GLOBAL oil demand is increasingly centred on transport and the petrochemicals industry, as other fuels such as natural gas, renewable energy and coal take precedence in the power sector. Oil demand from the power sector could be reduced by around 30% over the next two decades, BP forecast in its Energy Outlook 2030 in early 2011. Meanwhile, improved efficiency in the transport sector and the potential for growth in the use of biofuels and alternative-vehicle technology, such as electric power, are set to further dampen oil-demand expansion.
All this means demand for oil is likely to be the slowest growing of any of the main fuels over the next 20 to 30 years. “Demand for power, rather than transport, will be the main driver of energy consumption growth,” said BP chief executive Bob Dudley. BP forecasts growth in global oil demand is likely to fall over the next two decades to average around 0.9% a year across the period, compared with 1.3% a year during 1990-2010.
But even such modest growth still means the world must find plenty of new oil resources to meet increased consumption and replenish existing reserves. That means a continuation of the trend, which has pushed exploration and production into increasingly challenging and expensive-to-exploit frontier regions, such as the Arctic and ultra-deep-water plays.
Precisely how that push will combine with the multitude of variables affecting the industry to shape the oil sector’s future remains to be seen. There is little certainty over how the oil market will develop beyond the next few years.
The Arab Spring of 2011 and its aftermath have provided a reminder that global events are unpredictable and play a vital role in shaping the direction of the oil market. Civil war in Libya, where oil exports were halted by the outbreak of violence in early 2011, proved more disruptive, as European refiners had to find alternative light sweet crude supplies from elsewhere, in a hurry.
Then there is the question of how much tolerance consumers will have if crude prices climb further, as oil becomes more expensive to produce, or further unexpected disruption occurs. For example, if the eurozone crisis triggered by economic weakness in Greece and other EU countries affects spending power and demand in the world’s larger economies, high oil prices could have a more pronounced effect on demand. And no-one can be quite sure how Chinese energy policy is going to develop – a change in tack there could have ramifications for everyone.
In June, a combination of the loss of supply from Libya and global economic uncertainties prompted the International Energy Agency (IEA), acting for OECD countries, to release 60 million barrels of crude from strategic storage – 2 million barrels a day (b/d) for 30 days – in a bid to bring oil prices down.
Demand rebound
The global economic downturn of 2008 triggered a decline in energy demand, but higher than expected growth since then – much of it in developing countries – took some in the oil markets by surprise. The recovery led to a rise in global demand of almost 3 million b/d in 2010, which was above many analysts’ forecasts. Growth is expected to be a less impressive 1.3 million b/d in 2011, taking total world demand up to 89.3 million b/d, according to the IEA.
The upturn has prompted the agency to reassess its demand forecasts. “After the sharp increase in oil demand in the second part of 2010, as the global economy recovered more quickly than expected from the recession, we now foresee higher mid-decade demand,” the IEA said in its 2011 Medium-Term Oil and Gas Markets 2011 (MTOGM11) report.
In its base-case prediction – based on an annual global GDP growth rate of 4.5% and an average oil price of $103 a barrel – the IEA sees average oil-demand growth of 1.2 million b/d a year over the 2010-16 period. That is around 700,000 b/d higher than it forecast at the end of 2010 and represents a cumulative rise of 7.2 million b/d between 2010 and 2016.
Most of that demand increase comes from non-OECD countries seeking to fuel their still fast-expanding economies. China is set to provide 41% of the rise on its own, with a further 53% coming from the rest of Asia and the Middle East (see Figure 1).
That this would be achieved despite the likelihood that oil-price subsidies in developing countries will be reduced shows the extent to which strong economic growth and increased prosperity will drive those markets. The IEA says countries with per capita income of $3,000-4,000 – considered to be the take-off range for rising oil demand – will be consuming around 45 million b/d of oil by 2016. That would represent a doubling of consumption for that income bracket in only 20 years.
