United Kingdom (part1)31 March 1998
With the privatisation of the electricity supply industry, including some of the nuclear reactors, a new competitive climate has been introduced. The nuclear operators have responded well to the challenge and last year nuclear accounted for over 28% of electricity supplied.
The United Kingdom (UK) comprises Great Britain (England, Wales and Scotland) and the six counties of Northern Ireland. It covers an area of 240 883 km2 (Great Britain 228 356 km2) and has a population of 56.5 million (Great Britain 5 million). The UK is a constitutional monarchy and a parliamentary democracy. The House of Commons is elected by universal suffrage whereas the House of Lords is hereditary and appointive. The present (Labour) government was elected with a large majority in May 1997 after 18 years of Conservative rule. The UK is a member of the European Union. It signed and ratified the Nuclear Non-proliferation Treaty in 1968.
The UK has larger energy resources than any other member of the European Union and is self-sufficient in energy. There are large reserves of coal, gas and oil, but no uranium. The coal industry has the lowest production costs by far of any EU coal industry and is the only one with a real prospect of long-term viability and not dependent on large subsidies. Nevertheless, since 1970, while production of gas and oil has steadily increased, there has been a dramatic fall in the production of coal and most of the coal industry has been closed down. Coal’s share of UK primary energy supply over this period has fallen from 46 to 20% while that of gas has increased from 5 to 35%. For the present, coal remains the dominant fuel for electricity generation, but it is set to lose this position to gas before 2000. Nuclear currently accounts for some 10% of UK primary energy supply.
The new government continues to rely on market forces and regulatory pressures to ensure adequate energy supplies and to drive down costs. It has, however, already shown itself more prepared to intervene than its predecessor and it is reviewing the system of utility regulation. A Green Paper is expected by this summer. The government has a manifesto commitment to reduce carbon dioxide emissions to 20% below 1990 levels by 2010 and to meet 10% of the UK’s electricity needs from renewable energy sources by the same date. It is also promoting combined heat and power technology. Support for nuclear power through the Fossil Fuel Levy and the Scottish Nuclear Energy Agreement ceased when the industry was partly privatised. The levy, which is effectively borne by customers through their electricity bills, continues in conjunction with the Non Fossil Fuel Obligation to provide support for the development of renewables. The UK electricity industry leads the world in electricity market liberalisation and the supply market is now expected to be open to full competition progressively from September 1998.
At the end of 1996 the total output capacity of generating plant in the UK was 73 261 MWe, 94% of which was owned by the main public supply generators and the remainder by autoproducers. During the year 1997 the main generators supplied 303.52 TWh (33.3% coal, 0.4% oil, 8.3% mixed (coal/oil/gas), 28.4% CCGTs, 28.6% Nuclear, 0.7% hydro (net of pumping) and 0.3% renewables). A further 5.98 TWh was purchased from autoproducers and 16.57 TWh was provided by imports. Over most of the country, peak demand (corrected to average cold spell conditions) is forecast to grow during the next seven years by 1.2% a year. The growth in the use of gas is set to accelerate, and in England and Wales alone the capacity of CCGTs installed is expected to double to 30.9 GWe by 2001/02. In contrast, nuclear capacity will remain virtually static and coal capacity is expected to continue to decline. Domestic customers provided the largest market (36%), followed by industry (31%) and commercial (20%).
The generation, transmission and distribution of electricity in the United Kingdom takes place within three distinct geographical systems – England and Wales, Scotland and Northern Ireland – which differ in size and organisation. The Scottish and English systems are interconnected and there is a 2000 MWe dc submarine cable between England and France. Northern Ireland is connected to the Electricity Supply Board of the Republic of Ireland and is due to be linked to Southern Scotland by a 250 MWe dc submarine cable by the year 2000. The approximate size of each market is indicated by the peak loads in 1996/97: England and Wales – 49 749 MWe; Scotland – 5758 MWe; and Northern Ireland – 1534 MWe.
After over 40 years in the public sector, the industry has undergone a major reconstruction during the past eight years and ownership of the utilities responsible for generation, transmission and distribution has been transferred from the state to private investors. The principal objectives of the 1989 Electricity Act, which laid the legislative foundations for the changes, were to create a competitive market in electricity and to provide financial independence from the government.
