The IEA reports that OPEC's effective surplus capacity will hit two million barrels a day later this year, and could drop to as low as one million barrels by 2012. That's a dangerously low margin in an industry that faces frequent disruptions, ranging in the past from hurricanes in the Gulf of Mexico, to pipeline ruptures in Alaska, to strikes in Nigeria. A constant source of concern is the ever-present fear of geopolitical strife in the oil-rich Persian Gulf region.
So far this decade, OPEC's spare capacity has been closer to three million barrels a day, and averaged between 3.5 million and four million in the 1990s.
At the same time, non-OPEC sources of new supply have become increasingly costly to produce. In the Canadian oil sands, and Venezuela's extra-heavy oil belt, the break-even point for new oil supplies is approaching $65 a barrel.
Average finding and development costs for international oil companies have more than tripled since the beginning of the decade - from $6.08 a barrel to $19.09, according to a survey by PFC Energy, a Washington, D.C.-based consultancy.
"Oil companies are paying a lot more for service, across the board," PFC analyst David Kirsch said. "At the same time, you're seeing a tremendous backlog in the service company workloads. So even if you have the money for a new project to come on line, you have to wait."
The rising costs and production challenges are among the factors driving prices, Mr. Kirsch said, as speculators bet that markets will remain tight and that tomorrow's barrel of oil will cost more to produce than yesterday's did.
"It certainly is a significant element of what's driving prices," he said. "It's just much harder to produce this stuff and there is a recognition now that your marginal barrel - which is coming from places like the [Alberta]tar sands - is around $65 a barrel."
While prices have climbed well beyond levels that justify new investment, oil companies have been slow to respond.
In part, that's because OPEC's state-owned oil companies control a growing share of the market and are less interested in making multibillion-dollar investments that will drive down prices. In part, it's because international oil companies endured market crashes in both the 1980s and the 1990s and have been wary about whether the sharp price increases of the past three years will endure.
And in part, it's because the prospects simply are not as attractive as they once were. British-based BP PLC this month agreed to spend $1.2-billion (Canadian) to develop three parcels in the Beaufort Sea, where one well can cost more than $60-million, where ice conditions are hazardous and rapidly changing, and where there are no pipelines to move to market any oil or natural gas that it might find.
"People are looking at the oil companies and they're looking at huge profits and are forgetting the amount of investment the oil companies now need to do if they are going to be able to meet the world's energy demand," said Candida Scott, senior director for cost and technology at Cambridge Energy Research Associates.
Output: 1.766 million barrels a day.
Reserves: 11 billion barrels. In addition, state-owned Petroleo Brasileiro SA (Petrobras) has estimated recoverable reserves at its new Tupi field of up to eight billion barrels, one of the largest discoveries in the past 20 years. And there are estimates that the Santos, where Tupi is located, could contain as much as 33 billion barrels of recoverable reserves.
The plan: Aggressive exploration and development of offshore fields to boost production from 1.77 million barrels a day to several million barrels a day by 2020.
The challenge: While Brazil is increasing its production from near-shore finds, the major discoveries lay hundreds of kilometres offshore, in extremely deep water. They occur some two kilometres under rock, sand and salt beds, in formations that include salt. The recovered oil must also be shipped by pipeline or tanker from well site to shore.
Technology: Petrobras may be buying as many as 17 new drill ships and semi-submersibles for development of the Tupi and Carioca fields alone. The company is still developing the technology needed to extract the oil from the rock under more than 1,000 metres of salt formation.
Cost of technology: Swiss investment bank UBS has estimated it could cost a staggering $600-billion (U.S.) to develop the two major subsalt fields, Tupi and Carioca.Companies: Petrobras is the principal operator/investor. Others in Brazil's offshore include Norway's StatoilHydro ASA, Britain's BG PLC, Spain's Repsol YPF SA, and U.S.-based Exxon Mobil Corp.
The results: Brazil is currently experiencing an oil-related boom as drilling ships and foreign companies flock to Rio de Janeiro to participate in the Santos basin activity. The recent finds have raised the possibility that the country could become a major non-OPEC source of crude oil exports, eclipsing Venezuela as the South American oil powerhouse. However, analysts warn that even if the optimistic estimates of reserves are firmed up, it will be tremendously costly to recovered the oil, and that flow rates from the untested subsalt formations may be disappointing.