FOCUS

EU gas market liberalization threatened by pricing issue

The European Union (EU) is becoming increasingly dependent on imports for its gas supplies as demand grows and production falls. Imports are mainly supplied under long term contracts between large, often state-owned producing companies and large European utilities. Under these contracts, the price of the gas is linked to that of oil. Not surprisingly, the price of Europe’s gas has risen substantially this year. The EU Commission believes that gas prices could be brought down if wholesale gas prices were based on competition within the gas market. The main sellers and–perhaps, surprisingly–many large gas importers are resisting the introduction of gas-on-gas pricing, threatening the Commission’s plans to liberalize the gas markets across the EU.

Import dependency

Demand for gas is growing rapidly in the 15 countries that constituted the EU in 2003 (EU15). Over the past 10 years, consumption has risen by 3.7% annually: more than five times the rate recorded by oil. At the same time, however, production of gas in the EU has gone up by only 1.7% a year and, since 2001, has been in decline. Imports, which represented 37% of consumption in 1993, now account for around 48% (see Table A)

Table A
EU15: Gas balance, 1993 v 2003

	1993	2003
	(bn cfd)
Consumption	27.1	39.1
Production	17.1	20.2
Net Imports	10.0	18.9
Import Dependency	37%	48%

Source: BP Statistical Review of World Energy, 2004

NB: Figures refer to the 15 EU member-states of 2003 and exclude the 10 countries joining in 2004

The consumption of natural gas has been encouraged by a number of factors. At the end of the 1980s, it began to become evident that there were enormous supplies of gas potentially available from the North Sea and from other regions that were reasonably close to Western Europe, such as Russia and North Africa. This helped to bring about a change in energy policy across much of Western Europe. Up to then, most governments there regarded natural gas as a scarce commodity. Its use tended therefore to be restricted to the household sector. The large scale industrial use of gas was seen as wasteful, and EU regulations prohibited its use in power stations. Gas producers tended to go along with the view that it should be reserved for premium uses, since this helped to keep gas prices high. The Netherlands, which was then the EU’s largest producer, even restricted exports, arguing that the country’s gas surplus was purely a temporary phenomenon.

The change in attitude from one of gas scarcity to a notion of an abundance of supply prompted a change in thinking about prices, as well. It began to be thought in some countries, notably Great Britain, that abundant supplies could bring down gas prices substantially. In order to encourage such a development, the government began to liberalize the wholesale and retail markets by ending the monopoly of the state-owned British Gas Corporation and allowing private gas suppliers to compete with British Gas for customers.

Gas consumption was also promoted by changing environmental attributes. Regulations were introduced to cut emissions of carbon and sulphur, which discriminated against the burning of coal and oil. Nuclear power meanwhile received a severe blow from the accident at Chernobyl in the USSR. Some countries began to phase out nuclear power: only France and Finland remained faithful to the idea of nuclear generation. Even hydro-electric power came under attack from environmentalists because of its effects on plants and animals. Everything was set for a revival in gas consumption.

Production from the British sector of the North Sea more than doubled between 1991 and 2000, rising from 4.9 bn cfd to 10.5 bn cfd. By contrast, output in the Netherlands, where gas depletion policies were much more conservative, stagnated in the 1990s before declining from 1996 onwards. By the next decade, though, output was in decline across the EU and even net exporters like Great Britain were in decline. Europe’s gas buyers were being forced to look ever-further afield for supplies: to the Middle East, West Africa, the Caribbean and even Australia (see Table B).

Gas consumption is unlikely to keep on growing at recent historic rates as prices rise and Europe starts to treat gas once more as a scarce commodity. An annual growth rate of 2.5% will nevertheless produce a demand total for the EU15 of 46.5 bn cfd by 2010: some 7.4 bn cfd above last year’s total. Production, on the other hand, could well be about 15.0-16.0 bn cfd, leaving 30.5-31.5 bn cfd to be imported, compared with 18.9 bn cfd in 2003. Most of this could probably be sourced from existing suppliers, notably Russia, North Africa and Norway. Beyond 2010, though, a supply gap begins to emerge which can probably only be eliminated by a sharp rise in long haul imports of liquefied natural gas (LNG) or a levelling-off of gas consumption.

