Schlumberger

Schorn Speaks at Cowen & Company Energy & Natural Resources Conference

Date: 12/4/2017

Ladies and gentlemen good morning. My thanks to Marc Bianchi and Cowen & Company for the opportunity to be here once again.

The dramatic downturn that we have seen during the last three years has meant that our industry has had to change. And while the pressure on service pricing has been severe, new technologies, integrated service offerings, and digital enablement have played an increasing part in lowering cost per barrel. The downturn has of course led to cost cutting, headcount reduction, and weaker financial performance, but it has also presented opportunities for transformation, reorganization, and new ways of working.

With signs of recovery now emerging as producers either work within available cash flow, or limit production more closely, I’m going to use my time today to show what this means for Schlumberger.

I have three topics to present before commenting on how we see the fourth quarter.

The first is technology, where I’ll show how transformation of our engineering and manufacturing processes has led to new generations of more reliable and more efficient field equipment to increase production and lower cost per barrel.

Second, I’ll discuss how scale and vertical integration are streamlining operational processes and workflows in the completions and production market to improve technical and financial performance.

And third, I’ll describe how technology systems are becoming increasingly digitally enabled to introduce new ways of working across E&P workflows to deliver a step change in behavior.

But before I begin with our view on the industry macro, let’s get the formalities out of the way.

Some of the statements I will be making today are forward-looking. These matters involve risks and uncertainties that could cause our results to differ materially from those projected in these statements. I therefore refer you to our latest 10-K filing and our other SEC filings.

When we look at the change in market fundamentals since the end of 2014, we see a number of things. Most importantly, global E&P capital spending has fallen from a high of about $700 billion in 2014 to less than $400 billion in 2016, driven by the precipitous fall in the price of oil. Brent, for example, has plummeted from $120 per barrel in 2013 to levels that demonstrated stability around $50 per barrel before rising above $60 level today. Upstream job losses have reached 440,000 or more, and the number of bankruptcies in the industry has topped 300. But in spite of this, production of crude oil and associated petroleum liquids has grown from 92 to 98 million barrels per day since 2013 showing little reflection of the dramatic drop in E&P investment.

But more importantly, the demand for oil continues to be strong with upward growth revisions in many areas, including the OECD. Growth in 2018 is expected to exceed 1.4 million barrels per day, supported by global GDP figures that clearly suggest that the demand for oil is solid. The 2018 IEA World Energy New Policies baseline scenario supports this view with forecasted annual demand of 105 million barrels of oil per day by 2040. An increasing percentage of this will have to come from new developments to replace production lost to decline.

One of the major factors driving the dramatic change of the past three years has been the rapid growth in production of light tight oil from unconventional reservoirs on land in the US. This has revolutionized supply, but signs of its limitations are beginning to emerge.

The first is the slowing in the forecast growth rate of lower 48 production, excluding the US Gulf of Mexico, through the period to 2020. The US EIA currently forecasts the growth rate of US production moderating to 200,000 barrels of oil per day by the end of the decade—a figure much lower than the 800,000-barrels-per-day growth of 2015. The reasons for this include supply chain inflation and operational inefficiencies that partly resulted from the downturn as well as the ongoing necessary move away from core acreage.

In addition, activity in the past has been largely driven by investors encouraging, enabling, and rewarding short-term production growth, often despite marginal to poor returns. This now appears to be giving way to a more moderate investment appetite where pursuit of production growth is balanced by greater focus on solid financial performance and cash flow. This is reflected by US land tight oil producers increasingly viewing $50 as the new floor for WTI.

More than USD 1 trillion in capex has been directed at US tight oil production since 2008. This represents about 20% of global E&P investment over the same period for a resource that currently contributes just 5% of worldwide production. From these figures it could be said that tight oil seems an expensive way to meet demand, and that cheaper-to-develop resources must be available.

Last, from the perspective of the reservoir, studies of tight oil well decline rates and the increase of fractured wells that interfere with production in nearby wells indicate that well spacing and completion volumes may be reaching a limit. If these concerns prove to be true, the ability of tight oil to influence global supply dynamics, and therefore price, will diminish over time.

In the OPEC-Gulf countries and Russia, which contribute 35% of global crude production, a firm commitment to the sound stewardship of resources has been reflected in a steady increase in oilfield activity. Among these producers, strong wellhead economics have countered three years of low oil prices, while production cuts by OPEC and Russia have helped re-balance global oil markets. OPEC has just agreed to extend these cuts through 2018.

