FOCUS
During a year of otherwise sluggish growth in demand, China’s oil consumption grew by 0.5 mn bpd in 2003. This enormous rise — representing year-on-year growth of 10% — accounted for 40% of the entire increase in world demand last year. High oil prices in 2004 are likely to continue to act as a brake on worldwide demand growth. Many exporters will therefore be relying on China to provide another large increase. They may well be disappointed. Chinese demand growth is likely to be slowed down by bottlenecks in the distribution system, and there could even be fuel shortages. These, in turn, could curb China’s impressive economic growth, and energy consumption with it. None of this means that Chinese growth will be insignificant. Moreover, even lower rates of growth in demand will have important implications for world oil markets: not least in terms of competition for oil supplies from the Middle East.
Chinese demand grew by just over 10% during 2003 to reach 5.5 mn bpd, pushing it past Japan to become Asia’s largest oil consumer. Crude-oil imports rose by four times this amount, to nearly 1.8 mn bpd (see Table A), to the particular satisfaction of producers in the Middle East and Africa. Almost as spectacular was the increase in refined product imports: up nearly a third compared with 2002, as China’s refiners struggled to keep up with increases in demand.
|
|
2002 |
2003 |
Change |
|
|
(th bpd) |
||
|
Crude oil |
1,247 |
1,750 |
503 |
|
Products |
|
|
|
|
LPG |
197 |
200 |
3 |
|
Jet |
9 |
15 |
6 |
|
Fuel oil |
281 |
420 |
139 |
|
Other |
48 |
75 |
27 |
|
Total |
535 |
710 |
175 |
Source:
(2002) International Energy Agency;
(2003) Pearl Oil estimate
The rise in oil demand occurred on the back of strong economic growth and the rapid rate of urbanization across China. The Chinese economy grew by an estimated 11% in 2003 and is now the world’s sixth-largest economy, after France. Its manufacturing sector has been boosted considerably by China’s admission to the World Trade Organization (WTO), which occurred in 2001. The growth of manufacturing has resulted in a sharp rise in electricity consumption which last year reached record levels. All this has led to a surge in the import of energy and raw materials to fuel Chinese industrial growth, and Chinese economic growth has been cited as a major factor in both rising oil prices and the increase in maritime freight rates worldwide.
Another important factor in the increase in China’s oil consumption is the country’s strong population growth: more particularly the growth in China’s urban population. As with manufacturing growth, urban growth has been accompanied by a sharp rise in electricity consumption. Urbanization, however, has also led to increases in the use of other fuels, including liquefied petroleum gas (LPG), kerosine and natural gas, as part of a more general trend for urban populations to switch from traditional, mainly biomass sources of energy for heating, lighting, and cooking, to commercial fuels. Urbanization has also been accompanied by a rise in motorcar ownership. boosting the consumption of gasoline. There has also been a steady substitution of coal by LPG and liquid fuels by households and commercial premises in the main urban areas.
Chinese oil consumption has been gradually moving towards the top end of the barrel with increasing use of motor gasoline and middle distillate. Heavy fuel oil (HFO) now accounts for 15% of the demand barrel (see Table B), compared with 25% around a decade ago. Gasoline consumption has started to take off recently following a rapid rise in motorcar ownership. Automobile sales rose by an estimated 70% in 2003, exceeding 1.7 mn.
|
|
(th bpd) |
(%) |
|
Naphtha |
500 |
9 |
|
Gasoline |
900 |
16 |
|
Jet |
120 |
2 |
|
Diesel |
1,700 |
31 |
|
HFO |
800 |
15 |
|
Others |
1,480 |
27 |
|
Total |
5,500 |
100 |
Source: Pearl Oil estimate
The recent steady decline in fuel oil consumption was reversed during 2003. Between 1997 and 2002, HFO use fell by 120,000 bpd, or 16%, but last year saw demand rise by 170,000 bpd, or 27%, to 800,000 bpd, exceeding its previous highest level in 1997 by 50,000 bpd. Part of the reason was undoubtedly the large increase in demand for electricity during 2003, but important quantities of fuel oil were imported as atmospheric residue, for use in refineries as a cracker feedstock to make gasoline and (especially) diesel.
