SLB (SLB) — Q1 2015 Earnings Call Transcript

Thank you. Good morning and welcome to the Schlumberger Limited first quarter 2015 results conference call. Today's call is being hosted from Houston. Joining us on the call are Paal Kibsgaard, Chairman and Chief Executive Officer and Simon Ayat, Chief Financial Officer. Our first comments will be provided by Simon and Paal. Simon will first review the financial results and then Paal will discuss the operational and technical highlights. However, before we begin with the opening remarks, I would like to remind 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, is included in the earnings press release on our website. We welcome your questions after the prepared statements. Now, I will turn the call over to Simon.

Thank you, Simon. Ladies and gentlemen, thank you for participating in this conference call. First quarter earnings per share, excluding charges and earnings credits, was $1.06. This represents decreases of $0.44 sequentially and $0.15 when compared to the same quarter last year. During the quarter, we recorded $439 million of pretax charges. This includes $390 million of charges associated with the headcount reduction of 11,000, as well as an incentivized leave of absence program. This program provides us with some flexibility as we manage the uncertainties of the current environment. In Venezuela, during the first quarter, the SICAD II exchange rate of VEF50 to $1 was eliminated and replaced with a new system known as SIMADI. The SIMADI rate was approximately VEF192 as of the end of the quarter. As a result, we recorded $49 million of devaluation charge during the first quarter. After this charge, the U.S. dollar value of our Bolivar denominated net assets is not material. Therefore, any further devaluations of the Bolivar will not have a significant impact on our results. Our first quarter revenue of $10.2 billion decreased 19% sequentially, while pretax operating margin decreased 255 basis points. Approximately 25% of the sequential revenue decline was attributable to the currency effect and the absence of the year-end increase in product, software and multi-client sales that we experienced last quarter. The remaining decrease was driven by activity and price declines. Despite the very challenging environment, pretax operating margin declined 255 basis points sequentially which resulted in incremental margins of only 33%. This is a result of prompt and proactive cost management across the organization. It's worth noting that although our revenue was significantly impacted by the fall in value of many currencies, this phenomenon does not have a significant impact on our pretax operating income. This reflects the benefit of our local cost structure which largely serves as the natural hedge against currency movements on our bottom line. Highlights by both product group were as follows. First quarter Reservoir Characterization revenue of $2.6 billion, decreased 21% sequentially, while margins decreased 447 basis points, to 25.7%. These decreases were largely due to seasonally lower multi-client and software sales and a fall in higher margin exploration activity. Drilling group revenue of $4 billion decreased 15% sequentially, while margins only declined 80 basis points. These declines were primarily driven by the severe rig count drop in North America. Production group revenue of $3.8 billion decreased 22% sequentially and margins fell by 389 basis points, primarily on lower pressure pumping activity and pricing pressure in North America land. Now turning to Schlumberger as a whole, the effective tax rate, excluding charges and credits, was 20.9% in the first quarter, compared to 21.4% in the previous quarter. This decrease reflects the fact that we generated a smaller portion of our pretax income in North America during Q1. As we continue to refine our business models throughout the year, the effective tax rate will continue to be very sensitive to the geographic mix of earnings. We generated almost $1.8 billion of cash flow from operations and net debt increased $100 million during the quarter, to $5.5 billion. This is all despite the consumption of working capital that we typically experience during Q1 which is driven by the annual associated with employee compensation, as well as the payment of $245 million in severance during the quarter. Even with the challenges of the current market, we still anticipate generating very strong free cash flow. This is because, during the downturn, we continue to reduce our investment in CapEx and working capital requirements will also come down. This combination should more than offset the decrease in earnings. During the quarter, we spent $719 million to repurchase 8.7 million shares, at an average price of $82.98. We spent $606 million on CapEx, full year 2015 CapEx, excluding multi-client and SBM investment, is now expected to be approximately $2.5 billion. And now, I will turn the conference call over to Paal.

