Demand for oil has risen strongly this year and some markets report shortages of certain products, yet oil producers report difficulties in selling their crude. Estimates by the International Energy Agency (IEA) suggest that world demand went up by 2.1 mn bpd, or 2.6%, between the first quarters of 2003 and 2004, and by 4.0 mn bpd, or 5.2%, between the second quarters of 2003 and 2004 (see Tables A and B). The apparent contradiction between high demand, oil shortages and problems selling crude is readily explainable by the fact that figures for demand refer to refined products, not crude oil. The supply of crude oil has, if anything, gone up by more than demand (see Table D). Refiners, on the other hand, have experienced considerable difficulties in meeting the increase in demand. Prices have risen sharply in consequence. Refineries are running close to their nameplate capacities in many parts of the world, making it difficult for them to absorb the extra volumes of crude oil. The situation, moreover, looks set to continue, ensuring that oil prices remain high for the rest of the year.

Rising demand

World oil demand is forecast by the IEA to rise by 2.6 mn bpd this year, or 3.3% versus 2003 (see Table B). This is considerably more than in recent years. World demand in 2003, for example, was only 1.7 mn bpd, or 2.2%, above the previous year’s level, whilst the rise between 2001 and 2002, according to the IEA’s figures was only 0.6 mn bpd, or 0.8%.

Table A
World Oil Demand, 2003 and 2004

Period	Demand
(quarters)	(mn bpd)
2003
1Q	80.2
2Q	77.1
3Q	79.2
4Q	82.0
Year	79.6
2004
1Q	82.3
2Q	81.1
3Q	81.4
4Q	83.9
Year	82.2

Source: IEA, August 2004

This year’s demand growth has been led principally by the US and China. IEA forecasts show a year-on-year rise of 0.8 mn bpd for China during 2004 and a 0.4 mn bpd increase in the US. Western Europe appears to have put on some 0.3 mn bpd, whilst Asia, excluding China, Japan and South Korea, looks set to rise by 0,.4 mn bpd (see Table C).

Table B
World Oil Demand, 2004 v 2003

Period	Change v Year-earlier
(quarter)	(mn bpd)	(%)
2004
1Q	2.1	2.6
2Q	4.0	5.2
3Q	2.2	2.8
4Q	1.9	2.3
Year	2.6	3.3

Source: IEA, August 2004

These increases in demand, however, are not occurring uniformly across the barrel. Early this year, there was heavy demand for gasoil, which is used both for diesel fuel and heating oil. Summer markets were dominated early by strong demand in the US for gasoline. More recently, there have been shortages of kerosine in several markets, while attention is turning elsewhere to gasoil once again. Heavy fuel oil demand, on the other hand, has been comparatively weak, with the exception of the US and Japan (see ‘Gas and Power’, August 2004).

Table C
Regional Demand, 2004 v 2003

Region	2003	2004	Change
	(mn bpd)
China	5.5	6.3	0.8
US	20.1	20.5	0.4
Asia*	8.1	8.5	0.4
OECD Europe	15.3	15.6	0.3
Middle East	5.6	5.9	0.3
Other	25.0	25.4	0.4
Total	79.6	82.2	2.6

* excluding China, Japan and South Korea
NB: Totals rounded
Source: IEA, August 2004

Supply goes up

Rising demand has been accompanied by a sharp increase in prices. Some of this increase represents a knee-jerk reaction by oil traders to dramatic political events such as the attacks on foreign oil workers in Saudi Arabia (see ‘The Month in Brief’, June 2004) or moves by the Russian government to sequester the assets of the country’s largest oil company, Yukos (see ‘The Month in Brief’, August 2004). Nevertheless, the underlying force for this year’s price rises is the increase in demand.

High prices, allied with the increase in demand, have encouraged oil exporting countries to produce close to maximum levels. OPEC, in particular, has raised production, reversing a decision at the start of the year to rein-in output to prevent a fall in prices (see ‘The Month in Brief’, March 2004). This undoubtedly led to some shortages of crude oil in the early part of the year, but the rise in world output in general has more than kept pace with that of demand (see Table D).

