After many years as a major producer and net exporter of natural gas, the United Kingdom faces the twin prospects of a sharp decline in its output and the need to find substantial volumes of gas to import. The British government, meanwhile, appears curiously relaxed about the imminent arrival of net importer status. There is little sense of urgency about the need for an infrastructure to handle future imports of gas and, with perhaps as little as two and a half years to go before self-sufficiency disappears, the government has decided to downgrade the role of minister of energy by making it a part-time appointment. Energy companies are paying rather more attention to the problem, but many participants in the British energy market lack the financial resources to develop an import infrastructure on the scale that is likely to be required. The British market was the first in Europe to deregulate, leading the way for the rest of the European Union. Entry barriers were lowered in order to create a highly diversified market containing many small and medium-sized players: in contrast to the large state monopolies that operated across much of Western Europe. Following the British example, the European Commission promoted the deregulation of markets across the EU and encouraged new market entrants to take on the giant state monopolies on the Continent. After a number of years in retreat, however, the former state monopolies may be about to experience a revival and, what is more, experience it in the country where the challenge to their monopoly privileges began. Europe’s giant utilities may be the only companies that can provide the import infrastructure quickly enough to keep the gas-burners alight in the UK.
The UK has been an important gas producer since the early 1970s, when production from the North Sea began to take off. In 2002, it was the fourth-largest producer in the world, after Russia, the USA, and Canada, with an output of 11 bn cfd (see Table A) and net exports of 900 mn cfd. Reserves, on the other hand, were a much more modest 25 trillion cubic feet (tcf): sufficient for only seven years’ production at existing levels.
The low level of reserves combined with the fact that the UK is a mature producer suggest that the UK will experience supply problems within a few years. Output, indeed, is already in decline, having peaked in 2000 (see Table 5.2b). Demand, however, continues to rise, and self-sufficiency looks set to end sometime between 2005 and 2007. Demand has been driven in recent years principally by power generation, where gas has been substituted for coal and oil.
Table A |
|
UK: gas balance, 2002 |
|
| (bn cfd) | |
| Production: | 11.2 |
| Consumption: | 10.3 |
| Exports: | 1.4 |
| Imports: | 0.5 |
| Net exports: | 0.9 |
| Proven reserves: | 24.6 tcf |
| Reserves:production ratio | 7:1 |
| Sources: OET Annual Statistical Review; BP; Cedigaz | |
The sharp increase in demand for gas in power generation was prompted by a number of factors. Large supplies of gas became available from the North Sea during the 1980s just as Margaret Thatcher’s government was deregulating both the gas and electricity industries. Thus, upstream companies seeking markets for their gas were able to establish large and secure markets for their production through the joint development of gas-fired power stations. Another factor promoting such developments was the development of combined-cycle gas turbine generating units, which allowed considerable gains in thermal efficiency by recycling heat from the gas turbines to a subsidiary steam-powered turbine. This greatly improved the economics of gas-fired generation, allowing it to be used for base-load generation rather than mainly at times of peak demand, as had been the case before. Clean air legislation also tended to favour gas over coal and oil in industrial applications. The result was a large scale switch from oil and coal to natural gas, which became known popularly as the ‘dash for gas’.
The result has been to provide the UK with a generating mix dominated by gas (see Table B), just as UK North Sea production enters a period of decline (see Table C). During the 1970s and ’80s, the mix of generating sources was more evenly spread, giving greater flexibility in coping with changes in fuel supplies. In the 1970s, for example, there was sufficient coal-fired capacity available to allow switching from oil after oil prices rose sharply from 1973 onwards. Equally, there was spare oil-fired capacity available in 1984 and 1985 during the UK miners’ strike.
There is now much less flexibility than before. New electricity trading arrangements introduced by the present government (see ‘The Month in Brief’, September 2002) have led to a fall in wholesale power prices and the planned closure of some stations. The outlook is for even less generating flexibility as coal- and nuclear-powered stations are shut in order to comply with the government’s environmental policies.
