FOCUS

Europe’s refiners to export more to Asia

Europe is becoming an increasingly important export–refining centre. As demand for light products begins to outstrip the capacity to produce them in some refining centres, Europe’s refiners are increasingly being called upon to supply the deficit. Europe is already an important supplier of refined products to the USA. Rising demand in Asia is now starting to draw European products there as well.

Capacity shortages

The world’s crude oil distillation capacity in 2003 was around 82 mn bpd, compared with refined products consumption of about 74 mn bpd, suggesting that there is some 8 mn bpd of spare capacity worldwide. On the face of it, this appears a comfortable margin, given that refiners tend to operate as near to maximum capacity as possible and can often raise throughputs above nameplate capacity for limited periods.

The problem is that refinery capacity is not distributed precisely in relation to patterns of demand, leaving some regions short of capacity. The USA is a prime example of a region with a shortage of crude oil distillation capacity. There, environmental legislation has imposed restrictions on operating and expanding refineries, leading in some instances to closures, while planning controls have made it almost impossible for refiners to gain permission to build on greenfield sites. The US market has additional problems caused by the state of its distribution system. Pipelines carrying crude oil to its refineries and products to market are often run at capacity, leaving the whole refining and distribution network with little spare capacity. This produces shortages whenever the system is overloaded by sudden surges in demand.

Shortages of distillation capacity are not, however, the only problem. Some regions, such as parts of Asia, do not have sufficient upgrading capacity to meet demand for light products like gasoline, kerosine, and (especially) gasoil. The situation is made worse in certain cases by the inability of relatively unsophisticated refineries in various Asian countries to produce the high quality, low sulphur products increasingly demanded across the region. The result of all this is that Asia is now turning to more distant regions for present and future product supplies.

Swing suppliers

Since the 1970s, a few areas have set out to supply countries with refining deficits. These so-called ‘swing’ refining centres are located principally in Singapore, the Persian Gulf, and the Caribbean. As the marginal sources of supply, these swing refiners can experience wide fluctuations in demand. During the early 1990s, for example, refineries in Singapore often operated at 100% of nameplate capacity. Following the Asian financial and economic crises of 1997, which were accompanied by a fall in demand, Singapore runs fell sharply. The situation was made worse by the opening of new capacity in other parts of Asia, such as Taiwan and India, in the years following 1997, this meant that by 2002, throughputs in Singapore were as low as 65% of capacity.

Since then, Asian demand has recovered strongly. Some refineries in the region, meanwhile, have closed down, including plants in Japan, China, the Philippines, and Australia. Late last year, runs in Singapore were around 75%. Capacity additions in the Republic of Korea since the late 1990s, on the other hand, have temporarily transformed that country into an exporter of products. Korean refiners possess about 0.4 mn bpd of swing capacity (see Table A).

Table A
Asia: Refined product exports, 2002

Country	Volume
	(th bpd)
China	225
India	144
Indonesia	169
Japan	80
Korea	700
Malaysia	148
Singapore	926
Taiwan	90
Thailand	128
Others	99
Total	2 709

Totals rounded
Source: OET World Oil Trade, 2003

Gulf refiners

The Persian Gulf is another major swing refining centre, with export refineries in Bahrain, Kuwait, Qatar, Saudi Arabia, and UAE (see Table B). Iran also exports small volumes (35,000 bpd in 2002), but most of its capacity is dedicated to supplying the home market. Iraq was once a significant exporter of refined products. Some 20,000 bpd were officially recorded as exports in 2002, supplied to Jordan under a UN-sponsored deal; but an estimated 50,000 bpd were smuggled out, mainly to Iran, UAE, and the Indian sub-continent, in defiance of UN trade sanctions. Last year’s US-led invasion put a stop to much of this trade, though up to 70,000 bpd of surplus heavy fuel oil has since been exported in exchange for lighter products (see ‘Focus’, January 2004).

