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Gould Speaks at Barclays Capital

Date: 09/07/2011

Schlumberger Chairman Andrew Gould speaks at Barclays Capital CEO Energy-Power Conference in New York.


Good afternoon ladies and gentlemen.

I would like to start by thanking Barclays Capital and James West for the invitation to speak at this conference. I am here in my capacity as Chairman of Schlumberger, a role I assumed on August 1 this year. My remarks are largely based on those that our CEO, Paal Kibsgaard, delivered at another conference last week.

My task today is to convince you that in spite of the market turmoil and short-term uncertainty we currently face, the fundamentals of oil and gas remain strong, and the case for investing in the leading oilfield services company remains strong.

I will do this by reviewing the macro environment for oil and gas to show that in the medium term the supply situation is likely to remain tight for both oil and gas. The theme of increasing complexity in finding and developing hydrocarbons also remains very valid and will require science and technology to play even more important roles going forward.

Second, I will outline how Schlumberger’s scientific depth and technical ability puts us in a unique position to outperform the market in both top-line growth and margin expansion. I will give examples of the technology approaches we are taking in our major markets.

Let me start with the macro environment.

In the past two years our industry has seen significant volatility, with the largest year-on-year fall in global energy demand in two decades followed by the largest recovery ever seen. This year, the world and our industry have faced major natural disasters and political unrest. And over the past months, financial markets have been significantly impacted by both the sovereign debt crisis in parts of the Eurozone as well as the US debt situation.

As a result, the 2011 and 2012 growth forecasts for the major OECD countries have seen significant downward revisions. Inflation pressure in some of the key non-OECD countries is also causing concern. The time needed to work through the current market situation remains unclear at this stage and will be a function of the measures taken by the US and the Eurozone countries. In the near term, there will likely continue to be uncertainty around the GDP growth rates as the political will on both sides of the Atlantic to take cohesive, decisive action seems to be lacking.

Against this landscape, we have not yet seen any impact on the activity plans of our customers but we continue to monitor the situation closely and are ready to adjust our plans if required. 
 
Looking at oil demand beyond the current turmoil, the latest update to the IEA reference case scenario forecasts an increase in oil demand of more than 7 million barrels per day between 2010 and 2016 to reach 95 million barrels per day. Lower GDP growth of 3.3 percent would reduce this by 2 million barrels per day.

For supply, the same IEA reference case forecasts global capacity to increase to nearly 100 million barrels per day over the 7-year period, using an annual decline rate of about 3.2 million barrels per day.

This would leave spare production capacity of around 5 million barrels per day, or 5 percent of total demand. In the reference case, the IEA assumes that new technology can reduce the annual decline rate in the aging non-OPEC production base by more than 1 percentage point compared to the 2009 mid-term forecast.

While a 1% number could be technically feasible, it may require significantly higher investment than that currently assumed. The growth in supply further assumes that new field developments in both OPEC and non-OPEC remain on track without delays, and that there are no other major supply disruptions from political or other unforeseen events.

So in summary, the IEA reference case for oil indicates that the supply and demand balance will remain tight in the medium term. And while there are downside risks on the demand side in the near term, there are also risks on the supply side leaving the overall reference case fairly balanced.

Let‘s then turn to natural gas.

After a 2.5 percent drop in 2009, world gas demand increased by 7.4 percent in 2010, one of the highest annual growth figures in 40 years. In 2010, LNG-demand increased by 25 percent, which is the largest increase in recent history, to reach 9 percent of global demand. The IEA medium-term outlook forecasts a growth in gas demand of 2.5 percent per year over the next 5 years, which is twice the rate of oil.

Asia remains the main engine for demand growth, followed by the Middle East, while OECD growth is revised downwards from 1.3 percent to 0.5 percent per year. Ignoring the short-term uncertainties in GDP growth, the global gas market is moving from oversupply towards more balance.

Global LNG demand continues to grow with much of the new Qatar production already being absorbed by the market. Looking at the supply side, medium-term growth will mainly come from non-OECD countries with the Former Soviet Union having the largest share followed by the Middle East. In the OECD countries, most of the growth will come from Australia, which will be the world’s second biggest LNG producer by the end of this decade.

