Thank you and good morning ladies and gentlemen.
Let me start by thanking Scotia Howard Weil, and Bill Sanchez in particular, for the invitation to speak here today.
This morning I will aim to demonstrate that Schlumberger is well positioned to weather the current industry turmoil, and also to further extend our industry leadership in the years to come.
I will do that by first giving you our view of the current business environment, the challenges facing the E&P industry, as well as our outlook for the global oil market.
Then, I will show you that solutions to the industry challenges exist, and that they can be converted into opportunities, from which Schlumberger is uniquely positioned to benefit.
And finally, I will review how we see the oilfield services market evolving this year, and how our significant leverage towards the international market will be a major advantage going forward.
But before we start, let us get the formalities out of the way.
Some of the statements I will be making today are forward-looking and our actual results may differ.
I therefore refer you to our latest 10-K filing, for a full description of the factors that can influence our performance.
Starting with the macro, I will focus my comments on the oil market, as the current dynamics in the gas- markets are not expected to change significantly in the coming years.
In terms of the global economy, progress continues to be mixed, but the general trend of a slow but steady recovery remains intact.
Over the past five years, economic growth has returned to stable levels between two and three percent with strength in the US being partly offset by challenges in Europe, and an apparent soft landing in China.
Over the same period, annual oil demand has increased by around one million barrels-per-day, as GDP growth and oil demand continues to be closely correlated.
Looking forward, global GDP growth is forecasted to stabilize above three percent with an expectation that lower oil prices may serve to stimulate economic growth and thereby reinforce demand.
Based on this, we do not see any reason to question the resilience of global oil demand in the years to come.
Looking next at global oil supply, we have witnessed two clearly diverging trends in recent years.
In North America, the extraordinary rise in tight-oil activity propelled US crude production to a 41-year high last December. This equates to an average annual growth of one million barrels-per-day, over the past four years, driven by a major increase in drilling and completion activity.
Internationally, the picture is quite different. In spite of a continued increase in E&P activity since 2009, total supply capacity, including OPEC spare capacity, has actually remained flat. This demonstrates the increasing challenges of replenishing reserves and production from existing fields.
The weakness in the international supply base was further demonstrated in 2014, when overall production capacity actually declined. And if we discount the significant production gains made in Iraq, Brazil and Russia in recent years, the weakness in the remaining international production base becomes even more evident.
So, on the supply side, the growth in North America in the past four years has been sufficient to match the increase in global demand, while production capacity in the rest of the world has remained flat, and hence steadily represented a lower share of global supply.
This trend is what ultimately triggered OPEC, last fall, to shift focus from protecting oil prices to protecting market share, which has led to a 50% reduction in oil prices over the past six months.
It seems clear that OPEC is determined to test the resilience of high-cost producers around the world, and particularly in North America, by letting the market dynamics determine the oil price and effectively making the high cost producers the new swing producers.
The drop in oil prices is therefore not primarily driven by global overcapacity, but is instead a result of the ongoing market share battle. This can be seen by the half-a-million barrel-per-day reduction in OPEC spare capacity in recent quarters, as they have increased their marketed supply to support the fight for market share.
The same volume of half-a-million barrels per day can also be seen in the build-up rate of global OECD stocks. The stock build-up is all taking place in North America, as tight-oil production is out-pacing infrastructure and refinery capacity, while international OECD stocks have remained flat over the same period.
The recent deviation in the established correlation between Brent prices and OPEC spare capacity is another clear sign that we are not in a real global overcapacity situation.
Let us next take a closer look at the link between E&P capex and supply growth, and what this means for the oil price outlook.
In North America, we have seen a doubling of E&P capex in tight oil over the past six years, with investment levels reaching $125 billion in 2014.
These investment levels, which clearly exceeded the cash flow coming from production, even at one-hundred dollar oil, generated an annual growth in production north of one million barrels per day.
With external financing becoming tighter and oil prices halved, North American operators are currently forced to dramatically cut investments in order to balance expenditures with available cash flow.
The impact of these reductions is seen in the rig count, which is already down more than 45% from the Q4 peak.
Given the lag between starting a new well and first production, the significant reduction in activity that started in January has yet to appear in the production numbers.
The impact is expected to materialize in the coming months, according to both the EIA and IEA, first as a reduction in monthly sequential production around mid-year, and by a flattening in year-over-year monthly production towards the end of the year.
Based on this, full-year North American production will still grow in 2015, but will likely be down in 2016, leaving a supply gap that needs to be filled by international producers.
In the international market, E&P capex growth was already decelerating in 2014 and this has already showed up in the production capacity, which started to decline last year.
In 2015, E&P capex spend in the international market will be down in the range of 10 to 15%, which means that the established trend of weakening production capacity is likely to continue and potentially increase in magnitude.