Much of the Middle East’s export capacity is designed to serve markets in Asia. Sales were badly affected by the economic turndown in Asia after 1997 and by the rise of non-traditional product exporters in Asia, such as India, Japan, Taiwan, Thailand, and South Korea (see Table A), many of which found themselves with surplus distillation capacity following the adoption of expansion programmes in the mid-1990s. Japanese exports were prompted by the removal of government restrictions on the refined products’ trade in the 1990s. More recently, Persian Gulf product exports have begun to be squeezed by growing demand within the Middle East itself.

Table B
Middle East: Refined product exports, 2002

Country	Volume
	(th bpd)
Bahrain	266
Kuwait	640
Qatar	64
Saudi Arabia	998
UAE	486
Others	397
Total	2 851

Totals rounded
Source: OET World Oil Trade, 2003

The Caribbean export refining business has grown up primarily to supply the USA. It is based mainly in Aruba, Curaçao, Trinidad and Tobago, and the US Virgin Islands, which between them have 1.3 mn bpd of export refining capacity. These refineries operate essentially as offshore US refineries. Panama and Puerto Rico also supply small amounts to the USA and some of the Venezuela’s refineries may also be considered as belonging to the same Caribbean export refining system.

New suppliers needed

The recent revival in Asia’s refined product demand, combined with the rapid increase in consumption in the Middle East, means that new refinery capacity will soon be required to service the markets east of Suez. China, in particular, is drawing-in increasing volumes of refined products. Last year, product imports went up by 33% to 710,000 bpd (see ‘Focus’, February 2004).

While, on paper, China has a healthy surplus of crude distillation capacity, several units are located on oil fields well away from the main consuming centres. Many other refineries are small, inefficient, and poorly located with respect to product pipelines, which are themselves often inadequate to serve a refined products’ market that is growing at more than 7% a year.

Despite the recent revival in Asian demand, few countries there have adequate plans to meet it from their own refining systems. Over-building of refineries in the late 1990s has caused some countries to slow down programmes to expand capacity. China plans less than 400,000 bpd of new distillation capacity between now and 2006. India may add around 600,000 bpd over the same period, but this is just over half what was originally planned. Indonesia’s political and economic problems since 1997 have led to a scaling back of refinery schemes. In Japan, consolidation is the order of the day, with some crude distillation units earmarked for closure. Last year, refinery capacity was shut down both in Japan and the Philippines (see ‘The Month in Brief’, October 2003).

The supply squeeze is likely to be experienced most severely in the gasoil market. Last year, Asia imported about 100,000 bpd from suppliers outside the region. By 2006, Asia’s net import requirement could be as high as 350,00 bpd. Most of Asia’s gasoil deficit is currently covered by the Persian Gulf, but growing demand within the Middle East is likely to mean that Gulf refiners will have less than 250,000 bpd to export by 2006.

Gasoline could also be in short supply east of Suez by that date. Last year, Asia was a net exporter of about 90,000 bpd of gasoline. By 2006, it may very well need to import a similar volume to this. The Middle East is unlikely to have any surplus gasoline by then as its own demand continues to rise. Many parts of the region are net importers already.

New refineries

Some Middle Eastern countries are trying to address the problem of future shortages by building additional refinery capacity, including new grassroots schemes, the upgrading of old-fashioned refineries and the expansion of existing refinery sites (see Table C). Some units, though, are also scheduled for closure including the 17,500bpd Sidon refinery in the Lebanon, the 27,000bdp Larnaca refinery in Cyprus and Oman’s 85,000bpd Mina al-Fahal unit, which is on a confined urban site in Muscat.

Two of the refinery expansion schemes — Pars in Iran and Ras Laffan in Qatar — are condensate refineries. There are also various schemes to add upgrading units to existing refineries. Bahrain, for example, is to add a 60,000bpd hydrocracker to its 250,000bpd Awali refinery and Saudi Aramco wants to upgrade its unsophisticated 425,000bpd Rabigh refinery, on the Red Sea.

Saudi refinery policy is not totally clear. The state oil company, Saudi Aramco, has recently begun to devote more of its energies to the natural gas side of its business, both in terms of gas and gas liquids. Last year, for example, it commissioned a 200,000bpd condensate splitter at Ras Tanura and further announced the building of four new gas-fired power stations. There are signs already that the new emphasis on gas may be at the expense of some new refining schemes. In particular, the upgrade at Rabigh looks unlikely to proceed in the near future.

