Economic growth seen during the 2003 to 2007 boom fueled growth in oil demand of 1.6 MMbbl/d on an average annual basis. Total global demand peaked in 2007 at more than 86 MMbbl/d, a figure that, at the time, stretched the global oil industry to its productive limits. By 2006, available OPEC spare capacity fell to 3 MMbbl/d, or 3.5% of global oil production.

Responding to this demand, OPEC countries, led by Saudi Arabia, undertook ambitious capacity addition projects beginning in 2004. Nearly 3 MMbbl/d of new crude production capacity has been added by OPEC countries since that time.

Oil demand, supply
The onset of the US subprime crisis and the resultant Great Recession led to the most significant contraction in global oil demand since the early 1980s. The world economy shed 1.8 MMbbl/d of oil demand in the two years of the recession, and PFC Energy expects that the prolonged debt workout in the OECD markets will continue to cap future growth potential in the broader economy. This limitation likely will result in medium-term global oil demand growth between 1.3 and 1.5 MMbbl/d, even with a more robust outlook for emerging markets.

NOCs have progressively increased their share of worldwide E&P expenditure. (Graphs courtesy of PFC Energy, Barclays E&P Survey, and Datamonitor)

The combination of increased capacity and lower demand caused OPEC’s spare capacity to rise significantly. More than 6.5 MMbbl/d of productive capacity now sits idle. In several respects, this will not pose the same challenge to OPEC’s ability to manage markets and achieve acceptable prices as it would have in the past.

OPEC countries have improved their operational capabilities to meet revenue requirements and energy needs from current output levels, while key states have seen their global strategic importance and prestige rise because of their maintenance of strategic supply capabilities in the event of unexpected disruptions to crude markets.

Additionally, there is a short-term absence of non-OPEC producers that could "steal" market share from OPEC – an important factor in precipitating previous price collapses. Over the next five years, the BRINK (Brazil, Russia, Iraq, Nigeria, and Kazakhstan) producers will bring significant new production into the market and test OPEC’s ability to manage markets and prices.

Overcapacity of the service sector
Preparing for an expected higher level of demand, service companies also have anticipated a constrained industry with

NOCs have progressively increased their share of worldwide E&P expenditure. (Graphs courtesy of PFC Energy, Barclays E&P Survey, and Datamonitor)

limited resources to develop projects and expansion plans that E&P operators had in the queue in the first half of this decade. From 2005 through 2007, the industry faced capacity constraints, and a few projects were delayed because of a lack of rigs, construction vessels, and more importantly, qualified people. In response, the service segments began building programs that brought into the market significant incremental capacity. At the same time, activity suddenly dropped, starting in mid-2008. There are assets still under construction that will be delivered during the course of the next two years that will contribute to the overcapacity condition of the industry.

For example, the offshore drilling industry expects more than 90 rigs to be delivered by the end of 2012, a situation that will keep fleet use below 80% – far from the close-to-100% balance observed in the years before the crisis.

In addition to overcapacity, there is lower demand for some services, particularly onshore drilling and oilfield services, which has kept the bargaining power in the hands of E&P operators and maintained service costs at prices at a lower level than three years ago. Some of this demand is not expected to return soon, so some markets will see an extended period of relatively low costs, at least until the demand recovers or the fleet reduces due to retirement of old assets, consolidation of players, or migration of capacity to alternative markets.

The variation of costs has been different depending on the particular segment and sector and varies among geographical

Capital expenditure CAGR will decline with lower costs and as developed areas reach maturity. (Graph courtesy of PFC Energy E&P Spending Forecast Model)

regions. A sudden and dramatic drop occurred in 2009 that took the cost base back to 2005 levels in the case of onshore services and to 2007 levels for offshore. Drilling is showing the most drastic fluctuations, with onshore activity taking the lead in terms of cost reduction; this particularly applies to the US onshore market, in which a dayrate drop of 40% was observed between 2008 and 2009. Operating costs remain the most stable given that ongoing production and the associated services have not been affected by the demand reduction.

2010 is expected to be the year of cost stabilization, with a relatively small variation from 2009. More drilling and construction capacity, along with delays in the execution of key projects, will force service costs to keep a downward trend, but at a slower pace than observed in 2009. PFC Energy estimates offshore services will drop another 5% in 2010, while onshore services will remain stable after a more drastic decline in the preceding two years.

E&P spending stabilized
According to industry surveys, E&P operators will have increased their spending by approximately 11% in 2010 after a drop of 14% in 2009, bringing the expected investment for 2010 to US $469 billion. Although higher than the $421 billion spent in 2009, it is 4% lower than the $490 billion spent in 2008. When analyzing the global expenditure by type of company, the national oil companies (NOCs) have significantly increased their participation from 27% in 2007 to a current 39% of total E&P spending. On the other hand, major international oil companies (IOCs) have maintained their spending share around 33% – an average that has been sustained since the early 1990s. The rest of the companies – more than 350 entities around the world – have suffered a drastic reduction in spending share from 40% in 2007 to 27% in 2010.

With strong finances, major IOCs have carried on with their development and exploration plans, delaying programs as necessary to take advantage of the lower cost environment and improving their project economics. On the other hand, most of the smaller IOCs have faced financial difficulties during the recession period and were forced to postpone or cancel some development and exploratory plans; they became the main contributors to the overall drop in 2009 E&P spending, cutting their budgets by 35%.

Several NOCs have taken advantage of the cash flows obtained during the years preceding the crisis. Some of them, such as Petrobras with its extensive undeveloped domestic assets, have focused on the development of their most difficult areas. Others, with limited local assets but strong financials, have pursued internationalization, such as the Chinese trio CNOOC, PetroChina, and Sinopec; Malaysia’s Petronas; and smaller and emerging state-owned players such as Colombia’s Ecopetrol.

With major NOCs and IOCs heading the list of spenders, in the next five years overall capital expenditure is expected to grow by 4% compounded annual growth rate (CAGR). Although significant, the rate of growth will be lower than the previous five-year period, when the average CAGR was almost 10%.

The important difference is that during 2005 to 2010, although there was a significant increase in activity, most of the E&P spending rise was driven by cost inflation; capital costs more than doubled in this timeframe. In the coming years, the cost base is expected to be more stable and the spending increase will be driven mostly by net incremental activity, especially after 2011 to 2012.