In the rest of the world, where the remaining 60% of the world’s oil is produced, there has been only limited growth in investment since the bottom of the cycle. This has affected some producers quite severely, particularly in countries that are dependent on oil revenue for economic growth.

We are, however, seeing signs in many areas of projects being prepared for final investment decision (FID). The total number of these this year is double that of 2016 and our overall international tendering activity is up by over 50% in 2017 compared to 2016 as measured by total contract value.

We are therefore increasingly positive on the fundamentals that support our global business as signs of recovery emerge across our customer base.

I’d now like to move on to look at technology, with a focus on the North America land market.

The tight investment budgets of the past three years have demanded increasingly more productive wells. This has been achieved through pad drilling to boost efficiency, longer laterals to increase reservoir contact, and faster drilling speeds to lower drilling times. All of these require new technology and improved operational execution. As lateral lengths reach 10,000 feet or more, conventional motors are challenged and rotary steerable systems are the technology of choice, reducing drilling times required to drill by factors of up to three.

Schlumberger is the leader in directional drilling, with a range of rotary steerable systems that has constantly expanded since the launch of our first fully rotational tool 20 years ago. The most recent member of the family is the PowerDrive Orbit system. Introduced in 2014, this tool uses a new, highly reliable pad actuation system that increases efficiency and enhances trajectory control. As a result, drilling time is cut significantly through an ability to steer accurately at high rotational speeds while being able to handle aggressive drilling environments.

Successive generations of drilling technology have delivered steadily increasing reliability. Our latest tools, however, benefit from transformation program initiatives focused on engineering and manufacturing the most reliable equipment possible.

Our Technology Lifecycle Management program for example, where field equipment is centrally maintained before operational deployment, has reduced the number of tools required per job and a smaller fleet is now able to cover a larger service market.

At the same time, workforce productivity has been enhanced through remote operations where domain experts interface directly with on-site drilling crews. On land in the US, the percentage of jobs supported by remote operations has increased from 13% in 2014 to over 31% year to date in 2017.

While internal changes such as these have benefited our own financial performance, the real benefit lies in the improved operational performance they have delivered to our customers.

In the Utica shale in Ohio, a PowerDrive Orbit system with other Drilling Group technologies recently drilled a series of super lateral wells that set a series of records for North America, with each new lateral exceeding the length of its predecessor. One of the first wells to be drilled exceeded 19,000 ft in a single run in a drilling time of only 104 hours. In October, two further laterals were drilled that broke the 20,000-foot barrier with each being drilled in a single run. In addition, the average rate of penetration of the seven laterals drilled so far on this project has increased by 55% from the first to the last. Operational execution has been perfect, with no lost time or service-related incidents.

In another example in the Midland and Delaware basins in West Texas, PowerDrive Orbit systems were used to drill a total of 80 wells over a 12-month period that saw the average days required to drill a well fall by 17%, with the customer able to reduce the average total drilling cost per lateral foot by 30%. The exceptional performance and reliability of the technology also enabled the total lateral footage drilled per well to increase by 9%.

The cost efficiencies that we have achieved through our transformation program for technology ownership have allowed us to redirect capex within budget to manufacture additional sets of equipment to add capacity for services that are in high demand.

I’d now like to show how streamlining hydraulic fracturing operations through scale and breadth has improved our executional reliability and efficiency in the completions and production market.

Three years ago in New York we highlighted that geometric completion designs had led to approximately 40% of perforation clusters in tight oil wells on land in the US not contributing to production. In helping overcome this issue, we developed what we called the geoengineered performance workflow.

This begins with identification of the reservoir quality. Based on this, extended-reach, geosteered wells are planned to land in the optimum reservoir volume. Next comes the engineered completions system designed to frack every useful cluster and place proppant from fracture tip to wellbore in every fracture. Last is the engineered flowback process that manages well cleanup during the startup of production.

OneStim, the new integrated completions technology, combines our industry-leading hardware technologies with automation and process re-engineering, operating software, and optimization software to drive operational efficiency and lower cost of ownership. It is the latest step in an evolutionary process built on our broad cross-disciplinary domain expertise.

To deliver the OneStim service to its full potential, innovative operational planning and optimum use of resources are essential. With the need for higher stage-counts, larger proppant volumes, and improved economics, the demands on workforce productivity, field equipment, and supply logistics are reaching greater levels.

