FOCUS

China competes for crude supplies

China’s oil demand is exerting a major influence on the world’s oil markets. The enormous growth in demand there is drawing crude oil from the Atlantic Basin to Asia, causing supplies to tighten in the west and adding to the upward pressure on the price of the Atlantic’s main reference crudes, Brent/BFO and West Texas Intermediate (see ‘Oil Price Review’). The main reason for China’s interest in Atlantic Basin crudes is its growing need for light, sweet crudes, which are needed to make light, low sulphur refined products.

Chinese demand for light, sweet crudes is likely to grow strongly as China introduces new, lower limits for sulphur in refined products. Such crudes will have to be imported, since China’s own production is principally of heavy crudes. A growing dependence on long-haul suppliers for crude is not entirely a welcome prospect as far as the Chinese are concerned since, in the longer term, they are likely to find themselves in competition for such crudes with Europe and the United States. The government is therefore trying to reduce the role of oil in the country’s energy balance in favour of natural gas, though this policy may not have very much impact in the near future.

Rising demand

The Chinese oil market is growing faster than any other major market in the world. Chinese statistics suggest that demand has risen by nearly 1.0 mn bpd to 6.5 mn bpd (see Table A). A combination of strong economic growth and artificially low government-set product prices has caused oil demand to rise by nearly 18% so far this year. The fastest growth has been in middle distillate. Gasoline consumption has gone up sharply as well. All of this has forced the Chinese to increase their imports of crudes with high yields of light products. In addition, recent changes in some product specifications have obliged them to import more low sulphur crude blends. Hence the rise in imports from the Atlantic Basin: principally from Africa.

Sudan is an important source of African crude, since it is there that China has its principal source of foreign equity crude. China’s main West African source of light, sweet crude is Nigeria. The country’s main refiner, Sinopec has term contracts for up to 100,000 bpd of Nigerian crude this year. Further volumes are brought on the spot market. The Chinese also obtain sweet crude from Angola, Equatorial Guinea and Gabon, though crudes from these countries are generally heavier than the gasoline-rich crudes produced in Nigeria.

Table A
China: Oil balance first half 2003 v first half 2004

	1H03	1H04	Change
	(mn bpd)
Demand	5.55	6.50	0.95
Production	3.50	3.50	unch
Net Trade
Crude Oil	1.55	2.30	0.75
Refined Products	0.50	0.70	0.20
Total	2.05	3.00	0.95

Source: OET estimate

Chinese demand for West African crudes has risen rapidly. In 2002, it was around 0.2 mn bpd. Last year West African imports had risen to just over 0.4 mn bpd. So far this year, they appear to be running close to 0.7 mn bpd, making up almost 30% of the country’s total net imports of crude oil (see Table A). China is Asia’s largest importer of West African crudes, accounting for over a third of Asia’s total crude oil imports from there.

China also takes additional, smaller quantities of crude from North Africa. Earlier in the year, the government signed a contract for deliveries from Algeria. Peking has also expressed interest in further deals with Libya and Egypt. As an indication of its interest in African crudes in general, the government has send a number of high level delegations to Africa this year for talks on oil imports, including three – to Algeria, Gabon and Egypt – led by the prime minister, Hu Jintao.

Reducing sulphur limits

African crudes generally have high straight-run yields of naphtha, which can be reformed into gasoline, and middle distillate. As such, they are preferable to many Asian crudes, which have high yields of atmospheric residue, from which heavy fuel oil is ultimately derived. Several crudes from the Middle East also have good yields of white products, but they tend to be higher in sulphur than African crudes, and this is becoming an increasing problem as China attempts to reduce the sulphur content of its principal refined products.

China has a sulphur limit of 800 parts per million (ppm) for gasoline and 2,000 ppm for diesel: both quite high by western standards (see ‘Looking Ahead’, September 2004). From October 2004, the municipality of Peking has introduced new limits of 500 ppm for both fuels. From July next year, the 500 ppm limit is supposed to apply to gasoline across the rest of China.

Chinese refineries are mainly configured to run on domestic crudes like Daqing, which are low in sulphur. The country has less than 0.8 mn bpd of middle distillate desulphurization capacity, compared with about 5.8 mn bpd of crude distillation capacity. There is a further 0.3 mn bpd of hydrocracking capacity which can also be used to produce low sulphur middle distillate from sour crudes, along with various other units capable of handling such crudes.