By contrast, the IEA predicts that in the more mature markets of the OECD, improved efficiency and the effect of higher oil prices, together with political and economic uncertainties, will lead to a fall in demand growth by 260,000 b/d a year on average – a cumulative 1.5 million b/d fall. This shift in demand growth is reflected in the downstream sector, where China’s oil-refining capacity is poised to soar by a third between 2010 and 2016, according to the IEA (see Figure 2).
While the disparity in growth prospects between developed and developing countries may be stark, China and other expanding economies will still not match overall consumption in the already industrialised world in five years’ time. By 2016, oil demand from China is forecast by the IEA to reach 12.05 million b/d compared with 18.81 million b/d in the US, while Indian demand is forecast to reach 4.05 million b/d, still lagging Japan’s 4.23 million b/d.
Transport driver
Away from the power sector, oil’s pre-eminence is also threatened, notably in the transport sector. “There are many forces at work to make vehicles more efficient – including new regulations, innovation, better lubricants and increased use of biofuels,” BP’s Dudley said. Other factors include the effect of higher petroleum prices, vehicle saturation in mature economies and likely cuts in fuel subsidies widely employed across the developing world, including leading economies such as China and India.
The growth of the biofuels sector will be crucial, as biofuels directly replace oil in the transport sector. Biofuels account for around 3% of transport fuel in terms of the energy they provide and that figure could climb to 9% by 2030, all of that displacing oil, according to BP. The push towards using electric and hybrid vehicles, and relatively clean transport fuels, such as compressed natural gas, will also dampen long-term oil-demand growth.
But BP does not see these developments having a significant impact on oil demand within the next 20 years, while the IEA says the transport sector will continue to drive global oil demand over the coming 25 years, followed by industry and agriculture, heating and power generation, and residential and commercial use.
In its World Economic Outlook 2010, the IEA estimates transport’s share of global primary oil consumption would rise to 60% in 2035 from 53% in 2009 under its new policies scenario (NPS) – this outlook assumes broad environmental and clean-energy policy commitments and plans already announced by countries are implemented.
Forecasters agree that oil will remain the dominant source of energy for transportation, by road, rail, air and sea. But underlying assumptions for such forecasts include a fair amount of guesswork, as no-one knows exactly how fast the uptake of cleaner transport fuels and electric vehicles will be.
Whatever happens, China will be an influential force. “The number of vehicles will continue to grow in all regions, although through 2030, growth will be fastest in those countries that do not already have a high level of vehicle ownership. For example, of the 400 million new cars that will be added to the world’s roads between today and 2030, more than one-third will be in China,” ExxonMobil said in its 2010 Outlook for Energy: A View to 2030.
The IEA says such growth means China could account for half of the global increase in oil use for transport between now and 2035. So, if the widespread adoption of substitute fuels and electric vehicles at the expense of oil is championed by the Chinese government, the global impact could be substantial. The same applies if the development of the next generation of less land-hungry biofuels becomes easier and cheaper to produce.
The contribution of oil-based fuels, such as gasoline and diesel, to total energy used in road transport is already forecast to fall – to 89% in 2035 from 96% in 2009, according to the IEA’s NPS forecast.
Petrochemicals on the move
The other main driver of oil demand is the petrochemicals industry, although here, too, growth is likely to continue to wane. The trend is most marked in OECD countries. In its World Oil Outlook 2010, published in September 2010, Opec reported that, in the 10 years between 1987 and 1997, oil use in the petrochemicals sector grew by 70%, 19% and 120% in North America, Western Europe and the Pacific members of the OECD respectively. However, in the following 10 years, the increase was only 6%, 5% and 18% respectively.
The petrochemicals sector remains highly susceptible to short-term economic changes, especially in OECD countries, where production and demand variations are closely linked to GDP fluctuations. Such a close correlation means the global recession hit oil demand in the petrochemicals sector severely.