Conventional gas will continue to play a central role in the coming 5 years making up more than 85 percent of the total gas supply. For unconventional gas, the EIA estimates that shale gas now makes up 25 percent of US production, and that this percentage will continue to grow.

The EIA also estimates that international shale gas resources are six times higher than those of the US. At this stage, international shale gas activity remains focused on exploration and pilot projects but activity will increase in the coming years and shale gas will begin to have an impact on international supply towards the end of this decade. I will discuss shale gas in more detail later.

Schlumberger’s growth is a direct function of our customers’ exploration and production spending. In 2010, the IEA estimated total E&P spending of around 550 billion dollars per year, corrected for future inflation, would be needed to address future oil and gas supply.

Given the increasing complexity and intensity of finding and developing new reserves as well as maintaining production from existing fields, we believe that this number will likely need to be higher. We also believe that going forward, the integrated oilfield services companies will play an even more important role in extracting the full potential of existing and new hydrocarbon resources, and that our share of the future spending will likely increase.

Finally we believe that the oilfield services companies that best help their customers to de-risk and drive project financial performance will ultimately be the most successful. Our approach to this challenge is to apply our unique scientific platform and technical abilities to all parts of our business—supported by our R&D investment of over one billion dollars per year.

To further illustrate how we apply our scientific platform in driving market outperformance, I will now outline our approach to four key market opportunities—exploration, drilling, deepwater and unconventional shale resources—highlighting in each case what sets us apart from the rest of the pack.

The importance of higher exploration activity is best illustrated by the growing supply challenge the industry is facing with the IEA estimating that around 40 percent of the oil production needed by the end of this decade has yet to be found or developed. By 2030, this figure will likely be about 60 percent. Natural gas resources show similar trends.

Adding future reserves is becoming more complex and technologically intense, and is associated with additional cost and risk. In the last ten years, more than half of the reserves discovered worldwide have been offshore—a trend that is likely to continue. Finding new reserves is also taking us to deeper waters and deeper targets often hidden below complex salt structures such as in the Gulf of Mexico, Brazil and West Africa as well as to frontier areas such as East Africa, East Timor and Greenland. The ability to de-risk exploration prospects prior to drilling therefore becomes more and more important.

Today, Schlumberger is the clear leader in all parts of the exploration workflow from modeling software to high-end wireline and well testing services. But it is our leadership position in seismic services that is the most unique compared to our competitors.

Establishing a clear picture of the subsurface and potential prospects will always be the starting point of any successful exploration campaign. Building on our science and technology platform, we continue to develop our ability to illuminate the subsurface to help customers identify and de-risk exploration targets.

In 2009, we introduced a new seismic technique called Coil Shooting in which the vessel sails in overlapping circles while continuously recording data. This technique delivers higher-fold and full-azimuthal coverage, and is also highly cost-effective as the downtime in turning to do another pass is completely eliminated. Building on the initial success of the Coil Shooting technique where one vessel was utilized, we have recently introduced a further development called Dual Coil. 

This technique involves two recording vessels each with their own source as well as two separate source vessels all sailing in the same interlinked circles to create unprecedented illumination of deep and complex exploration targets. Schlumberger is the only company offering this technique based on our technology leadership in streamer steering and positioning, single-sensor recording, noise removal, and processing and interpretation.

By way of a progress report on the uptake of this technology, Coil and Dual Coil surveys have already been completed in the Gulf of Mexico, Brazil, Angola and the North Sea.

Worldwide exploration statistics show that on average two out of three frontier exploration wells today are unsuccessful. This indicates that in spite of advances in seismic technology, the industry still fails to properly manage exploration risk. It has long been our belief that exploration prospects can be further de-risked by combining seismic data with petrophysical well data and petroleum system modeling to better understand the risk components of trap, reservoir, charge and seal.

