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Gould Speaks at Simmons & Company Investor Conference
Schlumberger Chairman and CEO Andrew Gould addressed delegates at the Simmons & Company International European Investor Conference held in Gleneagles, Scotland.
Download the complete presentation (1.9 MB PDF)
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Ladies and gentlemen, good evening, I would like to thank Simmons & Company and particularly
Bill Herbert for their kind invitation to speak at this opening dinner.
I doubt if anybody here this evening will question that the past year has seen radical changes in
the fortunes of the oilfield service industry. Lower commodity prices have led operators to
dramatically reduce expenditure, cancel projects or request price concessions to improve
project economics. In spite of these changes however, I am struck by other, perhaps more
significant developments that are also taking place. Hydrocarbon sources are changing as easy
fields are produced; the client base is shifting and growing geographically; and the interaction
between the two is segmenting the business in a way that we have rarely seen before. At the
same time the disappearance of cheap money and the dramatic fall in operator cash flows has
added further complexity. As a result, we are becoming required to cover a wider range of
hydrocarbon opportunities and customer types while positioning for the uncertain timing that
surrounds the resumption of growth in demand. Indeed, in the current global recession, the
industry driver has become that of lower demand, and not tightening supply.
My remarks this evening begin with a view of how I believe the economic recession has affected
short-term supply and demand for both oil and natural gas, what this means in the medium- to
long-term, and why little of this really affects our focus. I will then describe how we have reduced
cost while protecting our key investments in people and technology as well as where we are
continuing to invest. I also will expand on the role of our seismic business as this has been
particularly affected by short-term cuts in exploration spending and I will show you why the
breadth, technical depth and financial strength of Schlumberger remain unparalleled in our
industry and how we will emerge from this recession much stronger than before.
But first, some macro-economics.
Many of you may have seen versions of this chart before. It’s a potted history of 40 years
of the oil business. The estimates for the next few years are based on a scenario using
the latest IEA Medium-Term Oil Market Report and you can see the increase in spare
supply capacity that has resulted from a combination of lower demand and new supply.
It is this combination that has led to lower prices and falling investment levels.
But even though investment in exploration and production almost tripled from 2000 to
2008, little additional oil production capacity was added. Part of the reason lies in the
inflation that developed across the supply chain, another part lies in the increased
production capacity of a handful of OPEC producers being counter-balanced by the level
of falling non-OPEC production. As the outlook for long-term global energy demand
remains little changed, I for one remain concerned that the inevitable 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 persists, will lead to inadequate supply when demand growth returns and to demonstrate that I would
like to share two scenarios with you.
These are based on the medium-term IEA report and cover the period 2008-2014. The first two
curves forecast oil demand over the period under two growth assumptions corresponding to two
different patterns of economic recovery—low in purple based on around 3% global GDP growth,
and high in blue coming from closer to 5% GDP growth.
These lead to a corresponding pair of spare capacity curves in orange and green. Low growth
means higher spare capacity and vice versa with spare capacity having a major effect on price.
You can see that we don’t expect much to change before sometime in 2010, but then, assuming
higher GDP growth, effective spare capacity narrows and we could potentially be moving to
higher prices and stronger activity.
But as investment levels fall, this chart also shows one other fact illustrated by the third pair of
curves. While we are seeing lower demand, we are also seeing lower overall supply capacity.
Already, between one-and-a-half and two million barrels of expected additional production
capacity have been lost to falling investment, and the forecasts do not show much change in that
number over the period of this chart. It is this lost or delayed production that leads me to feel
concerned about the effects of lowered investment once growth returns particularly in view of
the new geographies where the industry will be looking for future sources of supply.
Turning now to natural gas, global demand is now expected to increase at an average rate of 1.8
% over the 25-year period from 2006 to 2030. This is nearly double the average increase in oil
demand over the same period. By 2030, natural gas demand will represent 22% of total energy
demand, while for the next two decades the power generation sector will account for nearly 60%
of this growth.
The largest relative growth in demand will come from Asia and the Middle East, driven not only by
increasing use for power generation, but also by housing needs, and as feedstock for the
petrochemical industry. By 2030, these two regions will account for a combined 30% share of
global gas demand—up from 19% today.