Table D
World Oil Supply, First Half 2004 v 2003

Region

1Q03

2Q03

1Q04

2Q04

Change

1Q04 v 1Q03

2Q04 v 2Q03

(mn bpd)

OPEC

Crude

26.7

26.2

27.9

28.2

1.2

2.0

NGL

3.5

3.9

4.3

0.8

0.4

Total

30.2

30.0

32.2

32.4

2.0

2.4

Non-OPEC*

OECD

22.1

21.3

21.7

21.4

(0.4)

0.1

Ex-USSR

9.9

10.1

10.8

11.1

0.9

1.0

Africa

2.9

3.0

3.3

3.4

0.4

Other

14.0

13.9

14.1

14.0

0.1

Total

48.9

48.3

49.9

1.0

1.6

Total World

79.1

78.3

82.1

82.3

3.0

4.0

* including NGL and refinery processing gains
NB: Totals rounded
Source: IEA, August 2004

Most of the gains in output have come from OPEC, where production of both crude oil and NGL has risen sharply, despite attempts to curb output earlier in the year. After OPEC, the former Soviet Union and Africa (mainly West Africa) have provided the most significant increases. Elsewhere, output has remained fairly stable. OPEC looks set to go on providing most of any future increase over the next year or so since that is where most of the world’s spare production capacity now lies (see ‘Focus’, June 2004). This fact worries several countries, notably the US, which wants to reduce its dependence on OPEC, especially the Middle Eastern members (see ‘The United States of America and the Quest for Energy Security’, Global Energy Review–details available elsewhere in OET).

Product shortages

This year’s oil shortages have manifested themselves as a series of supply shortfalls for various refined products. There have been various shortages across the world at different times, but the main ones have tended to concern the US and Asia. Between them, these two regions account for 43% of world demand and 62% of this year’s growth in demand (see Table C).

The early part of the year was dominated by concerns about middle distillate, especially in the US, where cold weather in January boosted the demand for heating oil. An early indication of the strength of Chinese oil demand came in the same month when shortages of middle distillate were reported there and imports of the product soared. China’s industrial demand boosted imports of heavy fuel oil as well.

Table E
Product Consumption in the US and China, 2003

Country	Consumption
	(mn bpd)
US
Gasolines	9.3
Middle Distillate	5.9
Heavy Fuel Oil	0.8
Others	4.2
Total	20.1
China
Gasolines	1.5
Middle Distillate	1.9
Heavy Fuel Oil	0.8
Others	1.7
Total	6.0

NB: Totals rounded

Source: BP Statistical Review of World Energy, 2004

Concerns about US gasoline supplies also surfaced early in the year: well in advance of the summer driving season. A recurring theme was the low level of gasoline stocks, which appeared inadequate to meet the demand levels expected later in the year. A further worry arose from a series of changes in the specification of gasolines used in various US states. One of the changes concerned the level of sulphur in gasoline. The smaller US refineries along with some foreign suppliers expressed doubts about their ability to meet the new specifications, which involved a reduction in sulphur content from 500 parts per million (ppm) to 120 ppm. Domestic and foreign suppliers also voiced concerns about their ability to replace the oxygenate methyl tertiary butyl ether (MTBE) in gasoline supplied to California, New York and Connecticut. All three states banned MTBE from 1st January (see ‘Focus’, May 2004).

Further pressure on the top end of the barrel came from the petrochemical industry, which stepped up purchases of naphtha during the summer months. European cracker operators switched to naphtha as propane prices soared. A revival in many Asian economies was accompanied by an increase in the output of petrochemical crackers, whilst China’s booming economy prompted olefin manufacturers to run flat out.

The increased demand from petrochemical crackers encouraged refiners to run more paraffinic crudes in order to produce petrochemical-grade naphtha. As a result, there was less gasoline-grade naphtha available, putting gasoline prices under further upward pressure. A similar situation is likely to occur next year following the commissioning of three new Chinese olefin crackers. Their combined demand for petrochemical-grade naphtha feedstock is likely to exceed 100,000 bpd, of which most will have to be imported from outside the Pacific Rim. The new Chinese demand is likely to increase imports into the Asia/Pacific region by 15-20%, to over 700,000 bpd.

