And also talk about when your contracts expire, when you end your current stage of work at Chicontepec?

Well the only [co] ones I’m prepared to comment on are the 8TGE three and four, which have been announced. Beyond that I’m not prepared to speculate on what Pemex might or might do. And we have – our current contacts actually we have been awarded some extensions to make up for some of the shortage of wells that Pemex feel they have, and therefore I think our Chicontepec contract with its extensions will carry us through most of this year. James Crandell - Barclays Capital: Secondly and I was even given all your explanations I was still surprised over the magnitude of the drop in seismic profitability relative to the revenues. Could you perhaps expand on that? And given where you were in the fourth quarter, where would you see the overall direction of profit margins from the fourth quarter levels in your seismic [inaudible]?

Well I think you have to remember that the third quarter is the strong quarter in the North Sea, and the North Sea has the highest seismic pricing in the world. So you’ve got a compounded effect of the boats moving to lower priced contracts outside the North Sea, transit times, and you also got – we had a number of boats in dry dock during the fourth quarter. So I – the magnitude is surprising. I agree with you, but it’s quite logical. There’s nothing particularly startling. I mean obviously in a port where you have transits and dry docks you can’t reduce your fixed costs very much in marine. The other portion of it was the, which we had somewhat anticipated, was the absence of multi-client both in North America and overseas during the fourth quarter. James Crandell - Barclays Capital: So some of this at least going forward at least should lessen, so would you expect overall your relative profitability in that business in terms of margin should improve over the next couple of quarters?

Yes. I’m not sure – Q1’s not a good proxy like Q4 but certainly in the second quarter yes.

Your next question comes from Michael Urban - Deutsche Bank Securities. Michael Urban - Deutsche Bank Securities: Presumably the cuts that you put in place in terms of headcount expense and CapEx stem from your planning process. At that level of employment and spend what does that imply or what are you planning on in terms of activity levels? Just trying to get a sense for where your head’s at and are you staffed for that expected level or is there just kind of a Part B if things deteriorate further?

While we obviously have an overall plan at the level of Schlumberger Limited, as a feel for people’s visibility beyond Q2 it’s still very poor. We’ve asked them to make a plan in two parts. So first half year plan, second half year plan. And we will revisit the second half year plan in April, May. The headcount adjustment we made now which as I pointed out in an earlier question was planned in November was to adjust to what we felt activity levels were likely to be in the first quarter if not half year. Now in fact we’re seeing – the situation is so dynamic, that I cannot rule out that we would not make another headcount adjustment in the first half year. And secondly depending on what comes in as the plan in April, May for the second half we will probably have to look at it again. It’s so dynamic that I’m not going to say that an adjustment we made is for anything beyond the visibility we have over the next three to six months. Michael Urban - Deutsche Bank Securities: And shifting back to the seismic business, at least one good day to point there to backlog up again. Roughly how long does that carry you? Does that get you halfway through ’09, through three-quarters?

Actually what happened is Dalton and I agreed earlier last year that the time was to go long. And so roughly half that backlog will be executed in – no, slightly more than that, sorry. North of $1 billion is in the next 12 months and the balance will be in the following year.

Your next question comes from Geoff Kieburtz - Weeden & Co. Geoff Kieburtz - Weeden & Co.: Just to pick up on that last question if I could. You clearly have a great deal of confidence in WesternGeco backlog. Can you help us understand why?

Well, because with the exception of one or two contracts who are with very reputable contracts, the work has already started. Geoff Kieburtz - Weeden & Co.: And you feel like once they start they’re going to complete the program as originally conceived?

We’re talking about very reputable companies breaking contracts. They might shorten the program but I don’t see them breaking contracts, Geoff. Geoff Kieburtz - Weeden & Co.: Could I ask you to just elaborate a little bit on the comment in the press release about at current prices, most of the new categories of hydrocarbon resources are not economic to develop. What are you referring to in terms of new categories of hydrocarbon resources?

Advanced EOR, Ultra Deep, Heavy Oil, [Tarsands], let alone coal to liquids or gas to liquids. There’s a very good graph, Geoff, in the International Energy Agency 2008 Outlook that shows the cost as of the time they did it in November, which each of these categories can be developed. Geoff Kieburtz - Weeden & Co.: And then kind of a follow-on, the deep water market – what are you expecting? You made a couple of comments already this morning. There are a lot of new rigs coming out. Do you expect that deep water activity, defined however you want to, will in fact increase in ’09 versus ’08 with the [inaudible] new rigs?