Today, North America pumps the same sand volume with 950 rigs as it did in 2014 with over 2,000 rigs. Each fracturing fleet consists of more than 40 pieces of equipment and requires between four and seven million pounds of sand per well that need more than 140 truck-loads or 35 railcars to transport. This makes a fracturing fleet like a high-volume factory that must be moved every two to three weeks.

Effective management is essential. Transformation program innovations such as distribution control tower and global equipment traceability initiatives that are leveraged by digital supply chain capabilities have provided highly effective solutions. Vertical integration adds another dimension through the ability to balance, for instance, our internal supply of sand against external suppliers. We have one sand mine already operational and several others being prepared for production.

These and other initiatives have allowed us to improve asset utilization by 30%, and reduce unit cost by 56%, despite the need to manage more than double the proppant volumes of just two years ago.

Transformation initiatives have also driven significant improvements in the efficiency of our field equipment, its operation, and its intrinsic reliability to enhance the mobility of both people and equipment. Our centers for reliability and efficiency track equipment to ensure that maintenance needs are detected and fulfilled with equipment performance data being streamed in real time from all stimulation crews to the reliability and efficiency centers. These innovations have already delivered significant performance improvement with workforce productivity growing by 40% while equipment reliability has improved by more than 55% during the last two years. This is equivalent to a net gain of three fleets in hydraulic fracturing capacity.

OneStim has also driven a new generation of field equipment that delivers greater efficiency and enables full workflow integration from geoengineering to well flowback and monitoring.

Conventional stimulation equipment, for example, automates only a few mixing and pumping functions and has its limitations when it comes to higher stage counts, greater volumes of proppant, and high-intensity pumping operations used in pad configurations. These requirements have driven the development of a new automated surface delivery platform that integrates modular automated skids, trailers, and silos to optimize operations and decrease crew size. Seven of our fleets are equipped with the platform and we are deploying additional equipment sets aggressively.

Cameron surface technologies, such as CAMSHALE pressure-control and wellhead equipment, have been integrated into operations and in the third quarter of this year CAMSHALE equipment was being deployed on about half of the stimulation jobs we conducted in North America. New Cameron technologies are also being introduced, including a horizontal fracturing tree that is 50% shorter and 25% lighter than previous generations. On multiwell pad completions, Monoline flanged-connections streamline operations and improves safety by replacing multiple lines to the well with a single line.

The OneStim systems we have deployed on land in North America have already pumped more than 3,700 stages in 128 wells. In addition, the planned OneStim joint venture with Weatherford will bring greater scale and additional completions technology to the offering, with the proposed venture receiving U.S. DoJ approval on November 28th. There are ancillary agreements to this deal that we still need to work through with Weatherford.

Before I comment on our expectations for the fourth quarter, I’d like to talk a little about the digital enablement of E&P processes and workflows.

Our objective is to connect E&P domains, people, and processes through a digital foundation. This goes beyond providing solutions through incremental change to a new way of working that offers new opportunities, unmatched performance, and a step change in efficiency. The DELFI cognitive E&P environment that we unveiled at our SIS Forum in Paris last September is designed to do that by uniting E&P planning and operations from exploration to abandonment and to remove the barriers between technical disciplines.

The DELFI environment brings together advances in domain, science, technical and digital disciplines, to make data, applications and workflows accessible to all users. With DELFI, geologists, drilling engineers, and reservoir specialists together with every other stakeholder in a project will be able to see the same information at the same time and collaborate seamlessly across domains. The best possible representation of the surface and subsurface is achieved through an integrated and intelligent system that shares insight between all users to eliminate the silos of today.

Development of the DELFI environment is the latest step in the 25-year history of our SIS product line, which was created in 1992 through the acquisition of GeoQuest. Critical mass was established when GeoQuest was integrated with existing Schlumberger petrophysical expertise and Geco geophysical workstation technology. Reservoir engineering capability was subsequently added with Eclipse simulators in 1995, Merak economic planning, risk, and reserves software in 1999, and Petrel 3D visualization software in 2002.

Steadily increasing internal development enabled functionality to be expanded quickly so that different asset teams could access the same data, and share the same earth model. By removing the obstacles of data transfer between applications, non-productive time decreased, data fidelity increased, and the quality of decision making improved. The result was a full suite of end-to-end software solutions and workflows covering all E&P disciplines.

But one thing was still lacking. Disciplines and domains were not joined up, and this silo nature prevented any one discipline, domain, or asset from integrating the insights of any another. The DELFI environment is our answer to this. Its development combines advances in technical and digital disciplines including artificial intelligence, machine learning, and data analytics with domain expertise and digital representations of individual hardware technologies across the E&P workflow.