A vital element in the privatisation process was the setting up under the 1989 Act of the Office of Electricity Regulation (OFFER), headed by the Director General of Electricity Supply (DGES). This is a non-ministerial government department with 14 offices across England, Wales and Scotland. OFFER’s main duties are to promote competition in generation and supply and to protect the interests of customers in regard to both prices charged and the quality of services provided. There is a separate regulator for Northern Ireland.
The structure of the electricity supply industry in the UK is today considerably more complex in both its organisation and methods of operation than it was before privatisation. The 16 state-owned utilities have been replaced by 18 investor-owned companies, floated on the stock market between April 1990 and December 1995, which cover all the non-nuclear sectors of the industry; by a company owning 15 of the nuclear reactors, which was floated in July 1996; and a state-owned company that owns the remaining 20 nuclear reactors. In addition, some 23 new generators, mostly using combined-cycle gas-turbine plants, have entered the industry.
In England and Wales the fossil-fuelled power stations of the former Central Electricity Generating Board (England and Wales) were initially divided between two new companies – National Power and PowerGen; and the Board’s 2100 MWe of pumped-storage capacity and the 275/400kV transmission system were transferred to the new National Grid Company (NGC) to make it independent of generation and supply. The 12 Area Electricity Boards in England and Wales were privatised as Regional Electricity Companies (RECs) with the same geographical distribution/supply franchises as before, but with freedom to engage in generation and to diversify into activities outside electricity supply.
In Scotland, vertical integration has been retained in the new companies ScottishPower and HydroElectric, which replace the former South of Scotland Electricity Board and the North of Scotland Hydro Electricity Board. Both these companies can build and operate generating stations and supply customers anywhere in Great Britain. In Northern Ireland, the four power stations were purchased by three independent power producers in 1992. They are obliged to sell their output to the Northern Ireland Electricity (NIE), which was floated on the stock market in 1993. The NEI has the monopoly of transmission and distribution, but supply is open to competition.
The RECs in England and Wales have an obligation under their public supply licences to supply customers within their franchise regions, but they can also supply, through second-tier licences, customers in other regions. They are required to provide open access to their distribution networks on a non-discriminatory basis so that generators and other undertakings with second-tier licences can also supply customers direct. This freedom to choose a supplier is currently restricted to customers with a maximum demand of 100 kW or more but from September 1998 the market will be progressively liberated, so that all customers will be free to choose their supplier. Competition in the over 100 kW market has been fierce and in England and Wales some 40% of sites with a demand of 100 kW or more already receive a second-tier supply, accounting for 64% of electricity sales to that market.
The NGC, after a period when it was owned by the RECs, was floated on the stock market in December 1995. The NGC owns and operates the 275/400 kV transmission system in England and Wales and is joint owner (with the Scottish companies) of the interconnector with Scotland and (with Electricité de France) of the cross-Channel cable, but it has sold its pumped-storage business, First Hydro, to Mission Energy of the United States. The NGC has a central role in the industry and a specific remit to facilitate competition. It provides open access to the grid for all generators and distributors who meet the technical requirements of the Grid Code. It is responsible for the scheduling and dispatch of generating plant above 100 MWe to meet demand at the lowest cost to the customer. The transmission licence holders (NGC, ScottishPower, HydroPower and NEI) publish Seven Year Statements each year of trends in demand to assist grid users determine investment decisions and business opportunities.
Under the new arrangements, the generators no longer have an obligation to supply or an assured market. In England and Wales they have to compete for their share of business through an open wholesale market, the Electricity Pool, which was established on 31 March 1990. The Electricity Pool does not itself buy or sell electricity: it is a contractual arrangement between the main generators and suppliers who wish to trade electricity. Purchase and selling prices are determined half-hourly. To offset the inevitable volatility in Pool prices, the participating traders have overlaid the Pool with both short and long-term contracts, known as Contracts for Differences (CfDs). Only some 10% of electricity sold is paid for at pool prices.
The 56 traders who currently use the Pool (Pool Members) include the CEGB successor companies, the Scottish companies, Electricité de France, independent generators and autoproducers and the RECs. In general all generators above 50 MWe and suppliers buying over 500 kWe must be Pool members. Special arrangements allow small generators (under 50 MWe), who do not require a generating licence, to trade either through the Pool or directly with their local REC.