The net effect of these units is that China can probably process a maximum of around 1.0-1.1 mn bpd of sour crudes, which is about the current level of such imports. Any increase in crude oil imports will therefore have to be made up almost entirely of sweet crudes; and these are likely to be sourced principally from Africa.

More product imports?

Competition for light, sweet crudes has pushed up their prices in relation to light and medium sour grades. The difference between Brent/BFO and the benchmark Middle Eastern crude, Dubai, has widened from around $1.00 a barrel in late 2003 to more then $9.60 at the end of September 2004. Faced with such price distortions, the Chinese may have to restrict their purchases of light, sweet crudes and import more refined products instead.

Another factor may also force China to increase product imports: namely a shortage of crude distillation capacity. Chinese refineries are running close to their limits. Throughputs are close to 95% of nameplate capacity. Moreover, some of that capacity is too small, too old or too remote to be economic, given China’s state-controlled refined product prices. There are plans for a further 0.3 mn bpd of new distillation capacity at Dalian, Dongxing and Jinshan in 2005, but this is less than half the expected increase in demand.

Product imports therefore look set to rise faster than those of crude oil. The government appears to expect this and is encouraging its state oil companies to obtain shareholdings in overseas refineries as the basis for setting up long term product supply agreements with China. Earlier this year, state oil trader Sinochem bought the 275,000 bpd Inchon refinery in South Korea. More recently, another state trader, China Aviation Oil (CAO) took 20.6% stake in the Singapore Petroleum Company (SPC), which owns half of the Singapore Refining Company’s 275,000 bpd Pulau Merlimau refinery. CAO is China’s main consumer of jet fuel, of which the country has a deficit. South Korea and Singapore are appropriate choices for Chinese companies since these are China’s two principal sources of refined product imports.

The size of CAO’s shareholding in SPC means that it will probably not play a very active part in the operational aspects of the Singapore refinery, unlike Sinochem, which intends to use its South Korean plant mainly to supply the Chinese market. Other refinery deals are more than likely, though these may not necessarily involve direct investment. Chinese companies may sign processing deals with foreign refiners under which they provide crude oil in return for refined products for an agreed fee.

Finding more crude

China’s preference is nevertheless to import crude oil rather than products, on grounds of energy security. The government believes that running crude in its own refinery system is better than relying on foreign refiners, especially in an era of increasing competition for scarce supplies. By the same token, it is anxious to control as much of its crude oil supply as possible, including crude oil produced overseas. To this end, the government has directed its state oil companies to invest in oil and gas production overseas.

The principal effort has been undertaken by PetroChina, which owns producing assets in several countries, notably Sudan, where it has 40% of the Greater Nile Petroleum Consortium and Kazakhstan, where it owns 100% of Aktobekaimunaigaz (see Table B). PetroChina’s overseas production amounted to 540,000 bpd in 2003. Its aim is to raise this to 750,000 bpd by 2005. Much of any increase is likely to come from Sudan.

Table B
PetroChina: Principal foreign upstream assets

Country	Field
Production
Azerbaijan	Gobustan
	Kurasangi-Karabagli
Kazakhstan	Aktobemunaigaz
	North Buzachi
Peru	Pluspetrol Norte
Sudan	Blocks 3, 6 and 7
Exploration
Algeria	Adrar
Ecuador	Block 11
Venezuela	Caracoles-Intercampo

Source: PetroChina; MEES

PetroChina has recently been followed into foreign upstream ventures by the country’s other main vertically-integrated state oil giant, Sinopec. At present, Sinopec has no overseas production, but aims to have 80,000 bpd by next year. Its main assets are in Iran, but it also has exploration acreage in Azerbaijan, Indonesia, Kazakhstan and Yemen, plus a technical cooperation deal at Algeria’s Zarzaitine field. This year, it outbid PetroChina for an upstream gas tender in Saudi Arabia. Two other state companies have foreign upstream assets. Sinochem has shareholdings in producing blocks in Ecuador and Tunisia, whilst China National Offshore Oil Corporation (CNOOC) has stakes in gas fields in Australia and Indonesia.