Table B |
|
UK: generating capacity, 2003 |
|
| Fuel | (%) |
| Gas | 38 |
| Coal | 32 |
| Nuclear | 23 |
| Oil | 4 |
| Other | 3 |
| Source: OET estimate | |
Much of Europe is viewing the British market with interest. Norway, Russia, and the Netherlands all see the UK as a potential new market for their own gas, while the EU as a whole is keen to see how the British model of gas and power deregulation will cope with the changes in gas supply over the next few years. The EU Commission is promoting a British-style liberalization of energy markets across the EU by calling for the breakup of vertically-integrated, monopolistic gas and power companies and the entry of new players on equal terms in order to create fully competitive markets (see box). Not all member-states agree. Some, like France and Germany, claim that deregulation reduces security of supply.
It is not only European countries that are targeting the British market for new sales. Several suppliers of liquefied natural gas (LNG) have their eyes on the UK and one, Qatar, has already earmarked 1.2 bn cfd of LNG for the British market from 2006–7. Some of the new gas, however, will come by pipeline from Europe, with Norway and Russia the most likely suppliers.
Norway is considering several options to supply gas to the UK. It already supplies 350 mn cfd from the Heimdal and Frigg fields in the North Sea via a pipeline to St Fergus in Scotland. Several options are now under discussion involving the supply of more gas using a variety of routes including St Fergus, and the pipeline systems centred on Teesside, Theddlethorpe, and Bacton, in England.
The Netherlands, which exports 100 mn cfd to the UK, is also planning more exports to the UK. Its options are either to use the existing British export pipeline from Bacton to Zeebrugge in Belgium (in the reverse direction) or to build a new pipeline direct from the Netherlands to Southern England. As with Norway, more than one pipeline route will probably be required. A rather more ambitious plan is to supply the UK by pipeline from Russia. The proposed line will run across the Baltic to Greifswald in Germany, before continuing via the Netherlands and under the North Sea to Bacton.
The Norwegian and Dutch proposals involve the delivery of up to 1 bn cfd of gas to the UK from 2005. Russia is planning to supply around 3 bn cfd from 2007. Pipelines, however, are not the only infrastructure that will be needed: LNG terminals are also required, as is a considerable capacity of gas storage.
Table C |
||||
UK: gas supply/demand, 2002–20 |
||||
| 2002 | 2006 | 2012 | 2020 | |
| (bn cfd) | ||||
| Production | 11 | 11 | 6 | 3 |
| Consumption | 10 | 11 | 12 | 13 |
| Net exports (imports) | 1 | * | (6) | (10) |
| * a small volume of net imports is likely | ||||
| Source: Pearl Oil estimate | ||||
The UK was the first country in the world to take delivery of LNG, when a cargo of Algerian gas was delivered to the regasification terminal at Canvey Island, on the River Thames, in 1965. The terminal was closed following the arrival of pipeline gas in large quantities from the North Sea. Various companies are now examining possible new sites for new import terminals. The first to open might be at Milford Haven in Wales. Petroplus, an oil storage company, has applied for planning permission to build an LNG receiving terminal there. A second terminal is under consideration by ExxonMobil for the import of LNG from Qatar. The first import facility could be opened in late 2005 if construction were to begin this year. ExxonMobil’s terminal is scheduled to be commissioned in two stages, in 2007 and 2009.
Another site under active consideration is the Isle of Grain, near London. Here, there is already an LNG facility that is currently in use as a storage unit for supplying gas to the grid during periods of peak demand. The British gas and electricity transmission company, National Grid Transco (NGT), has been granted planning permission for an import terminal there, with completion planned by 2005. Petroplus, ExxonMobil and NGT have together proposed the construction of nearly 3 bn cfd of LNG import facilities: sufficient for around half the UK’s total projected input requirements in 2012 (see Table C).
LNG terminals are nevertheless not the only new infrastructure required to handle the increased imports of natural gas. None of the Milford Haven terminals can go ahead unless the area is connected to the National Transmission System (NTS), which is operated by NGT. This will require the building of a 70-mile spur from west Wales to the nearest point on the NTS.
Another issue that needs to be addressed is the lack of gas storage in the UK. Storage was not regarded as necessary other than for short-term operational reasons during the period that the UK had first call on its own supplies from the North Sea. Once it becomes a net importer, however, it will be at the end of a gas supply chain that, in some cases, may stretch across Western Europe. Without a considerable increase in storage, it faces supply shortages in the first severe winter from about 2006 onwards (see Table C). Norway’s Statoil is to store 6–8 bn cf of gas in salt caverns in Yorkshire, but several more such facilities will be needed from 2006 onwards.