The Pool is managed by the Pool Executive Committee (PEC) appointed by Pool members and is financed by a levy on members. It is administered by two NGC subsidiaries, Energy Systems and Information Services Ltd (ESIS) and Energy Pool Funds Administration Ltd (EPFAL). The Pool is at present the subject of a wide-ranging review which is being conducted for the government by the Director General of Electricity Supply.
Impact of privatisation
Prices to all classes of customer have fallen in real terms since privatisation as a result of reductions in costs and improvements in productivity, the pressures of competition and the impact of the Regulator. At the same time, the industry has proved highly profitable.
Since 31 March 1995, when the government gave up its “golden share” in the RECs, the distribution side of the industry in England and Wales has witnessed a spate of takeovers and mergers. Only one of the RECs, Southern Electric, remains independent and seven are now subsidiaries of US-based utilities. All the RECs and the Scottish companies now have an interest in supplying gas as well as electricity and eight RECs have telecommunication licences.
The government still holds a “golden share” in three of the main generators, National Power, PowerGen, and British Energy, which restricts individual shareholdings in these companies to 15%. It has so far also blocked attempts by them to buy into the RECs. However, all but one of the RECs are now involved in generation and some 6000 MWe of plant previously owned by National Power and PowerGen was divested to Eastern Electricity in 1996, to make it the UK’s fourth largest generator. As a result of this and the new companies entering the generating market, there has been a dramatic change in the shares of the main generators and a significant increase in competition. There has also been a shift towards gas-fired generation and some 18 GWe of coal-fired capacity has been closed or mothballed.
The more competitive market and regulatory restraints at home, have encouraged the main generators, the NGC and some of the RECs to use their new freedom to borrow on the capital markets and to exploit investment opportunities abroad with considerable vigour. National Power and PowerGen have between them invested more than £1.7 billion in over 16 GWe of capacity in various countries, and British Energy has entered into a joint venture to acquire and operate nuclear power stations in the USA. The NGC is part of a consortium that operates the Argentine transmission company Transener.
Several of the generators and RECs fund a core research programme into utilisation and distribution technology at EA Technology Ltd (EATL) at Capenhurst, the successor to the Electricity Council’s Research and Development Centre. It is supplemented by European and UK government grants. The generators and NGC also maintain their own research and development facilities.
There are currently 35 reactors (20 Magnox, 14 AGRs and one PWR) with a combined capacity of 14 208 MWe in operation at 15 sites. They accounted for 28.6 of the electricity supplied in 1997. The AGRs and PWR are owned by British Energy plc (BE) and operated by its wholly-owned subsidiaries Nuclear Electric Ltd and Scottish Nuclear Ltd; the Magnox units are owned and operated by Magnox Electric plc, which is now a wholly-owned subsidiary of British Nuclear Fuels Ltd. Six commercial Magnox units (Berkeley 1 and 2, Hunterston A1 and A2, and Trawsfynydd 1 and 2) and five prototype reactors (WAGR, two FBRs (DFR and PFR), an HTGR (Dragon) and a SGHWR) have been closed and are in various stages of decommissioning. Among the Magnox units in operation are the four units at Calder Hall, the world’s first industrial scale nuclear power plant, which are now 41 years old and have been cleared for a further period of operation.
Until 1996 the development of nuclear power in the UK was in the hands of state-owned authorities and utilities and was bedeviled by politics. Successive governments, Labour and Conservative, firmly believed that they were qualified to determine which types of reactors the utilities should build and the rate at which they should be ordered. In addition, an over- centralised and largely secretive administrative system restricted the independent examination of decisions taken on technical matters, load forecasting and costs.
Nuclear power was excluded when the rest of the electricity supply industry was privatised in 1990. Initially, two state-owned companies, Nuclear Electric plc and Scottish Nuclear Ltd, were formed to take over and operate the nuclear stations previously owned and operated by the Central Electricity Generating Board and the South of Scotland Electricity Board. Following a lengthy review of the prospects for nuclear power in the UK, the government in May 1995 confirmed its commitment to nuclear power, but stated that there was no case for providing more public funds for the construction of nuclear power stations. It also announced that Nuclear Electric and Scottish Nuclear would become subsidiaries of a new privatised holding company, British Energy; and that the Magnox reactors operated by the two companies would be transferred to a new government-owned, public limited company Magnox Electric, which would later be integrated with British Nuclear Fuels Ltd (BNFL). The restructuring of the industry (into British Energy and Magnox Electric) took place on the 31st March 1996 and British Energy was floated on the Stock Exchange in July 1996. Magnox Electric shares passed to BNFL in February 1998.
