斯倫貝謝公司 (SLB) 2009 Q2 法說會逐字稿

Welcome to the Schlumberger conference call.

(Operator Instructions) Later, there will be a question-and-answer session and instructions will follow at that time.

As a reminder, today's call is being recorded.

At this time, then, I'd like to turn the conference over to Vice President of Investor Relations, Mr.

Malcolm Theobald.

Please go ahead, sir.

Thank you, Kent.

Good morning and welcome to Schlumberger Limited second quarter 2009 results conference call.

Today's call is being hosted from Paris where the Schlumberger Limited Board meeting took place yesterday.

Before we begin with the opening remarks, I'd like to remind the participants that 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.

Joining 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 second quarter and his comments on the outlook, Simon, will first review the quarter's financial results.

After the prepared statements, we will welcome your questions.

And now, I will turn the call over to Simon.

Thank you, Malcolm.

Ladies and gentlemen, thank you for participating in this conference call.

Second quarter income from continuing operations, excluding charges, was $0.68 per share, down $0.10 sequentially and down $0.48 compared to the same quarter of last year.

We continued to actively manage our cost base.

In this regard, we have continued to reduce our head count, which resulted in charges of $0.07 in the quarter, primarily relating to severance.

Additionally, as a result of these work force reductions, we were required to record a noncash pension and other post-retirement benefit curtailment charges in the quarter of $0.10.

These head count reductions are expected to be largely completed by the end of the third quarter.

Turning to the business segments.

Oilfield services second quarter revenue fell by 9% sequentially.

While WesternGeco revenue increased 1%.

Oilfield services generated $1 billion in pretax operating income, down $233 million sequentially, with margins declining by 245 basis points to 20.6%.

By area, oilfield services sequential pretax operating margins highlights where as follows.

North America declined to 1%, on the heavy pricing pressure across most of the area and the sharp drop in activity pressure mainly in US land and in Canada.

The sequential margin decline is equally attributable to US land and Canada.

Internationally, margins were at 25.1%, a decline of 170 basis points from Q1.

Latin America decreased by 206 basis points to 17.6%, primarily due to a less favorable revenue mix, coupled with cost inflation in Brazil, currency devaluation losses and pricing pressure in the Peru/Colombia/Ecuador and the impact of the lower activity in the Venezuela/Trinidad & Tobago.

These decreases were partially offset by the increased IPM activity in Mexico/Central America.

Europe/CIS/Africa margin was 24.2%, which was 172 basis points lower than last quarter, primarily due to the lower activity levels and less favorable revenue mix, Nigeria & Gulf of Guinea, West and South Africa and the North Sea.

These decreases were partially offset by an increase in Russia as a result of the improved activity levels.

Finally, Middle East & Asia slipped 107 basis points to 32.1%, primarily as a result of the lower overall activity in the area.

At WesternGeco, pretax income of $97 million reflected an increase in the pretax margins of 739 basis points to 17.3%.

The increase was primarily due to higher multiclient sales and improved profitability in marine as cost reductions initiatives more than offset the impact of the lower revenue.

Now, turning to Schlumberger as a whole.

The effective tax rate, excluding charges, was 18.2% and including the charges it was 19.8%.

The rate was lower than last quarter due to the substantially lower proportion of pretax earnings in North America.

The ETR for the year is expected to be in the lower 20's.

As a reminder, the ETR is very sensitive to the geographic mix of earnings and as such, we may experience volatility on a quarterly basis.

Net debt was $990 million at the end of the quarter, an improvement of $537 million from Q1.

This improvement was driven by strong cash flows from operations.

We ended the quarter with $4.9 billion of cash and investments on hand.

In addition, $2.3 billion of committed debt facilities with commercial banks remained unused and were available at the end of June.

This compared to short-term debt of only $1.6 billion, which includes $321 million of our convertible debentures, which are now classified as short term.

Significant liquidity events during the quarter included $503 million of CapEx, $229 million of pension funding and $186 million of acquisitions.

We did not buy back any of our stock during the quarter.

Oilfield services CapEx is expected to approach $1.9 billion in 2009.

While WesternGeco is now expected to reach $530 million, which includes approximately $225 million relating to the construction of seismic vessels.

In summary, our balance sheet remains very strong and provides us with a significant amount of financial flexibility.

And now, I turn the conference over to Andrew.

Thank you, Simon.

Good morning, everybody.

Schlumberger's second quarter revenue fell 7.8% sequentially to $5.53 billion.

Compared to the first quarter, the overall sequential rate of revenue decline slowed as a further precipitous drop in North America was offset by slowing rates of decline and some recovery in other parts of the world, including Russia, where revenue recovered noticeably due to seasonal trends and improving activity.

In North America, gas drilling in both the US and Canada reached a five year low, as demand remained weak and storage levels remained way above the seasonal averages.