Not enough kerosine

Growing demand for naphtha is squeezing another market: jet kerosine, which is used as aviation turbine fuel and for heating, lighting and cooking. It has a further use as a blendstock for making certain grades of automotive diesel.

The kerosine fraction lies between those of naphtha and gasoil. Its output can therefore be curtailed as refiners try to maximize their production of the two other fractions. The current pressure on kerosine is coming from gasoil. In China, gasoil demand is being driven by electricity demand. As the country’s generation, transmission and distribution systems buckle under rapidly rising demand, more and more Chinese businesses and households are installing diesel generators. This year has seen China transformed from a net exporter to a net importer of gasoil.

At the same time, Chinese demand for jet kerosine is also growing strongly thanks to a boom in air travel in China this year. Imports of jet fuel during the second quarter of 2004 were close to 60,000 bpd: nearly 200% higher than in the same period in 2003. Third quarter imports are likely to be even higher, boosted by the country’s largest-ever purchase tender, amounting to 5 mn bbl.

Gasoil is in high demand in Europe, as refiners and consumers seek to build up stocks in advance of the winter heating season. The situation has been exacerbated in Western Europe by an 8% fall in Russian gasoil exports, compared with a year ago. Demand appears to be rising strongly in Russia and the government is discouraging gasoil exports with an increase in export duties. European gasoil stocks are also low. Inventory levels in Rotterdam recently touched a 15-year low.

Stocks are also low in the US. Here refiners are struggling to produce extra middle distillate owing to a shortage of lighter crudes. Refiners in Europe and Asia have sought to meet high demand for naphtha, kerosine and gasoil by distilling as much light crude as possible. Crudes from Africa and the North Sea have been taken increasingly to Europe and Asia rather than to the US Gulf, leaving refiners there with heavy, sour grades from Latin America and the Persian Gulf. Although many US refineries are configured to handle heavy and sour crudes, even they are now beginning to struggle to keep pace with demand for light products.

As the northern hemisphere winter approaches, refiners worldwide will continue to struggle to balance competing demands for kerosine and gasoil. Recent shortages of kerosine have caused prices to rise well above those for gasoil and this, in turn, has prompted some refiners to produce more kerosine. Gasoil, though, continues to drive the middle distillate market. Higher gasoil demand, however, often means higher demand for kerosine as well since kerosine is required as a blendstock to bring certain grades of diesel and heating oil to the right specification in terms of sulphur, density and other important characteristics.

Refiners not coping

Refiners are unlikely to achieve the right balance between kerosine and gasoil. Price movements between the two products look set to fluctuate wildly as a result. A more general problem for refiners seeking to maximize the production of light products is that much of the extra crude now being provided by OPEC is at the heavier end of the range. The result of this is likely to be higher production of high sulphur fuel oil, one of the few products for which there has been no great boom in demand. Some refiners therefore may have to reduce runs in order to avoid being left with large, unsold stocks of fuel oil.

The increasing proportion of heavier crudes in OPEC’s export slate is likely to go on causing problems into 2005 and beyond. Early next year, for example, once the winter heating season is over, refiners across the northern hemisphere will direct their efforts towards building stocks of gasoline in advance of the summer driving season. More heavy crude will put both their distillation and upgrading units under strain. If refiners are to produce more light products they will have to increase throughputs; but this is likely to prove increasingly difficult as so many of the world’s refiners are running close to nameplate capacity. The situation in the US could be particularly acute early next year as refiners undertake a heavy programme of maintenance, leading to widespread shutdowns. Next year’s maintenance programme is expected to be more prolonged than usual as a result of the postponement of some refinery turnarounds during 2004, as US refiners tried to cash-in on high margins when product prices soared. Next year’s product prices look like being just as strong, with supplies just as tight as they are now: not just in the US, but across the world as well.

THE MONTH IN BRIEF

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

Record oil prices, more violence in Iraq and (some) oil companies in trouble

Oil prices moved into uncharted territory as demand soared and supply was squeezed. Nervousness about Iraq, Russia, low stock levels and a world refinery system under severe strain (see ‘Focus’) propelled WTI above $49 a barrel in the second half of August. Product prices were equally strong. European gasoil prices topped $400 per tonne for the first time ever as Russian gasoil exports faltered. Kerosine and naphtha prices also went up sharply on strong demand: only heavy fuel oil failed to take part in the outbreak of summer price madness. Eventually, however, the new price records proved unsustainable–at least, for now–and prices fell back, leaving WTI around $43.