British Energy has its headquarters in Edinburgh and a small office in London. The board comprises the non-executive chairman, four executive directors and five non-executive directors. The executive directors include the chairman of Nuclear Electric and the chairman and chief executive of Scottish Nuclear, who are both deputy chairmen of British Energy, and the chief executive of Nuclear Electric. The British Energy board is mainly concerned with group policy and strategic planning, while day-to-day operational matters are left to the two subsidiaries. These have their own boards of directors but no longer publish separate annual reports and accounts, only annual safety and environmental reports. Until now Nuclear Electric and Scottish Nuclear have continued to operate much as they did before privatisation, but with an increasing amount of co-operation in areas where they have a common interest. However, a main board committee is now studying ways in which the activities of the group might with advantage be more closely integrated.
Nuclear Electric has its headquarters at Barnwood, Gloucester, England, and operates the ten AGRs at Dungeness B, Hartlepool, Heysham and Hinkley Point B and the PWR at Sizewell B, which have a total capacity of 7738 MWe. It supplies electricity to the Pool and directly to an increasing number of contract customers. Scottish Nuclear has its headquarters at East Kilbride, Scotland, and operates the four AGRs at Hunterston B and Torness, which have total capacity of 2684 MWe. It has a contract to supply all its electricity to ScottishPower and Hydro Electric until 2005. Both companies are active in seeking opportunities to expand consultancy work overseas and these activities are now co-ordinated by British Energy International. There are exchange agreements with Korea Electric Power Corporation (KEPCO) and the Spanish utility ENDESA, and twinning arrangements with power stations in Russia and Ukraine.
In the year ended 31 March 1997, British Electric had a turnover of £1870 million and it declared a profit before tax of £61 million, compared with a loss in the previous year. The improved performance was largely due to a 10% increase to 67.2 TWh in the electricity produced and an 11% reduction to 2.11p/kWh in the cost of each unit of electricity supplied. BE’s achieved price was 2.54p/kWh, down 1% on last year but still representing a premium of 7% over pool price.
The company has benefited from the considerable improvements in the performance of the AGRs, both in terms of load factors and reduced statutory outages, that were achieved by Nuclear Electric and Scottish Nuclear in the run-up to privatisation and from the entry into service of the Sizewell PWR, which has operated with high load factors. Five AGRs (Torness, Hartlepool, Heysham 1 and 2 and Hinkley Point B) have now been cleared by the NII to move from two to three-year intervals between outages; and on-load refuelling, which has been routine at Hunterston B and Hinkley Point B, has been extended to Heysham 2 and one unit at Torness.
In pursuit of greater efficiency, the company aims to reduce staffing levels by 24% to below 5000 by March 2000. This is expected to save £50 million a year. Profitability will also be improved by the contracts concluded (June 1997) with British Nuclear Fuels for fuel, reprocessing and storage services for the company’s AGRs. British Energy says these will produce savings of some £10 million in 1997/98 and “very competitive prices for fuel discharged from around 2004 onwards”.
British Energy announced immediately after it was set up that it had decided to cancel plans to build new PWRs in the UK. It withdrew the application to build Sizewell C and said it would make no use of the then existing planning consent for Hinkley Point C. The reason given was that “the future of UK energy prices is at present insufficiently certain for British Energy to invest in new nuclear or indeed any other form of new generation in the short term”. However, the then chief executive stated that “construction of new nuclear plant remains part of BE’s business strategy, provided it offers an appropriate return to its shareholders.”