Whilst production has begun to show some decline and summer demand has been strong, it will still require a further substantial increase in demand, particularly in the industrial and power generation sectors, to stimulate and sustain higher levels of drilling.

Looking at the areas in detail and starting with North America.

The US land geomarket recorded a further steep drop in revenue as the rig count declined approximately 27% and as pricing continued to erode.

Revenue in Canada also dropped significantly due to the impact of the seasonal spring break up, the general reduction in land drilling activity and the effect of significant pricing pressure.

In the US Gulf of Mexico, however, revenue fell more modestly as lower pricing and further weakening on the shelf drilling activity were partially offset by slightly higher deepwater activity.

In the Latin American area, the Venezuela/Trinidad & Tobago geomarket showed the sharpest sequential revenue decrease as a result of lower activity and a revenue deferral pending finalization of certain contracts.

This decrease, however, was somewhat offset by an increase in the Mexico & Central America geomarket, as integrated project management activity and efficiency both increased.

Within Europe/Africa/CIS, revenue in Russia grew sequentially on the seasonal rebound of offshore activity in the east, among generally improved activity levels in both east and west Siberia.

This growth was also supported through higher sales of artificial lift and completions products.

In North Africa, revenue grew from strong demand for testing services and completions products.

These positive factors, however, were more than offset by reduced demand for drilling & measurements and wireline services in Nigeria & Gulf of Guinea and West & Southern Africa geomarkets, in addition to lower drilling & measurements and well services activities in the Caspian and North Sea geomarkets.

Lower Schlumberger information solutions software sales, as well as reduced demand for drilling & measurements, wireline and testing technologies in continental Europe, also contributed to the overall area's sequential revenue decline.

Lastly, in the Middle East & Asia area, sequential revenue fell primarily due to lower activity in the Gulf geomarket, as well as in the East Mediterranean, Arabian, Indonesia, Australia/Papua New Guinea and India geomarkets.

Pricing pressure also began to impact revenue across the area.

These decreases, however, were partially offset by an increase in revenue in East Asia on strong exploration related demand for testing services, wireline and well services, and a rebound in activity in the China/Japan/Korea geomarket following the winter slowdown in the first quarter.

At WesternGeco, there was some recovery in multiclient sales, both in North America and overseas.

Although this, together with increased activity in land, was offset by weaker marine revenues.

Marine pricing continued to decline due to excess capacity in the market.

Several new marine and land contracts were booked during the quarter, giving better visibility on the next few months.

However, multiclient sales remain difficult to forecast until there is better visibility on year-end oil prices.

Against this background, we have continued to take action to right size our operations without diminishing our capacity to react to market changes.

Overall, our operating cost base declined approximately $300 million compared to the first quarter, as cost reduction programs continued to be implemented.

Careful management of both working capital and investment, led to the liquidity improvement that Simon described.

Our outlook for the remainder of 2009 assumes some stability but no major increase in North America natural gas rig before 2010.

And as a result, service pricing will remain depressed.

Overseas, further activity declines will occur but will be limited, while the pricing concessions made in the first half of the year will effect revenues in the second half.

The current volatility in the oil price makes it unlikely that our customers will sanction any major increases in expenditure.

We are aware that a number of projects are continuing to be postponed or canceled.

We are also concerned that higher finding and development costs of new supply, coupled with lower oil and gas prices and more restrictive credit markets, are stifling investment flows.

This situation, if it it persists, will lead to inadequate supply when demand growth returns.

The shape of the economic recovery beyond 2009 and the consequent recovery in oil and gas demand, remain the determining factors for future activity increases.

Thank you and I will now hand the call back to Malcolm.

Thank you, Andrew.

We will now open the call for questions.

(Operator Instructions).

And our first question come today comes from Kurt Hallead with RBC.

Please go ahead.

Good morning or good afternoon in Europe.

Thank you, Kurt.

Andrew, by -- at the end of the first quarter, you reference that this cycle was progressing very similar to prior cycle periods.

And that would be due to the reason that the international markets, from a volume standpoint, could lead lower into 2010.

And I noticed in the commentary that you had here today, that your international reference points were really focused on the second half of 2009.

So I was wondering if you can kind of update us on your thoughts -- as to whether your thoughts have changed, and if so how, as you kind of look out beyond 2009 from an international volume standpoint?

Well, I don't think my thoughts are substantially changed.

If there is an element of doubt in predicting beyond the end of the year, it is the fairly rapid recovery that has taken place in the oil price.

As I said in the comment this time, I think that there's too much volatility in the oil price at the moment to sanction much increase in spending.

But if at the end of the year, it persists at the higher end of the range that we've seen so far this year, then I do think that it might, if you like, not lead to the same reduction in activity next year that I was perhaps originally thinking of.