Table B
EU15: LNG imports, 2003

Importer		Supplier
	Trinidad & Tobago		Oman	Qatar	UAE	Algeria	Libya	Nigeria	Australia	Total
	(mn cfd)
Belgium						305				305
France						890		65		955
Greece						53				53
Italy						195		338		533
Portugal								82		82
Spain	8		31	181	23	723	73	408	8	1,455
Total	8		31	181	23	2,166	73	893	8	3,383

Source: BP Statistical Review of World Energy, 2004; Cedigaz

NB: Figures are for contract volumes only

Pricing gas

An important factor in determining the future rate of growth in gas consumption will be the price of gas and this, in turn, will depend on how it is traded between the major sellers and Europe’s large buyers. The most important price indicators for much of the EU are provided by the long term contracts between the main importers and producers. These usually last for 20 years or more and require the buyer to commit to take 90-95% of the volumes specified throughout the contract. These provisions are known as take-or-pay. Prices, gas volumes and other details are specified in considerable detail and such contracts are highly complicated documents. Their full provisions are seldom revealed and this opaqueness is often criticized by the EU authorities as inhibiting the development of fully competitive markets.

The sellers are normally state-owned or partly state-owned producers, such as Norway’s Statoil, Russia’s Gazprom and Sonatrach of Algeria; or LNG consortia consisting of state oil and gas companies and international oil and gas majors. Buyers tend to be large, integrated utilities, sometimes state-owned, like Gaz de France, or private companies like Germany’s Eon (see ‘Gas and Power’, October 2004).

The contracts themselves contain various prices depending on the conditions under which the gas is delivered. Prices consist of a base price, which is then linked to the price of other commodities, usually oil. The oil price element might be gasoil, heavy fuel oil, crude oil or some combination of these. This indexation allows the seller an automatic increase in prices during the period of the contract as long as the oil price goes up as well.

Buyers seem also content with the idea of a steady long term increase in prices since they normally have sufficient dominance of their regional markets to enable them to pass on higher prices to their customers. The EU Commission wants to end such single company dominance in markets like France, Portugal and parts of Germany, and to replace it with a competitive market like that in Great Britain. At the same time, it wants to reduce the role of oil price-linked supply contracts and introduce gas-on-gas competition as the way of setting wholesale prices.

Adopting the British model

Deregulation of the British market began in the 1980s, when the government ended the monopoly of the state-owned British Gas Corporation and the regional gas boards and unbundled the Corporation into three separate companies, British Gas, Centrica and Transco, covering respectively the upstream sector, supply & trading, and gas transmission. These three companies were then privatized, along with the gas boards, which were responsible for distribution and retail sales. Customers were allowed to choose their own supplier and suppliers were granted access to the country’s pipeline network. A spot market in gas grew up in response to the entry of a large number of new suppliers, many of which did not have production, storage or pipelines of their own. An industry regulator was appointed to oversee the restructured industry.

The introduction of spot markets, a futures market and other derivatives helped to bring about gas-on-gas competition. Gas prices fell over several years, British North Sea output more than doubled, turning the UK into the world’s fourth-largest producer of natural gas. An interconnexion with the continent allowed British spot gas to be exported to Western Europe, providing cheaper competitive supplies in some markets.

The European Commission began to propose a similar model of deregulation for the rest of the EU, as part of a wider effort to create a single market in energy. In May 1998, it issued a Gas Directive, providing a timetable for the gradual opening-up of all EU markets to competition as follows:

Year	Minimum Level of Gas Market to be Liberalized
2000	20%
2003	28%
2008	33%

Some countries already had greater degrees of market-opening by 2000 than those specified in the Directive. Great Britain became 100% liberalized in August 2000. Germany had also begun to adopt some of the measures outlines in the Gas Directive before 2000, though not those relating to open access to pipelines (see ‘Gas and Power’, October 2004). Denmark declared it would open its markets at a faster rate than that required by the Directive. Other countries, though, were less accommodating. Portugal and Greece sought 10-year exemptions (known as ‘derogations’) from the Directive, whilst France more or less resisted the entire process.