Compared with China’s likely crude oil import requirements, the state companies’ overseas production is not very significant. The government is seeking yet more foreign acreage, especially in Africa, but further deals may take some time. PetroChina nevertheless maintains that it wants its foreign assets to account for half if oil and gas production by 2020.

This is an ambitious target for what is basically a domestic Chinese oil company. Sinopec, too, is likely to try and raise its presence abroad substantially over the next decade or so. All this is in line with Peking’s policy of having as much of China’s oil requirements as possible under Chinese control. This is seen as the most effective way to guarantee Chinese energy security in an era of scarce resources and increasing competition for oil supplies. As such, it harks back to earlier Chinese policies of being self-sufficient in oil and other major resources (see ‘Focus’, February, 2004). Such a policy is likely to prove expensive. In its anxiety to become vertically-integrated overseas, Sinopec has already overpaid for foreign assets. A similar policy pursued by Japan following the oil price shocks of the 1970s absorbed huge sums of money in return for very little result in terms of improving energy security. Chinese investment would almost certainly be better devoted so expanding and upgrading the country’s refinery system, since it is a shortage of refined products rather than crude oil that has affected China this year.

Improving energy security

China’s best hope for improving its energy security, however, lies in reigning-in the rapid rise in oil consumption that is taking place at present (see Table A). Much of the country’s economic effort has been devoted to expanding the manufacturing sector, with comparatively little effort being devoted to energy conservation. This year, Chinese oil consumption has been rising at about double the rate of the country’s economic growth. There is thus considerable scope for improving energy efficiency.

Alongside conservation, China should also substitute as much oil use as possible with other energy sources. The government recognizes this and has begun a programme to increase the use of natural gas. Chinese gas consumption in 2003 amounted to 3.2 bn cfd. Government policy is for this to rise to around 19.5 bn cfd in 2020. For this to happen, however, China will need to construct a massive new infrastructure to handle the gas. At present, the country has no unified transmission system: just a series of isolated onshore and offshore grids connecting the main areas of production to nearby cities plus a slightly more extensive system linking Peking with fields to the south-west of the capital.

The government has announced ambitious plans to build a 1.2 bn cfd pipeline across the country from the Tarim Basin in western China to Shanghai, with a further line branching off to serve the Peking region. The western end was completed in January this year. The remaining part of the line was due to receive its first gas in September. There are plans to raise the capacity of the system to 1.8 bn cfd eventually.

The line is one of several proposed across China. Others include pipelines linking China with Central Asia and Russia. In addition, there are proposals for at least seven liquefied natural gas (LNG) receiving terminals on the eastern seaboard. Among those proposed is a 400 mn cfd terminal being developed by CNOOC in Canton province, which is due to open in 2006 and a 365 mn cfd terminal, in Fujian, which is also being developed by CNOOC and is due to open in 2007. A further regasification terminal is planned in Shandong, and is meant to be open in time for the 2008 Olympic Games. A year later, CNOOC plans a terminal in Zhejiang. Further schemes are slated for Shanghai, Dalian and Tianjin.

Table C
China: Energy balance, 2003

Source	Consumption
	(mn toe)	(%)
Oil	914.3	39.8
Gas	566.8	24.7
Coal	573.9	25.0
Nuclear	181.9	7.9
Hydro-electricity	60.9	2.7
Total	2,297.8	100.0

NB: Percentage totals rounded

Source: BP Statistical Review of World Energy, 2004

All of these schemes require a customer-base which, in turn, presupposes the construction of gas grids serving the various terminals. While progress is being made on both these fronts, some of the schemes may not be developed within their planned timeframes. Moreover, some terminals may be too close to other, competing schemes to allow all of them to be built. CNOOC’s proposed terminal at Tianjin, for example, is close to other schemes in Shandong and Dalian.

In these circumstances China may well fail to meet its target for a six-fold increase in gas consumption by 2020. Furthermore, gas substitution may equally occur for coal as for oil, given the government’s aim to clean up the air in China’s industrial cities. Oil looks like retaining its dominance in China’s energy balance (see Table C) for the foreseeable future, ensuring that energy security continues to worry the authorities in Peking.

THE MONTH IN BRIEF

This section summarizes downstream developments of the previous month. Exploration & Production are covered in ‘Upstream Review’.