And while natural gas is expanding outside traditional consuming countries, a significant share of
the projected production increase will come from the Middle East with most of the remainder
coming from the Former Soviet Union countries and Africa.
Such changing patterns are leading to a global change in inter-regional gas trading—an activity
that is expected to more than double over the period to 2030—and something that is being fueled
by liquefied natural gas supply and transportation.
Indeed, a massive expansion of LNG capacity is underway with much of this expected to be
available by 2012 with such expansion at a time of recession and lower demand leading to excess supply and unfavorable economics. You can see that just as in the case of oil demand and supply,
little will change before 2010 after which the combined effects of growing demand and reduced
investment narrow the excess supply gap. In the medium- to longer-term therefore, significant
efforts will be needed to find and produce considerably more gas than is available today.
And again, just as in the case of oil, we can expect to see those efforts take place in new areas,
and in search of more complex resources. In fact, the majority of the world’s known natural gas
resources lie in non-conventional accumulations in tight sands, shale beds and coal beds as
evidenced by data from BP and the IEA.
Nowhere is this trend more evident than in North America where non-conventional gas now
represents more than 40% of US domestic production—a figure that has been made possible by a
range of new technologies that maximize the contact between the shale formation and the
wellbore. This performance will continue to evolve as technology for maximizing the production
through drilling and completion is enhanced by other new technologies for modelling the most
productive streaks prior to fracture stimulation.
Worldwide however, non-conventional gas resources represent only 10% of total production with
commodity prices and project costs dictating whether, where and when their development will
expand. That said, major coal-bed methane projects are already underway in China and Australia
demonstrating how new geographies will contribute to future supply.
Yet unlocking even more conventional resources will require considerable new technology.
By way of illustration, the IEA has reported that 43% of world conventional gas reserves contain
significant amounts of hydrogen sulfide or carbon dioxide. In the Middle East, where 40% of the
world’s proven gas reserves exist, 60% of the reserves contain hydrogen sulfide, or sour gas.
These numbers indicate that the industry will be required to manage increasing concentrations of
sour gas—a highly corrosive fluid that leads standard equipment to suffer dramatic failure—as
well as greater volumes of carbon dioxide that must be extracted and stored. The technology to
store carbon dioxide is already available as pilot projects in the Norwegian North Sea and the
Algerian Sahara have shown.
The technology to manage sour gas production is also available, and we scored a significant
success in the Middle East recently on a well test where our equipment spent 55 days downhole
in a 300 deg F well with up to 30% sour gas content to acquire more than 8 million pressure and
temperature measurements and 150 downhole samples. This performance surpassed our
customer’s expectations and enabled all reservoir characterization objectives to be met despite
the exceedingly difficult operating environment. When you look at photographs of sour-gas failed
equipment such as this, you can appreciate this success.
Let me turn now to our strategy and how we try to operate within the growing diversity in the
hydrocarbon types I have mentioned. We have always had a policy to be number one or number
two in the areas we choose to compete in. The numbers shown here reflect the most recent
Spears data.
There are other areas where a service is important to us but is not necessarily one we need to
own. Our joint venture in drilling fluids is a good example as are a series of joint ventures in land
drilling companies around the world. Land drilling is a capital intensive business where national
Governments increasingly want to encourage local competition. Equipment is readily available
and drilling activity is a good source of local employment. At the same time, joint ventures provide
long-term access to outside expertise as our 50-year such venture in Saudi Arabia has
demonstrated. The recent move in Mexico to encourage local company participation in large
drilling tenders is a further example. This is normal and there is always more pressure to go this
way when rig prices are low and work is scarce.
In the current environment, there is considerable discussion around possible M&A in the service
sector. And while we have been actively pursuing targets that either complement our portfolio or
our geographic presence, we do not rule out adding certain other services lines to those shown
here. The price however has to be right, and any such services would have to complement those
we already provide.
As I said earlier, different hydrocarbon types, and varying reservoir maturities increase the
complexity of the service company technology offering. While many of the challenges remain the
same, the scale and manner in which our technology portfolio is applied is not. To explain this I
would like to show you two aspects of how we approach different markets. These are the
integration within the portfolio, and the organization to deliver the service.