Table C
Middle East: refinery expansion plans, 2004-6

Refinery	Distillation additions
	(th bpd)
Iran
Abadan	120
Arak	50
Bandar Abbas	100
Pars	120*
Qeshm	120
Total	510
Jordan
Zarqa	50
Lebanon
Tripoli	40
Oman
Sohar	116
Qatar
Ras Laffan	140*
Total	856

* condensate refinery

Another area of uncertainty over future refined products’ production in the Middle East is the amount of effort that will be devoted to producing light products from this synthesis of natural gas. Iran and Qatar between them have announced plans for between 513,000 bpd and 934,000 bpd of gas-to-liquids (GTL) capacity, but only one small plant is actually under construction. The large-scale development of GTL as a source of refined products remains many years away (see ‘Focus’, October 2003).

Europe to the rescue?

Another swing supplier of refined products is therefore needed. One candidate is Europe. Spare refining capacity exists in a number of countries and several are significant exporters of products (see Table D). Italy and the Netherlands already have a long history of swing refining. Other important product exporters are the UK, Belgium, Germany, and the Nordic countries. In Eastern Europe, Romania has long been an entrepot refining centre, while the former Soviet Union (FSU) is an important supplier of gasoil: mainly to Western Europe but now, increasingly, to other, more distant regions as well.

The main external market for European product exports is the USA. Gasoline trade is particularly important for refiners located in the main Western European countries. Russia’s most important product export is gasoil.

Table D
Europe: refined product exports, 2002

Country	Volume
	(th bpd)
OECD
Belgium	400
Finland	101
France	348
Germany	349
Italy	383
Netherlands	1,311
Norway	168
Spain	122
Sweden	164
UK	443
Others	453
Total	4,242
Non-OECD
Romania	47
Others	218
Total	265
FSU
Russia	1,235
Others	292
Total	1,527
Total Europe	6,034

Totals rounded
Source: OET World Oil Trade, 2003

Asian countries may soon begin to turn to European refiners for both gasoline and gasoil. While Western Europe may be able to supply motor spirit to both the USA and Asia, it will not be able to meet Asia’s rising need for imports of gasoil, since it is itself in deficit. The only large net exporter of gasoil in Europe is the FSU, notably Russia, which may struggle to supply both Western European and Asian markets.

Europe’s exports of refined products could be squeezed further if some refinery units in Eastern Europe close following the accession of several countries from the region to the EU. Some of the older, less sophisticated refineries there may shut once their domestic product markets are open to competition from existing EU member states (see ‘Focus’, November 2003). Several small, inland refineries are under threat in other parts of the EU, and there are few plans for major capacity additions, given the problems of obtaining planning and other consents. In the longer term, Asia’s product shortages will have to be met from within the region. So far, it is not clear how the Asians intend to resolve this problem.

Apart from the 0.6 mn bpd of new crude distillation capacity planned by India and the 0.4 mn bpd that may be commissioned in China, there are few firm expansion plans in other parts of Asia covering the period between now and 2006. Indonesia has announced proposals for two new refineries with a total capacity of 0.3 mn bpd, but it is not clear whether either will be built. Vietnam similarly plans to build 0.3 mn bpd of new capacity but only about half of this may actually be built. A further 0.1–0.2 mn bpd is planned across Asia over the next 2–3 years. In all events, a capacity shortage looms. Further imports from Europe appear essential.

THE MONTH IN BRIEF

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

OPEC cuts quotas, prices soar and Saudis rethink gas policy

Iraqi representatives first agreed proposals for a new provisional constitution then disagreed just as the agreement was due to be formally launched. One area of contention is the degree of autonomy to be allowed to Shi’i and Kurdish areas, both of which contain important oil installations. Many were killed in bomb attacks on a Shi’i religious festival. Oil exports were more than 20% below planned levels of just over 1.5 mn bpd. A new, 0.4 mn bpd export terminal opened at Khor al-Amaya. This should help relieve congestion at the nearby Basrah Oil Terminal. The new terminal, however, will initially operate at only two-thirds capacity. In a move that could prove politically controversial, US forces in Iraq have imported middle distillate from an Israeli company.