Fifty dollar oil, Nigerian rascals and bad news all round

Oil prices finally broke through the $50 barrier. Malaysia’s Tapis breached that psychologically important level in late September to be followed shortly afterwards by WTI, which rose to $50.50 a barrel on 28 September. IPE Brent achieved a record high of $46.80 on the same day. Prices climbed steadily through the month (see ‘Oil Price Review’) on what seemed to be a near-inexhaustible supply of bad news. Hurricanes disrupted oil production, transport and refining in the US Gulf. Iraq remained in chaos as another important psychological barrier was breached: the death of the thousandth member of the US armed services (Iraqi civilian deaths are estimated at more than ten times this number). Iraq’s exports to Ceyhan in Turkey were disrupted once more by attacks on the pipeline. In Nigeria, meanwhile, militia groups attacked government forces in the oil-producing Niger Delta region and warned foreigners to leave. Shell cut its output and evacuated some staff. Several Nigerians were reported killed in Port Harcourt. The rebels want greater local control of the oil industry. The government dismisses the militia groups as “rascally elements” and “smugglers”. The Delta region produces about 2.5 mn bpd. In a separate dispute, trades unions are threatening strikes in the oil industry over a 25% hike in domestic gasoline prices.

More bad news came from Russia as Yukos cut its oil exports to China by 60% and threatened to stop them altogether in October as its dispute with the authorities in Moscow rumbled on (see ‘Looking Ahead’, August 2004). Russian crude exports by pipeline fell in August to their lowest level since February. Elsewhere in Russia, President Putin approved plans to merge the state oil company Rosneft with the gas monopoly Gazprom (see ‘Looking Ahead’). All the talk of supply shortages has led Taiwan to raise its strategic stockpiles of crude oil by 85% to 10.4 mn bbl. The US government released some of its own strategic stockpile to three refiners whose crude supplies were interrupted by Hurricane Ivan. Previously, US Vice-President Dick Cheney had said that the Strategic Petroleum Reserve (SPR) would only be used if the US lost supplies of over 5 mn bpd. The refiners will have to return an equivalent volume of crude to the amount supplied to the SPR.

ExxonMobil and Saudi Aramco are to help fund the expansion of the 80,000 bpd Fujian refinery in China to 240,000 bpd. The scheme will provide the Chinese refinery sector with much-needed upgrading capacity (see ‘Focus’) and allow China to run more sour crude. ExxonMobil and Saudi Aramco have also joined state refiner Sinopec to propose the establishment of a retailing and distribution network in Fujian province. Shell is to conduct road trials of its gas-to-liquids (GTL) diesel fuel in Shanghai. Similar trials of its GTL fuel are under way in London, Berlin, Tokyo and Los Angeles. BP has sold its LPG business in the Czech Republic to Flaga Plyn. Romania has awarded 30% shares in gas distributors Distrigaz Nord and Sud to Ruhrgas and Gaz de France, respectively. Each company will ultimately take a 51% shareholding. The EU has approved the sale of Shell’s Portuguese retail network to Spain’s Repsol.

London’s International Petroleum Exchange (IPE) is to replace its open-outcry morning sessions with screen trading in what looks like a halfway-house to full electronic trading. The New York Mercantile Exchange (Nymex) is discussing the opening of an energy futures exchange in Singapore. China’s new fuel oil futures contract, launched in August (see ‘The Month in Brief’, September 2004) is struggling to attract participants, threatening plans for further oil futures contracts in China. A major new gas pipeline has come a step nearer to operation with the filling of the line by PetroChina. The West-East line will connect western China with Shanghai. LNG exports from Peru have moved a step nearer to realisation with the award of exploration licences to the companies proposing to build the export terminal (see ‘Gas and Power’, September 2002). Chile is reported to be planning an LNG import terminal following problems importing gas from Argentina (see ‘Gas and Power’, May 2004).

GAS AND POWER

Germany struggles to curb price rises

Gas and power suppliers in Germany are under fire from the government, industry associations and consumers following the announcement of price rises of up to 20%. The government has expressed particular concern that high gas and power prices, coming on top of record oil prices, pose a major threat to Germany’s already weak economic growth.