Shortages of diesel were reported throughout 2003 and into 2004 as state-owned refineries failed to keep pace with the growth in demand. At the same time, the state refiners pressed the government to restrict imports of diesel fuel in order to keep domestic prices high. Domestic prices, however, were capped by state-imposed price controls, preventing the state refiners from realizing the full benefit of booming local demand. They therefore decided to take advantage of the high diesel prices in other Asian markets and exported part of their output (see Table C). At the same time, they began to import increasing amounts of atmospheric residue in order to make more diesel.
|
|
2002 |
2003 |
Change |
|
|
(th bpd) |
||
|
Naphtha |
16 |
20 |
4 |
|
Gasoline |
142 |
180 |
38 |
|
Diesel |
16 |
45 |
29 |
|
Total |
174 |
245 |
71 |
Source:
(2002) International Energy Agency;
(2003) Pearl Oil estimate
In a further attempt to maximize prices at home, the state oil companies restricted supplies of crude oil to the country’s small, independent refiners. The latter tend to consist of simple distillation units located in the main consuming areas, such as Guangdong and Shandong, in the south and east of the country. In order to circumvent these controls, many of the independent refiners imported fuel oil, which they then redistilled with crude oil in order to make diesel.
Diesel is the most important product in China, accounting for nearly a third of demand (see Table B). It has widespread traditional uses in agriculture and transport Over the last few years, its consumption has been boosted by the rapid spread of diesel stand-by generators, which businesses and households are buying in order to beat the large number of power cuts.
The three main sectors driving oil demand are transport, power generation, and petrochemicals. Transport is likely to provide the largest component of any demand growth over the next year or two, thanks to the high rate of growth in motor vehicle ownership in China. In recent years, the principal growth in vehicle ownership has come from motorcycles, but last year saw what could be the start of a sharp rise in car sales. Up to now, motorcar use has been restricted by the country’s poor road network; but China has recently begun to address this issue with the announcement of a large highway-building programme. Further impetus to car ownership has come from recent cuts in the taxes on motor vehicles and on the introduction of hire-purchase schemes. WTO membership also requires the opening-up of the domestic market to motor vehicle imports, which should both increase the supply of vehicles and help to bring prices down. On present trends, China’s net exports of gasoline could all but disappear within a couple of years.
Jet-fuel consumption also looks set for high growth levels over the next few years following a government decision to expand the country’s airport capacity. There may be a slowdown in the rate of increase in air travel as a result of the current outbreak of bird ’flu’ in Asia, but if China’s experience of the Severe Acute Respiratory Syndrome (SARS) outbreak in 2003 is anything to go by, the effect of bird ’flu’ on air travel in China should be small.
Demand for electricity boosted demand for fuel oil considerably during 2003, causing a sharp rise in imports (see Table A). In addition to keeping pace with the country’s strong economic growth, the power generation sector also had to meet a large rise in the demand for air-conditioning in the east and south during the summer months. Over the next few years, Peking wants to see a greater role for natural gas, hydroelectricity and nuclear fission in power generation. Demand for HFO is nevertheless likely to go on rising since the generating sector is unlikely to be able to shut down oil-fired units for a number of years owing to a general shortage of generation capacity. Oil-fired units will therefore continue to be used to meet base-load demand rather than their normal role in industrialized countries of supplying electricity in peak periods. China is even likely to have to build some new oil-fired capacity simply to keep pace with short term increases in demand.
One of the most rapidly growing sectors of China’s manufacturing industry is plastics. This has led to greatly increased demand for olefins such as ethylene and propylene, and for the main aromatics: benzene, toluene, and xylene. China relies heavily on naphtha to produce these intermediate petrochemicals and continued economic growth is likely to boost naphtha use considerably. Other possible feedstocks for petrochemical crackers include gasoil and LPG, but both of them are likely to be in high demand as petroleum fuels.
China’s impressive economic growth implies an equally impressive rise in oil consumption in future. Chinese oil-demand growth, however, faces a number of constraints: notably, the country’s distribution system. Supply shortages have been reported across many parts of China this winter. One reason behind last year’s 33% rise in refined product imports (see Table A) is the fact that it is easier for many parts of southern and eastern China to import products from neighbouring countries than it is to bring them in from other parts of China. The Chinese oil industry is heavily based on the producing regions in the north of the country, leaving the rapidly-growing southern provinces like Fujian and Guangdong with insufficient refinery capacity to meet their needs. There are few north-south pipeline links, forcing many areas to rely in part on the country’s inefficient railway network for the delivery of liquid fuels.