But it really does depend on where the oil price is the end of the year and not where it is now.

Okay.

That's great.

I appreciate that color.

Now, my follow up is, you made some explicit reference here to some deferrals of revenues in Venezuela.

And we know, obviously, the mess that, again, that country has been.

Can you give us your updated view on what you see as the prospects of any recovery in Venezuela?

And can you update us on the receivable situation there, please?

Well, during the quarter, we've made very satisfactory progress on the receivable situation.

And we also made considerable progress on the renewal of three major contracts but we were not able to book the revenue in the second quarter because the actual inking hasn't been done.

And therefore, there was a fairly large sum -- amount of revenue that was deferred to the third quarter.

As to the overall levels of activity in Venezuela over the coming months, it's a little early for me to say what I think [PDVSA] is going to do.

But certainly, the general situation in terms of receivables and contracts has shown a marked improvement over where we were at the end of Q1.

Okay.

Great.

Thank you.

Great.

Thanks.

And we have a question now from the line of Michael LaMotte with JPMorgan.

Please go ahead.

Thanks, and good afternoon Andrew, Malcolm and Simon.

Hi, Michael.

If I could ask quickly on the OGX contract and maybe talk about the differences between this structure and a typical IPM contract and whether or not there are other offshore opportunities like this out there?

So the difference is that, whereas, what we are providing in the OGX contract is very similar to what we would provide in a classic IPM, obviously, the size of the amount and the risk involved means that we cannot take the same risk as we do in land IPM contracts.

So this is somewhere between IPM and bundle services.

So there's not perhaps the same scope for incremental due to performance but the actual rate of renumeration is a lot better than it would be in a basic IPM contract.

And we are providing a lot of the technical services around the development, as we would do in IPM.

And yes, there are other opportunities of this type.

In terms of market size, if I think about IPM opportunities on land versus this type of thing offshore, is this an emergent market, is this a big market that is just you get a little bit of share into?

What's the penetration of --?

I think there are two.

So firstly, I don't think this is the huge market.

It's obviously a very profitable market because it's deepwater.

I think that the market falls into two types of market.

The first, is the OGX type where there is a definite wish to harness Schlumberger's technical expertise.

The second type where this occurs is the remote market where a customer doesn't have any infrastructure whatsoever and rather building a complete infrastructure.

So, this would typically be more in exploration or the delineation, than in development.

They will ask Schlumberger to manage a lot more of the process than we would in a normal offshore operation.

Great.

Second question, on Russia, I'm intrigued by your comments that the improvement was not just seasonal.

Would you care to elaborate and perhaps talk about how you would characterize Russia today and the recovery?

Well, I think that to be honest, there were two events, which are not seasonal.

The first is the fact that the ruble exchange improved considerably against the dollar.

And the second, is that the Russian oil companies who count in rubles, obviously, their first quarter results were huge.

And therefore, there is more cash to invest and perhaps a greater willingness to invest than there was in the fourth quarter of last year.

So I think that it's probably very definitely sustainable through this the rest of this year.

In addition, I understand there's a probable change in the tax law.

So, I think that while it's not going to be gangbusters, there is the scope for considering more investment in Russia than we originally thought.

That's great.

Thanks, Andrew.

Thank you.

And our next question then comes from the line of Ole Slorer with Morgan Stanley.

Please go ahead.

Thank you very much.

And Andrew, you mentioned that you've -- it sounds like you're quite concerned about the 2010 plus outlook for oil supply given the current delays and investment trends that you are seeing out there.

Could you care to elaborate a little bit more because we just had the IEA come out and increase their estimates on non-OPEC production?

And can you just sort of talk a little bit about how you might differ or where you agree or what you see?

Well, actually, the thing that worries me more than anything else and that's why when I answered Kurt's question I stressed the level of the oil price so much, is our customers' cash flows.

Because even our very largest customers are having to borrow or dip into their war chest to sustain their spending.

And they will only go on doing that for a certain period of time.

And therefore, if we don't have a fairly substantial improvement in the oil price by the end of this year, then the risk is that the cash flows will be such that they will not actually increase at all in 2010.

So, that's why I am so insistent that it hinges on the level of the the oil price at the end of this year.

Now, in terms of supply, you've seen the easy stuff go away, the heavy oil and the tar sands and all the rest of it, which is a fairly substantial chunk of production that was originally included in the sort of 2012 estimate.

And I tell you what we're seeing now is a very definite caution on the part of our customers, which leads them to postpone fairly substantial projects.

And if they don't see an increase in their cash flow, they're going to go on doing that.

And my points is, that if that happens, it's just going to accelerate the supply decline.

And if that occurs at the moment when demand starts to grow, the crossover could be quite violent.

I don't have -- I don't comment on the IEA's.

Okay.

