Ladies and gentlemen good morning. My thanks to Jud Bailey and Wells Fargo for the opportunity to be here today.
My intention this morning is to spend about 20 minutes on prepared remarks focused on the changes we see in oil supply and demand, together with how these are translating to activity for our Areas and Product Groups. We’ll then open the floor to a longer-than-usual Q&A session. That way we’ll spend more time talking about what you’d like to know, rather than me delivering a standard presentation.
First the legal information. Some of the statements I will be making today are forward-looking. These statements are subject to risks and uncertainties that could cause our results to materially differ from those projected in these statements. I therefore refer you to our latest 10-K and other SEC filings.
Thank you, let’s get started.
The reasons for today’s crisis in the industry are well accepted. Supported by high oil prices, the search for new sources of supply in recent years to meet rising demand led to increasing investment in complex deepwater basins and in unconventional resources. Both of these are higher-cost complex environments, deepwater because of the scale of operation and the technology required, and unconventional because of the time taken to develop the needed technology and workflow. With non-OPEC unconventional production rapidly rising between 2013 and 2015, OPEC’s desire to protect market share, as opposed to oil price, has now led to the most severe market slowdown in 30 years.
This has meant that profitability and cash flow have fallen to unsustainable levels for many operators. As a result, E&P capital expenditure has been cut with exploration halted, development aggressively curtailed, and service industry prices relentlessly squeezed. While this playbook might have allowed the business to return to normal in the past, we do not think that oil prices will return to their previous high levels any time soon, short of a major supply upset, given the greater availability of lower-cost Middle-Eastern supply and the progress that has been made in the cost of unconventional resource development in North America.
The current downturn is now 20 months long since the US land rig count peaked in October 2014. It already outpaces that of 1986/87 and estimated E&P spend for 2016 is now about a third below that of 2014. At such levels, continual growth in production capacity cannot be maintained, and production lost to decline cannot be fully replaced. With year-on-year growth in demand robust at 1.3 million barrels per day, year-on-year growth in supply declining due to lower investment, and spare capacity at minimum levels, we are gaining more confidence in an onset of recovery driven by the tightening supply-demand balance. This is in fact made more likely in view of the usual overshoots both to the upside and to the downside.
These comments offer little in granularity, so I would now like to show how production in some key areas is falling. Much of this is due to lower E&P investment. However we must also recognize that environmental events such as the wildfires in Canada, and security and other disturbances elsewhere have also reduced overall production. These effects will accelerate a return to balance in supply and demand.
Here in the United States, for example, after a multiyear increase in oil supply driven by unconventional resources that peaked in mid-2015, production has fallen by an average of 90,000 barrels per day every month this year. This overall figure includes declining shale oil production with recently completed deepwater and other offshore projects helping to offset some of the drop.
OPEC countries, and particularly Saudi Arabia, have been pumping at near-maximum rates with Iran production growing by 770,000 barrels per day as sanctions were lifted. Growth in Iraq, however, has flattened, production in Nigeria has fallen by 470,000 barrels per day, and other falls have been noted in Venezuela and Libya. Taken together, the net effect since mid-2015 of some OPEC members pumping at high rates, while others experience decline, is a minor increase in production of only 140,000 barrels per day.
Outside North America, and outside OPEC, production is on a clear downward trend as evidenced by losses from a growing number of countries. Budget cuts in Mexico have already led to a fall of 100,000 barrels per day in Mexico, with lower activity in Colombia also leading to a decrease of 100,000 barrels per day, and production declining steadily in in the non-Russian former Soviet Union countries. China has not been exempt, with production down 250,000 barrels per day. In these and other non-NAM, non-OPEC areas, many of the factors that fueled increasing performance have evaporated as spending levels have dropped in response to lower commodity prices.
However, when we look at geographical spending levels, we also see areas where international spending levels have decreased less than average. Overall E&P spend in 2016 in the Middle East, for example, is expected to be close to 2014 levels and this offers opportunities in spite of pricing pressure.
With these comments in mind, I’d now like to give you our latest operational update, starting with the Western Hemisphere.
Rig count levels in North America now appear to have stabilized at a level 80% below the peak of October 2014. With oil price levels approaching $50 per barrel for WTI as supply and demand move into balance, operational visibility is beginning to improve and the rig count is now expected to increase on land during the next two quarters. Though the current equipment overhang is far in excess of what is required to service these wells.
This view must also be balanced against the existing overhang of pressure pumping equipment in North America. Any return to service of currently inactive assets will affect an industry return to profitable pricing levels, which are currently 20% to 30% below breakeven. We therefore do not expect to see any marked increase in service pricing in the short term. At the same time, our own staffing levels are adequate, and we will be ready to gradually increase activity as market conditions improve.