Where refineries do exist in the south and east, they are often unable to operate at maximum levels owing to the difficulty of obtaining supplies of crude oil. The lack of deepwater ports in the south restricts access by the largest crude oil tankers, while inland refineries in eastern China can find their ability to bring in crude oil restricted by low water levels on the Yangtze river.
The low level of oil storage in China means that oil refineries frequently have to cut runs when crude oil supplies are restricted or interrupted. The government recently sought to address this issue with the announcement of plans for a strategic oil stockpile. Four tank farms are to be built, initially. These will be located in the northern and eastern provinces of Liaoning, Shandong, and Zhejiang. Following them, further storage is to be added in the south, but the entire scheme is unlikely to cover more than 21 days of crude oil imports. Without considerably more investment in both storage and distribution, China will continue to experience shortages of refined products in the main consuming areas of the east and south.
For most of its nearly 55-year history, the People’s Republic of China has pursued a policy of self-sufficiency in oil. Its transformation in recent years into a net importer has forced a radical rethink of policy by the ruling Chinese Communist Party (CCP). Major efforts were made at first to reverse the loss of self-sufficiency by opening up the upstream sector to foreign participation. Offshore exploration flourished but few large discoveries were made such that the continental shelf simply served to offset the decline in China’s older onshore fields rather than enabling China to increase its oil production substantially, as had been the original idea.
A further attempt was made to develop the oil reserves of western China with outside help but, again, no large discoveries were made, and many foreign companies complained they were being denied access to the most promising acreage, which was reserved instead for the state oil industry. The development of the west was further hampered by the reluctance of the government to construct a pipeline to connect the remote areas being explored with the main oil consuming centres of the east.
China still wants to increase its oil production, but now the policy is to use Chinese state-controlled companies to develop oil production outside China. The China National Petroleum Corporation (PetroChina) has acreage in Africa, South East Asia, and Central Asia, and is now moving into Latin America. The Chinese are also talking to the Russians about linking oil fields in Siberia by pipeline to China.
China’s foreign quest for oil, however, is starting to worry some countries. Russia is wary of becoming over-dependent on China for the exploitation of its Siberian fields. Moscow has long harboured fears that its remote eastern areas could come under the economic and political influence of China, given that many parts of eastern Russia are much closer to Peking than the Russian capital.
The USA has shown concern about China’s growing interest in Central Asia and the Trans-Caucasus, which it wants to see supplying mainly Western markets. Washington sees countries such as Kazakhstan and Azerbaijan as providing an important alternative to the Middle East and has been actively promoting a pipeline to link these former Soviet republics with the Mediterranean (see ‘Focus’, July 2002).
China’s quest for oil supplies is also increasing its involvement in the Middle East. China imported about 1.1 mn bpd of crude oil from there in 2003, principally from Saudi Arabia, Iran, and Oman, and this total looks set to rise considerably in future. Chinese opposition to the Anglo-American invasion of Iraq was based a good deal on fears over future oil supplies. The Chinese appear to fear that the war in Iraq will either lead to further destabilization of the region or US dominance of the Persian Gulf. Both outcomes are likely to be equally unattractive to Peking.
China’s concerns over oil security are not confined to the Middle East. It views US influence in Asia with growing concern as well. The establishing of an American military presence in Central Asia is seen by some in Peking as part of a wider US policy of restricting Chinese access to the oil and gas reserves of countries like Kazakhstan and Turkmenistan. There is a similar level of alarm over US ties with a range of countries lying between the Persian Gulf and the South China Sea, which are seen by some of the CCP’s more hawkish members as constituting a US attempt to control the flow of oil from the Middle East to Asia. The Straits of Malacca and Taiwan are seen as particularly vulnerable to US intervention, while the USA’s long-standing alliance with Japan is regarded as completing the encirclement of China. As the two countries become more dependent on energy imports, relations are likely to come under increasing strain.
THE MONTH IN BRIEF
This section summarizes downstream developments of the
previous month. Exploration &
Production are covered in ‘Upstream Review’.