Based on this, the global oil market is clearly heading for a tightening which could lead to an increase in Brent prices in the second half of this year.
We further expect to see a widening gap between WTI and Brent prices until production and stock levels in North America have normalized.
As overall supply continues to tighten, we further assume that OPEC will continue to focus on market share and that they therefore will be prepared to move more of their spare capacity into the market to prevent a spike in oil prices.
Building on this overview, let us next look at the current industry challenges and how Schlumberger will turn these challenges into opportunities that we are uniquely positioned to capitalize on.
The significant profitability and cash-flow challenges facing the E&P industry today are driven by escalating costs-per-barrel for new hydrocarbon developments and the growing investment burden of stemming decline in the existing production base.
New developments, particularly in tight oil and deepwater, have significantly higher break-even costs than conventional fields, and the shift in activity mix towards these resources types over the past decade has increased the overall cost base for the industry.
At the same time, the cost of maintaining production from existing fields is steadily increasing, with the industry needing to replace the third of today's production that will be lost to decline by 2020, on top of adding new capacity to meet the future growth in demand.
The combination of escalating costs, from both new and existing fields, relatively flat global oil production, and range-bound commodity prices, have therefore in recent years started to put significant pressure on E&P profitability and free cash flow. It is therefore no surprise that a 50% fall in oil prices, since last October, has only served to dramatically aggravate the situation.
The current industry challenges are therefore structural, and will not disappear even if the oil prices were to return to the levels of the past. So the industry is therefore forced to think anew, and to actively look at changing the way it works.
This includes seeking new solutions to reduce costs and increase value for future projects, by creating a step-change in both technical and financial performance throughout the entire E&P value chain.
As seen from the chart, there is currently a wide range in capex intensity between the four main resource types of land conventional, tight oil, shallow water and deepwater.
With a capex per barrel averaging over $40, the urgency of finding these solutions is highest for tight oil and deepwater fields, which today consume around 40% of the global liquids-related E&P capex, while only representing around 12% of global oil production.
Still, there will also be a strong focus on reducing cost per barrel and increasing production from shallow water and conventional land fields, as more investments are likely directed towards these resources types in the short term to meet the ongoing growth in demand.
We see the current industry challenges, and the subsequent need for the industry to change, as a huge opportunity for Schlumberger. And we are in a perfect position to capitalize on this through our ongoing Transformation program, the scale and breadth of our offering, and our unmatched execution capabilities.
So let us look closer at the opportunities we see within each of these four resource types, starting off with tight oil, where I will focus my comments on US land.
Tight-oil production in the US has increased more than six-fold in the past five years.
These impressive results have been achieved by an unprecedented growth in investment levels, far outpacing the cash-flow generated from production, and further supported by significant cost and efficiency improvements from the supplier industry.
With the recent 50% drop in oil prices, drilling and completion activity is currently being scaled back dramatically, as the E&P companies are forced to balance investment levels with available cash flow.
Going forward, we believe financial prudence, where investments are limited to the cash flow generated by production, will be the new normal for US tight-oil developments. This further means that drilling activity will be focused on the acreage that is still viable at lower oil prices and that a further reduction in cost-per-barrel will be critical going forward.
Looking at the opportunities to improve cost-per-barrel in the US tight-oil basins, a lot has already been done in terms of driving down the cost-per-well which has been more than halved in the past five years.
We therefore believe that the biggest opportunity going forward will be to significantly improve production per well. After having doubled the horizontal length and number of stages per well in the past five years, while also significantly increasing volumes of water and proppant per stage, the average well production has still not improved noticeably.
The solution to increase production per well can instead be found in engineered completions that uses formation-evaluation data and completion-modelling software to optimize fracture placement. Production can be further increased by using completion technologies and fracturing fluids that ensure that each perforation cluster is properly fractured, while also maximizing fracture conductivity.
We have, over the past five years, established a full set of technologies that addresses all of these opportunities, including ThruBit wireline logging for formation evaluation, Mangrove software for completion modelling, and HiWAY and BroadBand techniques for fracturing efficiency.
Our scientific solutions, continue to deliver well production that consistently outperforms a brute force approach, and we expect that the focus on improving production per well will accelerate market penetration of these technologies going forward.
We will further support the market uptake by continuing to engage in technical discussion at C-level of our key US land customers.
And, based on the confidence we now have in our shale technologies and expertise, we are also prepared to move to more risk-based business models, both for new wells and for the significant market opportunity linked to re-fracturing of older wells.
So with that, let us move on to look at the deepwater market.
The extreme operating conditions of deepwater developments make them very complex and capital intensive, while the long project planning and execution timelines also often introduce cost overruns and delays.
Still, deepwater basins have represented a much welcomed exploration horizon for both large IOCs and small independents in the past decade, and hence, have attracted significant investments.