In his statement in the 1996/97 annual report, the chairman of British Energy says a principal goal for the company is to invest its surplus cash in projects that will ensure its continued viability beyond the time when its existing stations cease generation. A first step towards improving the balance of the company’s generation mix in the UK was to take a 12.5% stake in Humber Power Ltd, which is building and will operate a 1160 MWe combined cycle gas turbine station. The company is seeking to hedge its pool price risk and to strengthen its position in the UK electricity market through a 15-year alliance, which has been agreed in principle, with the REC Southern Electric. The two companies have also agreed on a modest joint-venture (Sabre Power) to build and operate a string of 50 MWe gas-fired and chp stations in England and Wales. Opportunities for investment in overseas generating plants have also been identified and in September 1997 a 50:50 joint venture – AmerGen Energy Company – was formed with PECO Energy to buy and operate nuclear plants in the United States. There have also been discussions with the provincial government in Ontario, Canada, with regard to a possible participation in Ontario Hydro.
British Energy’s liabilities in respect of power station decommissioning and the management of spent fuels and waste arising from its nuclear power stations are put at £5.6 billion discounted at 3%, of which £3.8 billion has been accrued to date. A segregated decommissioning fund, administered by trustees independent of British Energy, was set up on privatisation. Following an initial endowment of £228 million, the company currently makes annual contributions of £16 million (subject to RPI indexation). The adequacy of the funding and contribution rates are reviewed by the trustees every five years.
Magnox Electric has its headquarters at Berkeley, Gloucestershire, England, and a London office. It owns and operates the 12 Magnox reactors at Bradwell, Dungeness A, Hinkley Point A, Oldbury and Wylfa, which have a total capacity of 3302 MWe, and a small hydro station at Maentwrog in North Wales. It owns the six Magnox reactors at Berkeley, Hunterston A and Trawsfynydd, totalling 1144 MWe, that are being decommissioned following the Safestore strategy. Magnox Electric also owns the Littlebrook facility, Dartford, Kent, which is responsible for the design of remote inspection and repair equipment in support of the company’s operating and decommissioning power stations, and the Oldbury Operator Training Centre, which is leased to Nuclear Electric.
From April 1996 until February this year the shares in Magnox Electric were held by the Secretary of State for Trade and Industry, who appointed the executive chairman and members of the board. With the transfer of Magnox Electric shares to British Nuclear Fuels Ltd, Magnox Electric will operate as a wholly-owned subsidiary of BNFL while arrangements for full integration of the two companies are completed. This is expected to take until the beginning of next year. The intention is that the 12 Magnox reactors operated by Magnox Electric and the eight units operated by BNFL at Calder Hall and Chapelcross will be brought together in a new BNFL business group, Magnox Generation, which will also include the other activities of its present Magnox Business Group. The present managing director of Magnox Electric will be the director of Magnox Generation. Magnox Electric’s decommissioning activities will be transferred to BNFL’s Waste Management and Decommissioning group.
Magnox Electric had a “letter of comfort” from the government which enabled the company to continue trading even though it had a negative balance sheet. The deficit, which was £1.3 billion in 1995/96 was expected to have fallen to £500 million in the current financial year (1997/98). Magnox Electric was also granted a government undertaking of £3.7 billion on 31 March 1996, in recognition of the transfer of liabilities and assets between it and the privatised British Energy. This undertaking increased annually by 4.5% above inflation (it would have been worth £4.3 billion at 31 March 1998) and was to be used as an when the company needed. As this did not fit with BNFL, which is a solvent company, the government has agreed a new £3.7 billion undertaking under which money will be paid to BNFL on a predetermined schedule. With the new agreement the government has been able to reduce its undertaking by £600 million and cancel the letter of comfort to Magnox Electric. There is also provision for the government to reduce its undertaking by a further £800 million if integration of the two companies achieves the expected savings in liabilities. The new organisation will have nuclear liabilities in the region of £9 billion (discounted) and it has been agreed in future to use a common discount rate of 2.5%. Previously Nuclear Electric used 3% and BNFL 2%.
In the year ending 31 March 1997, Magnox Electric earned £528 million on electricity sales of 19.1 TWh. With arrears of payments from the nuclear premium and other income, it was able to declare an operating profit of £261 million on a turnover of £896 million. This masks the fact that Magnox Electric was selling for 2.5p/kWh electricity that it cost 3.0p/kWh to produce. However, the company points out that its avoidable costs at 1.3p/kWh remain well below market electricity prices. (The avoidable cost is defined as the cost of continuing operation to the end of the station’s assumed life minus the costs that would be incurred if the station were to close immediately divided by the projected future output.) Strenuous efforts are being made to reduce operating costs. The NII has agreed to the interval between statutory outages at Olbury being increased from two to three years, a first for a Magnox station.