Although the import infrastructure developments will be developed by oil and gas companies, government also has a part to play. Up to now, though, the British government has kept well in the background, even to the extent of making the role of energy minister a part-time one, to be combined with responsibilities for e-commerce and the postal services. New import pipelines, however, require international agreements covering routes and various other cross-border trade issues. In the case of the proposed Russian pipeline, more than one foreign government is involved, leading to the likelihood of delays in negotiating such important matters as routes, volumes carried and ownership of both pipelines and gas.
There is also enormous uncertainty over the government’s attitude towards the role of gas and other fuels in the UK’s future generating mix. UK demand for gas has been largely driven by power generation since the 1990s and its role as a generating fuel is expected to go on increasing; but by how much is not at all clear. Coal-burning looks set to decline in order to enable the UK to meet its targets on carbon emissions under the Kyoto Protocol. Nuclear power is also scheduled to decline: the country’s Magnox nuclear stations are due to be decommissioned by 2010 and the newer Advanced Gas-cooled Reactors (AGRs) are due to close shortly after that date. There are no plans to build any new nuclear power stations. The government has from time to time hinted that some of this capacity will be replaced by new nuclear capacity, but it has shied-away from any firm policy announcement, fearing the political opposition such an announcement would provoke. Instead, it has made equally vague pronouncements about replacing fossil fuels and nuclear with renewable energy.
The government originally announced that renewables would account for 20% of electricity generation by 2020: in itself nowhere near sufficient to offset the decline in coal and nuclear power. This policy has since been quietly abandoned (see ‘The Month in Brief’, March 2003) in favour of a 10% target for renewables by 2010. Even this lower target, however, looks unrealistic. Most renewable schemes are for small, decentralized power units. What is needed to meet the 10% target is a few large schemes, such as tidal barriers and huge banks of wind turbines. Such schemes, though, tend to become bogged down in lengthy planning inquiries, sufficient to delay many of them until well past 2010. There is also growing opposition to wind power, which tends to be concentrated in areas popular with tourists, on grounds of both visual intrusion and noise. The Ministry of Trade and Industry proposed in July that it would try and forestall such objections by siting wind turbines out at sea, but they will still be visible: again, in many cases, from tourist resorts. Moreover, these giant installations will not be able to operate continuously owing to the variability of the wind; so back-up capacity will be needed for the times when the turbines are not functioning at or near full capacity: more than half the time, in fact. What this back-up capacity will consist of, or where it will be sited, remains obscure.
The only conclusion must be that gas will increase its role in the generating mix: at least until 2010, if not some way beyond. The increase in gas demand will have to be met by imports (see Table C), for which new infrastructure will be required. Some of this may not be ready in time to prevent some shortages of gas at certain periods of peak demand. The main problems look like being with new pipeline links to the Continent and their associated storage facilities. This should, on the other hand, boost the prospects for LNG, which could meet around half the UK’s import requirements by 2010, or shortly afterwards.
EU Energy Liberalization
The European Parliament has agreed to a series of proposals designed to liberalize gas and electricity markets in the EU. The main ones are:
Still unresolved is who will provide the new infrastructure and how it will be financed. US companies played an important role in developing the existing infrastructure, but many of these have withdrawn in the wake of losses incurred in energy trading and elsewhere (see ‘Gas and Power’). What attracted them was the open British market compared with that of most of the Continent: the same conditions that spawned a host of new British energy companies. Many of these, though, are too small to finance the new import infrastructure, which is likely to be developed by the well-capitalized international oil and gas companies and the large vertically-integrated utilities of Continental Europe. The EU has proposed several measures to loosen their hold on their domestic markets (see Box). Some countries argue that these giant utilities are necessary in order to undertake major new developments of a strategic nature, such as long distance pipelines. Others fear that this will give them a stranglehold over supplies and prices. The British market looks like continuing as a test-bed for the new gas industry, just as it was in the previous decade.
© Blackwell Publishing Ltd, 2003