Yes. Yes. Definitely. I think some of the rigs as I said in an earlier question will be pushed – instead of doing the expiration they were planned for will be pushed for development because development brings cash flow. But I don’t see any huge reduction in the deep water commitments that people have already undertaken. I think it’s far more a question for 2010, Geoff. Geoff Kieburtz - Weeden & Co.: And the combination of volume increase but a mixed shift for development translates to an impact on Schlumberger how?

Well, we don’t make as much money in development as we do in expiration as you know. So you know to the extent that there is a shift – the service intensity in development is much less than in expiration. So it actually reduces our scope to sell to a certain extent.

Your next question comes from Brad Handler - Credit Suisse. Brad Handler - Credit Suisse: I guess first question I come back to the U.S. market, can you give us an update on kind of the contract renegotiation status? You know a year ago we heard a lot about the process of negotiating pricing particularly in pumping but I think it was broader than that for the U.S. market for the coming year and it sounds like that has been delayed to some degree. Can you update us on that?

I think that it’s best to say that customers knowing they were going to lay down rigs and therefore would have more bargaining power pushed out the contact renegotiation into much later than they normally would have done. I would think that we’re probably about 70% through it now for the key product lines, yes. Brad Handler - Credit Suisse: So just to key on that, to the point that we will start to see the impact of those discussions in Q1 or is it more of a Q2?

No, I think you’ll see them in Q1. But you know sorting out the effect of the new contracts from the drop in rigs and all the rest of it is going to be quite complicated. Brad Handler - Credit Suisse: On a relative basis versus the prior year for a percentage of work and again your comment makes it more complicated to answer this, but to the percentage of work that you expect will prove to be under some form of contract versus the spot market?

I don’t think it will change very much, no. So you know 60, 70% will be under contract. Now what the scope of those contracts is going to be, I don’t know because rigs are dropping so fast it’s difficult to tell. Brad Handler - Credit Suisse: Are they presumably of the same nature? Are they sort of covering a certain area? For what work is done, here’s the price –

Yes. Brad Handler - Credit Suisse: Can you comment – would you be willing just to make a comment if the consensus EPS is sitting at $3.50 can you comment on how you all feel about that consensus number, just to try to get it out there?

Well, given the way I’ve been talking this morning, I suspect that the consensus number will come down from $3.50.

Your next question comes from Kevin Simpson - Miller Tabak & Co. Kevin Simpson - Miller Tabak & Co.: Simon, there was a decent sized jump in the post-retirement benefits line. I wondered – I guess I hadn’t really looked at it and so maybe it’s been moving up through the year, but I wondered what the explanation for that is. Is that a number that goes higher in ’09?

So there’s two explanations for that. One big part of the increase was related to a decision we made in the fourth quarter to convert a pension scheme we have for our international mobile staff from a defined contribution to a defined benefit. In other words, we given the market condition, we felt that we would take the risk and convert it to a defined benefit. It was a target benefit associated with the average carrier. Now the other part is no secret. It’s the value of the assets due to the market condition dropped. Now overall including the international mobile pension plan, we are about 70% funded. So this is why you see this big shift between the two layers. Kevin Simpson - Miller Tabak & Co.: So then obviously x stock market conditions, the number now of the $2.37 billion is representative of where you’re going to be going forward?

Well, I mean, this would be dependent on the first as you said the value of the assets, the market condition. But we also plan to fund some of these shortfalls. In a few quarter we put some money, $230 million and we have spare money to fund the different plans during 2009. So it will be hopefully less. Kevin Simpson - Miller Tabak & Co.: And then is the aim – you know, obviously huge uncertainty here in terms of how far down, but pretty still lower but fairly robust CapEx program. Is the aim to be cash neutral this year or is that possible I guess in the [inaudible] environment?

Let me comment on that, Kevin. We planned to be cash neutral but we have a lot of options to stay very cash positive. Kevin Simpson - Miller Tabak & Co.: And would that include cuts in CapEx?

Yes. Did you hear him explain we did an H-1, H-2 plan? So we do the H-2 plan in May we’ll look at the CapEx again. Kevin Simpson - Miller Tabak & Co.: So actually post the 1Q conference call.

Yes.

