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February 2003

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United 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.

Map of the United KingdomBACKGROUND

The United Kingdom (official name: United Kingdom of Great Britain and Northern Ireland, abbreviated: UK) is a major political power, and also the world's fourth-largest economy. The country joined the European Union (EU) in 1973 (confirmed by referendum in 1975), but has not yet decided whether to adopt the European Monetary Union's single currency, called the euro. The UK government is in the process of assessing the national economy to determine whether there is sustainable convergence and sufficient flexibility with the economies of the euro zone to make joining feasible. The government is also studying the possible effects on employment, investment, and the financial services industry of adopting the euro. Results from these studies are expected to be available in June 2003, after which the UK government will decide whether to recommend joining the euro zone. If the recommendation is made, a vote will be taken in Parliament and a referendum of the British people will follow.

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
North Sea oil and gas reserves were first discovered in the 1960s. The North Sea did not emerge immediately as a key non-OPEC oil producing area, but North Sea production grew as major discoveries continued throughout the 1980s and into the 1990s. Although the region is a relatively high cost producer, its high quality crude oil, political stability, and proximity to major European consumer markets have allowed it to play a major role in world oil and gas markets.

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 UK holds about 5 billion barrels of proven oil reserves, almost all of which is located in the North Sea. Most of the country's production comes from basins east of Scotland in the central North Sea. The northern North Sea (east of the Shetland Islands) also holds considerable reserves, and smaller deposits are located in the North Atlantic Ocean, west of the Shetland Islands. There are over 100 oil and gas fields currently onstream, and several hundred companies are active in the area. In 2002, the United Kingdom's production declined to an estimated 2.53 million barrels per day (bbl/d), down from a historical high of 2.95 million bbl/d in 1999. Production is expected to decline further in 2003. Most of the UK's crude oil production ranges in gravity from 30 o to 40 o API. Most high quality crude is exported, while cheaper, lower quality (mainly from the Middle East) crude oils are imported for refining. According to the UK's Department of Trade and Industry (DTI), unit costs for UK oilfields averaged just over $17 per barrel in 2001, though fields that started production in the 1990s have lower costs.

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%.

As the UK's oil fields mature, the industry's focus has been shifting from searching for new oil discoveries to finding ways to continue productivity of mature fields. The number of fields in production in the UK at the end of 2002 was just over 260, while the number of fields under development was 84. There were 144 new projects being considered on mature oil fields, an increase from 96 in 2001. 

The eleventh onshore and twenty-first offshore licensing rounds were announced by Energy Minister Brian Wilson in FebrUK Oil Production and Consumption through 2002.  Having problems contact our National Energy Information Center on 202-586-8800 for help.uary 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.

Industry Structure
Industry reorganization that started with BP's 1998 merger with Amoco continues. The merged BP Amoco, (now BP) already one of the world's largest petroleum companies, announced in April 1999 its intentions to take over Los Angeles-based Atlantic Richfield (Arco), which was completed in April 2000. The merged company is truly global and is the world's third-largest publicly traded oil and gas company. Most of the majors have a share of UK North Sea production, including BP, ChevronTexaco, Conoco, ENI, ExxonMobil, Royal Dutch/Shell, Texaco, and TotalFinaElf. Amerada Hess, Enterprise, and Statoil also have large shares. 

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.  

The UK's crude oil refining capacity is approximately 1.79 million barrels per day, just slightly more than the country's consumption. However, the UK imports and exports refined products because British refineries produce an excess of some grades and products and insufficient quantities of others for local demand. Additionally, demand for gasoline varies seasonally. The largest refinery is ExxonMobil's (Esso's) 311,240-bbl/d Fawley refinery in Southhampton, one of the largest in Europe and marine tanker accessible. It also has a pipeline to the on-shore Wytch Farm field. The 100,000-bbl/d Port Clarence Phillips-Imperial Petroleum refinery at North Tees is connected by pipeline to the Phillips Consortium Ekofisk Oil Terminal at Seal Sands, giving it a direct feed from the North Sea. The Grangemouth refinery is also directly connected to the North Sea through the Forties Pipeline System.

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.