Most attention is at present focused on the country’s largest electricity suppliers. Four companies–Eon, RWE, Vattenfall and EnBW–dominate the domestic market. Before Germany’s gas and power markets were deregulated, the supply industry consisted of a much larger number of separate gas and electricity companies, along with many local suppliers and distributors. A series of mergers and takeovers has led to the formation of a small number of integrated utilities supplying a range of utilities. Eon, for example, as well as supplying electricity, owns 100% of the gas producer Ruhrgas as well as 39% of the coal company, RAG, formerly known as Ruhrkohle. Critics charge that the gas and power industries are now too concentrated to be fully competitive.

Householders are particularly badly off in terms of energy prices. A German household using 3,500 kWh of electricity per year pays approximately $760: the highest annual rate in the EU. At the other end of the scale, households in Finland pay only $455 annually. Industrial consumers are not much better off, either, having the second-highest rates in the EU after Italy. Deregulation was supposed to bring prices down. After five years of market liberalization, German electricity prices are 8% above their 1999 levels, and set to go even higher.

Deregulating the wrong way?

Some argue that the rise in electricity prices means that deregulation itself was a bad idea, and there has been some resistance in other parts of the EU to market deregulation (see ‘Gas and Power’, July 2004). The main problem, however, seems to be the way in which the German market was liberalized after 1999.

Prices did indeed fall following deregulation, but then began to rise again. At the same time, the electricity industry began to consolidate into a small number of large groups, which some see as a powerful oligopoly able to force prices higher. The situation, however, is more complex.

Whilst the large electricity companies undoubtedly did try to raise their prices, consumers showed remarkably little inclination to switch to suppliers offering lower priced power. Fewer than 5% of households, for example, bothered to change suppliers. Industrial users showed a good deal more interest in switching suppliers immediately following deregulation in 1999, achieving tariff cuts of up to 50% in some cases. Since then, though, they appear to have become less successful in playing-off suppliers against one another, and prices have risen once more.

A further factor has been the rise in energy taxes. In April 200, for example, the Renewable Energy Law required utilities to purchase electricity from renewable sources at a premium rate, designed to encourage the building of more renewable generating capacity. Under the Law, the utilities were allowed to pass on these extra costs to their customers.

No regulator

The main problem with deregulation, however, has been the lack of a regulator. Elsewhere in the EU, governments have established new official agencies to oversee the liberalization of electricity and gas markets and to investigate abuses Germany has relied instead on existing institutions, such as the Federal Cartel Office, which has had insufficient powers to deal with certain aspects of the gas and power markets.

The Cartel Office is nevertheless probing the prices charged by the major electricity companies for third party access (TPA) to their transmission systems. Consumer groups, however, say that the Cartel Office’s efforts are too little and come too late to be of much assistance in dealing with the present high level of prices.

The government has reacted to such criticisms by announcing the establishment of a regulator from next year. Gas and electricity markets will come under the existing regulatory authority covering the post and telecommunications industries (RegTP). Even this move, however, has its critics. Many consumer groups point out that the energy regulator was supposed to be in place by the middle of this year. Others claim that the regulator does not have sufficient powers to stop price rises.

RegTP will be able to investigate tariff agreements covering TPA and to order, if necessary, such access tariffs to be cut. The German state government, along with the main groups representing gas and electricity consumers, want the regulator to investigate and approve TPA tariffs before they come into effect. Arguments over this issue may well delay the establishment of the new energy regulatory system.

The regulatory system as at present proposed may not suit the gas and electricity companies, either. The prospect of having tariff agreements altered retroactively is likely to create uncertainty over business decisions, including investment in new transmission capacity. RegTP wants to see more imports of electricity as a way of bringing down prices in the domestic market. Germany imports from low cost producers such as France and the Czech Republic. Without greater certainty on revenues from TPA, some utilities may be less keen in future to increase transmission capacity to enable more power to be imported.

LOOKING AHEAD

Putin strengthens control over the energy sector

A proposal; by the Russian government to make it easier for foreigners to invest in the gas monopoly Gazprom disguises a separate move by Russia’s President, Vladimir Putin, to tighten the state’s control over the oil and gas industries. As well as easing restrictions on foreign ownership of Gazprom’s shares, Mr Putin has merged the company with the state-owned oil producer, Rosneft. In return for the acquisition of Rosneft, Gazprom will give the government some of its shares to add to its existing shareholding, giving the government, in effect, control of the gas giant.