In fact, deepwater discoveries have expanded from representing one quarter of total discoveries twenty years ago, to now making up around two-thirds of all discoveries, and also more than 10% of global oil reserves.
With project economics already challenged, the recent drop in oil prices is now resulting in a sharp reduction in deepwater exploration activity and could also delay sanctioning of new developments. However, ongoing projects are likely to continue, given the large and long-term investment commitments already made.
In spite of this set-back in activity and investments, we firmly believe that the industry will come up with new development solutions that will reduce cost-per-barrel allowing investment levels to recover in the medium term.
The magnitude of deepwater reserves and production potential is simply too large for the industry to ignore.
This is particularly true for many IOCs, who are already challenged from a production growth and reserve replacement standpoint, and who will therefore likely seek new solutions to convert their recent discoveries and unexplored acreage into viable future projects.
In terms of deepwater development costs, lower rig rates, improved drilling efficiency from optimizing the entire drilling system, as well as prediction of drilling hazards through new look-ahead LWD technologies, all hold significant cost saving potential.
Significantly reducing downtime linked with BOP testing and certification is another area that can yield large cost savings.
And finally, the high cost and long lead times for both subsea and floating infrastructure, can be significantly reduced through industry standardization and by moving towards more modular designs.
In addition to these cost savings, deepwater developments also hold significant upside potential in terms of production and reserves, with recovery factors currently half of those seen in shallow water.
Upfront design optimization of the entire production system, focused on flow assurance and including extended use of intelligent completions, where production can be optimized remotely, thereby minimizing physical well intervention, will all be critical.
Production can also be increased by using dual-boosting solutions, including in-well ESPs and subsea multiphase pumps, and also by moving to subsea processing as this becomes available, in order to reduce the energy waste linked to lifting unwanted fluids to surface.
Through our industry leading exploration, drilling and production portfolio, and our OneSubsea joint venture, we currently have a wide range of technologies and capabilities that can help address most of these opportunities. OneSubsea has recently scored several industry firsts, including delivery of a subsea multi-phase compressor to Statoil in the North Sea, and installing a high-pressure subsea boosting system in the ultra-deep US Gulf of Mexico.
We continue to work closely with our customers, to accelerate the implementation of all these solutions and to help improve the overall financial performance from deepwater projects.
Conventional land and shallow-water developments, with their lower capex intensity, will likely see increased investment levels in the coming years as the industry looks to meet the growth in demand in the most economical way.
Given the significantly lower complexity of these resource types, they are generally not in need of specific solutions beyond the general focus on new technology, reliability, efficiency and integration.
Still, one undeniable trend stands out, representing a unique opportunity in the land market, relating to the steadily increasing drilling intensity required to maintain and grow land production.
Comparing the three key land markets of Saudi Arabia, Western Siberia in Russia, and US land, all with similar production levels, shows a wide spread in drilling intensity.
And, we believe that the rate of new-well drilling is set to grow significantly in lower drilling-intensity markets ranging from Saudi Arabia to Western Siberia, as operators look to drive recovery factors and maintain or increase production rates.
The trend of increasing drilling intensity on land will benefit strongly from a further step-change in drilling efficiency, which we intend to create, by continuing to improve our drilling optimization workflows and to now expand them to also include the land rig.
Since the 2010 acquisition of Smith International, our Drilling Group has become Schlumberger’s largest in terms of revenue, with a complete range of industry-leading product lines, delivering all aspects of downhole drilling tools, drilling fluids and mud logging.
Building on this technology portfolio, we continue to improve drilling-system integration and drilling performance, through our 20-plus petro-technical engineering centers, which offer a complete range of drilling, geo-mechanics and formation evaluation capabilities.
Over the past four years, we have also extended our thinking to include the land rig which represents an additional optimization dimension for drilling performance.
And this is the basis for acquiring Saxon, as well as the pending Eurasia deal in Russia, which together with a range of joint ventures and contracted rigs around the globe, will make up one of the largest land rig fleets in the world.
These moves have permitted integration of land drilling expertise into the Drilling Group in order to further pursue the goal of increased drilling performance.
We firmly believe that an optimized rig design, fully focused on drilling automation, and better catering for all of our other drilling related services, holds significant upside for Schlumberger.
Add to this a brand new drilling optimization software, built on big data analytics from the 70 million feet we drill every year, coupled with an upgraded rig control system, and we believe we can create a further step-change in drilling performance.
And in true form, we are currently applying the full strength of the Schlumberger R&D organization towards realizing this vision.
As the industry seeks new technical solutions and improved financial performance, it will be critical to take collaboration and commercial alignment between the operators and suppliers to a completely new level.
In the upstream industry today, the engineering design of most aspects of a new project is done by the operator, with the full scope subsequently split into discrete parts that are bid out to the service industry, on the basis of lowest price wins. This approach assumes that securing the lowest price for each part will lead to the lowest cost and highest value for the project which, for very simple projects, may be true.