First of all, we view our services in response to categories of customer reservoir activity—such
as exploration and appraisal. Each of our technologies—such as Wireline, Well Services and so
on—may own part of such a category. For example, exploration and appraisal would typically
involve WesternGeco, Drilling and Measurements, Wireline and Testing. This doesn’t exclude
other technologies of course having some input and when I’m asked if the breadth of our portfolio
is an advantage or an impediment to our investment profile, I would say it’s an advantage. The
reason for this is that in the current environment where higher costs, more difficult geologies, and
more complex hydrocarbon types are challenging customer economics, our capacity to integrate
reservoir understanding, technology and operational process across different services is an
increasing advantage.
Let me just illustrate that by one example of unique Schlumberger seismic and drilling technology
integration designed primarily for exploration and appraisal work.
There is of course close affinity between seismic and directional drilling to ensure that a well is
drilled in the right place, but the trick is to integrate data sets at different scales by reconciling lower-resolution seismic depths to higher-resolution logging-while-drilling measurements fast
enough to correct well trajectory in real time. With the spread cost of deepwater rigs remaining
in excess of a million dollars a day, drillers cannot wait long for new information—however
valuable it might be. In addition, the failure to foresee events leading to unplanned sidetracks has
been a major source of cost overruns in deepwater wells.
The drilling process involves two distinct cycles. The first is planning—which is long-term—while
the second is execution and is short-term. Schlumberger seismic-guided drilling changes this by
integrating the two in a real-time model continuously updated by new information as the well is
drilled.
The first picture here shows the model when we start drilling the well. This incorporates all prior
understanding of the sub-surface. When we add seismic logging-while-drilling data as we drill,
we can update the model by sending the data to a support center where a team of geoscience
experts analyzes any differences. When these reach certain thresholds, a complete re-imaging is
undertaken.
With conventional technology, this can take months—too long to have any bearing on the drilling
of the well. Using a unique integration of software, process and computer technology, seismicguided
drilling reduces the time required to re-image so that the new measurements influence
the operation almost immediately. The last picture shows the result—the well was successfully
drilled into the formation top, which as you can see is in a very different place from the original
plan.
Seismic-guided drilling has already been proven in the deepwater Gulf of Mexico. We are now
expanding its testing to fields in the Middle East and Asia that will help us demonstrate the
benefits in different geological settings and drilling environments. The ultimate benefit to the
customer of this type of technology integration will be the reduction in technical risk and project
costs.
While seismic-guided drilling is a specific integration of technology, the strength of our
deepwater portfolio is increasingly leading to differentiated market share within the 100-plus new
deepwater rigs entering service over the next five years. It is also leading to increasing
technology integration with some level of project management from Schlumberger. This is best
illustrated by the recent announcement by OGX—the largest private E&P company in Brazil by
offshore exploratory acreage—who awarded us an integrated services contract covering well
construction engineering, project coordination, geomechanical modeling, logging, directional
drilling, LWD, cementing, completion, well testing and artificial lift services on four offshore
semisubmersible drilling rigs. Other similar projects include integrated service contracts for
ONGC in India, and StatoilHydro in Egypt.
Another benefit of integration can be seen in the large IPM projects in Mexico. These have
involved aspects of rig design and logistics as well as the optimization of a number of our different service lines. The result has been increased efficiency where on the Burgos field for
example, we have drilled nearly 1200 wells and in doing so have reduced the time per well more
than threefold. Chicontepec, also in Mexico and where we have drilled more than 750 wells is
another example. Increasingly, this type of drilling, which is being called “Factory Drilling”,
provides opportunities for innovation in drilling process and technology. We are convinced that
as production matures, particularly on land, customers will increasingly outsource this process to
the service industry to reach the drilling intensity necessary to meet production targets. It will be
the service industry’s role to reduce well cost through greater process integration while earning
a proper return. This type of project is becoming increasingly competitive as recent tendering has
shown, and we are looking increasingly at projects where we can add more value through
integration rather than through the mechanical drilling process alone.
The increasing complexity of shale gas production in North America is another example where
we believe that further integration is possible. What started as a cost-driven exercise has
become much more technology intensive through horizontal drilling and staged fracturing that
while turning the process into something much more complex, still requires proper
characterization of shale gas resources to maximize potential. With the potential of this market,
any idea that we are a better investment proposition because we have less exposure to North
America is a short-term perspective. The costs of shale gas development will rise as different
basins are exploited and the technology profile will continue to evolve.