So, if the oil price continues to drift higher, with an economic recovery gaining traction, under that scenario, how do you see the outlook?

Then I think there will be some time in 2010, and please don't try to tie me down to the exact day, Ole, some time in 2010, our customers will gain sufficient confidence to start to rebuild activity.

But don't, please don't, I do not think that's in 2009.

And I do think that's a function of the oil price and their cash flows, if they see them going into 2010.

Just one follow-up question on WesternGeco.

You had mentioned for the first time now, CSEM and the [TDEM] integration with [Q.] Could you talk a little bit about the scope to use this as a tool to maybe withstand some of the general margin and pricing pressures that you highlighted in seismic in general?

I think that the capacity to do the integration is going to lead to a higher value multiclient product and therefore, a better priced multiclient product.

That's the scope I see for the moment, Ole.

Thank you.

Thanks.

Our next question then comes from Bill Herbert with Simmons.

Please go ahead.

Thanks.

Good morning.

Andrew, getting back to the road map, if you will, for non-North American margins, recognizing that 2010 is certainly opaque and there's enough uncertainty with regard to the remainer of 2009.

But quarter on quarter, you're down about 170 basis points internationally.

By year-end, what do you expect within a range the margin contraction to be in the non-NAM realm?

And I think to frame it for you, Andrew, just very quickly, one of your peers suggested that international margins would be down 300 to 500 basis points within the next two to four quarters.

And I'm just curious as to whether you ascribe to that view?

Yes, I know.

I don't think that's an unreasonable position to take.

Okay.

I don't know whether they'll go that far but they could.

That really is going to depend a great deal on what -- if you say two to four quarters it's really going to depend a great deal on what the activity looks like in the back end of that.

Right.

Because if I recall correctly here, the first quarter, your prophecy for non-North American margins was a typical Eastern Hemisphere correction, if you will.

18 months taking to unfold, margins down basically 50% from the recent peak, which would imply margins somewhere in, frankly, the high teens.

And margins to bottom either first or second quarter of next year.

And if you're suggesting 300 to 500 basis points from here and you're thinking that that could be on the high end with regard to the rate of margin contraction, it sounds like you're a little bit less, what's the right word, "pessimistic" with regard to where margins are going to bottom.

I think, as -- in what I know today, that's for the rest of 2009, it is probably reasonable to assume I am a little less pessimistic.

Okay.

However I would put this big rider on whether or not that we have another leg down in 2010 because activity -- because our customers' cash flow or our customers consolidating or whatever else they do, means that there's another leg down in activity.

In which case, I would become much more pessimistic.

Understood.

Second question relates to North America margins.

Clearly, everybody is sort of enduring a lot of duress for reasons that we all know.

You're taking a lot of costs out of the system.

The North American, at least the US, rig count is grouping for a bottom.

Canada is seasonal recovery.

It looks like most of the pricing woes are behind us, although you're going to get some quarter on quarter flow through.

Should we expect margins, assuming that activity, basically, is not going to take another significant leg down, that margins have essentially bottomed for you in North America?

I'm going to be very bold and say that Canada will improve.

Yes.

On the basis of some modest seasonal rebound.

And North America, I don't think will go any lower.

Okay.

Great.

Thank you very much.

Great.

Thank you.

And our next question then comes from the line of Daniel Pickering with Tudor Pickering Holt.

Please go ahead.

Morning.

I just want to clarify a comment that you made, Andrew, in your remarks where you talked about -- or I think Simon maybe said that Canada and the US contributed equally to the correction in margins from Q1 to Q2.

Is that -- does that mean they were both down the same amount in dollars or percent or I just -- it would make a very big decline in Canada if it was the same dollar amount?

No, it's in the percentage terms.

Dan, if you take the drop that we experienced from Q1 to Q2, the major part of it is a split equally between Canada and US land, yes.

Got you.

And in percentage terms, yes.

Okay.

Thank you.

That helps.

And then, Andrew, last quarter, I asked you about whether or not we can make more money in 2010, Schlumberger Corporate entity, than we did in 2009.

And you said it didn't seem logical that you would.

As I look at the world today, oil prices are better, as you mentioned.

North America is maybe a little bit worse, pricing issues, there's a lot of mix issues going on for Schlumberger.

Has your view changed?

Is it not logical to make more money next year or is it now possible?

Well, an awful lot will depend what happens in North America because we could hardly make less.

And then, again, it comes back to everything I've said to everybody else about what is the oil price going to do towards the end of this year.

There is one element of this cycle that we don't understand yet.

And it's a logical element in every cycle and that is, what do our customers do when their cash flows really start getting crimped?

So the hedges run out, they need to go to bank or cut their dividends or whatever else they need to do to fund their projects.

Do they do that or do they cut their projects?

And that really is going to depend on their perspective of oil prices towards the end of this year.