Thank you, Simon and good morning, everyone. Our first quarter revenue declined 19%, driven by the activity collapse on land in North America and the associated pricing pressure. International activity was lower, as customers cut budgets in response to lower commodity prices and was also impacted by the normal seasonal effects in the northern hemisphere and the fall of certain local currencies against the U.S. dollar. In spite of these top line headwinds, we have been able to minimize the impact on our pretax operating margins, to prompt and proactive cost management and by further accelerating our transformation program. This is reflected in our first quarter international margins which are essentially flat sequentially and are up year-over-year. We have also delivered better decrementals than in any previous downturn, with sequential decremental margins as low as 33%, with North America and the international areas achieving 39% and 25%, respectively. The pace and magnitude of the activity reductions, particularly in North America, has been almost unprecedented and we have to go back to the mid-1980s to find anything similar. And while we thought we had adequate plans in place going into the quarter, activity declined even faster than expected which required us to revise our plans accordingly. This made managing the quarter challenging, including the decision to further reduce our workforce by 11,000 employees, bringing the total personnel reduction to 20,000 or around 15%, compared to the peak of the third quarter of 2014. Looking at our corporate financial performance, we generated more than $1.2 billion of free cash flow, before restructuring payments, during the first quarter. And we remain confident in our ability to generate free cash, even in these market conditions. And we expect to maintain the cash quality of our earnings by continuing to convert 75% or more of our net income into free cash flow. By geography, our North American revenue decreased 25% sequentially which was significantly lower than the 32% drop in land rig count. Operating margins in North America decreased 670 basis points sequentially, to 12.9%. In spite of these severe activity and pricing declines, sequential decrementals were limited to 39%, as we remain fully focused on flawless execution and proactive cost management. In U.S. land, drilling and stimulation activity was down in all basins, while activity also dropped significantly in Canada, while the reduction in rig count was further impacted by the early Spring breakup. In the U.S. Gulf of Mexico, deepwater activity was resilient in the first quarter, although we’re seeing a steady change in service mix from exploration towards development work, driven by budget cuts from most of our customers. On land in North America, pricing pressure was greatest for hydraulic fracturing services, although some of this impact was mitigated to increase new technology uptake, particularly for our BroadBand stimulation services and Infinity completions products. In spite of this, market pricing for certain products and services has already reached unsustainable levels; however, we’re being selective in the pursuit of market share and very disciplined in the avoidance of loss making contracts. We continue to work with our customers to have lower drilling and completion costs, by focusing on the savings that new virtuals and technologies can bring. We’re doing this through our technology integration groups, that house the full arrangement of shale expertise, spanning formation evaluation, drilling, stimulation and completions. The experts making up these integration groups are located in the larger shale basins in North America land and have both the scientific understanding of how to optimize shale developments and also an in-depth knowledge of our complete technology offering which they combine to design the best solution for each reservoir and each well. The track record we have established over the past five years has now given us the confidence to propose a range of new business models to our customers, where we initially absorb the incremental cost linked to our workflows and technologies, in return for an upside based on the actual production results. One example of our unique shale technologies is HiWAY which helps customers increase production and ultimate recovery while using less water and proppant. In the period between 2012 and 2014, wells completed with HiWAY technology in the Eagle Ford showed a 26% increase in the best three months of production, compared to wells stimulated with conventional treatments. HiWAY technology also helped save around 1.4 billion gallons of fracturing fluid and about 2.8 billion pounds of proppant, in more than 1,000 wells. The success of the HiWAY technology is now being complemented and extended by the rapid uptake of BroadBand Sequence which has already shown remarkable performance for a range of customers in both new well completions and in refracturing of old wells. In the international markets, revenue declined 16% sequentially, driven by seasonal weather impact, currency effects and customer spending cuts. But despite the severity of the sequential revenue decline and the unfavorable shift in revenue mix, we managed to minimize the impact on our pretax operating margins which was essentially flat with the previous quarter, at 24.1%. This performance was achieved by strong execution, proactive cost and resource management and the acceleration of our transformation program. Which together, were able to offset the margin impact from both reduced activity and the pricing pressure we were seeing from all customer groups. In terms of managing the pricing pressure, we remain fully focused on navigating the commercial landscape by carefully balancing the pursuit of market share with the protection of operating margins and by always aiming to trade any pricing concessions for additional work scope or better contract terms. Within the international areas, Middle East and Asia revenue declined by 13% sequentially, while pretax operating margin improved by 30 basis points, to 28.6%. Performance was impacted by a double-digit sequential drop in revenue in the Asia Pacific region and by lower product and software sales, but was partially offset by robust activity in the DTC region. Year-on-year revenue decreased 5% and margins grew by 230 basis points. In the Middle