I could expound all evening on the differentiation we can produce through integration of
technology and process across our portfolio. It is much more important for you to understand that
this is only the beginning of integration. One of the key enablers used across the industry is the
unique Schlumberger Petrel workflow process software within the Ocean open software
environment. Over the last seven years, Petrel has become the de facto industry technical
software choice with four out of the five super-majors making it their standard. At least two
super-majors have migrated many of their proprietary software routines to the Ocean
environment as Petrel plug-ins. All the NOCs, and a majority of the independent operators use
Petrel. There are more than 20,000 users. Our competitors are even asking for licenses. Petrel
allows tasks that were previously performed sequentially in different scientific domains to be
performed concurrently on a common data set. To call this software environment the Windows®
of petrotechnical software would not be far from the truth. It enhances the capacity to integrate
across the exploration and production world.
As customer projects become more complex, and both cost and risk become of ever-greater
importance in the decision-making ability to create efficiency, there are many opportunities for
growth beyond the provision of discrete services. Our current examples of technology integration
include hydraulic fracture monitoring, intelligent completions in maximum reservoir contact wells,
dynamic reservoir testing and many more in addition to the seismic-guided drilling process I
described a few minutes ago.
Let me now describe how Schlumberger is organized to address this changing market.
Ten years ago Schlumberger was managed through individual service lines that reported back to
product line Presidents organized into two groups at the headquarters level. Customers
sometimes had to interface with as many as eight local Schlumberger representatives. Objectives
were set by product line, which meant that we had no coordination at the local level and any form
of integration was therefore impossible. There was no incentive to rationalize support cost at the
local level.
We then moved to the current system of four geographical areas managing a number
GeoMarkets and frankly it has taken us most of those ten years to make the system function
optimally. It has brought us huge advantages in market share gains, technology penetration and
customer understanding. It has allowed us to move Research and Development closer to the
field—such as in Russia and Saudi Arabia. It provides us with unparalleled market intelligence, a
second-to-none recruiting and training organization, and a support structure that is increasingly
the low- cost alternative. Adding a service line presence in a particular geography for example
comes at very low structural cost.
However, it is important to understand that the true opportunity for this organization still lies
ahead. It has been a long process to reach the maturity of today as the relationships between
service line representative, customer and GeoMarket manager have constantly evolved. But now
having reached maturity, the GeoMarket manager and his technical staff will enable the
integration to come as the delivery of the solutions will happen at the local level.
One of the most important tools of the GeoMarket manager is the Schlumberger Data and
Consulting Services organization. This is the largest single community of geoscientists in the
industry. They aren’t always visible because they tend to work in small groups close to the
customer in the GeoMarket. Their presence in the GeoMarket fills two roles—first the
interpretation support to our measurement services, and second the extensive geosciences
consulting they provide to customers. In doing so, they define new uses of our discrete services
as well as identify opportunities to integrate. Seismic-guided drilling requires a team of
geophysicists, geologists, petrophysicists and drilling engineers without the close co-ordination
of whom the project would not be possible. But just before my competitors rush out and try to hire
these people let me say that it will be extremely expensive, as they are the best protected group
in Schlumberger—even better protected than the CEO.
I am therefore convinced that the maturity of the GeoMarket organization will increasingly
identify opportunities for further integration of technology and process that will create additional
efficiency and value for our customers. I am also convinced that this structure is ideal for the
deployment of the next generation of discrete technologies engineered by our integrated
engineering, manufacturing and sustaining organization under the Excellence in Execution
initiative that I outlined earlier this year.
Before I summarize our outlook let me turn briefly to our seismic business.
While seismic exploration activity is currently low and there is an excess in supply of marine
vessels, this does not, in my opinion, look like a situation that will persist very long for two
reasons. First, a look at the license awards over the period 2003 to 2007 shows many of the
regions that characterize the challenges of new supply. You can see the potential emergence of
whole new provinces—such as offshore Greenland, or central Sub-Saharan Africa. And while
there are extraordinary concentrations of activity in known provinces in Brazil, North Africa, the
North Sea and Southeast Asia, there is also growing interest in Eastern Siberia and New Zealand.
It is clear that the age of easy oil and gas is over.