Then, the next logical phase in any cycle is that they start to consolidate.

And we actually haven't seen very much of that.

So, to be determined?

To be determined.

That's the big rider on where the oil price is in the last quarter of this year.

Okay.

Thank you.

Great.

Thanks.

And our next question comes from the line of Geoff Kieburtz with Weeden.

Please go ahead.

Thanks.

Good afternoon.

Hi, Jeff.

Andrew, you've several times described this sort of huge uncertainty that faces us toward the end of the year as to what customers are going to do based on, in your view, what oil prices are doing at the time.

How do you manage Schlumberger with that sort of uncertainty?

You've got cost cutting efforts going on, you've reduced head count.

Do you do more of that and take a chance that you don't have enough if the activity picks up?

Or do you hold on and take the risk that if it's weaker, your profitability suffers?

We would, I think, in these circumstances having gone where we've gone with head count, hold on.

Now, we do have a volume of skilled people who have been put on leave of absence.

So, I'm not going to tell you how many but we could call back a considerable body of people on one month notice.

So we have a considerable body of people who badly needed a rest, Geoff, because they've been working very hard for last three years, who have gone on an incentivized leave of absence.

Okay.

So you have kind of an option there.

Yes.

And does that option expire?

After one year.

So, it's toward the middle of next year.

Okay.

And a second question is, as you reference the uncertainty about what your customers do in regards to consolidation, how do you look at the oilfield service market in terms of current conditions and consolidation or M&A opportunities?

I think if North America remains sort of bumping along the bottom for the next six months, then you will see some consolidation in the industry.

I'm not saying it's going be us.

I'm just saying that I think the bumping along the bottom for the next couple of quarters will tire -- wear some people out.

Could it conceivably be Schlumberger?

Well, we're always open for a good opportunity but the opportunity has to be real and mature.

And I'm not sure that we're going to see that because, as you know, what we can buy is quite limited.

Yes, okay.

Thanks very much.

Thank you.

And we have a question now from the line of Mike Urban with Deutsche Bank.

Please go head.

Thanks.

Good afternoon.

Andrew, I would generally agree with our comment that I wouldn't expect your customers to reopen '09 budgets based on where we are today.

But I am a little surprised that maybe some projects that had been budgeted but delayed aren't potentially moving forward or delayed maintenance or deferred maintenance not moving forward because those are pretty short lead time and high impact activities with the oil price where it is.

I was wondering if you could comment on that a little bit?

Well, I think -- yes, if you're talking about workover, I think that's -- workover projects, production enhancement and enhanced maintenance, all the rest of it, absolutely.

They may loosen up a few more dollars.

I was talking about a net increase in the number of projects.

I don't think you're going to see any major projects sanctioned until there's a much greater degree of confidence over the stability in the oil price.

Okay.

You've bounced around by a considerable amount already this year.

It's been up, down and now it's up again.

They're going to want to see some boundaries on it before they commit.

Okay.

But some of the marginal stuff is kind of shaking things up but nothing is very --.

Yes.

All right.

Great.

And then the follow up would be, obviously the international markets aren't necessarily monolithic and you've talked about Russia increasing a little bit.

So, if you're talking about kind of a net decline on the major projects side, what's going to be a little better or a little worse over the balance of the year?

Well, I think that for example if the oil price holds up where it is, the North Sea will be a little bit better than we thought but that's from it being way down.

Then I think that certain parts of Southeast Asia may be a bit better than we thought.

I don't think -- it maybe a little -- it may help North Africa a little bit, particularly Algeria, it may help even parts of South America a bit.

But this is -- yes, it's nice to have but it's not going to move the needle in the industry if people spend a little more money on workover.

I was referring to your comment about continued declines in activity level.

Some of those things are better.

Then what's worse, if those things are a little better?

Well, what is worse is if, in some of the very big projects, some of the partners say, "We don't want to do the next phase." And all of the other partners say, "If you're not going to do it, we're not going to do it either." We haven't seen a lot of that yet but I have heard some of our customers say, "If X doesn't follow, we won't follow either." So, this is where I start to talk about strain on the cash flow.

Okay.

Got you.

Thank you.

Thanks.

And our next question comes from the line of Daniel Boyd with Goldman Sachs.

Please go ahead.

Hi, thanks.

Andrew, when we look at the break down of international margin pressure going forward, I'd assume some areas such as land may have felt the impact of oil pricing sooner, just because it's shorter cycle.

Whereas, price concessions on longer term projects such as deepwater may have not actually flowed through results yet.

As you pointed out, that's still to come.

Can you comment on what you're seeing in here and how that might impact different geomarkets?

Well, I think actually you need to segregate it more by customer than type of project because the IOC's have been very quick to react and quick to implement price negotiations, whether it be offshore activity or land activity.