While seismic technology advances have made significant contributions to better evaluate trap and reservoir risks, almost three-quarters of dry exploration wells are due to inadequate understanding of seal and charge risk. Petroleum system modeling enables geoscientists to better simulate hydrocarbon migration, entrapment and preservation to address these risks.

We are the only service provider who can offer a fully software-enabled workflow covering seismic and petrophysical interpretation as well as petroleum system modeling.

This example from the North Sea shows predicted gas and oil accumulations in red and green in a Petrel model built using this integrated workflow. The green lines indicate the flow paths of the hydrocarbons predicted to have charged these structural traps. Clearly the ability to model and predict both structure and charging of potential reservoirs has huge potential to de-risk exploration targets.

Building on this platform, we continue to invest heavily in this area to further extend our leadership position.

Moving on to drilling, the last ten years have seen a doubling in the number of land and offshore rigs operating worldwide with drilling targets now found deeper with more challenging well profiles and in higher pressures and temperatures. These all represent tougher and more complex drilling conditions with such trends set to continue. There is therefore enormous potential value in creating a step change in industry drilling performance. This can be done by drilling faster when the drill bit is on bottom, and by reducing the 10 billion dollars lost per year through problems such as tool failures, stuck pipe and lost circulation.

While the principle of drilling is relatively simple, the reality of the drilling process is highly complex to understand and predict. The interactions between rig, drillstring, drilling fluid and formation are all interdependent and vary rapidly as downhole conditions change. Over the past decades we have seen excellent examples of advances in individual drilling technologies such as top drives, rotary steerable systems and PDC cutters.

Still the general approach to drilling optimization has changed little since the 1980s. We believe that in order to create the next step change in drilling performance we need to take a systems approach and move the entire drilling process from being partly an art form to becoming a full-fledged science.

One of the reasons why drilling remains partly a form of art is that few companies have the technology span to embark on the transformation, while the ones that had lacked the scientific platform or the ambition.

With the 12 billion dollars we spent last year on the Smith and Geoservices transactions, we are now uniquely positioned to take on this challenge building on clear leadership positions in most of the significant drilling segments.

In terms of the Smith integration, progress has been outstanding to the point that the transaction was accretive to our earnings per share in the second quarter, almost one year earlier than initially planned.

We are already engaged in transforming drilling into a full-fledged science by focusing on four elements.

First, we continue to invest heavily in the development of new individual drilling technologies combining the capabilities of all our various drilling product lines. We have already made significant progress in the past year and in the coming years we will introduce a wide range of new advanced technologies to the market.

Second, we are creating the drilling industry’s most powerful technical community by co-locating our GeoMarket drilling experts into drilling support centers. In these centers, well planning and upfront design is done together with our customers. The centers also monitor and support wellsite operations in real time. By the end of this year we will have 10 such centers established, a number that will increase to 30 by the end of 2012.

Third, we have some of our brightest minds working on creating numerical models able to predict the behavior of the entire drill string as a function of changing surface and downhole parameters. In doing this, we benefit from our extensive experience in high-volume data processing inversion techniques and system modeling, and early versions of these models are already being tested today.

Finally we believe that the ultimate step change in drilling performance will come from automation where real-time measurements are fed into the numerical models which again control the key drilling parameters.

The move towards drilling automation will need to be handled with caution and the drilling process will always involve human oversight and potential intervention similar to how airline pilots operate today.

To illustrate the potential of numerical drilling models and drilling automation, let’s look at an example from one of our IPM projects. Here we built a simple numerical model to optimize the drilling rate as a function of weight-on-bit and the rotational speed of the pipe, with the output of the model applied to 14 wells in real time.

For the first 13 wells, that output was fed to the driller who entered the settings manually into the rig controls giving an average improvement in drilling rate of around 20%. In the 14th well, the model output was fed directly into the rig controls without any human interaction—leading to an improvement of more than 60% and significantly higher than wells operated manually. The model used in this example was quite basic but it gave a good indication of the upside potential science can realize in drilling.

Results like this confirm our belief that we have both the ability and the ambition to lead the transformation of the drilling process into a full-fledged science.