Table C
EU15: Pipeline imports, 2003

Country	Suppliers			Total
	Norway	Russia	Algeria
	(mn cfd)
Austria	87	542		629
Belgium	566			566
Finland		468		468
France	1,286	938		2,224
Germany	2,554	3,459		6,013
Great Britain	639			639
Greece		145		145
Italy	677	1,908	2,074	4,659
Netherlands	280	135		415
Portugal			242	242
Spain	221		619	840
Total	6,310	7,595	2,935	16,840

Source: BP Statistical Review of World Energy, 2004; Cedigaz

NB: Figures are for contract volumes only

The British model was regarded by many continental countries as inappropriate for their markets. Several countries had long-established, vertically-integrated, national gas utilities owned and operated by the state. These dated form the era when natural gas was seen as a scarce resource and they were seen by their governments as essential to ensuring the security of future gas supplies. Market mechanisms were viewed with considerable suspicion. Some countries, like France, tended to regard their large state utilities as national champions, and were as a result reluctant to contemplate their unbundling into separate companies focused on one main sector of the gas business; let alone their sale to private, and possibly foreign investors.

Privatization was not seen by the EU Commission as an integral part of the liberalization process. Market deregulation, however, often obliged publicly-owned companies to raise new capital in order to restructure their operations to make them more competitive. This affected some of the smaller continental utilities, such as the many hundreds of municipally-owned distribution companies in Germany and elsewhere.

It rapidly became obvious to the EU Commission that certain countries might seek to derail the liberalization programme completely and so several attempts were made to speed-up the process. The Commission finally decided that gas markets in the EU15 should be 100% liberalized by 1st July, 2007. some derogations were allowed for the 10 countries joining the EU in 2004 (see ‘Focus’, November 2003).

Towards a liberalized Europe

Gas markets remain unevenly deregulated across the EU. Only seven countries–UK, Germany, Denmark, Italy, Spain, Austria and the Netherlands–are officially 100% liberalized. Within this group, however, there are varying degrees of actual competition. In some countries, market opening has led to little change in patterns of gas buying. In Germany, for example, fewer than 5% of large industrial consumers have changed suppliers. There has been rather more switching of suppliers in Spain and the Netherlands, and most switching in Great Britain.

Spot trading has also been slow to spread from the British mainland to the rest of the continent. About a quarter of Great Britain’s gas trade is conducted via the spot market. No continental country comes near this proportion. The main spot markets on the continent are close to the pipeline connecting Bacton in Eastern England to Zeebrugge in Belgium. The Interconnector, as it is called, allows spot gas to be traded in both directions.

Continental spot markets exist based on the pipeline and storage hubs of Zeebrugge on the Belgian-Dutch border at Zelzate, on the Belgian-German border at Aachen and on the German border with the Netherlands at Bunde-Oude. The last-mentioned is particularly appropriate as a spot pricing point since it is the meeting point for gas flows from the Netherlands, Germany, Norway and Russia, and also possesses gas storage facilities nearby.

Continental pricing nevertheless remains dominated by opaque long term contracts between large buyers and sellers. Gas prices therefore are linked to oil rather than being based on gas-on-gas competition, as the EU Commission wants. This state of affairs looks like continuing for some time.

Spot trading requires good transmission across the EU with non-discriminatory third party access (TPA) to gas grids. Although links do exist between most grids, they are mostly inadequate to accommodate a lively spot trade in gas. Moreover some parts of Spain and Portugal and the whole of Greece remain separate from the main EU transmission system. In the key German market, TPA is not operating smoothly (see ‘Gas and Power’, October 2004). Transmission tariffs in France make competitive spot trading all but impossible in most of the country (see ‘Gas and Power’, July 2004).

Different gas specifications across the EU also inhibit spot trade across national boundaries. In countries still dominated by large, vertically-integrated gas companies, spot traders can find it difficult to gain access to gas. The EU has tried to circumvent this by obliging the integrated utilities to resell some of their contract gas, but such sales only involve small volumes. The large buyers and sellers themselves can restrict spot trading further by not participating in it themselves to any great extent. Ma

Full-blown competition across the EU is unlikely without further standardization across gas markets. The European Commission is pressing for uniform rules on TPA, and there will probably have to be greater physical access between individual countries’ gas grids. Attitudes to liberalization, however, may be about to change in some countries as gas production falls and imports rise. Large importers (see Tables B and C) may see long term contracts with large suppliers as a better way of ensuring their future energy security than leaving everything to the market.