So, it's more, if you like, where you have strong concentrations of IOC activity that the price concessions have been greatest than by any particular type of activity.

That's why for example, you take somewhere like the UK sector of the North Sea or West and Southern Africa, what you like is dominated by large companies that the pricing pressure is a lot greater.

Okay.

That's helpful.

And then, as an unrelated follow-up, when we look at North America, can you comment on your ability to remove capacity from the market outside of just pressure pumping?

And do you see that as an opportunity?

Well, we do relocate assets in the other segments.

So, drilling & measurements and wireline, a lot of the assets that are in North America are going to fill CapEx requirements in overseas geomarkets and therefore, reducing the CapEx that we use overseas.

It's a lot more difficult with prime movers.

So, it's a lot more difficult to move trucks around the world, for example, than it is to move tools.

Partly for regulatory reasons and partly because it's just a lot more expensive.

So you might park it.

Okay.

Thank you.

Thanks.

And our next question then comes from the line of Jim Crandell with Barclays.

Please go ahead.

Andrew, could you give your current views on Iraq?

How quickly you think that activity could ramp up with both the NOC's and the IOC's?

And then, do you think this business could be $1 billion business for you in the next year or two?

So I think that -- so firstly, what are we doing in Iraq?

We are currently constructing a base in the southern oilfields, on speculation.

We don't have contracts to justify that base.

On the basis that when activity does come back in serious amounts, that's the best physical location to be in.

We are, as our competitors have remarked, talking to everybody.

I -- the security conditions under which we are operating are still really at the margin of what we can do safely.

We probably on a wellsite visit will have as many security people as we do people doing operations.

And I think that the likelihood is that the first activity we will see is going to be with the Iraqi national oil companies for the fields.

And I think it's likely to really only make a difference next year.

And I think the chances being at a $1 billion business in two years is zero.

Really, okay.

A follow up question, Andrew, relates to North American results here in the first quarter.

And it struck me that due to your stronger competitive position in deepwater and in Alaska, that break even results must be viewed as disappointing to you.

And was this in large part because the pricing deteriorated in some of your core businesses a lot than what you would have thought?

I think that actually the shelf -- the Gulf of Mexico was quite disappointing because of the reduction in shelf activity.

I think that we were disappointed with US land.

It is largely a matter of pricing and it is across most of the segment.

But we are -- we were badly hurt in Canada, too by both activity and pricing.

How did pricing trend, how was pricing, Andrew, versus your expectations in businesses such as wireline and WD directional?

Well, I don't think that -- I think wireline, everyone was a bit surprised by amount that wireline pricing declined but then the decline in activity in cased hole was so great that we shouldn't really have been that surprised.

And in drilling & measurements I don't think there was -- I don't think that the pressure was nearly as bad as it was in the other segments.

Okay.

Thank you.

Thanks.

And our next question comes from the line of Bill Sanchez with Howard Weil.

Please go ahead.

Morning, Andrew.

Morning, Bill.

Andrew, I just wanted to follow back up and I think you touched on it but just to be clear, you mentioned about the pricing renegotiations that took place in the first half impacting your second half international results.

I'm just curious today, are we at a point in some markets where that has completely abated as it relates to renegotiating existing term contracts?

Or is it just moderate or are there still areas where it's just as strong today as it was say three or six months ago?

Well, I think that unless there's another leg down, we've pretty much finished the price renegotiations with all of our major IOC customers.

But a lot of those negotiations were only finished during the second quarter, so the pricing effect is going to be seen in the third and fourth quarter.

And that I think largely those renegotiations are done.

The rest of it, what I think be the rollover of tenders, which as you know it takes much longer to work through the system, which is why I've always said I think there's no reason why this cycle would be particularly different from any other cycle.

And the full effect will take 18 months to work itself through the system.

But for the major customers, most of the renegotiations were done in the first half of the year.

Okay.

One follow up, you talked about your thoughts on IPM on the last quarter call and the balance between owning rigs and not owning rigs and successes you could have in IPM going forward.

Any changes there to your thoughts?

I know, potentially, there's another competitor on the service side coming in on Chicontepec now.

Just your thoughts maybe in Mexico incrementally going forward, just kind of your IPM views going forward in terms of owning rigs versus using more of a managed services approach going here forward.

So frankly, I don't think there's one answer to the thing because as the world develops, particularly in countries where the economies are becoming more sophisticated, the issue of local content is going to become greater and greater.

And the capacity to import, particularly, a piece of equipment like a rig that's available on the market is going to become more and more difficult.

So generally, we will favor a managed services approach.

In terms of Chicontepec, we have an exposure, which I would not want to increase.

I feel quite comfortable where we are for a number of reasons and therefore, I'm not surprised -- and I'm not at all surprised to see more and more contractors trying to break into that market.

Thank you, Andrew.

Thank you.