The UK contains an estimated 26.0 trillion cubic feet (Tcf) of natural gas reserves, most of which are in non-associated gas fields located off the English coast in the Southern Gas Basin, adjacent to the Dutch North Sea sector. The UK shares the declining Frigg field with Norway (39.18% to the UK), which produced only 17 million cubic feet in 2002, and will shut down in 2004. It also has a small share of the 0.44-Tcf Statfjord field (14.53%). There are a few small fields on-shore, while the Irish Sea contains the large Morecambe and Hamilton fields. Morecambe alone accounts for up to 20% of British natural gas production. Due to a decline in production and the maturation of its gas fields, the UK could become a natural gas importer in the next three years. Key producing gas fields in the North Sea include BP's 5.7-Tcf Leman, Chevron and Conoco's 3-Tcf Brittania, Shell's 1.7-Tcf Indefatigable and 0.8-Tcf Clipper, and TotalFinaElf's 0.85 Tcf Elgin. Key pipelines are the Scottish Area Gas Evacuation (SAGE) system to the St Fergus Terminal, which handles gas produced from a number of North Sea fields, including Britannia, the Beryl and Brae areas, and others in the central/northern North Sea, the Central Area Transmission System (CATS) that also goes to the Central North Sea, and takes gas from several fields, including Everest, Judy, and Jade, and others, and the Far North Liquids and Associated Gas System (FLAGS) that takes gas from the northern North Sea, including the Brent, Magnus, Cormorant, Ninian, and Hutton fields.

UK natural gas production and consumption graph.  Having problems contact our National Energy Information Center on 202-586-8800 for help.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.

Chart 2.2 2000 Gas Production (Billion cubic metres) .  Having problems contact our National Energy Information Center on 202-586-8800 for help.Industry Structure
British Gas was the monopoly supplier to the interruptible market until the passage of the 1995 Gas Act, which split the company into supply and shipping (British Gas Trading Limited) and while other functions remained with British Gas, including transport subsidiary Transco. In 1997, Centrica was demerged from from British Gas, and British Gas was renamed BG. Centrica is the holding company for British Gas Trading, British Gas Services, the Retail Energy Centers, and is the producer in the Morecambe fields. BG retained Transco, along with exploration and production, international downstream, R&D and properties. In October 2000, BG again split, with Transco becoming part of a separate holding company Lattice Group. Independent Gas suppliers entered the firm (non-tariff) market in 1990, but the larger interruptible market (smaller customers) brought in competition in 1995. The consumer gas market was deregulated by region from October 1997 to June 1998, such that all residential and commercial customers could choose their supplier at the end of this process. At the end of 2000, suppliers other than British Gas Trading had captured 20-30% of the market in many regions of the UK. In July 2001, Houston-based Dynegy purchased BG Storage from what remains of BG for $590 million, acquiring gas production wells and platforms, salt caverns, pipelines, and a natural gas processing terminal.

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.

Coal production and consumption in the United Kingdom have decreased dramatically since 1986. UK coal production fell from 119 million short tons (Mmst) in 1986 to 35.3 Mmst in 2000. In 2000, steam coal accounted for 80% of coal demand, coking coal for 15%, and anthracite for 5%. Electricity demand accounts for 75% of coal demand in the UK. In the late 1980s, coal accounted for about two-thirds of the United Kingdom's thermal electricity production. By 2001, only 37.2% of UK electricity was coal-fired, and the figure is expected to drop further by the end of the decade. Coal mines are located primarily in central and northern England and southern Wales, with some coal mines also found in southern Scotland. The UK produced 34.9 million tons of bituminous coal and 353 thousand tons of anthracite coal in 2000. The UK also produces some metallurgical coke, although not in sufficient quantities to meet the demands of its steel industry. Net imports of coal have been rising each year, and in 2000 were 30.8 million Mmst.

UK coal production and consumption through 2001.  Having problems contact our National Energy Information Center on 202-586-8800 for help.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. 

The United Kingdom has 72.4 million kilowatts of installed electric capacity, about 80% of which is thermal, 18% nuclear, and 2% hydropower. The country generated 355.8 billion kilowatt hours (bkwh) of electricity in 2000, making it the third-largest electricity market in Europe (behind Germany and France). In 2001, only 37.2% of UK electricity was coal-fired. The remainder was accounted for by natural gas (31.5%), and primary electricity sources such as nuclear and hydroelectricity (25.8%).