Iraqi oil exports in January were about 15% below planned levels. Officials blamed bad weather at the Basrah Oil Terminal, but the continuing unrest inside Iraq is taking its toll as well, as attacks on oil installations show no signs of abating. Lower oil exports mean that there is less money to spend on increasing oil production capacity and there are reports that the year-end capacity target of 3 mn bpd has been revised downwards. Halliburton subsidiary Kellogg, Brown and Root (KBR) has been replaced by the US military’s Defense Energy Support Center as a fuel supplier to Iraq, following allegations of overcharging by KBR (see ‘Focus’, January 2004). US and British leaders George W. Bush and Tony Blair have been heavily criticized for the continuing failure of inspectors to find weapons of mass destruction in Iraq.
US commercial stocks of crude oil have fallen to their lowest level in 29 years, pushing them below the minimum level normally required for the efficient operation of the refinery system. The government meanwhile has continued to increase its own crude inventories, known as the Strategic Petroleum Reserve (SPR). Some of President Bush’s opponents have blamed the shortage of commercial stocks on the diversion of supplies to the SPR. Six US energy firms have been fired by the Commodity Futures Trading Commission for giving false information to price-reporting services in an attempt to manipulate natural gas prices. US refiner Valero is to buy El Paso’s 315,000 bpd Caribbean refinery on Aruba. Saudi Aramco and Shell announced the sale of their 180,000 bpd Delaware City refinery to Premcor.
Kuwait is to privatize 120 petrol stations belonging to the Kuwait National Petroleum Company. Nigeria meanwhile has failed to attract bids from major oil companies for controlling interests in its state-run refineries. Sasol and Exel Petroleum are to merge to create southern Africa’s largest integrated petroleum fuels business. BP has put all of its 270 petrol stations in Singapore and Malaysia up for sale, saying they do not give the company a sufficiently large retail market share in the two countries. BP is also selling its 2% share in the integrated Chinese company, PetroChina. Shell’s share price lost 7.5% in one day when the company revealed it has overstated the size of its reserves. Some large shareholders have called for the company’s board to be restructured.
The French government has postponed the privatization of Électricité de France and Gaz de France following opposition from trades unions. The companies’ privileged position in the French energy market has been criticized both by competitors and the European Commission (see ‘Focus’, October 2002). The Commission has proposed compulsory energy conservation targets for EU member states of 1% per annum from 2006 to 2012, based on the previous five years’ consumption. It has also given clearance for Statoil to purchase part of BP’s In Salah gas development in Algeria, which is to supply EU countries from 2004, but has failed to secure powers over EU gas supplies in the event of a supply emergency.
Foreign gas suppliers are lining up to supply the British market as North Sea output falls (see ‘Focus’, October 2002). Norsk Hydro and Germany’s Wingas have announced a joint venture to be known as HydroWingas to supply the UK. Turkey and Greece have agreed to cooperate on a gas pipeline connecting the Middle East with Europe. Soaring demand for coal by electricity generators, a fall in Chinese exports and higher US imports have pushed thermal coal prices to their highest level for over a decade.
GAS AND POWER
China is not the only rapidly growing economy facing an energy shortage (see ‘Focus’). India may also find it difficult to source future supplies. Its gas programme in particular faces supply problems. Several potential suppliers say Indian prices are too low to make deliveries there economic.
On the face of it, India is an attractive market for energy suppliers. It is both large and growing. Over the last decade, India’s economy has grown at around 6% a year: about twice the rate at which the US economy has grown. Energy consumption has gone up annually by 4% over the same period. Gas demand, on the other hand, has grown by more than 6% a year and is set to maintain a similar rate of growth over the coming decade. Any increase in consumption, however, will have to come largely from imports.
The gas will be imported initially as liquefied natural gas (LNG), though there are also plans for pipeline connexions with Iran, the Arabian peninsula, and Central Asia. Pipeline imports are complicated, however, by the fact that the pipelines themselves will almost certainly have to pass through Pakistan (see ‘Looking Ahead’, November 2003). The Indian government has expressed grave concerns about the possible interruption of supplies by Pakistan, and any pipeline scheme will have to await a substantial improvement in relations between the two countries.