Iraq continued to occupy the market’s attention as violence and unrest remained at a high level. Pipelines were attacked, disrupting output from several fields. Exports from Kirkuk were interrupted until 21st August, when the damaged pipeline to Ceyhan in Turkey was repaired. Flows were nevertheless only restored to 40% of the line’s 1.2 mn bpd capacity. Attacks damaged pipelines elsewhere in the country, affecting production in the Rumailah and West Qurnah fields. Oil supplies were interrupted to the Daura refinery, near Baghdad, and to Iraq’s crude export terminals in the Persian Gulf. Further disruption occurred as a result of a Shi’i uprising in southern Iraq centred on the Shi’ite holy city of Najaf. As fighting between the Shi’i and US-led government forces spread, the South Oil Company, which is responsible for production from the country’s southern fields, reported attacks by Shi’i on some of its installations. Exports from the south were reported at 900,000 bpd at the end of August: less than half their normal level. To add to Iraqi woes, a report by the Inspector-General of the US-led Coalition Provisional Authority (CPA) claimed that nearly $9 bn of oil and other revenues handled by the CPA could not be properly accounted for.

High oil prices have boosted the incomes and share prices of oil companies (see Tables 24a and 24b). Some, though, have not benefited quite so much from this year’s bonanza. In Russia, Yukos continues to flounder (see ‘Looking Ahead’, August 2004) following the freezing of its bank accounts, which caused oil traders to mark up crude oil prices by $1 a barrel. Shell will need some of its extra revenues to pay fines imposed by the UK’s Financial Services Agency (FSA) and the Securities and Exchange Commission (SEC) of the US for overstating its oil and gas reserves (see ‘The Month in Brief’, February 2004 and passim). The FSA, in a particularly strong ruling, referred to “market abuse” and “unprecedented misconduct”. Shell may now be sued by disgruntled private investors. There was better news for ExxonMobil after it managed to head off a strike threatening its 600,000 bpd Nigerian oil and condensate production.

Argentina fared less well in this respect. Crude oil exports were cut by 55% to 100,000 bpd following unrest at the main export terminal. The US has announced that its Strategic Petroleum Reserve will be within 3% of its long term target volume of 700 mn bbl by April next year. India meanwhile has announced a more modest plan to establish a strategic stockpile of 37 mn bbl. Japan’s Idemitsu Kosan is to reopen its 133,000 bpd Tomakomai refinery on Hokkaido, which was damaged last year in an earthquake. ExxonMobil and Saudi Aramco have announced a feasibility study on a retailing joint-venture with state oil company Sinopec in China’s Fujian province. The fuels will come from a proposed refining and petrochemical complex which the US and Saudi partners are planning there. Shell is to sell its 64% share in the Rayong refinery in Thailand to the Thai national firm, PTT. The world has a new futures contract. Shanghai Futures Exchange launched its heavy fuel oil contract on 25th August. The contract is denominated in yuan per tonne. Several airlines have announced fuel surcharges to compensate for higher kerosine prices.

GAS AND POWER

British gas prices up; but for how long?

The UK’s main gas supplier, BG, announced a controversial 12.4% price rise in August with the words that the era of cheap energy was over. Other suppliers have warned of steep price rises in both gas and electricity prices as the UK’s gas production declines and is replaced by more expensive foreign imports. Many consumers disagree with this analysis, saying that the British gas market is inefficient. Some even go so far as to claim that gas suppliers have been involved in price-fixing.

BG’s latest price rises are not expected to be the last by any means. Industrial consumers are bracing themselves for increases of up to 50% for both gas and power. One of the country’s largest energy consumers has admitted privately that it may have to shut down some of its operations during this winter’s peak pricing period.

Gas prices were rising sharply even before BG announced its new prices. Last year, spot prices were as low as about $2.70 per mn BTU. Recently, they were running at double that amount and winter prices are expected to be in the region of $9.00 per mn BTU.