Deepwater operations pose the ultimate challenge for our industry in terms of both cost and risk. With the very high day rates of the latest-generation deepwater rigs, the cost of service company operational failures often dwarfs the service company tickets. The Deepwater Horizon incident has stressed the importance and value of operational integrity from the service industry. Services such as seismic, wireline, directional drilling and well testing, all play critical parts in deepwater developments. Schlumberger is the clear leader in the deepwater market today and this is a position we have earned by taking a scientific approach to all aspects of our operations.

In 2007, we embarked on a long-term program called “Excellence in Execution” with the ultimate goal of elevating our operational performance to a completely new level. Through “Excellence in Execution” we are both extending our basic technology lead by re-shaping our approach to product development, and re-defining the consistency of our wellsite operations.

To extend our technology lead, we focus on functionality, which is what the technology is able to do when it works properly, as well as on reliability, which is how the technology actually works. In our new approach to product development, we build on best practices from the automotive and aerospace industries to drive both functionality but even more, the reliability of our technology.

Many of our competitors will claim to have comparable technologies to us on the basis of functionality alone. However, when overlaying functionality with reliability it quickly becomes clear that this is not the case.

In terms of the consistency of our wellsite planning and execution, we focus on both competency and workflow management. Prior to 2007 we already had a well established training and competency management program covering every employee group and, in particular, our field population. In 2009, we extended our program to monitor in detail the development of deepwater expertise in all our technology lines while putting in place a deepwater competency certification process. Through this program, we have rapidly grown a unique deepwater technical domain with the depth of expertise needed to meet the growth in deepwater activity.

When it comes to workflow management, we have established detailed processes for project preparation, real-time monitoring and control as well as change management and we require full compliance to these processes from all employees. In the event we are precluded from following our standard operating procedures, we have also empowered every employee to shut down operations and involve their manager onshore.

When we combine our unique technology with our consistency in wellsite delivery, we offer a compelling proposition for managing cost and minimizing risk in the deepwater domain.

Over the past three years, we have already made significant progress in reducing the non-productive time associated with our operations, something that has already been noticed by our customers. With the expected growth in deepwater activity, our lead in operational integrity provides another great opportunity to outperform the market.

Let me then turn to unconventionals, where I will focus my comments on shale and how we continue to apply our wide scientific platform to optimize the development of these important resources.

The current industry approach to shale development in North America is sub-optimal, as it involves significant cost and resource waste. We generally see horizontal wells being spread evenly over the acreage, with the entire horizontal section completed and fractured with massive amounts of water proppant and hydraulic horsepower. This approach would lead you to believe that the shale reservoir quality is constant. However both core data and production results confirm that this is not the case. Shale reservoir quality, similar to all other hydrocarbon reservoir quality, varies both vertically and laterally.

The reason for the current approach is that the reservoir evaluation measurements and prediction workflows used for conventional resources have up until recently not been available for shales. Shale as a productive reservoir on a large scale is new to the industry. And the standard logging measurements interpretation techniques and modeling workflows used in sandstones and carbonates cannot be directly applied.

Without these workflows we operate more or less blindly. The industry solution has therefore been to maximize the coverage of the shale volume with wells and stages with the hope of hitting enough of the good stuff to reach reasonable levels of production and recovery.

However as the industry continues to perfect the factory drilling and completion of horizontal shale wells with ever increasing hydraulic fracturing intensity, it does not compensate for the lack of fundamental reservoir understanding of shale as a resource.

The current approach involving tremendous resource and cost waste is illustrated by data from the Barnett shale. Looking at the first 12 months of production for all wells completed since 1980—including those drilled vertically, deviated and horizontally—the best performing horizontal wells clearly outperform the vertical and deviated wells, yet a high number of the horizontal wells show no production improvement in spite of much higher drilling and completions costs.

So let’s look at the three dimensions of cost and resource waste associated with the current sub-optimal approach.

First, many wells are drilled in areas of the shale plays with poor production potential and subsequent production results.

Second, the horizontal wells are completed along their entire lengths even though significant parts of the horizontal section have no production potential as observed from actual production logs.