Having hinted that production quotas would be unchanged, OPEC ministers cut them by 1.0 mn bpd at their 10 February meeting in Algiers. The new quotas, which come into effect on 1 April, total 23.5 mn bpd: some 2.5 mn bpd below actual output levels during January. The status of quotas was rendered somewhat opaque by a remark by Saudi oil minister Ali Naimi that quotas were subject to “official” and “unofficial guidelines”. It seems that overproduction may be sanctioned if crude oil prices remain high.

Product prices have been boosted by low inventories in consuming countries and high levels of refinery maintenance in Europe. Refinery shutdowns in California led to sharp price rises for gasoline on the US West Coast. Gasoline shortages were recorded elsewhere across the USA as refiners struggled to meet new specifications for motor spirit, pipelines and terminals became congested, clean tanker rates rose sharply and domestic inventories fell. Canada announced plans to raise ethanol production by a third to 65,000 bpd to meet proposed new gasoline specifications. The Republic of Korea wants to increase its crude oil stockpile by 10 mn bbl to 81 mn bbl as a buffer against future oil price rises.

The Ukraine refused to reopen a 180,000 bpd pipeline to the Black Sea port of Odessa to allow Russia to export more oil by that route, saying that the line is earmarked for Kazakhstan. Russia would not have been able to make use of it in any case, since all Black Sea exports have been disrupted by seasonal storms and Turkish restrictions on tanker traffic through the narrow Bosphorus and Dardanelles. Ankara’s move has delayed tankers in transit, causing freight rates to soar. Russia diverted some exports to terminals in the Baltic (see ‘Focus’, December 2003). Turkey’s privatization board approved the sale of a controlling stake in the state oil refining company Tupras to Russia’s Tatneft and Turkey’s Zorlu Group despite opposition from trades unions.

Shell’s chief executive Phil Watts resigned following heavy criticism over the company’s downward revision of its proven oil and gas reserves (see ‘The Month in Brief’, February 2004). A rather more popular managerial move was that by UK-listed Fortune Oil to sell its stake in a jet fuel joint-venture in China and to move instead into the country’s rapidly expanding gas distribution business.

Sonatrach has been forced to export more gas by pipeline to honour its contracts following an explosion at the Skikda LNG terminal. In what could be a reversal of the kingdom’s policy of developing gas for domestic consumption only, Saudi Arabia’s oil minister has declared that his country “may well export (gas) to international markets.” Saudi Aramco signed a letter of intent to sell the Delaware City refinery it owns jointly with Shell to Premcor. The Saudi government is to co-operate with Russia over joint-ventures for oil and gas projects.

GAS AND POWER

Brazil struggles to reform electricity sector

The reform of Brazil’s electricity industry is running into problems: legislators have delayed a bill to liberalize prices; the government has called for management changes in the state power company, Electrobras; and the national oil company, Petrobras, is under attack for failing to fulfil gas contracts signed with power generators, which has led to electricity shortages in the north-east of the country.

Reforms delayed

Brazil’s electric power sector has been hit by a series of problems whilst struggling to keep up with booming demand. With annual consumption now running close to 330 bn kwh, Brazil is by far the largest electricity market in Latin America (see Table 7a). Demand is also growing at a robust 5% a year, straining the capacity of the country’s generating, transmission and distribution systems. Against this background, the government has been trying to attract new investment into the power industry through a programme of market liberalization and privatization. Political opposition to some of the reforms, however, now threatens to delay the whole process.

A bill to deregulate various parts of the electricity industry has attracted considerable parliamentary opposition. Several amendments were tabled, delaying approval of the bill by the country’s national congress. The legislation deals principally with electricity pricing and includes proposals for a pool system of power trading.

