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Background | Gas | Coal | Electricity | Environment | Profile | LinksUnited Kingdom
With its significant North Sea reserves, the United Kingdom is a major European oil and natural gas producer. It is also one of the largest energy consumers in Europe.
Information contained in this report is the best available as of
February 2003 and is subject to change.
Despite the UK's lack of participation in the euro, the country has continued to attract foreign direct investment (FDI) - about $586 billion total at the end of 2001, second in the world after the United States. The UK is an even larger exporter of capital - outward FDI at the end of 2001 totaled $992 billion, making it the third largest target for foreign investment after China and the United States. The UK maintains a smaller public sector than many of its EU counterparts.
The UK, like most of the OECD, saw growth rates remain low in 2002. Real gross domestic product (GDP) is estimated at only 1.6% for 2002, but is projected to increase to 2.7% in 2003. Despite this slow rate of economic growth, unemployment continues to fall, reaching a new 27-year low of 3.1% in December 2002. Although it recognized the risks of a continuing sluggish economy in the euro zone, as well as the potential for U.S. consumer spending to falter, the Bank of England chose to leave interest rates untouched at 4% in November 2002. Housing price inflation has become another concern, having increased at the unsustainable rate of 26% in 2002.
The UK is by far the largest petroleum producer and exporter in the EU (Norway is not a member of the EU). It also is the largest producer and an important exporter of natural gas in the EU. Most of the UK's oil and gas reserves and production are located off the coast of Scotland, with the Scottish city of Aberdeen considered to be the nation's oil and gas capital. The International Petroleum Exchange (IPE), the second-largest energy futures exchange in the world, is located in London. The second and third-largest publicly traded energy companies in the world in terms of market value -- Royal Dutch/Shell and BP, respectively -- are based in the UK (Royal Dutch/Shell is also based in the Netherlands). Because major UK energy companies are private, the eventual decline in British oil and gas production could translate to an increase in UK companies' involvement abroad, mitigating the effect in the overall UK economy, though Scottish employment is particularly sensitive to North Sea production levels. The UK has high taxes on petroleum products, making for among the highest prices in the EU, though its electricity prices have been steadily declining.
In July 1999, a Scottish Parliament met for the first time in almost 300 years. "Devolution" gives the Scottish Parliament the ability to tax its own citizens, plus jurisdiction over local issues such as education, health, transport, and agriculture. It has no effect on the economic and industrial structure of the United Kingdom, which remains a single market. Devolution has had no effect on North Sea oil and gas production.
North Sea Oil and Gas
Many of the world's major crude oil prices are linked to the price of the North Sea's Brent crude oil. (Brent crude is a blend of North Sea crude oils and does not come exclusively from the Brent field.) Because Brent crude is traded on the International Petroleum Exchange in London, fluctuations in the market are reflected in the price of Brent. Therefore, all other crude oils linked to Brent can be priced according to the latest market conditions.
The North Sea is considered a "mature" area, with few large discoveries likely to be made. Only a few frontier areas hold the possibility of further discoveries of large oil and natural gas fields. In both of the major North Sea producing nations, Norway and the UK, government and industry are taking steps to restructure their oil and natural gas sectors to make them more internationally competitive. In November 2002, Chancellor of the Exchequer Gordon Brown announced plans to abolish all royalty taxes on North Sea oil and natural gas, which apply to fields that were granted development approval before April 1982. Measures have also been taken to make the area more attractive to smaller firms.
The domestic UK oil and gas industry is expected to decline as reserves are depleted in the coming decade. The British Oil and Gas Industry Task Force (OGITF) was set up in 1998 to bring together government departments and oil and gas industry representatives (the oil and gas industry is 100% in the hands of the private sector) to discuss the future of the industry. A successor body to the Task Force, known as "PILOT", now has been created to oversee the execution of Task Force recommendations and future developments. PILOT's goals for 2010 are to maintain oil production at or above 3 million bbl/d, have $4.8 billion annual investment in the industry, create 100,000 more jobs, create $1.6 billion in additional revenue for new business, and make the UK the safest place to work in the world oil and gas industry. By 2005 PILOT hopes to increase oil exports by 50%.