Shortage of gas

Much of the current argument about gas prices is based on the notion of future shortages. It is further argued that such shortages must be met from expensive foreign imports: hence gas prices must go on rising. This argument, however, confuses two separate issues that are both dealt with under the heading of ‘shortages’.

Table F
UK: Gas reserves and balance, 2003

Reserves
Proven Reserves:	22.2 trillion cf
Reserves:Production:	6:1
Gas Balance
Production	9.9 bn cfd
Consumption	9.2 bn cfd
Net Exports	0.7 bn cfd

Source: BP Statistical Review of World Energy, 2004

The UK is at present an net exporter of gas (see Table F). Despite the low reported level of proven reserves, output should not fall sharply over the next 2-3 years since high prices are likely to encourage British gas producers to increase their recovery levels. At the same time, demand is unlikely to rise by very much without an extension of the distribution network. Gas consumption has, in fact, declined by 2% since 2000. If, on the other hand, the UK were to become a net importer, any volumes likely to be required could be supplied by existing suppliers (see Table G) using existing pipelines.

Where there could well be a shortage, however, is amongst industrial and commercial users during the winter, especially if the weather were to be exceptionally cold. The UK finds it difficult to meet such surges in demand owing to the lack of storage. The system tends to rely on extra imports from Europe during peak demand, and it is these that can prove expensive.

Table G
UK: Gas Trade, 2003

	Volume
	(mn cfd)
Exports
Belgium	165
France	125
Germany	395
Ireland	360
Netherlands	425
Total	1,470
Imports
Germany	40
Netherlands	45
Norway	640
Total	725

Source: Cedigaz

Foreign gas

The UK will eventually become a net importer of gas, perhaps in about 3 years. By then, though, there should be plenty of foreign gas available from some of the many projects aimed at supplying the UK with gas from 2005 onwards. The first is likely to be the upgrading of the line known as the Interconnector which links southern England with Zeebrugge in Belgium. This line can operate in both directions to allow the export of British gas when continental prices are high ands vice versa. Capacity increases are planned for 2005-6.

In addition to this, there are plans for two new lines under the North Sea: one from Norway, the other from the Netherlands. The Norwegian line is designed to pipe gas from the giant offshore Ormen Lange field to the north of England. If the line is completed as planned, it could supply some 2 bn cfd from about 2007. The Dutch proposal is for a 1 bn cfd line from 2006 onwards. Added to these two lines is the Interconnector which, by 2007, should be capable of carrying over 2 bn cfd.

Pipelines, however, are not the only projects on the drawing-board. There are proposals for at least three LNG import terminals: one of 385 mn cfd at the Isle of Grain, near London, and two at Milford Haven in west Wales. The first of these could have a capacity between 580 and 870 mn cfd; the second could be as large as 1.9 bn cfd. All three could be in operation by 2009. By the following year, Russia’s Gazprom says it wants to have a 2.9 bn cfd pipeline connecting Russia, Germany and the UK.

If all these projects were to go ahead as planned, British consumers would have potential imports of 11.3 bn cfd available to them by about the end of the decade: not a shortage by any stretch of the imagination. Some projects almost certainly will not go ahead as planned, either being cancelled, postponed or cut back in size. That still leaves the UK with plenty of foreign gas in addition to its own, albeit declining production. The UK is even likely to be exporting gas in 2010, despite being a net importer by then. The Interconnector could well be in use as an import and export route as now, but with some of the gas being provided by Norway via its North Sea pipeline links to the British gas transmission network.

None of these developments, however, will prevent seasonal shortages from occurring. The only answer to these is more storage. There are signs that this too may increase. New underground storage facilities are planned in four areas in England and LNG terminals will have further storage of their own. Lower, not higher prices should be the outlook for the British gas market over the next few years.

LOOKING AHEAD

Europe struggles with new sulphur rules

Plans by the European Commission to reduce sulphur levels in petrol and diesel across the EU are unlikely to be realised on time. The Commission wants the sulphur content of both fuels to be reduced to 50 parts per million (ppm) by 1st January, 2005. Some Mediterranean refineries have indicated, however, that they will not be ready to produce material of that standard by then. The EU is not the only area planning to reduce sulphur levels (see ‘Focus’, May 2004). One further complication connected with lower sulphur limits in refined products is the likelihood of a growing surplus of sulphur recovered from the fuel.

