As the world struggles with the inflationary issues of oil heading towards US$130 a barrel, investors must focus on the opportunities this event throws our way.

We examine the supply issues supporting a long-term oil price above US$75 per barrel (a level that justifies many deep offshore drilling projects) and explain why production has shifted from low to high cost, leaving the world to rely on more expensive oil. Turning to the opportunities what is our rationale for investing in the oil service sector, the providers of the offshore oil rigs, storage and supply vessels, drilling equipment and engineering know-how?

So, are we running out of cheap oil? Saudi Arabian production is a useful case study illustrating how globally maturing onshore oilfields can turn from low to high cost within just a few years.

Saudi is the primary provider of cheap oil, providing 31% of OPECs oil and possesses the worlds most prolific oil fields. At the top is the Ghawar field the King of Kings. Over the last half century it has provided between 55% and 65% of Saudis total production. However, like many of the smaller fields, Ghawar is in unavoidable decline and, like a game of chess, once the king has fallen, the game is over. Right now the King is in check. In fact, since 2006, the depletion of Saudi oil fields has accelerated from an 8% decline, to 10% to 14%. So, we can see that production volumes are in jeopardy.

What about cost? Are the Saudis still producing cheap oil? To answer this we need to look at what happens to an individual oil well when it matures.

When the giant fields were young, they had individual wells with flow rates of between 40,000 and 80,000 barrels of fluid a day virtually every drop was oil. Processing requirements before export or refining were minimal. This level of production has not only fallen between 2,000 to 5,000 barrels of fluid a day, but the content has changed dramatically.

As an oil field matures, the reservoir pressure drops, allowing surrounding subterranean water to invade the reservoir. This pressure drop may also prompt drillers to inject water, usually seawater, into the reservoir in order to maintain its pressure, thereby driving the oil to the surface. To avoid contaminating the fragile water table, the injected water is normally desalinated, requiring costly desalination plants to be built. The contamination of water creates a water and oil mix (water cut), which must be cleaned using a Gas and Oil Processing Plant (GOSP) at additional cost, before being sent through to a refinery. The older the well, the lower the reservoir pressure, the greater the water cut, the higher the cost.

There are significant cost implications of rising water cut. To get 10 million barrels of oil from a well-stream with 25% water cut, you must process 13.3 million barrels of well fluid. If the water cut moves up to 50%, this figure jumps to 20 million barrels. Basically, Saudi must increase its level of processing capacity (increasing the size and number of GOSPs) just to maintain its production levels. According to Dr Sadad Al-Husseini, former Executive Vice President of Exploration and Production, this is one of the many factors that has pushed the cost of extraction in Saudi from $2 to $75 a barrel. This situation is echoed globally as many of the once giant, cheap producing oilfields have already peaked, including:

• Russias Samotlor in 1983
• Alaskas Prudhoe Bay in 1987
• Mexicos Cantarell in 2003
• Chinas Daqing in 2004

With no major onshore oilfield discovery since 1975, there are few cheap drilling options replacing them.

Are companies producing enough of this expensive oil? The answer is no. The industry uses a measure called the Reserve Replacement Ratio (RRR). This is the number of proven reserves divided by the number of barrels being sold. If the number is below 1, then they are not finding enough oil to replenish what they have sold. Industry RRRs have fallen from 1.3 in 1996-2000 to 0.9 organic RRR in 2007. There is growing pressure on companies to increase their proven reserves by producing more oil. A reserve is termed proven if it is considered reasonable to extract oil in the future, from a known physical resource, with known techniques and in the present economic conditions.

The few onshore options available mean the industry must develop offshore fields. There are three ways in which the oil industry can address the issue:

• Companies can discover new resources by supporting providers of seismic equipment and exploration know-how.
• The industry can improve extraction techniques. Today, the recovery rate of an oil reserve is typically 35%. Any 1% increase represents an increase in reserves by years. This favours sub-sea engineering companies, sub-sea equipment, manufacturers and companies that are involved in well maintenance and Enhanced Oil Recovery (EOR).
• The current economic conditions have improved significantly, with the long-term oil price forecasts well above the investment hurdle rate for many deep sea projects. In the absence of cheaper alternatives, oil companies are looking to convert oil fields into proven reserves. In order to book a reserve as proven, oil companies must drill one appraisal reserve well, one contingent well and provide a Planning Development and Operation (PDO) timeline, proving that they have secured drilling capacity, subsea equipment etc. This necessitates long-term action and is extremely positive for oil service companies order books and visibility of earnings.

As exploration moves into deeper and harsher environments, a new industry is being developed. This necessitates innovation in equipment design and expertise in extreme engineering niches that the Norwegians are particularly adept in, having honed their engineering capabilities in the demanding North Sea environment. These new designs and challenges are very evident. Over-supply is not yet apparent. Visibility is high and deep sea rig supply looks tight until 2016, positively implicating demand for the entire oil services sector.

Richard Robinson
European Specialist