The eleventh onshore and twenty-first offshore licensing rounds were announced by Energy Minister Brian Wilson in February 2003. These rounds will mark the beginning of a new type of license for the UK, in which the traditional licensing fee will be cut by 90% for the first two years, thereby providing more opportunity for smaller companies to enter the North Sea market. The two-year "promote" license will expire after two years unless a substantive work plan has been agreed upon, e.g. the drilling of a well. This two-year period is intended to give companies a chance to explore for oil and gas before promoting the licensed area to investers to acquire funding for drilling and other work.
Talisman Energy, Limited announced in October 2002 the discovery of oil in an area of the UK Central North Sea adjacent to the Buchan field. A test well discovered a gross oil column of 164 feet. The 40o API oil flowed at a rate of 6,600 bbl/d. Talisman already produces 145,000 bbl/d from its North Sea concessions.
In July 2002, the UK government awarded 25 offshore production licences to groups comprised of 33 different companies. Six new companies have acquired their first license in the area, and licenses were awarded to small niche players as well as the larger, more familiar firms. Licences will cover two, four-year terms. After the first term, half of the license will revert back to the government. At the end of the second four-year term, any acreage that is not specifically covered by a specific development plan will also return to government control.
In February 2002, the UK government offered 22 Petroleum Exploration and Development licenses for bid in the nation's 10th Onshore Licensing Round. Fourteen of the areas to be licensed are for companies concentrating on extracting natural gas from coalmines, which may boost hard-hit local economies in former mining areas.
Another important development is the Skene field, which is being developed by operator ExxonMobil as a subsea tie-back to the Beryl Alpha platform. This field has a complex mix of hydrocarbons, including crude oil and condensate, that is estimated to be about 100 million barrels of oil equivalent. Only the implementation of the latest technology using a heated flowline bundle has made recovery possible. Natural gas first flowed from it in January 2002.
The Leadon field came onstream in late 2001, with development costs estimated to have been between $600 million and $700 million. Initial production was 10,000 bbl/d, and the field is expected to peak at 45,000 bbl/d, with field life estimated at sixteen years. The field's water depth of 370 feet required the use of subsea horizontal wells that are tied to a floating, production, storage, and offloading vessel, in this case called the Kerr-McGee Global Producer III, which has a storage capacity of 500,000 barrels.
Europe's largest on-shore oilfield is Wytch Farm. Estimated reserves are 500 million barrels. Egdon Exploration is active in the area, and it is hoped that even smaller fields can be economically viable as they are on-shore. Other smaller on-shore fields are clustered in east-central England.
BP Exploration is managed from Aberdeen, Scotland (as are most other companies that are active in the British North Sea). BP produces oil and gas and brings ashore about 40% of the UK's total oil production through the Forties Pipeline System to Grangemouth, Scotland. BP has producing fields in the North Sea and, since the end of 1997, in the North Atlantic, west of the Shetland Islands. It operates the Sullom Voe oil terminal in the Shetlands, which is Europe's largest oil terminal. The 206,000-bbl/d oil refinery and petrochemical complex at Grangemouth represents one of Scotland's largest industrial complexes.
British independent oil companies, important in the North Sea oil scene, were particularly hard hit by the oil price collapse of 1998. However, as oil prices rise and the UK government makes investment more attractive for smaller, independent firms through special licenses, they are beginning to show renewed interest. The Energy Ministry has shown some concern that British independents are in danger of being taken over by the large corporations, as evidenced by the Energy Minister's support of Enterprise Oil's management when it resisted an unsolicited takeover bid by ENI. Enterprise, the largest British independent, unsuccessfully attempted to take over the second largest, Lasmo, which was later acquired by ENI in 2001. Italian oil and gas giant ENI began its acquisition of British independents when it bought British-Borneo in March 2000. Small British companies such as Tullow, Highland, Consort, Intrepid, Paladin, and Venture have all done well in the North Sea market, often by concentrating their efforts on areas with small reserves that are not considered materially viable by major operators.