Magnox Electric calculates its liabilities for reprocessing of fuel and waste management at £6.6 billion and for station decommissioning at £1.8 billion discounted at 3%. £7.9 billion had been provided to end March 1997. The company has established a Liabilities and Decommissioning Division to manage its liabilities and actively reduce them.
New business opportunities are being sought in both the UK and abroad to diversify away from one technology and one set of customers. This includes exploiting the company’s sites for new generating plants and marketing its skills in plant life management and decommissioning. The business obtained includes a £10 million contract from the UKAEA for the dismantling of the core of the WAGR, an engineering design project at Hanford, USA, the provision of decommissioning support services in Japan and operational plant engineering projects, largely concerned with improving safety and operational performance, in Eastern Europe. Work in Eastern Europe is dealt with by the European Support Branch, while new business opportunities are channelled through the Business Development Branch.
The UK Atomic Energy Authority (UKAEA) was set up as a statutory corporation in 1954 with a remit covering atomic research in general, the production of fissile materials and nuclear weapons and the development of civil nuclear power. Over recent years the Authority has moved progressively away from its original roles, but continues to be responsible to the Secretary of State for Trade and Industry. Since April 1994, when several activities were separated off and have since been privatised, the UKAEA’s main tasks have been to care for and, at the appropriate time, manage safely the dismantling of the nuclear facilities developed when it was an R and D organisation, and the disposal of the resulting waste in an environmentally acceptable way (the DRAWMOPS programme); to exploit the property assets on its sites; to exploit the nuclear facilities that remain useful and operational; and to implement the UK’s fusion energy programme. In addition to safety and environmental protection, an overriding aim is secure value for money for the taxpayer, who foots the bill. Also, by involving outside companies, the authority has secured an expansion in the competitive market for nuclear decommissioning and waste management.
The UKAEA has been successful in reducing its costs and this has impacted on the estimated value of its remaining liabilities. In 1996/67 money values and discounted at 6% to April 1997 these were £2.4 billion compared with £3.3 billion in March 1994. In 1996/97 the UKAEA generated a total income of £256 million, some 61% of which was provided by the Department of Trade and Industry (DTI) under the DRAWMOPS programme. Any profits made on the Authority’s commercial activities (£4.5 million in 1996/97) are returned to the DTI. Some 72% of the total 1996/97 expenditure of £247 million was on contracts, most of which were competitively tendered, with external organisations. Staff at the end of 1996/97 numbered 2030. Over £8 million of the total staff costs of £59 million was accounted for by UKAEA staff seconded to the JET fusion project.
The UKAEA is responsible for both the UK fusion research programme and the UK’s contribution to the Joint European Torus (JET). The in-house programme centres on spherical tokamaks (START and MAST) and is funded by the DTI (£15 million in 1996/97).
The UKAEA still owns sites at Dounreay (Caithness), Windscale (Cumbria), Risley (Cheshire), Harwell and Culham (Oxfordshire) and Winfrith (Dorset). The aim is ultimately to dispose of all its property holdings. Decommissioning activities involve some 14 research and prototype reactors and several other radioactive facilities built over the past 50 years. The projects include the Steam Generating Heavy Water (SGHWR) and the Dragon reactor at Winfrith, the WAGR at Windscale, the Prototype Fast Reactor (PFR) and waste management operations at Dounreay, and chemical engineering buildings at Harwell. A feature of the programme has been the divesting of experienced teams from the UKAEA to commercial companies such as WasteChem, NNC, and Rolls-Royce Engineering. An important example of the use of contractors was the appointment in August 1996 of W S Atkins and Associates, supported by AEA Technology and Rolls-Royce, to assist the UKAEA team in managing the Dounreay site.
Commercial nuclear fuel services for research and isotope producing reactors continue to be operated at Dounreay. These include fuel fabrication, uranium recovery and reprocessing. The plant reprocessing fuel from the Prototype Fast Reactor was shut down in September 1996, following a leak in the dissolver. This prompted a full review of all the options for managing the PFR fuel and a combined UKAEA/BNFL team is now analysing the options for the replacement of the dissolver. In the meantime the plant is reprocessing un-irradiated material using another dissolver, the residue recovery plant, which was designed for this purpose.