Third, the amounts of horsepower and water applied to each stage are excessive creating fracture networks much deeper than what can be propped, and where the un-propped part of the fracture network closes as soon as the hydraulic pressure is released.

Simulations show that if the entire depth of the fracturing network was indeed contributing, production from the average well would be three to four times higher. 

Building on our subsurface science strengths, we have now established a reservoir modeling workflow for shale reservoirs. This workflow incorporates seismic core analysis and basic wireline and logging-while-drilling measurements using unique modeling and data inversion techniques.

With this workflow we are now able to build three-dimensional reservoir models capable of predicting variations in shale reservoir quality to help customers to pick the best well locations on their acreage. 

The model, when coupled with wireline or logging-while-drilling measurements from the horizontal sections, can also be used to select the optimum well path and completion intervals to avoid spending time, horsepower, water and proppant on stages that have no production potential.

The top figure shows an example where this workflow was used for a customer. The warmer colors on the map are areas where our model predicted good shale quality, while the colder colors show poorer shale quality. Prior to building the reservoir model, the customer had already drilled three wells in the poor part of the shale. Based on the model, three new well locations where picked as seen on the map and they all gave initial production rates three to four times higher than the first three wells.

We have now proven this technique for a number of customers in the US and the results have been very positive and we believe that this integrated workflow has the potential over time to transform the current industry approach.

To optimize the stimulation design of each stage, the key is to balance the extension of the created fracture network with the ability to prop it, to ensure that the fractures remain open and contribute to production.

Hydraulic fracture monitoring and more advanced fracturing fluid systems like HiWAY are key technologies to facilitate this. HiWAY continues to make inroads in the various shale basins in the US as well as overseas and so far this year we have pumped around 2000 stages and saved more than 135,000 tons of proppant. As we continue to expand HiWAY into new shale basins, and our customers get more comfortable with the use of the technology, we are also starting to reduce the water volume and horsepower used in our jobs with very positive results.

In a recent job in the Barnett shale we reduced water and proppant volumes by around 40% each and average horsepower by around 25% while the initial production was significantly higher than expected. This is an excellent example of how we can achieve more with less by applying science.

We are already seeing signs that the scientific approach to shale developments is gaining momentum and as the IOCs continue to build their positions in the shale basins both in the US, and overseas this trend will only strengthen. The scientific approach will also be critical overseas as the industry faces more public pressure to minimize the operational footprint and adapt to less available infrastructure compared to North America.

Lastly, the onset of such a scientific approach will elevate the importance of reservoir evaluation, drilling and advanced fracturing fluid systems in future shale developments. These are three technical domains where Schlumberger holds clear leadership positions.

Ladies and gentlemen, in this presentation I have highlighted that in spite of the uncertainties in short-term GDP growth, the fundamentals for oil and gas remain strong providing an underlying trend of higher investment in exploration and production. Furthermore, the slender supply-demand gap will drive our customers towards resources that are more difficult to develop and this will continue to increase the intensity and complexity of the supply challenge.

Schlumberger has the broadest portfolio of technology, the largest pool of experience and talent, and the most advanced operational processes to help de-risk and drive the financial performance of our customers’ projects. Our size and footprint provide the required presence and critical mass as exploration and development activity moves to new remoter basins. 

These unique strengths and the current market opportunities will allow us to continue to outperform the market in both top line and margin growth on a long-term basis. It is probable as a result that Schlumberger will continue to generate considerable free cash flow and I would like to close by reiterating our policy on the use of our cash.

First, cash will be retained for the growth of the business through acquisitions, capital expenditure, or the expansion of working capital.

Second, Schlumberger will continue with a progressive dividend policy with the proviso that we will stress test the cash requirement for the dividend against a very harsh downturn scenario in order never to be in a position that might lead to a dividend cut.

Finally, we will repurchase our own stock in the market with our objective being first to ensure our shareholders are not diluted by employee stock programs and second to absorb cash beyond the needs I have already described.

Ladies and gentlemen thank you for your attention.

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