East region, our lump-sum turnkey projects in Saudi Arabia gained momentum during the first quarter and we expect solid drilling activity going forward, together with more fracturing and rigless work. In the United Arab Emirates, development activity on the North Island of the project has now started, with more rig additions planned over the next few quarters. On this project, Schlumberger has been awarded the five-year contract for the supply of integrated well construction services, with further details provided in our earnings press release. Activity in the rest of the DCC countries was also strong in the first quarter. While in Iraq, revenues in the North remain muted, at around half of the peak levels seen in 2014 and activity in the South of the country was steady around the levels seen in the fourth quarter. In Southeast Asia, activity in China was seasonally lower in the first quarter, but activity also declined in the rest of the regions, as customer budget cuts continued to be implemented. In Latin America, revenue declined 20% sequentially, while pretax operating margin improved 59 basis points, to 21.5%. Revenue was impacted by decreased activity in Mexico, Brazil and Columbia, as customer budgets were cut and also by the fall in the value of the Venezuelan Bolivar. Still, these effects were partially offset by slight activity increases in Venezuela, Argentina and Ecuador. Year-on-year revenue decreased 6% and margins grew by 39 basis points. In Venezuela, activity continued to improve with new contracts and with several of the joint ventures in the Faja, while activity is also ramping up in Trinidad. In Mexico, revenue decreased significantly on a combination of customer budget cuts, as well as seasonal weather effects that mainly impacted offshore activity. The reduced spend mainly affected non-development activity, although some exploration work was also delayed. Elsewhere in Latin America, offshore activity in Brazil remains weak, with a deepwater slowdown continuing, as Petrobras announced budget cuts early in the quarter. In Argentina, activity remains resilient in the first quarter, driven by stimulation work and continued new technology uptake in the Vaca Muerta and with new project startups offsetting the completion of others. In Europe, CIS and Africa, revenues fell 17% sequentially, with margins declining by 133 basis points, to 21%. Year-on-year revenue decreased 12% and margins grew by 66 basis points. The revenue decline was mainly due to continued weakness in the ruble and lower seasonal activity in Russia. In the UK North Sea, exploration activity fell to its lowest level in recent history, as customer spending decelerated, while rig count in the Norwegian sector appears to have reached a bottom. In Sub-Sahara Africa, both development and exploration activity was down sequentially across the region. In Algeria, our activity was flat sequentially, while work in Libya was limited to offshore locations, with onshore operations largely shut down for the quarter. Looking at the industry as a whole, the current financial challenges will not disappear, even if oil prices were to recover to the levels seen in recent years. The industry is therefore forced to seek new ways of working together to reduce costs and create more project value. And we have seen a much closer collaboration between operators and large service companies as a significant opportunity to create technical solutions that will achieve these objectives. At Schlumberger, we're ready to enter into these types of collaborations. And based on our technical and financial strength, we're also prepared to promote more risk-based contract models, where we're compensated based on the solutions we have designed, as well as on the performance of our execution. And these contract structures are currently being tabled with a number of customers as part of the ongoing commercial discussions. Turning to the 2015 outlook, visibility still remains limited. However, we expect the largest open in E&P investments to occur in North America, where 2015 spend is expected to be down by more than 30%. We further believe that a recovery in U.S. land drilling activity will be pushed out in time, as the inventory of uncompleted wells builds and as the refracturing market expands. We also anticipate that our recovery in North America land activity will fall well short of reaching previous levels, hence extending the period of weak pricing. In the international market, we expect 2015 E&P spend to fall around 15% which will create challenges in terms of both activity and pricing levels, but considerably less than the headwinds seen in North America. The reduction in international spend will be seen primarily through lower activity levels, but also with some pricing impact for basic technologies and with a continuation of the already observed shift from exploration-related services towards more development activity. In terms of geography, we expect the GCC states of the Middle East to increase investments in 2015, as the core part of OPEC prepares to recoup market share, as the rest of the global supply base continues to weaken. Elsewhere, we expect to see a double-digit reduction in E&P investment levels in Latin America, led by Mexico and Brazil. In Europe and Africa, led by the North Sea and Sub-Sahara Africa. And in Asia, led by China, Malaysia and Australia. In Russia, conventional land activity in western Siberia continues to be resilient, but the overall revenue contribution from Russia will remain subdued until there is a meaningful recovery in the ruble exchange rate. While the global fall in activity level is severe, we remain focused on the things we can control which are our cost and resource base, the effective deployment of our technology and expertise and the quality and integrity of the products and services we provide. We remain confident in our ability to weather the storm better than our surroundings, based on our favorable international leverage, our fair technology leadership in North America shale and the acceleration of our transformation program. These elements will together create the platform that should allow us to increase revenue market share from slower earnings per share reductions that our peers in the coming quarters and continue to reduce working capital and CapEx intensity, while delivering on matched levels of free cash flow.