Meanwhile, the longer-term slowing of demand growth in industrialised nations is being accompanied by a gradual shift in global petrochemicals production to Opec member states and emerging Asian markets, such as China and India. For example, Saudi Aramco, Saudi Arabia’s national oil company, is set to make final investment decisions on some $45 billion to $50 billion of refining and petrochemicals projects this year, as the kingdom bolsters downstream development to obtain more value from its hydrocarbons reserves.
Rising feedstock costs will help dampen demand everywhere. The price of naphtha – the main petrochemicals feedstock in Europe and Asia – averaged about $710 a tonne in 2010, compared with $525/t in 2009. That upward trend continued in early 2011, with naphtha passing $1,000/t in April. While large-scale producers have, so far, been able to pass much of the rise on to their customers, they have been warning that such a high naphtha price is unlikely to be sustainable.
In the US and the Middle East, the benefits of increased use of ethane feedstock, derived from cheap domestic natural gas, rather than relying on oil are clear. Against a backdrop of falling gas prices, production of ethane feedstock in the US has increased by 25% over the past five years, according to ExxonMobil Chemical. That situation led to rising US petrochemicals exports and increased investment in the country’s ethane-cracking capacity in 2010.
The rapid development of petrochemicals capacity in non-OECD countries will lead to an increase in trade between these new producers and industrialised nations. The IEA sees new capacity in Asia and the Middle East, run on cheap ethane and liquefied petroleum gas, putting older naphtha-based capacity in OECD countries under intense competitive pressure. In its MTOGM11, the agency forecasts demand for petrochemicals feedstock rising by 1.7 million b/d between 2010 and 2016.
Eking out fresh supply
Oil supply is set to be heavily influenced by the same factors that have been in play recently, namely: high prices; the increasing cost of production; and – when demand is high – labour and equipment bottlenecks. The use of enhanced oil-recovery (EOR) to increase production from mature fields will be heavily dependent on a high oil price – unless there are subsidies or a tougher regulatory environment.
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Much of the oil is also likely to come from Opec members in the Middle East although, around the peripheries of the sector, unconventional oil and reserves from frontier offshore zones will play an increasingly significant role (see Figure 3).
With oil prices unlikely to collapse in the present economic climate and with demand holding up, the overall outlook for production looks positive for the next few years. The IEA said in June 2011 that there were even more reasons to be bullish about sustained output growth than there were just a year earlier. “With the cost of developing the marginal non-Opec barrel, be it in Brazil’s deep water or Canada’s oil sands, estimated in the $40-100/b range, and with most oil companies testing project profitability at prices significantly below $100/b, the view on upstream economics looks favourable, suggesting most upstream projects will go ahead.”
In North America, the industry has had to reassess its outlook to account for projects delays in the Gulf of Mexico in the wake of April 2010’s Deepwater Horizon disaster and the pick-up in prospects for the development of shale oil to accompany production from Canada’s oil sands. The IEA predicts delays to US Gulf of Mexico projects could cost around 300,000 b/d in production by 2015, but says this will be more than offset by an improved outlook for unconventional oil output in the US.
The US Energy Information Administration (EIA) concurs on the prospects for shale oil. “Advances in horizontal drilling and hydraulic-fracturing techniques continue to enhance the development of shale-oil formations. Improvements in drilling equipment and monitoring instrumentation are among the advances that have contributed to the slowdown, and subsequent reversal, in the decline in US domestic oil production,” the EIA says in its Annual Energy Outlook 2011. US oil production averaged 5.51 million b/d in 2010, compared with 5.36 million b/d a year earlier and 4.95 million b/d in 2008, when the economic downturn was biting hardest.
But, as with unconventional and other hard-to-access oil reserves around the world, the extent to which US shale oil is exploited will be determined by oil prices. The EIA notes that its prediction for production from oil shale in 2035 is nearly three times higher in its high oil-price case, which assumes crude at $200/b, than in its business-as-usual case, which assumes prices at $125/b in 2035. Offshore drilling would also be significantly higher – up 26% from today – in the high oil price case.