Our next question comes from the line of Waqar Syed with Tristone.

Please go ahead.

Andrew, could you comment on the timing of Saudi gas initiatives?

When you think they could pick up rigs?

They've laid off some oil rigs but on the gas side, they've been talking about it.

When do you think that potentially could materialize?

Well, I think there already has been a considerable shift of land rigs to gas exploration.

That's taken place.

It took place in the first quarter and the end of last year.

And offshore, there is no doubt that the bulk of the rigs and increase they do in offshore rigs is going to be focused on gas development, as they have a number of reasonably successful discoveries.

So, I don't think it's -- I think it's happening.

I don't think it's about to come.

Okay.

And in terms of revenue per rig, how does that compare in Saudi Arabia between an oil well and on a gas well, how does the revenue and margins kind of change between the two?

Well, like anywhere else, the gas wells tend to have more revenue per rig, not necessarily the same level of profitability or return on sales.

And in terms of Saudi, in terms of oil wells, it depends very much what type of oil well you're talking about.

If you're talking about a 6,000-foot development well in [Goua,] the revenue is not very high.

If you're talking about a very complex horizontal well on Manifa, it's a very different point of view.

So, you can't draw a general rule.

But as a general rule, the same ratio of better revenue on a gas well applies in Saudi Arabia as it does anywhere else.

Okay.

And then on unconventional gas outside of North America, what are you seeing in terms of activity and how do you -- when do you think it's going to become a material business?

Well, I think that there's no one answer.

For example, you can see already that a lot of the coalbed methane work in Australia is already being tendered.

If you're talking about shale gas, North America type, the cost of development overseas is going to be very different from what it is in North America.

And the chief reason is because North America already has the most developed oilfield service infrastructure in the world and therefore, rigs, fractories, water carriers, all of the rest and the availability of water for this business is something that's very well understood.

Whereas, that is -- with perhaps the possible exception of Germany and Austria, that is not at all the case overseas.

And therefore, we think it will happen but we don't think it's something that's going to spread everywhere very fast.

If it does start reasonably quickly, we think it's probably going to be in Eastern Europe.

Okay.

And how about the tight gas initiative in Saudi?

Is that -- how advanced is that and --?

Sorry.

What do you mean?

That Saudi Arabia was looking at drilling the tight gas reservoirs.

And has the profit started, is that --?

Well, we have had a tight gas center of excellence in our research center in Dharain for over a year now.

Staffed largely by specialists from North America.

So, we consider that something that's thoroughly underway.

Great.

Thank you.

And our next question comes from the line of Brad Handler with Credit Suisse.

Please go ahead.

Thanks.

Could you please speak to the modestly lowering of CapEx guidance for '09 relative to the last quarter?

Are we looking at cost savings or have you made some adjustments to the CapEx program?

I think we're largely looking at backfilling with transfers from idle CapEx in other markets.

And I don't think you can talk about cost savings yet.

I do think, actually, that it is possible that that continues and it drifts a bit lower over the balance of the year.

Okay.

That's helpful.

And that certainly -- that seems to make sense on the oilfield side.

On the seismic side, at WesternGeco, are you deferring some of the CapEx on the new vessels?

No, we're not hurrying but we're not deferring them.

We're completing them as and when it's reasonable to do so without incurring additional costs.

So, we haven't -- with the exception of certain vessels that we did not take delivery of on the leases, we are not deferring any of the CapEx on the owned vessels.

For the unrelated follow-up, on the M&A side, $186 million in the quarter, I think we saw a press release on Techsia.

Can you give us some information about -- I'm going to guess that that wasn't all for Techsia.

Can you give us some information on what else you bought?

Yes, the rest was a couple of small technology related companies in Russia.

Thank you.

And our next question then comes from the line of Robin Shoemaker with Citigroup.

Please go ahead.

Thank you.

Andrew, I wanted to if you -- in the your comment about the postponement of projects or delay or cancellation, does, do deepwater drilling and development projects, are they also in that category?

They actually have been surprisingly resilient.

So yes, we've seen some postponement but not cancellations.

So for example, we do see a lot of contracts that will actually come into operation in deepwater in the second half of 2010 and then 2011.

There's been very little actual cancellation.

Where there has been another movement, which I think I talked about last quarter, Robin is a shift from exploration to development on the basis that development produces cash flow.

Okay.

And just staying on that theme then, at your position market share in deepwater prospectively with the rigs that will be entering service over the next couple of years, how do you feel about your market share in various project lines with regard to the installed equipment and awards that may not have already been made?

Well, I don't know about awards that have not already been made but what I can tell you is that on awards that have been made for projects that are known and have been tendered, I am very satisfied with the market share that we have.

Okay.

All right.

That's good for me.

Thank you.

Thank you so much.

And our next question then comes from the line of Pierre Conner with Capital One Southcoast.