In January 2003, BP announced that it would invest the $41 million necessary to reinstate the fluidized catalytic cracking unit (FCCU) at its Grangemouth refinery. The FCCU has not been operational since 2000, when it suffered fire damage. BP aims to have the unit operational in 2004, with output expected to be maintained at 19,000 bbl/d of high grade motor gasoline components.
The retail gasoline market is dominated by Esso (ExxonMobil), BP, Shell, TotalFinaElf, Texaco, and Conoco, which together account for 58% of gasoline sales. Supermarkets now account for 8% of retail sales. Total retail sales were 28 billion liters (7.4 billion gallons) in 2000. The transport sector consumed 74% of petroleum products in 2000, whereas the energy industry consumed just 7%. Fuel oil use has declined 30% since 1998, as industrial and home-heating demand has dropped in favor of natural gas.
ATP Oil & Gas Corporation announced the successful testing of the Helvellyn well, which is located in the North Sea's Southern Gas Basin, in January 2003. The well tested at 60 million cubic feet per day (Mmcf/d). The initial discovery of natural gas in this field was made by BP in 1985, though the company did not develop it. At present, ATP is making the final preparations for production, which include modifications to the BP-operated Amethyst platform to support a 9.3 mile pipeline running from the platform to the well. Production is scheduled to begin during 2003.
A division of National Grid Transco (NGT) has submitted a proposal to build the UK's first LNG import terminal in 40 years. If approved in early 2003, the terminal would be built on the Thames estuary 37 miles east of London. NGT is also preparing to change the way in which in sells capacity in its transportation system, and hopes to draw in more Norwegian supplies.
The largest project to come online in 2001 (in March) in the British North Sea is the TotalFinaElf-operated Elgin/Franklin platform, which might prove to be the last big North Sea production platform. It is the world's largest high-pressure, high temperature development. The Elgin/Franklin platform has extensive processing facilities, unlike most North Sea platforms. The $2.3 billion platform is expected to last for 22 years in its location in the central North Sea, in the Graben area, off the coast of Scotland. It is to produce 700 million barrels of oil equivalent, about half condensate and half natural gas. This equates to peak production of 350 million cubic feet per day (Mmcf/d) of natural gas. The export pipelines are shared with the Shearwater field, and include a 294-mile gas pipeline to Bacton and a 24-mile condensate pipeline to the Marnock platform. The Shell-operated Shearwater field in the central North Sea was inaugurated in September 2000, and has reserves of 0.71 Tcf natural gas and 110 million barrels of condensate. Gas production is expected to peak at 375 Mmcf/d.
The UK's gas and electricity regulatory body is the Office of Gas and Electricity Markets (Ofgem). Ofgem has proposed reforming price controls on Transco's pipeline usage fees. The privatization of the UK's gas industry, leading to an increased gas supply and reduced prices, has helped gas to replace much of the UK's reliance on coal as a source for electricity generation. The natural gas share of utility fuels was 1% in 1988 and is expected to increase to almost 50% by 2010. Privatization in the UK has progressed well in advance of EU requirements.
Between 1984 and 1985, the British coal miners' union staged a year-long strike. The strike dramatically altered energy production and consumption patterns in the United Kingdom for that year and precipitated the longer term decline of the industry (see graph). Employment in the industry has plummeted since the late 1980s. The United Kingdom began liberalizing its electricity market in 1989, and this liberalization is one of the major reasons for the decline of the country's coal industry. Prior to the privatization of electricity, the cost of domestic coal to electric utilities had far exceeded the cost of coal traded in international markets. The Central Electricity Generation Board (CEGB) had been the primary purchaser of British coal. The CEGB largely subsidized the British coal industry, purchasing domestic coal at above world market prices and then passing on those costs to consumers. This ended when National Power and PowerGen, two private electricity generation companies, were formed in the early 1990s, weakening the bargaining power of British Coal, the national coal company.