Second, the benefits of advanced seismic technology are growing. Some years ago, I remarked
that the single-sensor approach of WesternGeco Q technology was continuing to surprise us with
its performance. As the industry looks for the deeper, more subtle and more complex reservoirs
of the future, the capability of Q becomes even more exciting and the potential of the technology
is far from mature even seven years after introduction.
Indeed, as structures become more complex the simple rules of geophysics begin to fail and it
can no longer be assumed that covering the surface with sources and receivers will successfully
illuminate the sub-surface structure. You can see this in the two WesternGeco survey designs
shown here. Green shading shows good illumination—meaning we will be able to see the
structure in the seismic data once we begin acquisition. Grey means we won’t. In the top image,
derived from a wide-azimuth survey design, not all of the structure will be visible. In the lower
image on the other hand, resulting from a coil-shooting survey design where the acquisition
vessel steams in a series of overlapping circles, the structure is shown much more clearly. Coil
shooting is unique to WesternGeco—no other system has the capability to adequately eliminate
the noise in the tight steering patterns that it requires. To date, we have already executed five or
six projects with a lot of further interest currently being shown.
In spite of the technological opportunities however, our short-term seismic results will continue
to be lumpy; driven by Marine vessel utilization and the level of multiclient sales. Indeed, the third
quarter, traditionally the best for marine, is unlikely to be so this year due to delayed start-ups,
cancellation of tenders and reduced survey sizes. For multi-client data, interest in offshore areas
and particular deepwater remains robust, but budgets have yet to be increased. We therefore
think it likely that the fourth quarter of this year and the first quarter of next will be the low point in
the seismic cycle while it will be the rate at which the older vessel capacity is removed from the
market that will govern the speed of recovery.
Let me now discuss where I think we stand in the cycle. Our operating cost base declined
approximately $300 million in the second quarter compared to the first as cost reduction
programs continued to be implemented. We have largely completed our headcount reductions
which topped out at approximately 12,000 people including contractors. We have been careful to
protect critical technical staff, and we have built a considerable body of trained engineers on
longer rotation or incentivised leave of absence on whom we can call should activity grow
rapidly. We have continued to recruit albeit at much lower levels than the previous five years.
We have protected our key research and development expenditures with only minimal
adjustments in the overall plan. We have reduced capital expenditure, but not where it is
supporting new opportunities such as those in deepwater. We have reduced our infrastructure
spend,` but not where it has a direct effect on our ability to grow such as in Brazil or Iraq.
As one would expect in an environment where rig count is generally reducing, most contractual
activity in the oilfield service business this year has been renewal of existing commitments,
mostly through renegotiation, with little new work except in some exceptional areas such as on
new deepwater rigs or in Mexico. Our own contract renegotiations with customers are largely
completed and I am satisfied we have lost no significant market share in this process and as I
mentioned before I am pleased with the success we have had in deepwater tendering. I am also
encouraged by the recovery in Russian activity over the summer.
So the question remains—where do we go from here? I mentioned in our second-quarter
conference call that I felt a sustained oil price of $75 would be necessary to increase drilling
activity, while for US natural gas an increase in demand would be necessary to move the price to
levels that would encourage any significant increase in drilling. The likelihood of these events
happening in a short timeframe remains a question of the general economic recovery.
There is no doubt that the effect of higher finding and development costs, more restrictive credit,
and lack of access to cheap hydrocarbon resources are having an effect on the risk profile
customers are willing to adopt in a world where all customers are seeing major reductions in free
cash flow. As a result, we expect them to curtail increases in expenditure until they are more
confident of commodity prices remaining high. For the service industry this is a classic dilemma.
The longer new expenditure is delayed, the more rapid will be the rebound when markets tighten.
At Schlumberger, our exceptionally strong balance sheet allows us to be patient over the exact
timing of the recovery. We will be vigilant around M&A opportunities and we will continue our
R&D spend to be ready with new products and services that help our customers reduce their
costs today while adding more value to their increasingly complex projects tomorrow. We will
continue to increase the degree of integration we can achieve through our technology, our
technical staff, and our uniquely mature geographical organization to produce new and
exceptional results for our customers and our shareholders. When exploration and production
capital expenditure increases again, and it will, we will be very well placed to continue to
produce exceptional financial results.
Ladies and Gentlemen, thank you very much. I wish you all a successful conference.
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