Opec, meanwhile, forecasts that, under its reference case, the cartel would increase its own crude supply only modestly by 2030. But it is keen to stress that this slow growth would be the result of increased production from non-Opec countries and an upswing in non-crude liquids supply, such as natural gas liquids (NGLs), rather than any resource constraint within Opec.
Oil prices in 20 years: who knows?
ALL SUPPLY and demand forecasts depend on predicting the future price of oil – no easy task given the vacillations of recent times.
Uncertainty is reflected in the widely differing oil price predictions offered by market forecasters. For example, the IEA uses an average oil price of $103/b as the basis for its 2011 five-year outlook, but that is more than $15/b higher than the figure it was using a year earlier. And when forecasters assess the market in 20 or 25 years’ time, they provide widely differing outlooks based on oil prices ranging from less than $100/b up to $200/b and beyond.
In the shorter-term, while there has been much talk about the increasing influence of speculators in determining the direction of crude prices, producers, especially Opec countries, still have considerable power over the market. As ever, the cartel has some difficult judgements to make on balancing oil supply and prices, as it needs to walk the fine line between maximising its revenues, while retaining its customers – an increasingly tricky task as more non-Opec supply hits the market.
Abdalla El-Badri, Opec’s secretary-general told Petroleum Economist in June 2011, following an acrimonious Opec meeting, that oil at $100/b would be no threat to the world economy. He said that represented a reasonable price, which could support heavy spending by Opec to increase production capacity over the next four years. At the time, North Sea Brent crude was hovering in the $110-$115/b range.
Achieving a consensus within Opec is becoming increasingly difficult, bringing extra uncertainty to the oil market. In May 2011, Prince Alwaleed bin Talal, a nephew of the king of Saudi Arabia, said that a price of $70-80/b would be appropriate. “We don’t want the West to go find alternatives to oil,” he said. El-Badri said he thought that this was unlikely, given energy consumption was set to grow by 40-45% in the next two decades, allowing room for all energy sources.
Others within the cartel, such as Iran, Algeria, Angola, Venezuela and Ecuador, are concerned that global oil-demand recovery remains fragile, and that Opec output should be constrained to prevent a price collapse.
Of course, Opec is not going to be the only producer in town – far from it, as non-Opec supply of both conventional and unconventional oil increases. And it is far from certain how oil demand will develop in the coming years, given variables ranging from increased biofuels use and the development of electric vehicles to the greater use of gas-based products as oil substitutes. |
GTL: oil of the future?
THE PRICE disparity between expensive oil and relatively cheap natural gas raises the prospect of a further layer of complexity for both markets, in the shape of a burgeoning gas-to-liquids (GTL) sector.
Developed for commercial use mainly by South Africa’s Sasol and Shell some decades ago, the process of converting gas into synthetic transport fuels, and for other uses, has had limited commercial potential in the intervening time, as oil has been too plentiful and gas generally too expensive to make it worthwhile economically.
Now the technology is coming into its own. In 2011, Shell began shipments from its Pearl GTL project in Qatar, where copious cheap gas reserves means it makes financial sense. The project is able to produce 140,000 b/d of fuel and 120,000 b/d of ethane and condensate, dwarfing Sasol’s existing 32,400 b/d Qatari GTL project, Oryx.
Despite the huge outlay – Pearl cost around $19 billion – the rewards are significant. The fuels produced are very high quality and sell for a premium into global markets, while the maintenance costs of GTL plants once built are relatively low. Shell estimates its operating costs at Pearl will be around $6/b.
Both Shell and Sasol are building and planning further projects and have a keen eye on anywhere with large, low-cost gas reserves and, if possible, high local oil demand, to make the economics stack up. China could fit the bill if it develops its shale-gas resources, while North America already does, given its huge unconventional gas reserves. Sasol is looking into developing a GTL project in conjunction with Talisman Energy in Canada. |