Yes, thanks a lot and congrats on some pretty magnificent effects on the efficiency initiatives that you're implementing. But my opening question would be, Paal, if you could just update us on your macro thoughts, the same way as you did on the previous two quarters? And your comments that the markets might be tightening in the second half of the year, particularly with respect to how you see non-OPEC, non-U.S., that 50 million barrel a day bracket, be affected by the lack of investment that we've seen over the past couple of years?

So our view on the macro hasn't really changed, compared to what we said both on the October and January call. First of all, the 2015 oil demand remains strong. And I was actually right in the latest IA report. It would now be about 1.1 million barrels per day. While on the supply side, we continue to see the market share battle playing out globally. Now the key question, as we discussed before, is when and where the large cuts in E&P investment is going to show up in the supply numbers. And the latest production data from March is now showing the first signs of a tightening in supply. And we’re basically looking at three main indicators. The first one is the core OPEC spare capacity which was down by 400,000 barrels in March, to 2.5 million barrels. The other one is the one you alluded to which is the non-NAM and OPEC production which showed a slight weakening in the first quarter versus the first quarter of last year. And given the reduction in E&P spend internationally; we expect this weakening to continue throughout this year. And the third one which everyone is looking at, is the U.S. monthly sequential production which is now showing the first signs of flattening. So based on this, as we said in January, we expect the global supply to continue to tighten in the second half of this year, so really no major change to our view on the macro.

Could you share your current perspective on the goals you set during the analyst day last summer? You mentioned expecting to be in the sixth to seventh inning by 2017, but it seems like progress is happening more quickly. Can you elaborate on the momentum and how much more achievement you see ahead?

So if you look at how we're driving business performance today which a lot of the focus is around managing decrementals, there are really three components that are part of driving this performance. First is the transformation of the mindset of our entire organization, where we have, in the past couple years, taken teamwork and the tightness of the chain of command to a completely new level. So this allows us now to plan and execute and also to adjust with great pace and agility. And this is the process that had been going on for a number of years. And I think it really demonstrated our capabilities, coming from this transformation and in the first quarter. Now the second is just diligent focus on basic cost and resource management. And this includes both our internal cost structures, as well as the third party spend. And although we did well in the first quarter in this area, as well, these efforts are going to continue into the second quarter. And then the third one is really the one that you're referring to which is the structural transformation of how we run the entire company. And here, we said we would be in the sixth to seventh inning in 2017. I would say that today, we're probably in the third inning, if you want to stick to baseball terminology. It's a multi-year program. It's going to bring a steady contribution to our performance and we're today active in looking to accelerate the pace of this implementation and there is a great pool from the entire organization now to accelerate this and I'm very pleased with the overall progress, in terms of how we're doing.

I wanted to actually reference your presentation of a few weeks ago which I thought was one of the better efforts, not only from Schlumberger but just from any industry participant in some time, so first of all with regard to a question regarding business model. You've referenced this in your earnings release, you've also referenced it several times, being prepared to move to more risk-based business models. And specifically, the significant opportunity associated with the re-fracking of older wells. So what kind of uptake are you seeing, with regard to the re-fracking opportunity? And when you describe this as a significant opportunity, can you quantify what that means, in terms of how large it is?

If you look at the work we've done so far and we posted some of the recent results in the earnings press release this quarter, a lot of the re-frack focus so far has been around being able to identify the candidates. And that's based on our understanding of the existing completions and the potential that these still hold. And then the other part is around, how do you effectively do the refracturing while minimizing the costs. So we have, to our engineer completion and our shale formation evaluation capabilities, as well as BroadBand Sequence, now established that growth technology offering. So in terms of how many wells, I would say there are thousands of wells in North America land that are candidates for refracturing and this is both shale liquids and shale gas. In terms of the market potential, I think you're talking billions, in terms of revenue opportunities, over an extended period of time. But this is quite a significant market opportunity. And I think the key here is that we're so confident in our ability to identify the right candidates and execute the refracturing work that we're prepared to take significant risks, in terms of how we go about doing this work. In many cases, if we can select the candidates, we are prepared to foot the entire bill for the refracturing work and then get paid back in production.