Putin takes control

In the aftermath of a series of terrorist attacks in Russia that killed an estimated 430 people, culminating in an attack on a school in Beslan in the Trans-Caucasus, President Putin announced a series of measures designed to increase the government’s control over many aspects of Russia’s political life. Strong central control was presented as necessary in order to bring terrorism under control. In particular, Mr Putin proposed to abolish elections for regional governorships, replacing them with a system under which governors would be appointed by the Russian President.

The oil and gas industries were not to be immune from this centralization of power into the hands of the government. For some time, Mr Putin has seen regional governments as using their local resources to make themselves increasingly independent of Moscow. Such developments have been most pronounced in regions containing large deposits of oil and gas or, occasionally, in areas lying across important pipeline routes, as is the case in Chechnya.

Some governors in particular have used levies on the oil and gas industries to enrich themselves, while others have awarded upstream permits to themselves, their agents or their supporters. In the past, governments have tended to ignore such practices, as long as the country’s new oil barons contented themselves with their riches and refrained from interfering in national politics. Another route to personal riches were the various privatizations of state assets that took place in the 1990s, making the new company owners millionaires several times over. Again, the unwritten agreement was that such people stayed out of national politics.

Mr Putin had already begun top bring the oil industry back under government control with the prosecution of the oil company Yukos and its founder Mikhail Khodorkovsky (see ‘Looking Ahead’, August 2004). State prosecutors have demanded the payment of some $3.4 bn in alleged unpaid taxes covering one year alone amid threats to break up the company if it cannot meet its obligations. The company has retaliated by threatening to suspend oil exports (see ‘The Month in Brief’). The Ministry of Natural Resources has meanwhile threatened to revoke Yukos’ operating licence for its most important production operation, Yuganskneftegaz.

Changes at Gazprom

Since Beslan, President Putin has sought to extend his control over the energy sector and, in a highly significant move, has restructured the gas monopoly Gazprom so as to give the government control of the company. In return for acquiring the state-owned oil producer Rosneft, Gazprom will give the government some of its stock so as to raise the state’s shareholding above 50%.

In order to stave-off possible foreign criticism of the deal, the government is also proposing to make it easier for foreigners to own shares in the new, expanded Gazprom. At present, foreign investors can only own Gazprom shares directly by buying American Depository Receipts (ADRs). The number of these is restricted to just over 4% of the company’s equity and ADRs trade at a premium to the normal shares. Some foreign investors have found a way round the system by buying through Russian nominees, but this can be a risky procedure.

Mr Putin has been anxious not to alienate foreign investors since Russia requires huge investment in its oil and gas industry. On the other hand, now he effectively controls the new oil and gas giant of Gazprom, he may feel that Russia can do much more by itself than before, especially now that oil and gas prices are so high. An early indication of whether he intends to remain friendly to foreign investors may come from negotiations currently under way between BP and Gazprom over the Kovykta gas field in Eastern Siberia.

Gazprom has been in talks with BP’s Russian joint-venture TNK-BP over the possible purchase of a stake in TNK-BP’s Kovykta field. It could now turn its attention to projects on Sakhalin Island where it has acquired interests that once belonged to Rosneft: in which case Kovykta could be seen as a rival project, since both developments are designed to export gas to East Asia. In either case, Gazprom has considerable negotiating clout since any gas exported from Kovykta would have to be transported by Gazprom’s pipeline network. The government is already taking a close interest in the situation and the Ministry of Natural Resources has put additional pressure on BP by hinting that it might revoke the company’s licence to develop Kovykta if it fails to play ball with Gazprom.

Mr Putin’s policy appears to be to tighten his control on the oil and gas industries and, more particularly, the revenues they earn. These are vital if he is to retain his strong hold on power. Further controls on the oil and gas industry appear inevitable.