In 1992, the British coal industry reached a turning point. Growing competition from increasingly available natural gas, the imminent removal of the regional electricity companies' captive franchise supply markets, and newly-enacted pollution abatement goals all worked to initiate the steady decline of the industry. The industry was privatized in 1994, at which point RJB Mining bought the major British Coal assets and become the country's major producer. Mining Scotland and Celtic Energy are the other two remaining companies. The UK coal industry received its first subsidies since 1995 after the European Commission approved a modernization plan and aid scheme in November 2000. The aid, distributed in three Tranches, was originally slated to be used toward mines/production units with long-term economic viability on the world market, but which were having temporary difficulties as they restructured in an effort to reduce production costs. Though scheduled to expire in July 2002, a fourth Tranche was added to extend the scheme through to the end of the year. Only units that received subsidy payments in Tranche 3 were eligible to receive continued assistance in Tranche 4. The total amount of aid was not to exceed £110 million, although Tranche 4 added £10 million to provide miners at the Selby Coalfield (which will close by the end of 2004) with favorable redundancy terms; a multi-agency taskforce to provide regeneration and retraining for the Selby mine; £5,000 per person for ex-British Coal miners at Longannet mine; and consultation on an investment aid plan for the coal industry. Production costs over the period 1992 to 1999 fell 35%, and the expectation is that these costs can fall further still, thereby allowing coal to remain a continually viable source of energy.
Some estimates predict that UK coal burn could fall to half its current level over the next eight to ten years, and that all coal-fueled electricity generation could end by the year 2016. New EU environmental directives, which are expected to further increase British coal production costs, are cited as a primary cause of this decline. RJB Mining is more optimistic about the future of British coal. RJB maintains that foreign coal prices will increase, making British coal more competitive, and that clean coal technology will allow power stations to burn increased amounts of coal without increased greenhouse gas emissions. Higher natural gas prices, gas-fired power plant outages for maintenance and repair, and reduced nuclear power led to a 14% increase in coal consumption by power producers in 2000.
Electricity privatization began in the early 1990s, and the final phase of transition ended in May 1999. Initially, all non-nuclear state-owned power stations were privatized and four major generating companies -- PowerGen and National Power in England and Wales, and ScottishPower and Hydro-Electric in Scotland -- were formed to operate the stations. The grid distribution system in England and Wales became the property of the National Grid Company. Regional Electricity Boards were privatized as separate distribution companies. Large customers were the first to be able to choose their suppliers, with all small customers (below 100 kW peak load) being able to choose by May 1999.
The number of electric generation companies in the United Kingdom has increased to 27 as a result of the liberalization process, according to DTI, such that 40% of the UK's electricity was generated by these new companies in 2000. In March 2001, the structure of the electricity industry changed yet again. Under the former system, generators and suppliers in England and Wales traded electricity through the electricity pool, which was regulated by the National Grid Company, owner of the transmission network. The New Electricity Trading Arrangements (NETA) changed this to a system based on bilateral trading between generators, suppliers, traders, and customers. The system includes forwards and futures markets, a balancing mechanism to enable the National Grid Company to balance the system, and a settlement process. Dallas-based TXU purchased United Utilities' retail electricity and natural gas business, Norweb Energi, for $465 million in August 2000. This, added to TXU's European retail business Eastern Energy, created the UK's largest electricity retailer, with over 5.6 million customers.
The UK electricity sector encountered several problems in 2002, most significantly the financial troubles of some large companies. TXU Corp. sought to bolster its finances by selling its assets in the UK to Powergen, a subsidiary of E.ON. However, the deal left TXU with five long-term contracts to purchase large amounts of wholesale electricity in the UK at fixed prices, which now exceed market levels by about $15/MWh. While restructuring of the electricity industry was intended to end market abuses by large electricity generators and increase the market's efficiency, the system has been so successful that in the last four years, prices have decreased by about 40%.