Offshore, there has been a slowdown in infill drilling in the Gulf of Mexico, although the effect of this has been more than offset by production startups on a number of new projects.
In Latin America, which has seen one of the largest drops in E&P spend since 2014 as major resource holders’ revenues fall, production in Venezuela, Mexico, and Colombia, are all significantly down. Budget cuts in Mexico have reached 50% year-on-year, to the lowest in the last decade, and it will take time for activity to build under the new licensing rounds. Brazil has seen budget cuts of 50% offshore and 70% on land leading to a focus on presalt production that hit a new record in May of more than 1.1 million barrels of oil equivalent per day from 52 producing wells. This focus should enable steady but gradual growth with 50 to 60 new deepwater wells per year. In Colombia, the rig count has fallen by 90% since late 2014, with activity only likely to resume once oil prices stabilize above $45 per barrel for WTI. And in Venezuela, our activity has been reduced in line with collections. At the same time we continue to work with all customers in Venezuela to potentially enable increased activity through different payment models.
Before we leave the Americas, it also interesting to discuss how overall production levels can be maintained with a balance of new and existing field supplies.
For example, while production declines are appearing in a growing list of countries, some are benefiting from investment decisions taken prior to the downturn and are showing growth from new development projects that are coming on line and are offsetting strengthening declines in base production.
In the US Gulf of Mexico, the new deepwater projects that have started producing since 2013 have contributed over 380,000 barrels per day in the first quarter of 2016 while the existing fields in early 2013 have declined by 130,000 barrels per day during the past year. Further growth in the Gulf of Mexico is expected this year with other significant projects starting-up.
In Brazil we see the same pattern. Total production has increased by 200,000 barrels per day since early 2014, but this has been achieved through the pre-salt development that has experienced growth in production of more than 450,000 barrels per day. The rest of Brazil’s fields have suffered the most from budget and activity cuts as development drilling activity has fallen by close to 60% since 2014, leading to a decline of 250,000 barrels per day. As the pre-salt production is essentially constrained by FPSO capacity, further growth will be determined by the two FPSOs that are expected in the second half of this year.
In the Eastern Hemisphere in the Europe CIS and Africa Area, activity in Norway has been characterized by the take-up of new integration-based offerings. Beginning with integrated services management to coordinate planning and logistics for greater efficiency for Statoil and Det Norske, these integrated offerings are meeting with increasing customer interest as the advantages of earlier involvement and specific technology deployments become more apparent. Activity in the Norwegian sector of the North Sea recovered for the domestic operators after the winter season, however the IOCs continue to reduce activity. In the UK sector of the North Sea, activity is flat with Q1, with limited seasonal recovery.
In Sub-Saharan Africa, activity also remains low after the completion of earlier exploration and appraisal work offshore and the recent deferment of some active projects, which will only resume when business conditions improve.
Turning now to the Middle East and Asia, the volume of activity in Saudi Arabia remains robust with increased drilling market share and additional land seismic work. Pricing levels, however, remain under pressure. Activity in Kuwait has also been robust, with a significant award for early production facilities for KOC, and early benefits from synergies with Cameron including internalization of supply. In other Middle Eastern GeoMarket* countries, there has yet to be any change in the ramp up of industry activity in Iran—where Schlumberger is not currently active—while Iraq has faced security issues in the North and delayed payments in the South.
Rig count in the Asia-Pacific region remains extremely low. In China, offshore activity is continuing while land operations in China are favoring the domestic service industry. While the geographical view will shape the recovery, I would also like to give you an update on how the Product Groups are performing.
With the acquisition of Cameron, four Groups now form the primary financial reporting basis for Schlumberger. Each Group has its own characteristics, based on factors such as new technology sales and product versus services mix. And in the last two years, approximately 60% of Schlumberger revenue has been generated from land operations, with the remaining 40% coming from offshore activity. This split is roughly the same in both North America and internationally.
This reporting structure is particularly important as the evolving integration business model allows us to optimize each of our product lines on a global basis and develop the management of our business support structures in line with the philosophy and implementation of our transformation program.
At our last investor conference in New York, we set incremental margin targets for 2017 by Group. These figures were 45% for Characterization, 40% for Drilling, and 35% for Production. As the downturn deepened, these growth targets became decremental margin targets, with an overall target of 30% to be achieved by managing resources against activity, and by balancing market share against margin.
As we navigate the bottom of the cycle, decremental margins are less relevant. While these may expand in the short term, we have not changed our view of our business since that of our first-quarter 2016 earnings call.