Your next question comes from Pierre Conner - Capital One Southcoast, Inc. Pierre Conner - Capital One Southcoast, Inc.: Just a little bit of follow up on seismic. If you could talk about sort of the difference in you commented about it, a rapid decline in library demand but yet the increase in the backlog. Is it customer mix or is it basically a data driven demand?

No, the backlog is not – there’s very little multi-client in the backlog. The backlog is marine and land acquisition or third party processing. Actually there is a very interesting difference between this cycle and the last down cycle in seismic. Because the last down cycle in seismic, WesternGeco had a balance sheet library value of approximately $1.1 billion. And this time it’s less then $300.

It’s $282.

It’s $282, and the multi-client that we are going to shoot through the first two-thirds of this year is already very adequately pre-funded. Because you know one of the dangers of the seismic business is everyone goes off and starts shooting multi-client without funding. I think this time around most of the seismic companies’ balance sheets are such that they won’t do that unless they have pre-funding. Pierre Conner - Capital One Southcoast, Inc.: My follow on to it relates to the margins and I imagine just from the magnitude of the revenue contribution from the marine versus the library, but the margins in the library significantly better because of the depreciate just as you point out. Was that a large contribution to the decline, the decrements, because of less library? Or really all driven mostly by they had dry docks and transit times?

I think it’s far more driven by the choppy quarter in marine, you know. The fact that we had dry docks and transits and you can’t cut the fixed costs when you’re just moving boats around. Pierre Conner - Capital One Southcoast, Inc.: As pointed out earlier that’s the biggest driver, depending on –

Yes. Yes.

Your next question comes from Robin Shoemaker – Citigroup. Robin Shoemaker – Citigroup: Andrew as you plan for the North America – the continued drop in North American activity you mentioned that this downturn is different from previous ones in several respects. Do you expect a kind of a B-shaped bottom to the North American drilling decline as we’ve seen in the last two downturns? Or is this something in your mind possibly very different?

The answer, Robin, is I don’t know yet because so much of what happens in North America is going to depend on a recovery in industrial [inaudible] I guess. And there are some things out there that could make it very positive. For example, if the new administration decommissions some coal-fired generating plants, that could increase gas demand fairly dramatically. The other unknown is what is the true decline rate of some of these new Shell Gas horizontal wells? So the answer is I don’t know at this point in time. But I would say the key factor is when demand starts to recover. Robin Shoemaker – Citigroup: On all the various currency impacts that you mentioned, and I assume some of the big ones are the pound, Canadian dollar, the Russian currency, do you have a aggregate impact of based on various markets of what that was in the negative sense in the most recent quarter?

Simon.

Basically we highlighted the impact of the currency on the top line. And the fact is, we don’t have impact of those currencies on a profitability. Our as a matter of fact, the stronger dollar overall is a slightly positive for us. But definitely on the top line as you highlighted, certain countries like Canada and North Sea, we have a high portion in the local currency. And some other markets much lower. But overall we are quite balanced between the income between these currencies and our costs and on a profitability basis there is no impact.

Your last question comes from Michael LaMotte - J.P. Morgan. Michael LaMotte - J.P. Morgan: I appreciate the opportunity to follow up and it’s related to CapEx. I was hoping you could talk a little bit about the priorities of the $2.2 billion in Oilfield with respect to replacement capital, new technology deployment, project related, etc.

There’s an awful lot of project related deep water CapEx. There is a lot of CapEx related to gas overseas. And after that I would say those probably if you like the new categories, Michael, then I would say its replacement and new technology. Michael LaMotte - J.P. Morgan: So if I think about a Plan B on the CapEx side in the second half it would really be subject to potential deferrals on gas and deep water, probably the biggest areas?

Probably. Yes. Or the fact that there had been some idling in the offshore market that allows us to take CapEx from other offshore rigs and put them on new ones.

On behalf of the Schlumberger management team I would like to thank you for participating in today’s call. Shelly will now provide the closing comments.

Thank you ladies and gentlemen. This conference will be made available for replay after 10:30 AM today and will run through February 23 at midnight. To access the AT&T replay system at any time, please dial 1-800-475-6701. International participants dial 1-320-365-3844 and enter the access code 972151. Again those numbers are 1-800-475-6701. International participants dial 1-320-365-3844 and the access code 972151. That does conclude your conference for today. Thank you for your participation and for using AT&T’s Executive Teleconference. You may now disconnect.