Okay, my second question is more of a macro issue. Referring back to the presentation from a couple of weeks ago, you showed a global drilling intensity slide where you compared the 2014 production numbers from the top three liquids producers, which were roughly the same at about 11 million barrels per day. However, there were drastically different levels of drilling activity to achieve that output: 36,000 wells in the U.S., 8,700 in Russia, and only 399 in Saudi Arabia. You also pointed out that there are several markets not identified that have significantly lower drilling intensity than the U.S. You mentioned that many markets need a certain level of drilling intensity to maintain flat production. My question is about not just keeping production flat, but also the ability and flexibility to increase production through greater drilling intensity. Can you address that?

What they're saying with that slide is that over time, basins mature. And in order to firstly maintain production and subsequently increase production which I think, in many of the land basins, we will be looking to do that in the coming years, you will have to increase drilling intensity. That's the basic message. So I think you're seeing that increase in drilling intensity happening in many basins around the world today. The drilling intensity is obviously generally far below what we're seeing today in North America land. But that’s basically because, in most of the other basins, we're still working within the conventional resource base. And as you move from the conventional towards more unconventional, you will also generally see an increase in drilling intensity from that. But I would say, even in the conventional basin, there is a growing drilling intensity which we're now looking to capitalize on, both through the subsurface integration of the technology and our investment in research and development, as well as now going forward with our focusing on establishing our read on the future.

In response to Bill's question, I find it particularly intriguing that today’s call shows a willingness to propose various business models, accept some incremental technology risks, and discuss a new collaborative approach. It appears we're not just considering the re-frack market in the U.S.; it sounds like you are suggesting an entirely new business model for how service companies and oil companies will collaborate in the future. I don't want to sound too futuristic, but it seems like you're advocating for something beyond the typical participation or risk-taking that companies have historically engaged in during market downturns. It appears you are indicating a fundamental shift in the industry.

I do, yes. And I think it's going to be very important, for the overall performance of the industry, that all the players that have something to contribute, not only to the implementation and execution part of the work we do. But also to how we design the solutions of what we're looking to build and develop, that they're all invited to the table. And I would say still remaining humble. I think we, from the Schlumberger side, we have a lot to contribute, when it comes to supporting the design decisions that many of our customers take for major drilling and completions developments.

There is no question that you have more expertise than most any other oil company. But having worked for both oil companies and service companies, service company comes to me in the oil company and says, let me show you a better way to do stuff. The first reaction is, I got engineers that know how to do it. So this is pretty much a change in psychology, if you would or how the industry operates. You're talking about, this isn't a quick implementation, I would think, but over time?

No, it's not a quick implementation and it's not something that we can do by ourselves. And currently, I think it's very clear. We're not saying that we can do the work our customers are doing better. But I think, given the capabilities that we have, I think we're underutilized today. And we have a lot more to contribute, even into the design elements of the work that is related to our expertise. And I think by being invited to the table to contribute, complementing what they are doing, I think we can achieve improvements in design and engineer costs out of the system, before we go to implementation. And by factoring in our implementation or execution capabilities in the design, I think we can also simplify and streamline the execution part of the work, as well. So this is something that we're going to offer, Jim. Some of our customers might take us up on it and some of the others might not and for the ones that are not, we will continue to work the way we're currently doing. But I think this is something that we believe can bring significant value and something that we're prepared to take on and also put some more skin in the game.

I have a follow-up question related to what Jim was asking. Specifically, I'm curious about offshore development and exploration. With the current low oil prices, the market is quite challenging. Some people are suggesting that the International Oil Company business model is struggling. It seems to us that this sector could experience a slowdown in a couple of years. Since this is a significant aspect of your business, could you provide us with some insights on how you believe the International Oil Companies will manage their transition to deepwater exploration? Additionally, how do you anticipate this situation developing to address the current challenges?

I think if you look at deepwater first, this represents a huge resource base for the industry. Now given the level of development cost today, as well as given the level of recovery factors we're seeing today, the cost per barrel for these types of developments is challenged. So there has to be a change in overall, in how these developments are done. We have to get the costs down and we also have to drive recovery up. And if you can do both, I think a large part of the reserve base and the discovery base that we have established over the past decade in deepwater, can and will be developed. So I think this is the challenge that the industry has and we're prepared to contribute towards finding the right solutions. And I think when the industry really puts their mind to something, we will find a solution and it will be sorted out. As to the separation, I think the playbook we're seeing now is the normal one. Exploration is the first thing that can be cut which is not going to have a short-term and immediate impact on production. Looking at the current levels of exploration spend today, it is clearly unsustainable. I don't think it's going to get fixed or improved any time soon or at least not in 2015. But it is very clear that this level of exploration spend is not going to continue for many years.