THE MONTH IN BRIEF

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

More price records, more Iraqi chaos and heavy Americans

Oil prices rose steadily during October on fears of winter supply shortages. US crude prices were boosted by the loss of over 450,000 bpd of production from the Gulf of Mexico, which the release of 4 mn bbl of crude oil from the Strategic Petroleum Reserve (SPR) failed to offset. The announcement by OPEC of higher production did little to calm market nerves, since the extra oil was predominantly heavy and sour, whilst demand was mainly for light, sweet crudes. Exports from Nigeria, OPEC’s main producer of light, sweet crudes, were threatened by the announcement of a general strike (see ‘Looking Ahead’). US light, sweet marker, WTI, hit a record $55.67 during trading on 25th October. Two days later, Brent reached an all-time high of $51.95 a barrel. Sour crude prices. by contrast, were little changed over the month, causing the sweet/sour crude differential to widen considerably. WTI ended the month more than $15 a barrel above Dubai, compared with some $3 a year ago. Product prices also set new records. In London, IPE gasoil rose above $500/t, while heating oil in New York breached $1.60 a gallon.

The effect of four months of sharply rising prices finally appeared to be making itself felt on oil demand. US gasoline demand posted a year-on-year fall of 1% in October. Middle distillate sales in Japan were also reported down versus a year ago. Heavy fuel oil consumption was lower in various markets. At the Canton Fair, Chinese manufacturers told of a slowdown in demand for their goods caused by the increase in oil and raw material prices. A rise in Chinese interest rates also looked like dampening the growth in demand. Germany’s chambers of commerce and industry reported that high oil prices were threatening the country’s economic recovery. France’s finance minister, Nicolas Sarkozy, announced $300 mn of support for road hauliers and other commercial fuel users and hinted of fuel tax cuts for all consumers, to the consternation of other EU finance ministers, who feared pressure from their own people for similar action.

Following the re-election of George W Bush as US president, American troops stormed the Iraqi rebel stronghold of Fallujah. Much of the rest of Iraq remained in a state of chaos. Attacks on three pipelines in the north of the country stopped exports to Ceyhan in Turkey and cut supplies to the country’s largest refinery, at Baiji. Previously, the 1 mn bpd Turkish export pipeline had been operating at 30% of capacity. A report by the US Central Intelligence Agency (CIA) exposed widespread corruption in the operation of the UN-administered oil-for-food programme that regulated Iraq’s exports of crude oil from 1995 until last year’s US-led invasion. The British government was reported to be offering to help Iran–tipped as a future US invasion target–to develop a civilian nuclear power programme in return for Iran’s abandoning its programme to develop nuclear power.

France has announced plans to build the first of a new “third generation” of nuclear power stations, starting with a 1.6 GW unit at Flammanville in Normandy from 2007 onwards. France’s 58 nuclear reactors generate about 78% of the country’s electricity. Investors oversubscribed a share offering by the Italian government of 20% of the national power utility, Enel. The sale of 45% of the partly state-owned electricity grid company, Terna, was also announced for 2005. Oil companies, including BP, announced large quarterly profits following the recent rise in oil prices amid criticism that they were charging too much for petrol and other fuels. There was more trouble for Shell as the company’s head of exploration and development cast doubt over some 900 mn boe of reserves, following other downward revisions earlier this year (see ‘The Month in Brief’, July 2004 and passim). The largest distributor of heating oil in the US, Star Gas Partners, warned it might seek bankruptcy protection after sales fell in the wake of rising prices. Some US airlines are planning reductions in services in order to cut costs following the rise in jet fuel prices. In a further blow to their cost-base, a US government survey has revealed that rising obesity amongst passengers is forcing the airlines to burn an extra 23,000 bpd of fuel.

GAS AND POWER

Camisea development boosts Peru’s gas use

The commissioning of Peru’s Camisea natural gas project in August will enable gas use there to rise considerably. Most of the gas will be used initially for power generation, which the government has sought to promote in conjunction with the scheme. The field is being developed by a consortium led by Argentina’s Pluspetrol in conjunction with another Argentinian firm, Techint, Algeria’s Sonatrach, South Korea’s SK Corporation and Hunt Oil of the US.

Major project

The Camisea project has involved the development of a gas field in the Amazon region and the building of a trunk pipeline across the Andes to the coastal cities of Lima and Callao. The cost of the project is put at $1.6-1.7 bn.

The development of Camisea has suffered a number of setbacks, including opposition from environmentalists, fierce arguments between central and local governments about how revenues should be shared out amongst them, problems over financing, and the departure of Shell from the consortium developing the field. Despite all this, it came on stream four days ahead of schedule on 5th August.