Looking now at the Groups individually, Characterization is more exposed to the international markets than to North America. In addition, more than half of its revenue is derived from exploration or other discretionary spend. All of its product lines lead their markets. The leadership and mix of its portfolio bring strong margin outperformance when markets are growing and technology needs are high, but when markets contract and discretionary spend is cut, decrementals expand. In the first quarter of 2016, revenue fell by 20% sequentially and operating margin dropped by 480 basis points resulting in a decremental sequential margin of 43%. Revenue in the second quarter is expected to sequentially decline by about 10%, however decremental margin will remain elevated as we continue to maintain the long-term capability and the petrotechnical expertise of the Group at this stage of the cycle.
In contrast, the Drilling Group is evenly exposed across all Areas. Performance is driven by rig count, and incremental and decremental margins average slightly more than 30% as markets grow or contract. At the same time, performance-based drilling contracts represent a growing proportion of the Group’s revenue. First-quarter revenue fell sequentially by 16% to $2.5 billion, operating margin fell by 183 basis points to 15%, leading to decremental margin of 27%. Drilling Group Revenue in the second quarter is expected to decline more severely by about 20%, impacted by a steeper decline in rig count from a combination of the spring break-up in Canada and lower rig counts on land in the US and in Latin America. As we continue to scale back Venezuelan activity, decremental margin will be further impacted.
The Production Group is more-than-half exposed to North and Latin America. It is this Group that is most significantly impacted by weak NAM activity, leading to lower margins. Both incremental and decremental margins typically exceed 30%. The Group, however, offers an important dimension of growth through Schlumberger Production Management where the performance-based element of a contract provides opportunities for accretive margin and superior return. In the first quarter, Production Group revenue fell sequentially by 11% to $2.3 billion, operating margin fell 9%, and decremental margin reached 33%. Production Group revenue in the second quarter is estimated to decline by 10%, impacted by the lower activity on land in Canada, the US and Latin America.
The fourth Group is Cameron, which is two-thirds exposed internationally. Activity is driven by both long- and short-cycle businesses with the long-cycle markets of OneSubsea and drilling equipment measured by orders and backlogs. In the first quarter, OneSubsea orders totaled $305 million, while backlog fell sequentially just under 5% to $2.87 billion. Drilling equipment orders reached $150 million, to lower backlog 23% to $1.31 billion. The short-cycle Cameron businesses are more NAM dependent. We are on track to deliver synergies of $300 million in the first year after close, and $600 million in the second. First-quarter Cameron revenue of $1.63 billion was down from $2.08 billion sequentially, with margin falling from 18% to 14.5%. We now expect Cameron revenue in the second quarter to be slightly down from the previous quarter. Finally, the Cameron acquisition will be accretive to both earnings and cash flow by the end of 2016.
Ladies and gentlemen, before we take your questions, let me just summarize the major points that I have made.
The latest production data indicate that oil supply and demand are moving fairly rapidly into balance, and may even overshoot as the E&P capex spend cuts of the past two years continue to impact the industry. At the same time, a number of OPEC countries are finding it increasingly challenging to maintain the high production levels seen last year. On the demand side, estimates of growth in demand remain robust.
Against this landscape, activity has yet to show any meaningful improvement. While minor increases in rig count in North America together with the move toward completing the inventory of drilled but uncompleted wells are positives, pricing pressure and the significant excess of service equipment will limit our earnings potential until 2017.
Internationally, activity continues to fall, although pockets of outperformance exist in Russia and the Middle East where Schlumberger is favorably placed through its wider geographical footprint. With oil prices now increasing we will be seeking to reverse the temporary pricing concessions we have made. Furthermore, as this picture develops, we will continue to focus on matching resources to activity, leveraging transformation initiatives, and maintaining the longer-term operational and technical infrastructure that will be needed in the future—particularly in North America.
Our plans for Cameron are firmly on track. Our estimates and expectations for revenue synergies are very much intact with a number of examples emerging through the integration of CAMShale into our hydraulic fracturing offering, the take up of managed pressure drilling through the wider Schlumberger global presence, and market success such as the early production facilities project in Kuwait.
The financial strength of Schlumberger continues to enable us to invest through the downturn. We have recently completed five “bolt-on” acquisitions of various technologies to either complete existing offerings, or to prepare for the growth of others. At the same time, as we announced before, we started a new SPM project that required a significant upfront investment in both the fourth quarter of 2015 and the first quarter of 2016. We remain ready to invest in other large SPM projects if and when sound opportunities become available.
Turning to the more immediate outlook, we do not see anything to challenge our view for the second quarter, which we increasingly believe may represent the final approach to a market bottom.
Ladies and gentlemen, thank you very much, I’ll now pass the floor to the chair.
Schlumberger President of Operations Patrick Schorn addressed the Wells Fargo West Coast Energy Conference in San Francisco.