Okay. And a separate topic on talking about the North America, you've talked about how the rig count won't go back to peak levels and I think we can all agree upon that. You talked a lot about the commentary around re-fracking opportunities. And clearly, you see that as a big opportunity going forward. But what are some of the other structural trends that you think are influencing that view? What are the other components that, as you think about North America and I'm not sure if you can give us an idea of where you think that rig count can be a normalized rig count, if you will. But can you talk about some of the other factors, structurally, that are impacting that view?

Over the past three or four years, there has been significant growth in shale liquids activity in North America, accompanied by an increasing free cash flow deficit in the exploration and production industry. This trend is not sustainable for the industry as a whole. However, there remains a core section of North American shale liquids that is economically viable even at current oil prices, and development in this area will persist. As the industry enhances its operations, particularly in terms of cost efficiency and production per well, there is potential for growth in developing tier 2 and tier 3 acreage. Currently, development is primarily limited to tier 1 acreage given the prevailing oil prices. Consequently, due to cash flow constraints, we do not anticipate rig counts returning to previous levels around 2000; instead, we expect them to stabilize somewhere between current levels and past highs. For the service industry, this implies that the pricing concessions currently in place will likely remain for some time, as there will be significant oversupply for various services due to the lower activity levels to which we will be recovering.

My question has to do with the overall trend in international revenues and margins for here. If we look back at past cycles, often, the international business trends materially lag that of North America. I understand some things are different this time. But might we be looking at, generally, a deteriorating overall level of E&P spend? And maybe even Schlumberger revenue over the next 12 months?

If we examine our perspective on total exploration and production spending worldwide, differentiating between North America and international markets, we anticipate that the drop in international spending will be considerably less than what we're seeing in North America. In North America, we're looking at a reduction of over 30%, while for international spending, we're estimating around 15%. The more important point to consider, beyond the spending cuts—which we are already witnessing—is the often underestimated resilience of our international business performance. Our ability to maintain margins and preserve our overall earnings potential in international markets has been quite commendable. Even with the 15% decrease in exploration and production spending, our revenues declined by 8% year-over-year in the first quarter, and our operating income fell by 3%. The crucial aspect is our capability to continue generating earnings, even in tough market conditions.

Do you think, based on your comments, that you have reached the lowest point for international revenues? Or do you expect that international revenues will likely decline from the first quarter levels?

Yes, at this stage, we see both North America and international revenue coming down further in Q2. But I would say more so in North America than in international.

And do you think that that will represent the bottom? Or do you think there could be further slippage in revenues, particularly internationally, in the second half of the year?

I would say that the revenue reductions in Q2 are slowing in pace. I'm not ready to say that it's the bottom yet.

If I could follow up quickly on this re-frack opportunity. I'm curious as to what the suite of services are? And how they differ from a conventional primary frack job? I imagine it's a lot more analysis involved. Can you just walk us through what the workflow looks like? And the level of intellectual capital that's employed in the process?

Yes, sure. So the overall workflow starts with us basically getting the well files and the well data from the operator. Our team of experts is then reviewing hundreds of candidate wells and we're taking the ones that we believe have the highest potential for increasing production after re-fracking treatment. So they're looking at the completion. They are looking at whatever formation evaluation data we have and then coming up with our candidate selection. Now in terms of the actual physical work execution at the well site, the first thing we need to do is to pull the pump out of the well and then prepare the well. But beyond that, it's just hooking up the fracturing treatment. And we basically pump a normal fracturing job, but with a BroadBand Sequence integrated into the job. Generally then flooding off the existing perforations that have already been fracked, to be able to elevate the pressure in the well to fracture the additional perforations that initially weren't fracked when the well was first completed. So the key enablers here are the ability of our subsurface experts to identify the right well candidates. And in addition to that, the BroadBand Sequence technology, where we can actually divert fracturing fluid into the perforations that haven't properly been fractured in the first place.

And is there any limitation, in terms of the initial completion, the hardware, the construction of that well? Any physical limitation?

No.