OIL PRICE REVIEW

Third Quarter 2004

Dated Brent crude 25 June close $34.29 per barrel

26 June–2 July Friday close: $35.18

Increasing supplies of crude oil from OPEC failed to prevent a rise in prices. Markets focused instead on a shortage of refined products, particularly middle distillate, in many areas. In the US, refiners were trying to maximize their production of gasoline in order to ensure adequate supplies for the remainder of the summer driving season, thereby diminishing their output of diesel and kerosine. Strong demand for diesel pushed up middle distillate prices in Europe, as did rumours that Russian gasoil exports might soon be curtailed as a result of a dispute between the government and the country’s largest oil company, Yukos, over unpaid taxes (see ‘Looking Ahead’, August 2004). Asian prices of kerosine rose sharply on reports that Japanese stocks were down by 30% compared with a year earlier.

3–9 July Friday close: $37.59

Refined products rather than crude continued to drive oil markets. Most attention was on the low level of product inventories in the main consuming areas. US product stocks amounted to just 32 days’ forward cover: the lowest ever recorded for the time of year. European gasoline stocks were down following a surge in exports to the booming US market. Asian gasoil prices rose as India diverted supplies from the export market to meet rapidly growing domestic demand. High electricity demand in the US boosted prices for low sulphur fuel oil. There was far less interest in high sulphur grades, however, and stocks in Singapore were reported at a nine-year high.

10–16 July Friday close: $38.93

Demand for crude oil picked up as refiners tried to replenish low refined product stocks. This, in turn, led to a sharp rise in prices for prompt crude. Asian refiners sought crudes with high middle distillate yields, pushing up prices of Malaysia’s benchmark Tapis grade. Several Asian buyers switched to cheaper long-haul crudes, such as Algeria’s Saharan Blend and Es Sider from Libya. European gasoline prices set new price records at $482 per tonne following a fire at the Mongstad refinery in Norway. US product prices were generally weaker on higher than expected refinery avails and a rise in imports of diesel form the Caribbean and Asia. Asia’s gasoil prices remained strong on good buying across the region. Low sulphur waxy residue was also in high demand following the shutdown of two nuclear power stations in Japan.

17–23 July Friday close: $39.50

OPEC cancelled a meeting scheduled for 21 July, stating there was “nothing more….to do”. Demand for prompt crude remained high as refiners continued to run close to maximum levels. European refiners scrambled to buy the remaining prompt North Sea barrels in advance of August’s planned maintenance shutdowns. Light sweet crudes were in particular demand in Europe and the US to meet high demand for gasoline. Asian refiners sought light crudes from Africa to help meet rising demand for kerosine. South Korea’s first-ever refinery strike boosted prices for most products across Asia. Hot weather in Japan lifted demand from utilities for low sulphur waxy residue. European gasoline prices fell back from their high levels of the previous week and US demand also eased, causing gasoline prices to fall.

24–30 July Friday close: $41.72

Prices rose sharply on fears of an interruption to oil exports from Russia, as the dispute between the government and Yukos deepened. WTI hit a record $43.05 a barrel on 29 July. IPE August gasoil had been at record levels the previous day, at $368.25 a tonne. North Sea crude prises rose above $40.00 as field maintenance cut supplies. European diesel went up sharply in line with IPE levels as buyers worried about a possible interruption to Russian gasoil exports. Middle distillate was strong in the US on tight supplies. As refiners cut naphtha production to make more jet fuel, naphtha prices also firmed, as did those of gasoline.

31 July–6 August Friday close: $43.00

OPEC’s new production quotas came into effect on 1 Aug, raising the output ceiling by 0.5 mn bpd to 26.0 mn bpd. Most of the extra demand for crude, however, was for light, sweet grades and not for the heavier and more sour blends available from the Persian Gulf. WTI rose by nearly $2.00 on 5 August to a record $44.50 a barrel. Earlier the same day, September IPE Brent went up by a similar amount to an all-time high of $41.30. Prompt Brent prices went even higher as supplies remained tight as a result of North Sea maintenance shutdowns. Sweet African crudes were in heavy demand in Asia as refiners sought to build stocks of middle distillate in advance of winter. Sweet Asian crudes were also sought after as refiners tried to meet high demand for low sulphur waxy residue from electricity utilities in Japan and South Korea, where hot weather boosted demand for air-conditioning.