Camisea is a major find. Reserves are estimated at 13 trillion cf and a second phase is already planned. Output from the existing phase is around 250 mn cfd, though not all of this can be marketed at present. Potential demand in the Lima-Callao region is somewhere in the region of 150 mn cfd. The largest supply contract signed so far is for 50 mn cfd, to be delivered to the power company Etevensa, which is owned by Spain’s Endesa.

The government is trying to encourage power generators to switch from coal and oil to gas from the Camisea project by offering tax concessions to utilities that do so. As well as wanting generators to stop using imported fuels, the government is keen to reduce the country’s reliance on hydro-electric power. Hydro-electricity normally accounts for about 90% of the country’s generating output, but operating rates have been reduced by water shortages.

Power investments

Peru may struggle to find investors in new gas-fired generating capacity. Power investment has been falling since 1991, when it reached $710 mn. Last year, it plummeted to less than $200 mn. Foreign investors blame political problems and the country’s electricity pricing regime for the decline (see ‘The Month in Brief’, June 2004). One large investor, Duke Energy of the US, has been involved in a long-running dispute over a tax claim.

The government is now trying to raise money for power investment by selling state shareholdings in electricity transmission companies. This year, it has offered stakes for sale in ISA Peru in the centre of the country, Red Electrica del Sur (Redesur) which operates the main grid in the south, and in a small Andean transmission company, Empresa Transmantaro.

Some of the royalties from the Camisea gas project are also being earmarked for electricity developments. These are likely to be primarily in the Cusco region, where the gas is produced.

Gas exports

The lack of large gas users, such as power generators, is forcing the Camisea partners to reinject gas into the reservoir at present. The economics of the field therefore depend mainly on the sale of liquids recovered from the gas. The project produces some 33,000 bpd of condensate and liquefied petroleum gas, which are piped to the coast and recovered from the wet gas before being sold domestically or exported to the US and Latin America.

Camisea has the potential to produce much more gas than the domestic market can absorb. A second phase is therefore planned to provide some 700 mn cfd of exports by about 2008.

Gas from this phase will be exported as liquefied natural gas (LNG), with Mexico and the US as the prime target-markets (see ‘Focus’, August 2004). Peru, however, has agreed to act as a conduit for LNG exports from its land-locked neighbour, Bolivia, which is also targeting the US and Mexico (see ‘Gas and Power’, May 2004).

The Camisea partners have experienced some difficulty in signing-up foreign LNG buyers. One potential Mexican buyer, Belgium’s Tractebel, failed to win a tender to build a regasification plant at Lazaro Cardenas in Mexico, causing some doubt about its future ability to import gas into Mexico. The company that did win the tender, Spain’s Repsol, is trying to promote LNG exports from Bolivia. Bolivia’s gas producers, on the other hand, say that the proposed export route to Ilo in Peru is too expensive.

Both schemes, on the other hand, could benefit from a proposal to increase the capacity of the Panama Canal. At present, standard LNG carriers are unable to use the canal, but wider locks could enable LNG vessels loading at terminals on the Pacific to serve receiving terminals in the US Gulf and along the US Atlantic Coast, where most US terminals are likely to be located (see Global Energy Review: The USA and the Quest for Energy Security, Table 20).

More hydro-electricity?

In the short term, the Camisea project is meant to provide natural gas for the domestic market, thereby enabling the country to reduce its dependence on expensive coal and oil and unreliable hydro-electric power. Around 90% of the gas from the first phase of development has been earmarked for ,power generation.

Power companies are nevertheless continuing to plan and build new hydro-electric stations. Tractebel is building a 130 MW plant at Yuncan, while Duke Energy’s Engenor subsidiary is extending its 250 MW Canon del Pato hydro-electric scheme. Another company, Cahua, owned by Norway’s SN Power, is also raising capacity. New gas-fired stations may take some time to appear.

LOOKING AHEAD

Nigeria struggles with tensions over oil

Following a wave of protests against an increase in the price of petrol, Nigeria’s main trades unions have called for a general strike from mid-November. Previous labour disputes have disrupted the production of crude oil and refined products, adding to international nervousness about global oil supplies. The labour unrest is part of a much wider conflict between Nigeria’s rich urban elites and the two-thirds of the population, mainly rural, who live on less than $1 a day. Tensions are particularly high in the Niger Delta region, where most of the country’s oil is processed.