Cutting sulphur

The EU’s sulphur reduction is part of a wider programme to improve motor fuel specifications, known as Auto-Oil. The process began in January 2000 and is due to be completed in 2009 (see Table H). As well as reducing the sulphur content of petrol and diesel, it also seeks to bring down the levels of other pollutants and to set uniform octane and cetane levels.

Table H
EU: Motor fuel specifications (Auto-Oil)

	Auto-Oil I	Auto-Oil II
	(1.1.00)	(1.1.05)	(1.1.09)
Petrol
Octane number (RON)	95	95	95
Octane number (MON)	85	85	85
Sulphur (% wt)	0.015	0.005	0.001
Aromatics (% vol)	42	35	35
Benzene (% vol)	1	1	1
Diesel
Cetane number	51	51	51
Sulphur (% wt)	0.035	0.005	0.001

NB: Octane and cetane levels are minimum levels; other levels are maximum levels

Source: European Commission

The aim of the Auto-Oil programme is to move to what are described as ‘sulphur-free’ fuels by 2009. These will have a maximum sulphur content of 10 ppm. This limit will be officially introduced on 1st January, 2009, but the EU wants to see such fuels in use before then. Germany has had 10 ppm petrol and diesel available since 2003, and filling stations in the UK now offer sulphur-free fuel. Under the
Auto-Oil II provisions, 10 ppm petrol and diesel are supposed to be available across the EU from next January.

Some EU refiners have protested that they will be unable to produce the new fuels by 2005. Most of the problems appear to be in southern Europe. If some Mediterranean countries are to comply with the new rules, they will almost certainly have to import some of their fuel supplies from northern Europe.

Disposing of sulphur

The EU is now working on proposals to reduce sulphur levels in other fuels, including heavy fuel oil, where the limit could fall from 3.5% to 1.5%, with even lower limits in certain areas, such as the Baltic (see ‘Looking Ahead’, June 2004). Some European refiners have also expressed reservations about these new limits.

The EU’s proposals are part of a worldwide process of bringing down sulphur levels in automotive and other fuels. Most industrialized countries are aiming for levels in petrol and diesel of between 10 ppm and 50 ppm over the next few years. Recently, Chinese officials hinted at much lower limits there. The government’s Automotive Technology and Research Centre is due to report on motor vehicle emission levels sometime next year, when it might well suggest new national fuel standards.

All these moves on sulphur, though, mean that the production of sulphur worldwide will increase. Whilst sulphur can be mined from deposits of naturally-occurring material, around 90% of the world’s sulphur production comes from the processing of oil and natural gas. Sulphur is used in the manufacture of fertilizers and other chemicals, tyres, paper, pharmaceuticals and some road and building materials. Demand for sulphur, however, is growing only slowly. As more and more sulphur is removed from refined products, the supply of sulphur looks set to outgrow demand.

World consumption is about 60 mn t/y. Production of sulphur, however, is running at around 62 mn t/y. At current rates of extraction by the oil and gas industries, supply could well exceed demand by 5 mn t or more by 2010. Disposal of sulphur has already begun to cause problems for some oil companies. In Kazakhstan, TengizChevrOil (TCO) managed to accumulate a 5 mn t stockpile of sulphur from its production of sour crude there. TCO’s solution has been to build a plant to turn the sulphur into pellets. The problem of disposing of sulphur from upstream operations has nevertheless made some oil firms wary of developing other high sulphur oil deposits in the region.

Several major producers of sulphur have been forced to stockpile sulphur and mines have closed down. Some relief for producers has come from China, which has imported large quantities; but a worldwide surplus remains. The oil industry needs to try and find more new markets for sulphur; or else it faces rising costs in stockpiling or otherwise disposing of sulphur. Some small refineries may even be forced to shut down. The industry’s task is unlikely to be easy. World crude oil production is becoming increasingly heavy and higher in sulphur (see ‘Focus’). The latest moves to remove more sulphur from refined products could prove just too much to bring world sulphur markets back into the balance.

World’s refinery system comes under severe strain