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.

In 1995, the government announced that it would privatize its more modern nuclear stations while retaining ownership of older stations. In 1996, more modern stations were privatized and British Energy became the holding company of Nuclear Electric and Scottish Nuclear, which merged in 1998 to form British Energy Generation, the nation's largest private nuclear generator and the world's first wholly privatized nuclear utility. British Energy operates eight nuclear power stations in the UK (as well as several in the U.S. through its AmerGen subsidiary that is jointly owned with PECO). Each station consists of two advanced gas-cooled reactors, except Sizewell B, which is a modern pressurized-water reactor. Nuclear power stations were not privatized simultaneously with non-nuclear stations.

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.

With a reduction in sulfur dioxide and carbon dioxide emissions, environmental conditions in the United Kingdom have improved over the past couple of decades. Some of these environmental improvements, such as a reduction in air pollution, can be attributed to the United Kingdom's energy use choices. Partially as a result of deregulation and the elimination of coal subsidies, coal's share of total primary energy consumption is gradually being replaced by natural gas.

Improvements in energy efficiency have led to a gradual reduction in both energy and carbon intensity. In 1999, energy intensity in the United Kingdom registered 7.8 thousand Btu per $1995, decreasing to 7.3 thousand Btu per $1995 in 2000, a 6% decline. However, carbon intensity in 2000 registered 0.11 metric tons of carbon per thousand $1995, maintaining 1999 levels. Per capita energy consumption, at 166.1 million Btu in 2000, is down slightly from 1999.

As the United Kingdom enters the 21st century, many energy and environment-related policies reflect the country's awareness of climate change issues. With introduction of the Climate Change Levy in 2001, and its exemption for renewable energy resources like solar and wind, these alternative sources of energy are beginning to gain more attention. For example, the United Kingdom hopes to increase the share of electricity generated by renewables from the current 2.3%, to 10% by 2010.

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.

Head of State: Queen Elizabeth II
Prime Minister: Anthony (Tony) Blair, re-elected June 2001
Population (2002E): 59.8 million
Location/Size: Western Europe, islands including the northern one-sixth of the island of Ireland between the North Atlantic Ocean and the North Sea, northwest of France/244,820 sq km (slightly smaller than Oregon)
Capital City: London
Language: English
Ethnic groups: English 81.5%, Scottish 9.6%, Irish 2.4%, Welsh 1.9%, Ulster 1.8%, West Indian, Indian, Pakistani, and other 2.8%
Religions: Anglican and Roman Catholic 40 million, Muslim 1.5 million, Presbyterian 800,000, Methodist 760,000, Sikh 500,000, Hindu 500,000, Jewish 350,000 (1991 est.)
Defense (8/98): Army, 113,900; Navy, 44,500; Air Force, 52,540

Chancellor of the Exchequer: Gordon Brown
Currency: Pound sterling
Exchange Rate (1/30/03): 1 US Dollar = 0.61 pounds
Gross Domestic Product (2002E): $1,527 billion
Real GDP Growth Rate (2002E): 1.6% (2003E): 2.7%
Inflation Rate (consumer prices, 2002E): 2.0% (2001E): 2.3%
Unemployment Rate (2002E): 3.1%
Merchandise Exports (2002E): $283 billion
Merchandise Imports (2002E): $324 billion
Merchandise Trade Deficit (2002E): $41 billion
Current Account Balance (2002E):  -$22.8 billion
Major Trading Partners: United States, Germany, France, Netherlands
Major Exports: Food, beverages, and tobacco; crude materials, fuels, chemicals, machinery, transport equipment
Major Imports: Food, beverages, and tobacco; crude materials, fuels, chemicals, machinery, transport equipment