Nigeria’s divisions

Nigeria’s economy is overwhelmingly dependent on revenues from the export of crude oil, which make up 95% of the country’s foreign earnings. Much of the oil income, however, has been siphoned off into the two main cities of Lagos and the new capital, Abuja, leaving the rural areas, where around 65% of the population still lives, impoverished. Revenues from crude oil exports have not even been reinvested in other parts of the oil industry, leaving Nigeria chronically short of refinery capacity and with poor distribution facilities. Even the crude oil industry itself is plagued by infrastructural problems such as leaking pipelines and poor storage facilities.

The country’s four refineries have a combined capacity of 440,000 bpd, but run at less than 45% of their capability, leaving Nigeria to import large volumes of refined products at international prices (see Table D), which are then sold inside the country at below-market prices. The government wants to end this system of subsidized prices and has therefore proposed to raise fuel prices. The most recent increase, which saw motor gasoline rise by 22% to just over $1.80 a gallon, was the main cause of the present labour unrest.

Table D
Nigeria: Oil balance, 2004

	(th bpd)
Production	2,350
Consumption
Refinery production	195
Product exports	85
Product imports	125
Total consumption	235
Crude oil exports	2,155

Source: OET estimate, Jan-Oct ’04

The government’s opponents point to the rise in oil revenues this year resulting from record oil prices. The state’s income is likely to be about $4.5 bn higher than originally forecast this year. The government says it is ploughing large sums of money into the Delta region for infrastructure improvements, but its hand has been stayed to some extent by opposition from the Muslim north of the country to further payments to the mainly Christian oil-producing areas in the south. Another problem is the widespread corruption in Nigeria, which causes large sums of government money to be diverted to the pockets of politicians and their supporters.

Oil reforms delayed

One of the areas requiring reform is the oil industry itself. The government has tried to improve the operation of the domestic oil market by deregulating parts of the downstream, industry, but has made only moderate progress. Plans to reduce subsidies on refined product imports, which last year amounted to $500 mn, have been threatened by strikes and other unrest each time product prices go up. Nigeria has also struggled to attract investment in its decrepit refining and distribution sectors. Poor fuel distribution in rural areas leads to constant shortages. Potential demand for refined products is estimated to be about 40% higher than actual demand.

The government has tried to improve distribution nationally by allowing private firms to compete with the state-owned Nigerian National Petroleum Corporation (NNPC). It is also attempting to reduce corruption connected with the import of refined products. Politicians have been using their influence to secure import licences for small local companies in return for pay-offs from the importers. NNPC, which awards the import contracts, has said it will only award future contracts to large, mainly international firms.

NNPC itself is due for reform, with restructuring and privatization both on the agenda. One important proposal is for the national oil company to lose many of its monopolistic powers in the downstream market in order to attract investment in infrastructure from new participants. This will probably involve the break-up of NNPC’s main downstream subsidiary, the Pipeline and Products Marketing Company (PPMC), turning it into a transport company with open access to its pipelines and terminals. The government also wants to see private, probably foreign investment in the country’s ailing refinery sector. Some oil companies and banks have already expressed interest in the idea. Trades unions and other groups, however, have expressed opposition to the idea.

Troubles upstream

Even more controversial are proposals by outside consultants to bring parts of NNPC’s upstream operations under the Ministries of Finance and the Environment and to increase the role of the Ministry of Petroleum. At present, NNPC is largely controlled by the country’s president, Olusegun Obasanjo.

Much of the current upstream attention, however, is on Nigeria’s foreign oil producers, which have attracted the ire of the nation’s poor for the state of the rural economy, especially in the oil-producing regions. Shell appears to have drawn most of their fire. The company has been blamed for a series of oil spills and criticized for not doing enough to relieve local poverty and corruption. The Nigerian Labour Congress has called Shell the “enemy of the Nigerian people”, accusing it of siding with the government “to oppress our people”. Shell has attracted further opposition from the trades unions for its plans to cut its Nigerian workforce as part of a cost-cutting drive. Nigeria wants to raise its oil production from 2.4 mn bpd to 3.0 mn bpd by 2007. Oil reserves should pose no obstacle to this target. What Nigeria really needs to do is to impose some stability on its oil industry.