Please go ahead.

Good afternoon, Andrew.

Andrew, on the premises that your answer to Dan's earlier question about the capacity in North America was excluding pressure pumping.

I wanted to get your take on that, on North America pressure pumping capacity?

Other players in this market have discussed retirements.

And would you care to talk about your plans?

Well, we do some retirement and we're doing some mothballing.

And as I think my competitor described, that is a lot to do with the condition of the equipment and the cost of refurbishing it or not refurbishing it.

And the fact some of these massive frac jobs chew up equipment, as I think they put it, much faster than traditional frac.

But today, we have a mix of retirement and mothballing.

And my assumption is that that retirement and mothballing then has increased with the current market and a shift towards higher intensity fracing.

Yes and it's still going on.

Okay.

And in an unrelated follow up actually, is to do with the pricing in marine.

And so, I wanted to understand, you have a backlog and I'm assuming you're executing against that backlog.

Yes.

Is there active renegotiation on contracts underway or help me understand the mechanics of that?

Actually, there has been very little attempt on the part of our customers to renegotiate seismic contracts that are being executed.

They have, of course, pushed them out or tried to shorten where they can do it, shorten the duration.

But actually, renegotiating price, they have not really been trying to do that.

Probably because they have a fairly clear optic of how far they're committed.

But obviously, when they retender or when they do tender, and in fact, there is quite a surprisingly high level of marine tendering going on, then they expect much lower prices.

Okay.

So the backlog is being renewed but at a much lower price, Pierre.

Understand.

Thank you, gentlemen.

Great.

Thank you.

And we have a question then from the line of Kevin Simpson with Miller Tabak.

Please go ahead.

Thanks.

So Andrew, I'm going to ask you a very macro question, an opinion, which maybe you'll want to duck.

Is that price that you're speaking of in and around $60?

So for, West Texas or whatever, a light sweet crude with -- which would give them a $10 cushion or can it be somewhat lower?

In my opinion, it's higher, Kevin.

Higher than $60?

In my opinion it's more like $70.

So and if we --?

Because their costs have gone up.

Because they're borrowing costs have gone up as well.

Government tax has gone up.

$60 is okay but it's not going to lead to a rash of new activity.

Whereas, I think $70 might be a lot more encouraging.

Okay.

And then an unrelated follow up as well.

The uptake of your value added technologies relative to prior down cycles, it seems like you're holding up better, maybe with the Petrel platform a little more integrated into the decision making process.

What would you -- and then the same with Q, a differential edge and data acquisition.

Would you -- what's your take on --?

So, probably a bit better but not much, Kevin because our customers are becoming exceedingly cost sensitive.

And therefore, the first thing they do is tell their engineers they're not allowed to buy the bells and whistles.

But certainly in the domain of software, the penetration of Petrel in the market continues to be extraordinary because it brings our customers immediate efficiency.

It's not price sensitive because it brings them immediate efficiency.

So, on the more traditional services, I would say, this is pretty much like any other cycle.

Okay.

So, a little better on the increments it's offered.

Okay.

Thank you very much.

That's it for me.

Thanks.

And our next question then comes from the line of [Gael de Bray] with Societe Generale.

Please go ahead.

Yes.

And I think my question has already been answered.

So, no need to ask it.

Great.

Thank you so much.

Then, we'll go to the line of Rob McKenzie with FBR Capital Markets.

Please go ahead.

Thank you.

Andrew I have a question you may not want to answer given the sensitivities but I'll ask it anyway.

There's been a lot of talk in Washington, the DC area here around potentially increasing regulation on hydraulic fracturing.

It's still very unknown what the outcome is but can you give us a handicap as to where you see that issue going?

And the potential effects, ie.

potentially, even positive or negative, positive potentially for wireline and other analysis tools and negative obviously, on pressure pumping?

Yes, I think that obviously, the situation with natural gas in the United States is such that having discovered or unlocked this enormous, huge resource, there's going to have to be a solution to be found.

Now, whether the solution will be positive or negative, I don't know because the one thing you can be sure of is it's going to increase the costs.

To the extent that the solution goes through some form of reporting and monitoring and all of the rest of it, I'm pretty sure that it will get pushed off onto the service industry.

But whether or not we'll be able to charge for it, I think, is going to depend on market fundamentals.

But common sense normally prevails and unlocking this resource is a huge positive for the United States' domestic energy balance.

And therefore, I am sure that some form of solution will be reached.

Okay.

Thanks.

That's all I had left.

Great.

Thank you very much.

And that does conclude our question-and-answer portion of today's call.

I'd like to turn the call back over to Malcolm Theobold.

Please go ahead, sir.

On behalf of the Schlumberger management team, I would like to thank you for participating in today's call.

And we'll now turn the call back to Kent.

Great.

Thank you so much.

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