Regular LNG imports are due to begin this year with the commissioning of the country’s first two regasification terminals at Dahej and Hazira in the western state of Gujarat. The Dahej terminal will be able to import 667 mn cfd initially, though capacity may eventually be doubled. Hazira’s start-up capacity is 333 mn cfd. At least five other LNG terminals are planned on both the eastern and western seaboards.
The Hazira plant is being built by Shell. India has made strenuous efforts to attract private investment to its gas sector, as well as to the electric power industry, which will be a major user of the gas. The results, however, have not been uniformly successful.
India’s policy has been to encourage investment in both LNG imports and domestic production. Some promising domestic finds have been reported, including a possible 10-trillion-cubic-feet (tcf) field in the Krishna-Godavari basin in Andhra Pradesh in eastern India. If the initial reserve estimates prove to be correct, this would raise India’s proved reserves of gas by more than one third, to nearly 40 tcf.
The economics of developing Indian fields is adversely affected by low domestic prices for natural gas. The government wants to see gas used much more widely across India, but fears that high gas prices may inhibit the spread of gas consumption. Similar considerations apply to the import of LNG.
Gas is supposed to substitute for oil across a range of uses, but fuel-switching is likely to be inhibited by the relatively low price of some oil-based fuels. India has a history since independence of subsidizing refined product prices. In recent years, the government has begun to remove these subsidies, but kerosine and diesel are subject to a mechanism known as the Administered Pricing Mechanism, which keeps their prices down during periods of high international prices.
In order to compete with low product prices, gas has sometimes had to be sold in India at prices as low as $2 per mn Btu. The National Thermal Power Corporation (NTPC) issued a tender last year to buy LNG at a base-price of $3 per mn Btu (after regasification). When import duties, taxes and distribution costs are taken into account, inland wholesale prices probably need to be nearer $5‑6 per mn Btu to be economic for sellers of LNG. NTPC managed to attract some measure of interest for its tender, but this appears to be very much a one-off deal by suppliers seeking a toehold in the Indian market.
One reason for NTPC’s low price ideas is the need to keep its electricity prices low. India’s electricity boards say they cannot afford to pay for high-priced electricity, given that so many of their household customers are poor. For this reason, power generators are often unwilling to sign gas contracts where the gas price is linked to that of oil. Petronet, which owns the LNG terminal at Dahej, is to purchase LNG from Qatar using a crude oil price-link. The main competitor for gas in the Indian power sector, however, is coal, not oil. Gas suppliers, though, are not keen to adopt a coal price-link owing to the difficulty of finding a representative and transparent reference price for coal in India.
An illustration of the problems of choosing a formula that provides the seller with a high price is provided by the Danhol power project in Maharashtra. The $2.9bn project was an Enron-led scheme to build a 2.2GW gas-fired power station in western India. The first phase, of 740 MW, was commissioned in 1999. Two years later, the remaining capacity was almost complete when the whole project was shut down.
The station opened before the associated LNG-importing facilities were built and was run on an interim basis with expensive naphtha. The Maharashtra State Electricity Board (MSEB) claimed that Danhol’s power was too expensive and refused to pay for it. The plant closed in June 2001 and MSEB’s bills remain unpaid. Following more than two-and-a-half years of legal wrangling, two of the partners in the scheme are trying to restart the plant and arrange for the completion of the second phase of the project.
If the plant were to be reopened, Dabhol would probably acquire an LNG import terminal. Two more terminals are planned on the west coast, at Jamnagar and Cochin, along with two more at Kakinada and Ennore on the eastern side of India. Pipeline schemes include one from Iran and another from Turkmenistan, both via Pakistan. A less politically controversial plan is for a 500mn-cfd line from Bangladesh to northern India. Bangladesh, however, is unable to decide whether to export the gas or to try and use it domestically. All these schemes depend on the creation of market conditions in India that enable gas to be supplied commercially whilst still allowing electricity to be sold at affordable prices. This may prove to be a difficult compromise.
LOOKING AHEAD
West Africa is turning into the most important deepwater oil exploration play in the world. Deepwater production of 0.5 mn bpd is forecast to rise to around 4.0 mn bpd within 10–15 years.