7–13 August Friday close: $44.84

More price records tumbled as fresh supply worries emerged. In addition to the ever-present threat of a loss of Russian exports, there were further concerns about supplies from Iraq and Venezuela. A tropical storm briefly halted production at some refineries in the Gulf of Mexico, helping to strengthen product prices in the US. WTI set a new record of $45.75 a barrel on 12 August during heavy fighting at Najaf in Iraq. IPE Brent reached a record $42.56. Naphtha demand in Asia boosted prices of naphtha-rich crudes such as Saharan Blend. Falling freight rates further encouraged Asian buying of African crudes. Heavy, sweet Asian crudes were in high demand to meet requests for increased supplies of low sulphur waxy residue from power companies in Japan. Refiners in most markets focused mainly on building up stocks of middle distillate.

14–20 August Friday close: $45.32

Middle distillate continued as the main preoccupation of refiners. European gasoil rose above $400 a tonne for the first time. In the US middle distillate prices were led upwards by jet fuel. Jet also led gains in Asia, though naphtha and low sulphur waxy residue were also strong. Heavy fuel oil, however, generally failed to participate in the product market’s strength. The growing export of heavy, sour crudes from the Persian Gulf helped to keep supplies of high sulphur fuel oil plentiful against generally weak demand, as did the level of exports from Russia. WTI breached the $49.00 level, whilst IPE Brent touched $44.45 a barrel on 19 August following an attack on oil facilities in southern Iraq.

21–27 August Friday close: $39.88

Crude oil prices fell sharply as fears of supply interruptions eased. Iraq announced the resumption of c rude exports via its much-bombed export pipeline to Turkey and Yukos’ travails temporarily fell out of the headlines. Sour crudes fell the most. Iraq’s Kirkuk blend was down by $6.60 on the week as high sulphur fuel oil prices plummeted. Some heavy, sour Latin American grades lost even more. Demand for crude oil was constrained in the US and Europe by refinery maintenance closures. Asian refiners continued to seek sweet grades for middle distillate and low sulphur waxy residue.

28 August–3 September Friday close: $40.18

Events in Iraq and Russia once again triggered price movements: this time in an upward direction. An attack on the Turkish pipeline prompted further fears about Iraq, while Yukos warned that its output was threatened by a court ruling of 31 August freezing the bank accounts of its subsidiaries. A further boost to prices came from US inventory figures showing crude stocks at their lowest level for more than five months. Demand was particularly strong for sweet crudes. Heavy Asian buying of West African grades tightened supplies of sweet crudes in other markets. Asian demand for middle distillate helped to push up the price of Tapis. The official selling price for August was a record $46.70 a barrel. Heavy, Middle East sour blends fell in relation to most sweet grades.

4–10 September Friday close: $41.84

Falling US crude stocks and high demand for middle distillate were reflected in higher prices. Gasoline prices by contrast, fell back in Europe and Asia. US Gasoline and other product prices were supported by a fall in imports from the Bahamas, the Caribbean and Venezuela, caused by Hurricanes Frances and Ivan. Hurricane damage also damaged power lines in Florida, cutting utility demand for fuel oil, and disrupted barge traffic along the US Gulf Coast. High middle distillate demand underpinned prices for sweet crudes, which continued to flow east of Suez in large volumes. Low sulphur waxy residue prices weakened in Asia as cooler weather reduced electricity demand.

11–17 September Friday close: $44.46

Light, sweet crude remained in high demand, especially in Asia where imports of West African crudes reached record levels. Abu Dhabi, as one of the few Middle Eastern suppliers of light, sweet grades, also benefited from Asian refiners’ desire to import middle distillate-rich crudes. Saudi Arabia and Iran, by contrast, struggled to sell their heavier grades. Hurricane Ivan continued to disrupt US markets causing nearly 1.5 mn bpd of oil production to be shut-in in the Gulf of Mexico and even more refinery capacity to be closed onshore

18–24 September Friday close: $46.02

US prices rose sharply as offshore production remained down in the aftermath of Hurricane Ivan. US refiners turned to Canada and the North Sea to make up the shortage of sweet crudes. IPE Brent hit a record high of $45.75 a barrel, but WTI remained below record levels. Middle distillate demand was strong, especially in Asia, where it helped Tapis to a new high of $50.00 a barrel. In the US, heating oil futures reached a high of 136.30 cents a gallon on 23 September, while in London on the same day, IPE gasoil hit an all-time high of $426.25 a tonne.