Let’s see how this works in practice—taking well construction as an example.

First, a planning team integrates all available data to determine the required well profile. Rock types, overburdens, pore pressures, zones of potential loss of circulation, offset well data, and many other pieces of information dictate the parameters required to drill as rapidly, as efficiently, and as safely as possible. The resulting well plan is delivered in hours, not months through digital enablement and team connectivity.

Second, the drilling engineering team selects the optimum bottomhole assembly, integrating specific choices of measurement-while-drilling, logging-while-drilling, directional drilling, drill bit and drilling fluid with surface monitoring capability and available drilling rig automation and control.

Third, this plan is loaded in to the control system of an integrated drilling system, which orchestrates operations and keeps track of all well construction information in real time. As the plan is executed, the drilling crew at the wellsite monitors both system and progress, reacting to changes and unexpected events in full collaboration with the drilling engineering team.

Fourth, the volumes of data collected from multiple sources, including sensors on the rig, tools downhole, instrumentation at the surface, and the logistical management systems are input into the DELFI environment. As more wells are drilled, machine learning and data analytics are integrated into the workflow for continuous process improvement.

All team members work in circular and seamless collaboration, avoiding inefficiency in handoffs between different services. Common coherent data, domain models, and engines lead to a common understanding that enables the system to deliver actionable insight to all participants.

The digital process that I’ve described for well construction can, of course, equally be applied to any other E&P workflow, from exploration to abandonment.

I’d now like to turn to the operational update for the fourth quarter.

Geographically, in North America land, we expect the growth trend to continue, but it will be moderated by the effects of the holiday season and the rig count flattening. We expect to generate further market share gains as we benefit from a full quarter’s activity from the capacity we redeployed in the third quarter. This will improve utilization and increase revenue sequentially. The transient costs we experienced in prior quarters should dissipate as we stabilize at higher activity levels, resulting in improved incrementals. North American offshore activity will continue to decline, while year-end multiclient and product sales are expected to be muted.

Internationally, we are looking for modest growth in the Middle East and Latin America Areas, while winter seasonality will lead to a decline in activity in Europe and Central Asia. International year-end product sales will also be muted.

By Group, starting with Reservoir Characterization, revenue is expected to be lower after the strong summer campaigns of the third quarter combined with seasonal reductions in activity throughout the Northern Hemisphere. For the Drilling Group, we anticipate revenue to be flat sequentially as higher activity on land in North America will be offset by lower drilling activity in the Northern Hemisphere following the peak summer drilling campaigns. This will be particularly noticeable in Russia. For the Production Group, we see revenue trending higher, although the pace of sequential growth will moderate due to holiday effects. At Cameron, we expect revenue to be modestly higher sequentially as growth in the short-cycle Surface and Valves & Measurements businesses benefit from robust land activity in North America and more than offset the slowing decline in the long-cycle OneSubsea and Drilling Systems businesses.

Overall, we anticipate fourth-quarter revenue to be slightly higher sequentially as the trends that drove growth in the third quarter continue, although these will moderate somewhat due to seasonal factors.

Ladies and gentlemen, in conclusion, I’d like to summarize some of the key points I have made today.

The narrowing gap between the supply and demand for oil has been steadily leading commodity prices higher. While the sustainability of this remains unknown we are turning increasingly positive on the overall outlook for our global business. It is of course too early to say what the specific impact of this will be on overall 2018 E&P spend as our customers are still in their planning process, but we do expect activity tailwinds in a number of regions around the world in 2018.

Throughout the downturn we have continued to invest in our business. Our long history of building market technology leaders has continued, and we possess the strongest platform of individual oilfield technologies that, coupled with software domain expertise in each and the ability to leverage the value of the data, will provide a foundation for new offerings to leverage the market recovery.

My examples today have also illustrated how our multiyear transformation program continues to contribute to performance, not only in cost savings as we change the way we work, but also in promoting new technology development to meet changing market needs. As the market turns to recovery, multiplication effects will accelerate performance and enable us to reach our goal of more than 65% in incremental margin once higher oil prices prove sustainable.

We are confident that our substantial financial strength, extensive geographical footprint and wide technology portfolio continue to position us as the leader in the oilfield services market, and make us one of the best investment opportunities as the market moves to recovery.

Thank you. I’m sure we have time for a few questions.

Patrick Schorn

Schlumberger Executive Vice President New Ventures Patrick Schorn addressed the Cowen & Company Energy & Natural Resources Conference in New York City.

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