Under the proposals, distribution companies will buy electricity from the pool rather than under bilateral contracts as at present. Under existing arrangements, distributors are allowed to buy some or all of their electricity from generators, which are, in many cases, part of the same company. Power bought in this way is often more expensive than that available on the existing wholesale market.

The introduction of the pool should lead to lower wholesale electricity prices. While this might be popular politically, opponents of the pool system claim that lower power prices will discourage further investment in the electricity supply industry. The government says that new power plants can charge a higher price for their output than older plants where construction costs have been fully amortized.

Attracting investment

The electricity industry believes that such measures do not go far enough to guarantee acceptable returns in future and has called for the government to amend the proposals. It also wants the government to pay for extensions to the distribution network rather than requiring the distributors to finance additions themselves.

The electricity industry in Brazil is a mixture of state-owned and private companies. The latter include AES, Duke Energy and El Paso from the USA, Électricité de France, Electricidade de Portugal, and Iberdrola and Endesa from Spain. Many private firms are critical of the investment climate in Brazil and some are reported to be considering pulling out of the country. Brazil needs to find an estimated $7-8 bn annually to finance the future expansion of the electricity industry.

The largest Brazilian electricity company is the state-owned utility Electrobras; but capital investment by Electrobras has been falling in recent years. Members of the government have heavily criticized the state company’s management and called for changes. The government’s critics, however, accuse it of wanting to install its own supporters at the head of Electrobras and other state-run companies.

Power shortages

The problem of power shortages in several parts of Brazil lies behind the recent moves to restructure the electricity sector. Generating capacity appears to be adequate in the south of the country, and Electrobras has even considered exporting power from that region to neighbouring Argentina. In the north-east, on the other hand, it is an entirely different story.

Demand there is growing at more than twice the national average. The north-east relies heavily on hydro-electric power, but water levels in rivers and reservoirs have been falling in recent years as more is extracted to supply the region’s growing agricultural and industrial demand. This year, there has been a series of power cuts despite the commissioning of a large number of oil-fired emergency generators. Electricity prices have rocketed as a result.

The situation in the north-east has been exacerbated by a shortage of natural gas for use in power generation. Over the last three years, new gas-fired stations have been built in an attempt to reduce the region’s over-dependence on hydro-electricity. The state oil company, Petrobras, contracted to provide gas to the generating plants, but now says it is unable to supply the volumes agreed. Part of the problem appears to be that the gas pipeline network cannot handle the amounts required by the generators. There have also been production problems in the northern gas fields.

The new north-eastern gas-fired stations were built as part of an emergency programme drawn up in the late 1990s to build 50 gas-fired generating units across the country to prevent future electricity shortages. In many cases, Petrobras was called on to finance the stations, in addition to supplying the gas. Brazil is short of gas, however, and is forced to import large volumes from Bolivia (see ‘Gas and Power’, September, 2002). The price of Bolivia’s gas is tied to that of oil, making it too expensive for some generators. The result has been that only 11 of the planned 50 gas-fired stations have been built. Petrobras meanwhile has announced heavy losses from the running of the plants in which it has a stake.

More gas in Brazil?

New gas discoveries by Petrobras, however, may offer some long-term relief for Brazil. The state company recently announced finds totalling 14 trillion cubic feet in the Santos Basin. The formation is an important deep-water structure (see ‘Looking Ahead’, February 2004), which is expected to provide more than half Brazil’s gas production by the end of the decade.

The Santos Basin, though, is not particularly well located to supply the energy-short north-east. Most of the Santos gas is likely to end up on the Sao Paulo region of southern Brazil, where it is likely to be used to supply a new generation of gas-fired power stations, designed to reduce imports of hydro-electricity from the north-east.

The Santos gas may encourage Petrobras to abandon the search for gas reserves in the northern half of the country. Several prospective areas are found in the north, but most require extensive new pipeline networks to connect them with consuming centres in the north-east. With hydro-electricity under a cloud as well, the north-eastern part of Brazil looks like remaining short of energy for some time to come.