TXU's difficulties have caused a domino effect in the UK energy market. In October 2002, UK Coal announced that it would suspend shipments of coal to the Drax power plant, the nation's largest, because the firm AES was uanble to pay the balance of its multi-million dollar bill. AES was unable to pay the bill because it was owed a large amount of money by TXU. AES had managed to pay half of the outstanding balance, but UK Coal was still reluctant to resume coal shipments to Drax due to concern that the remainder of the balance might not be paid soon enough. A deal was reached in late October and shipments were resumed.
Powergen, with 2.6 million retail customers as well as 14% of electricity generation in England and Wales, merged with Louisville-based LG&E Energy in December 2000. Powergen announced in October 2002 that it will close two of its own plants and several of TXU's plants in order to reduce the UK's 25-30% overcapacity in electricity generation. Powergen will also take over TXU's 5.6 million customers when the deal is finalized.
In Scotland, the two main companies, Scottish Power and Scottish and Southern Energy, cover the full range of electricity provision. Ofgem has made proposals to further reform the Scottish power market. Northern Ireland, part of the United Kingdom but not part of Great Britain, is served by Northern Ireland Electricity, one of the largest companies in Northern Ireland and part of the Viridian Group. Northern Ireland has a separate electricity and gas regulatory body, Ofreg. The grids of Northern Ireland and the Republic of Ireland are connected for electricity import/export.
No new nuclear plants have been built since 1995, but because of limited domestic coal and gas reserves in the long run, new construction is under discussion, at least to maintain nuclear's market share as older nuclear plants are retired. Of the UK's 33 reactors, 26 are of the old Magnox design. Six of the Magnox reactors are being decommissioned, as well as the Dounreay prototype fast reactor. The remaining Magnox plants are run by the state-owned British Nuclear Fuels. British Nuclear Fuels operates the Sellafield reprocessing plant, and is one of only two companies in the world that provides reprocessing and recycling technologies. The British nuclear industry is regulated by the Department of Trade and Industry's Nuclear Directorate.
British Energy PLC encountered serious financial problems in 2002, which prompted the UK government to provide a £650 million ($1 billion) loan and £10 billion ($16 billion) in subsidies for the company. Nuclear energy provides nearly 20% of the UK's electricity at present, and is reported to be losing approximately $3 million a day, due to an increase in the cost of producing electricity combined with lower wholesale market prices. In an effort to improve its finances and avoid government administration, British Energy agreed to sell its Canadian subsidiary, Bruce Power, to a consortium led by Cameco Corporation for £300 million. Other members of the consortium include TransCanada Pipelines and Borealis Capital. In February 2003, BE agreed to a four-year plan to supply 15% of its output to Centrica, the nation's largest natural gas and electricity supplier, in a deal that is hoped will cushion the ailing nuclear energy company from further declines in the wholesale energy market.
Sources for this report include: Aberdeen Press & Journal; BBC News; CIA World Factbook; Economist; Economist Intelligence Unit ViewsWire; Financial Times; Global Insight World Economic Outlook; Hart's European Offshore Petroleum Newsletter; International Energy Outlook 2002; Oil & Gas Journal; Petroleum Economist; Petroleum Intelligence Weekly; The Scotsman; U.K. Department of Trade and Industry; U.S. Energy Information Administration; WMRC Daily Outlook.
* The total energy consumption statistic includes petroleum, dry natural gas, coal, net hydro, nuclear, geothermal, solar, wind, wood and waste electric power. The renewable energy consumption statistic is based on International Energy Agency (IEA) data and includes hydropower, solar, wind, tide, geothermal, solid biomass and animal products, biomass gas and liquids, industrial and municipal wastes. Sectoral shares of energy consumption and carbon emissions are also based on IEA data.**GDP based on EIA International Energy Annual 2000.
For more EIA information on the United Kingdom:
EIA - Country Information on the United Kingdom
Electricity Restructuring and Privatization in the United Kingdom
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