But, in an environment of increasing complexity and where there are strong interdependencies between the various parts, such an approach significantly underutilizes the capabilities of a company like Schlumberger. We are today the largest developer of the intellectual property of hardware and software used to explore, drill, and produce hydrocarbons, in all parts of the world.
Last year we served 6,500 customers in 85 countries, drilled more than 70 million feet and recorded more than 12 million operating hours, spanning a full range of oilfield products and services. And with the industry’s largest petro-technical community, including over 10,000 experts, we clearly have capabilities that can contribute to the design of complex oil and gas developments, and help ensure that the solutions are optimized for both cost and value.
We believe that a significant upside can be realized if operators were to partner with a preferred supplier who can contribute to design, and at the same time has a broad execution capability. The value created by such collaborations, together with a closely aligned commercial model, will far outweigh small variations in supplier prices from the existing procurement-driven contracting model. We are therefore actively engaging with our customers, promoting this operating model, and we see this approach as a critical part of the industry’s effort to overcome its current challenges.
The ongoing industry-wide efforts to force pricing concessions from the service industry will not solve the industry problems. On the contrary, this will likely delay the creation of new solutions as service capabilities and support levels will have to be reduced.
The chart clearly shows that from 2010 to 2014, the growth in pre-tax operating income for the 20 largest oilfield service companies has been on par with the growth in E&P capex spend. So the oilfield services companies are not enjoying inflated prices or excessive profits and hence, this is not the real problem of the industry.
Let us then turn to the market outlook for oilfield services.
Even with a partial recovery in Brent prices in the second half of this year, we still expect international E&P spend to be down in the range of 10-15% versus 2014. This reduction in spend will include an element of pricing concession but will still largely be made up of activity reductions, in particular for exploration-related services.
In terms of geography, we expect the GCC part of the Middle East to still post growth in investment levels in 2015 as the core part of OPEC prepares to pick up further market share, and as the rest of the global supply base continues to weaken.
Elsewhere, we expect to see double-digit spend reductions in Latin America driven by Mexico and Brazil, in Europe and Africa driven by the North Sea, and Sub-Sahara Africa and in Asia, driven by China, Malaysia and Australia.
In Russia, conventional land activity in Western Siberia continues to be resilient, but our earnings contribution from Russia will remain subdued until we see a meaningful recovery in the ruble.
In North America, we are seeing activity reductions and pricing pressure in the Gulf of Mexico, but this is still minor compared to the dramatic activity collapse and pricing pressure taking place on land.
Our North America outlook assumes a widening gap between WTI and Brent prices in the coming year, and furthermore that future US tight-oil activity will be constrained by the available cash flow from production.
Furthermore, we expect that a recovery in US land drilling activity will be pushed out in time as the inventory of uncompleted wells builds and the re-fracturing market develops.
We also believe that the recovery will fall significantly short of reaching previous activity levels.
Lower rig activity in the medium term also means that we are facing an extended period of over-capacity for drilling and fracturing services, and likely a weak pricing environment for the foreseeable future.
While the overall outlook for oilfield services remains challenged, it still clearly favors Schlumberger due to our strong leverage towards international markets.
Based on our outlook for the oilfield services market, our favorable international leverage, the acceleration of our Transformation program, the breadth and scale of our offering and our unmatched execution capabilities, we confidently aim to continue our run of financial outperformance.
First, this means gaining revenue market share as the glass ceiling in the international market is broken.
Second, posting a significantly lower reduction in earnings per share compared to our competitors, through much better decremental margins.
Third, continuing to reduce working capital and capex as a function of revenue, driven by our Transformation program.
And fourth, still delivering unmatched levels of free cash flow, even in the most severe downturn the industry has faced in decades.
Ladies and gentlemen, in conclusion, I would like to make the following points.
The current industry challenges are structural and will not disappear even if the oil price recovers to previous levels, and hence, the industry is now forced to change. Part of this change must include much closer collaboration between the operators and the large service companies, to jointly create technical solutions that can reduce costs and increase project value, in particular for tight-oil and deepwater developments.
Schlumberger is ready and capable to enter into this type of collaboration, and based on our technical and financial strength, we are also prepared to establish commercial models where we are much more aligned with our customers.
In the short term, activity visibility still remains limited as many of our customers are making drastic and sometimes unpredictable cuts to protect margins and cash flow. In this environment, we remain focused on what we control, which is our cost and resource base; the deployment of our technology and expertise; and the quality and integrity of the products and services we provide to our customers through our highly trained workforce.
So, in the midst of the current industry turmoil, we are fully focused on capitalizing on the opportunities we see, and that is why Schlumberger is still a very attractive investment proposition.
Schlumberger CEO Paal Kibsgaard addressed the Scotia Howard Weil 2015 Energy Conference held in New Orleans.