Deepwater production is primarily found on the margins of the Atlantic Ocean. Production worldwide is about 2.5 mn bpd, of which Brazil and the US account for 1.0 mn bpd between them. West African deepwater output is about half that level and comes from the Gulf of Guinea. The US and Brazil might add some 2.3 mn bpd to their production within 10–15 years. West African deepwater production, on the other hand, may rise by up to 3.5 mn bpd over the same period such that it accounts for around one half of the world deepwater total, compared with one-fifth at present.
The Gulf of Guinea contains some of the world’s most prospective deepwater acreage. Several fields have already been identified and other areas are slated for large scale exploration over the next few years. Activity is focussed at present on areas off Angola, Nigeria and Equatorial Guinea.
The first deepwater field to be brought into production in the Gulf of Guinea was Angola’s Kuito field, which was commissioned by ChevronTexaco in December 1999. The field lies under about 1,200 feet of water and produces about 70,000 bpd. A much larger field, Girassol, which is operated by Total, was brought on stream off Angola in late 2001. Girassol lies under about 4,200 feet of water and is producing some 200,000 bpd.
Nigeria has one deepwater field, Abo Central, operated by Agip, at water depths of over 1,500 feet. Production began in 2003 and is now running at 30,000 bpd. There are two deepwater fields in production off Equatorial Guinea. ExxonMobil’s Zafiro field started in 1996 in relatively shallow waters, but has since been extended to depths approaching 2,500 feet. An expansion programme completed last summer enabled output to be increased to 170,000 bpd. The country’s other deepwater field is the Ceiba field, operated by Amerada Hess in water depths of up to 2,400 feet. Ceiba was commissioned in November 2000 and now produces about 50,000 bpd.
Several new deepwater fields arte planned and some existing West African fields are due to be expanded. ExxonMobil is developing several fields as part of a project known as Kizomba. Later this year, Kizomba A, covering the Hungo and Chocalho fields, is due on stream with an output of about 250,000 bpd. Water depths on Kizomba A exceed 3,600 feet in places.
In late 2005 or early 2006, the US company plans to commission Kizomba B, consisting of the Dikanza and Kissanje fields, which lie under 3,000 feet of water. Output is expected to be in the region of 250,000 bpd. Subsequently, ExxonMobil plans a third phase, Kizomba C, which will open up the Batuque, Mondo and Saxi fields.
By early 2006, a further Angolan development should be in operation, ChevronTexaco’s BBLT, consisting of the Belze, Benguela, Lobito, and Tomboco fields, where water depths are put at more than 1,100 feet. BBLT will be developed in two main phases, with output scheduled to reach 200,000 bpd by the end of the decade.
ExxonMobil is also heavily involved in Nigeria’s deep-water exploration. It plans to commission the 150,000 bpd Erha field in late 2005. Water depths here are around 3,500 feet. Before that, Shell plans to bring the 225,000 bpd Bonga field on stream, in about March this year. Bonga lies in over 3,000 feet of water off Nigeria and is also expected to produce 150 mn cfd of gas.
Equatorial Guinea’s deepwater production should rise within a few years from further developments in the Ceiba and nearby fields. Ivory Coast is expected to commission its first such field in 2005, when Canadian Natural Resources starts up the 70,000bpd Baobab field, lying under 2,900 feet of water.
West Africa’s deep-water production looks set to go on increasing for several more years with further developments off Angola, Nigeria, and elsewhere. Among the Angolan projects planned for 2006 and beyond are Total’s Dalia field, expected to produce around 250,000 bpd and ChevronTexaco’s Agbami field, which is expected to produce at similar levels to Dalia. BP is at the preliminary stages of developing a field off Angola and both ExxonMobil and Total plan further developments there.
Shell and Statoil are looking at a major deep-water gas project off Nigeria and Shell may also develop the Bonga South West oil field in association with its existing Bonga development. ChevronTexaco has plans for a further Nigerian field at Aparo.
Exploration successes in the Gulf of Guinea are encouraging upstream activity elsewhere off Western Africa. The discovery of the Chinguetti field in 2,400 feet of water off Mauritania has encouraged further exploration there. Chinguetti looks to have reserves in the 100–200mn-bbl range, which is somewhat smaller than those in the Gulf of Guinea, which tend to be around 0.5–1.0 bn bbl. These larger fields are likely to claim the lion’s share of international attention, especially when such fields can be developed to share sub-sea production facilities with one another.