LOOKING AHEAD

Refiners turn to coking to make light fuels

The increasing demand for transport fuels, combined with the falling quality of crude oil available to many refiners, is creating a demand for more refinery conversion units. One option is for refiners to add more hydrogen to their heavy residues, making them both lighter and lower in sulphur. This still leaves unconverted heavy residues to be disposed. In the past, many of these would have ended up in the heavy fuel oil (HFO) pool; but with the consumption of HFO in decline, many refiners are opting instead for another option: removal and conversion of carbon. The most popular of these options is coking.

Coking converts heavy residues to lighter liquids, leaving behind petroleum coke as a solid. There are three main types of coke: needle coke, calcined coke and green coke. The three have different properties and uses. Needle coke is a low sulphur product used in the manufacture of steel, and normally commands the highest price of the three grades. Calcined coke is intermediate in sulphur and used by the aluminium industry. Green coke is the highest in sulphur and lowest in price, and is used as a fuel or in the cement industry. The needle and calcined coke markets are somewhat specialist and are dominated, especially in the case of needle coke, by a few specialist producers.

US refineries

Coking is particularly popular amongst refiners in the USA. Most medium-sized and large US refineries have coking units. The USA has some 2.4 mn bpd of coking capacity capable of producing 130,000 short tons per day. Nearly half of the coking capacity is found in the Texas-Gulf Coast region. Green coke production has risen by some 40% over the last decade: about four-times the rate at which refinery runs as a whole have risen, reflecting the increasing levels of conversion of heavy residues in the USA.

The US petroleum coke industry is based primarily on the supply of cheap, heavy, high-sulphur crudes from Venezuela and Mexico. There is little market outside marine bunkers for any HFO produced from these crudes: hence the attraction of coking. Cokers generally convert about two-thirds of their feedstocks in to white products, leaving the remaining one-third as solid coke. About 60% of US petroleum coke production is exported, with Japan the largest market.

The deteriorating quality of the crude oil used in US refineries is encouraging refiners to increase coking capacity. Over the past five years, crude gravity has been decreasing by about 0.2°API annually. Frontier Refining, for example, has announced plans to increase coking at its El Dorado, Kansas refinery and ConocoPhillips may install a unit at its Wood River, Illinois refinery.

Selling coke

Most of the additional coke produced in US refineries is likely to be high in sulphur and therefore destined for the fuel market. Needle coke normally has a sulphur content lower than 2% by weight and needs much sweeter crudes than those increasingly on offer from Latin America. Moreover, the demand from the steel industry for needle coke has been fairly stable over the last decade or more, making it unlikely that any refiner would want to enter the needle coke business.

Nor is much of the additional coke production likely to be anode-grade material for the aluminium industry, since this requires a sulphur content of about 2.5% which, in turn, requires a crude fairly low in sulphur and metals. Much of the new coke production is likely to be in the 3-6% sulphur range, making it suitable only for green coke, though some with a sulphur content right at the bottom of this range could be blended with low sulphur coke to produce anodes.

Green coke is considerably lower in value than the other two grades. Needle coke sells for about $400-500 a tonne, compared with $300 for anode coke and about $30 a tonne for fuel coke. Green coke’s price is essentially set by that of coal, though coke typically has a heating value some 20% or so higher than that of coal. The high sulphur content of green coke, however, means that it must normally be burned in power stations fitted with flue gas desulphurization.

Spreading cokers

The additional supply of petroleum coke in the USA is likely to exceed any increase in domestic demand over the next few years. At the same time, however, the export market for US coke may well start to contract as refiners outside the USA invest in coking capacity. Some producers of heavy crudes have begun to build cokers themselves. Mexico began such a programme in the late 1990s. Europe has tended to prefer hydroconversion to coking, but here, as in the USA, there is a growing problem of balancing falling demand for high sulphur fuel oil with an increase in the consumption of white products, especially middle distillate.

Increasing production of coke worldwide, however, threatens to turn it into a distress product. There are some methods, such as flexicoking, which convert coke into gas, but the heat content of the gas is too low for many fuel applications. Refiners will have to become increasingly sophisticated in the coal as well as the oil markets if they are to go on producing coke.