If I could ask a follow-up for Simon, real quick. Just on the working capital numbers. The receivable turns looked pretty good, but working capital use in the first quarter was still pretty high. Is that inventory? Can you delve into that a little bit, Simon?

Normally, we have seasonality to the working capital and the first quarter is a quarter where we consume working capital. And this year around, actually the receivable was a positive. Inventory stayed flattish, but the biggest consumption was on the accounts payable and employee payable. The first quarter, we basically meet all of the requirements of the incentives, the bonuses of the previous year. And as we highlighted, we also had the payment associated with the restructuring of $245 million. So the main impact on the working capital came from the other elements that I highlighted. So over $1 billion, by the way, Michael.

Yes, that $245 million was in that, then, as well?

The $245 million was a restructuring cost, with Venezuela, obviously, it's not the cash element. The biggest issue is, as I mentioned, accounts payable and employee payable was more than $1 billion of deterioration.

And then Simon, Paal mentioned 75% plus free cash flow conversion as a target. The Free Cash Flow deployment in the repurchase program was also impressively high. Is there a target there that we can apply, going forward?

So as we always said, Michael, the number or the amount that we will spend on the buyback is always a balancing number. Our priority is to invest in the business, whether it's CapEx or future revenue stream, SPM, multi-client. And then the dividend, obviously, we will continue to meet our commitment and revise it every year. And the balancing period will always be the buyback. And during the downturn, the conversion rate, you know, is always helping.

It's wonderful to witness everything coming together as you had planned during your energy investor day last June, so congratulations on that achievement.

Thank you.

You're welcome. The follow-up question that I've been having and we had an opportunity to canvas a number of different investors last night and it still seems the primary question on everybody's mind, from this point forward, is how sustainable is this relative performance on decrementals? I think you addressed it broadly in your commentary, about the execution and transformation and so on. And I think the million-dollar question out there is, are the decremental margins going to moderate into the second quarter and then second half of the year, from where they are in the first quarter? And in conjunction with that, how much of this decremental margin performance has really been, say "one-off"? Or how much of this decremental performance is truly structural in nature?

If we concentrate on the decrementals related to our international business, it’s important to note that our decrementals in Q1 were 25%. This performance isn’t a one-time occurrence. Moreover, it isn’t just limited to one quarter. The overall strength of our well-balanced international business is often underestimated. Looking back to 2012, we achieved incrementals of 35% in 2012, 42% in 2013, and 69% in 2014. Our ability to effectively manage the international business, despite facing increasing challenges in exploration, deepwater, and seismic operations, as well as significant costs from IOC spending starting in 2014, is evident. These incrementals clearly indicate that the decrementals we experienced in Q1 are merely a continuation of years of improving business performance.

Now my follow-up question is about your statement regarding the U.S. recovery not returning to previous activity levels while we may encounter some pricing pressure for a while. I'm trying to understand how the anticipated significant amount of re-fracking fits into this. I would have expected that a large volume of re-fracking would lead to quicker capacity absorption and possibly a faster recovery in pricing since companies will be addressing the backlog of re-fracks. Could you clarify how re-fracking may not result in an accelerated capacity absorption? I would appreciate your insights on this matter.

I think for the re-frack, this work scope, I think, is going to be limited to the companies that can do the two things that I stated earlier. Firstly, help the customers identify the right candidate. And secondly, have technologies that make the cost base of the refracturing feasible and economical. And based on the work we've done, in terms of identifying candidates during trials, re-fracks for a range of customers already, the economics, based on the BroadBand Sequence technology, is actually quite attractive in between refracting an old well or drilling a new well. So I think it would be limited to the companies that have that capability. Now even if there were a range of companies that could do it, I still think that this market overall, in terms of absorbing capacity, isn't going to fix the problem. So if you look at the overall activity that we had last year, where we had about 2000 rigs operating, we're down now below 1000. If you take a pick anywhere in between the two numbers of where the recovery is going to come back, no matter what number you pick I think it's very clear that it's going to be significant over-capacity in the market. And that means that pricing that is now already at very low levels is not going to improve in that situation. So re-frack is an opportunity for the companies that have the right technology to it. I don't think it's going to have a big enough impact to fix the overall capacity issue in North America land. But it will be, I think, a very good avenue of growth for the companies that can identify the right candidates and also have the technology to effectively re-frack, while keeping costs low enough to make it economical.