Secretary of State for Trade and Industry: Patricia Hewitt
Minister of State for Industry and Energy: Brian Wilson
Proven Oil Reserves (1/1/03): 4.9 billion barrels
Oil Production (2002E): 2.53 million bbl/d, of which 2.25 million bbl/d was crude oil
Oil Consumption (2002E): 1.7 million bbl/d
Net Oil Exports (2002E): 0.83 million bbl/d
Crude Oil Refining Capacity (1/1/03E):
1.78 million bbl/d
Natural Gas Reserves (1/1/03E): 26.0 trillion cubic feet (Tcf)
Natural Gas Production (2000E): 3.8 Tcf
Natural Gas Consumption (2000E): 3.4 Tcf
Natural Gas Net Exports (2000E): 0.4 Tcf
Major Systems: Brent, Ninian, Forties, Flotta, Fulmar
Major Fields: E. Brae, Brent, Forties, Magnus, Miller, Scott
Oil and Gas Companies: Amerada Hess, BP Amoco, BHP, Chevron, ExxonMobil, Kerr-McGee, Phillips, Ranger Oil, Shell, Texaco
Recoverable Coal Reserves (12/31/99E): 1.65 billion short tons
Coal Production (2000E): 35.3 million short tons (Mmst)
Coal Consumption (2000E): 66.1 Mmst
Electrical Generation Capacity (1/1/00): 72.4 gigawatts (79.8% thermal, 17.9% nuclear, 2.0% hydro, 0.2% other)
Electricity Generation (2000E): 355.8 billion kilowatt hours (bkwh)
Electricity Consumption (2000E): 345.0 bkwh

Secretary of State for the Environment, Food, and Rural Affairs: Margaret Beckett
Total Energy Consumption (2000E): 9.9 quadrillion Btu* (2.6% of world total energy consumption)
Energy-Related Carbon Emissions (2000E): 147.8 million metric tons of carbon (2.5% of world carbon emissions)
Per Capita Energy Consumption (2000E): 166.1million Btu (vs. U.S. value of 355.8 million Btu)
Per Capita Carbon Emissions (2000E): 2.5 metric tons of carbon (vs. U.S. value of 5.6 metric tons of carbon)
Energy Intensity (2000E): 7,632 Btu/$1995 (vs U.S. value of 10,918 Btu/$1995)**
Carbon Intensity (2000E): 0.11 metric tons of carbon/thousand $1995 (vs U.S. value of 0.17 metric tons/thousand $1995)**
Fuel Share of Energy Consumption (2000E): Oil (35.1%), Natural Gas (36.3%), Coal (15.4%)
Fuel Share of Carbon Emissions (2000E): Oil (38.9%), Natural Gas (35.5%), Coal (25.5%)
Status in Climate Change Negotiations: Annex I country under the United Nations Framework Convention on Climate Change. Under the negotiated Kyoto Protocol (signed on April 29th, 1998 - not yet ratified), the UK has agreed to reduce greenhouse gases 8% below 1990 levels by the 2008-2012 commitment period.
Major Environmental Issues: Sulfur dioxide emissions from power plants contribute to air pollution; some rivers polluted by agricultural wastes and coastal waters polluted because of large-scale disposal of sewage at sea.
Major International Environmental Agreements: A party to Conventions on Air Pollution, Air Pollution-Nitrogen Oxides, Air Pollution-Sulphur 94, Air Pollution-Volatile Organic Compounds, Antarctic-Environmental Protocol, Antarctic Treaty, Biodiversity, Climate Change, Desertification, Endangered Species, Environmental Modification, Hazardous Wastes, Law of the Sea, Marine Dumping, Marine Life Conservation, Nuclear Test Ban, Ozone Layer Protection, Ship Pollution, Tropical Timber 83, Tropical Timber 94, Wetlands and Whaling.

* 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

Links to other U.S. Government sites:
CIA World Factbook - United Kingdom
U.S. State Department Country Commercial Guides: Europe
U.S. State Department Consular Information Sheet
U.S. Geological Survey, map of the United Kingdom including oil fields

The following links are provided as a service to our customers and should not be construed as advocating or reflecting any position of the Energy Information Administration (EIA) or the United States Government. EIA does not guarantee the content or accuracy of linked sites.

British Petroleum
Royal Dutch/Shell
International Petroleum Exchange
Grampian Oil and Gas Directory (an online database of companies operating in Scotland)
Electricity Association
National Power
Northern Ireland Electricity
Department of Trade and Industry
British Embassy in Washington, D.C.
Scottish Parliament
Royal Institute of International Affairs, Energy and Environmental Programme

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File last modified: February 14, 2003


Charles Esser
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Fax: (202) 586-9753
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