So Paal, you generally see an increase in market share during a downturn, and you're anticipating a 15% decline in international E&P spending. Should we interpret that to mean that Schlumberger's revenues will drop by less than 15% this year?

I believe we have some promising opportunities this year to increase our market share. We discussed this in the January call. The current conversation regarding the challenges we see in the international market could potentially create more opportunities for us to grow market share. Additionally, since we are managing a very efficient and effective international business, this may provide us with further chances to leverage our capabilities to gain market share. While we are not overly focused on market share, we will seek out opportunities as they arise. Our goal is to navigate the commercial landscape by balancing the pursuit of market share with maintaining strong margin performance.

I would expect that as well. If you calculate the numbers, it suggests there will be sequential growth internationally in the latter half of this year. However, my main concern is international margins, because in the last cycle, we noticed that international margins decreased even as revenues began to rise. What are your thoughts on this? How do you see this cycle evolving? Are we in a different situation where revenue increases could lead to slightly higher margins, or will negative pricing impacts affect us again?

We're already seeing challenges, both in activity and pricing and it's not the market. Obviously, with these significant spend reductions that's always going to be there. I think the difference we're seeing, at this stage, is that based on these incrementals that I referenced just in the previous question, our ability to continuously drive performance, to how we execute internationally and leveraging the scale we have of operations. And also have a steady contribution from the transformation that is what is allowing us to hold margins up the way they are. We have significantly outperformed our competitors in margins over the previous two or three years and this has got nothing to do with pricing. Every bid on lowest price for basic technologies in any country around the world, the only thing that differentiates us from the competition is that we're able to translate this revenue into higher margins, basically based on how we run the company. So we're always winning any bid on the lowest price. And we have to be commercially competitive. But the key here is the internal management of the company and how we run and execute. And I think that ability has improved significantly over the past three or four years. And that's why we hope that we should be able to manage both decrementals and overall margins better this time around, in the international market, than what we've done in previous cycles.

I was wanting to ask about BroadBand Sequence and I spent a lot of time with your technology guys last month in Houston. How much of that business now is a push model, being you going to your clients and talking to them about the attributes of that versus a pull model, where the clients are actually coming to you saying, we need this technology?

I still think there is a mixture that any new technology in North America land, the uptake takes some time. But what we did differently this time around, with broadband in general versus what we did with HiWAY, is that in the third quarter last year, myself and a few of my chiefs, we went around to a range of North American E&P companies and presented the concept of this technology, and also offered them trial runs to try this out. And that's why the general uptake of BroadBand Sequence has been significantly faster than what HiWAY was, which was always, actually, quite good, as well, in 2011. But the rate of uptake of BroadBand Sequence has been significantly higher than what HiWAY was.

Okay, got it. And then just an unrelated follow-up, we think about the international markets and I know you touched a lot on the U.S. market and production there. But internationally, that's a pretty heavy decline rates, as well, a lack of investment international markets. What do you see as the potential for a significant drop in supply from the international side? And on that topic, is it possible not to be bullish on at least brent prices, going forward?

I think you're right. We believe that there is a weakness in the non-NAM, non-OPEC supply base. It was basically flat Q1, year-over-year. But given the reductions we're seeing in spend and the weakness in several of the key basins, we expect that weakness to continue and potentially increase, as the year progresses and I think that's why we believe that there will be some recovery in Brent. The question is, to what extent OPEC wants or is willing, to put more barrels on the market to stabilize prices at some level below $100.

Thank you. So before we close, I would like to thank all of you for participating in today's call. As your questions have indicated, you're all concerned that this market is quite challenging at the moment. I think it's useful to summarize the three most important points that we have discussed this morning. First, the past quarter has been challenging to manage. But by being able to quickly adjust plans and by continuing to focus on what we control, we have delivered significantly better decremental margins, compared to previous cycles. And our international leverage and the acceleration of our transformation program, are together creating a strong platform for financial outperformance, also, going forward. Second, we believe that the industry needs to think differently, in order to reduce project costs and increase project value. And we see closer collaboration between operators and the large service companies as a key element in achieving this goal. And this closer collaboration should also include more performance-based contracting models which we're fully prepared to enter into. Last, while we continue to actively manage cost and resources throughout this downturn, by streamlining overhead structures and reducing field capacity, we can quickly add back capacity when opportunities arise to take on more work. Through the efficiency gains created by our transformation program and through our unmatched recruiting and training machine which is fully intact. That concludes the call for today. Thank you.